UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
ý
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2017
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File Number: 001-36463
PARSLEY ENERGY, INC.
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction
of incorporation or organization)
303 Colorado Street, Suite 3000
Austin, Texas
(Address of principal executive offices)
46-4314192
(I.R.S. Employer
Identification No.)
78701
(Zip Code)
(737) 704-2300
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Class A Common Stock, $0.01 par value
Name of each exchange on which registered
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý
No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨
No ý
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý
No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant
to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý
No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in
definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the
definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
Non-accelerated filer
ý
o
(Do not check if a smaller reporting company)
Accelerated filer
Smaller reporting company
Emerging growth company
¨
¨
¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting
standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨
No ý
Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 30, 2017 was approximately $7,591,987,385 based on the closing price as
reported on the New York Stock Exchange.
As of February 28, 2018 , the registrant had 264,053,796 shares of Class A Common Stock and 52,731,731 shares of Class B Common Stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive proxy statement for the 2018 Annual Meeting of Stockholders, to be filed no later than 120 days after the end of the fiscal year to which this Annual Report
on Form 10-K relates, are incorporated by reference into Part III of this Annual Report on Form 10-K.
PARSLEY ENERGY, INC.
FORM 10-K
ANNUAL PERIOD ENDED DECEMBER 31, 2017
TABLE OF CONTENTS
PART I.
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
PART II.
Item 5.
Item 6.
Item 7.
Business
Risk Factors
Unresolved Staff Comments
Properties
Legal Proceedings
Mine Safety Disclosures
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Selected Financial Data
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
Item 8.
Item 9.
Item 9A.
Item 9B.
PART III.
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
PART IV.
Item 15.
Item 16.
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Information
Directors, Executive Officers, and Corporate Governance
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Certain Relationships and Related Transactions, and Director Independence
Principal Accounting Fees and Services
Exhibits, Financial Statement Schedules
Form 10-K Summary
i
Page
6
22
42
43
53
53
54
55
59
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85
85
85
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86
86
86
86
86
87
94
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
Various statements contained in or incorporated by reference into this Annual Report on Form 10-K (this “Annual Report”) that express a belief,
expectation, or intention, or that are not statements of historical fact, are “forward-looking statements” within the meaning of Section 27A of the Securities Act of
1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These forward-looking
statements include statements, projections and estimates concerning the Company’s operations, performance, business strategy, oil and natural gas reserves,
drilling program, capital expenditures, liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims and
disputes, derivative activities and potential financing. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,”
“believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes.
Forward-looking statements are not guarantees of performance. We have based these forward-looking statements on our current expectations and assumptions
about future events. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends,
current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. Actual results may differ
materially from those implied or expressed by the forward-looking statements. These forward-looking statements speak only as of the date of this Annual Report,
or if made earlier, as of the date they were made. We disclaim any obligation to update or revise these statements unless required by law, and we caution you not to
rely on them unduly. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business,
economic, competitive, regulatory and other risks, contingencies and uncertainties relating to, among other matters, the risks discussed under “Item 1A. Risk
Factors,” as well as those factors summarized below.
Forward-looking statements may include statements about our:
business strategy;
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;
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 Annual Report that are not historical.
1
We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of
which are beyond our control, incident to the exploration for and development, production, gathering and sale of oil, natural gas and NGLs. These risks include, but
are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and
other operating risks, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to
capital, the timing of development expenditures, and the other risks described under “Item 1A. Risk Factors.”
Additionally, we caution you that reserve engineering is a process of estimating underground accumulations of oil, natural gas and NGLs that cannot be
measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost
assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made
previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ
significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.
Should one or more of the risks or uncertainties described in this Annual Report occur, or should underlying assumptions prove incorrect, our actual results
and plans could differ materially from those expressed in any forward-looking statements.
All forward-looking statements, expressed or implied, included in this Annual Report are expressly qualified in their entirety by this cautionary note. This
cautionary note should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf
may issue.
Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the
statements in this cautionary note, to reflect events or circumstances after the date of this Annual Report.
2
GLOSSARY OF CERTAIN TERMS AND CONVENTIONS USED HEREIN
The terms defined in this section are used throughout this Annual Report:
(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) Development well . A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
(8) 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.
(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 and after acquiring the related 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 used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle
within a specified interval.
3
(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 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, in which all of the membership interests (including incentive units) in Parsley Energy, LLC were converted to in
connection with our initial public offering.
(31) Proved developed reserves . Proved reserves that can be expected to be recovered:
(i)
(ii)
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
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.
(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.
4
(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.
5
ITEM 1. BUSINESS
Overview
PART I
Parsley Energy, Inc. (either individually or together with its subsidiaries, as the context requires, “we,” “us,” “our” or the “Company”) was formed in
December 2013 to succeed our predecessor, which began operations in August 2008 when it acquired operator rights to wells producing from the Spraberry Trend
in the Midland Basin from Joe Parsley, a co-founder of Parker and Parsley Petroleum Company.
We are an independent oil and natural gas company focused on the acquisition and development of unconventional oil and natural gas reserves in the
Permian Basin. The Permian Basin is located in West Texas and Southeastern New Mexico and is comprised of three primary sub-areas: the Midland Basin, the
Central Basin Platform and the Delaware Basin. These areas are characterized by high oil and liquids-rich natural gas content, multiple vertical and horizontal
target horizons, extensive production histories, long-lived reserves and historically high drilling success rates. Our properties are located in the Midland and
Delaware Basins, where, given the associated returns, we focus predominantly on horizontal development drilling.
As of December 31, 2017 , we had an average working interest of 81% in 372 gross ( 282.6 net) horizontal wells, of which 319 gross ( 241.0 net) are in the
Midland Basin. As of December 31, 2017 , we operated 80% of the horizontal wells in which we have an interest and had the rights to develop 351,857 gross (
219,747 net) acres in the Permian Basin, with approximately 301,160 gross ( 174,392 net) acres located in the Midland Basin and 50,697 gross ( 45,355 net) acres
located in the Delaware Basin.
We intend to grow our reserves and production through the drilling and development of our multi-year inventory of identified drilling locations. As of
December 31, 2017 , we have identified 12,303 gross ( 8,040 net) potential horizontal drilling locations on our existing acreage.
The following table summarizes our net leasehold acreage and technically identified horizontal drilling locations as of December 31, 2017 :
Area (1)
Midland Basin (3)
Delaware Basin (4)
Total Permian Basin
Net Acreage
Net Identified Drilling
Locations (2)
Average Lateral Length
174,392
45,355
219,747
7,225
815
8,040
6,624
8,333
7,479
(1)
(2)
(3)
(4)
Please see “Item 2. Properties.”
We have estimated our drilling locations based on well spacing assumptions for the areas in which we operate and other criteria. The drilling locations on
which we actually drill will depend on the availability of capital, regulatory approvals, commodity prices, costs, actual drilling results and other factors.
Any drilling activities we are able to conduct on these identified locations may not be successful and may not result in our adding additional proved
reserves to our existing proved reserves. See also ‘’Item 1A. Risk Factors.”
Our horizontal location count in the Midland Basin assumes 660’ to 990’ between well spacing, which is equivalent to five to eight wells per 640-acre
section per target interval. The ultimate spacing may be less than these amounts, which would result in a higher location count, or greater than these
amounts, which would result in a lower location count.
Our target horizontal location count in the Delaware Basin assumes 660’ to 1,320’ between well spacing which is equivalent to four to eight wells per
640-acre section per target interval. The ultimate spacing may be less than these amounts, which would result in a higher location count, or greater than
these amounts, which would result in a lower location count.
At December 31, 2017 , our estimated proved oil, natural gas and NGLs reserves were 416.4 MMBoe based on an internal reserve report prepared by our
internal staff of petroleum engineers and audited by Netherland, Sewell & Associates, Inc. (“NSAI”), our independent reserve engineers. Of these reserves,
approximately 50% are classified as proved developed producing. Based on this report, at December 31, 2017 , our proved developed reserves were approximately
57% oil, 19% natural gas and 24% NGLs. These calculated percentages include proved developed non-producing reserves.
6
Our 2018 budget for capital development expenditures is approximately 1,350.0 million to $1,550.0 million , 85% to 90% of which is expected to be used
for drilling and completions and 10% to 15% of which is expected to be used for infrastructure and other expenditures. We expect approximately 20% of the total
budget to be associated with drilling and completions for proved undeveloped reserves as of December 31, 2017 . Our capital budget excludes any amounts that
may be paid for acquisitions. For the years ended December 31, 2017 and 2016, our aggregate drilling and completion expenditures were $1,049.6 million and
$401.6 million , respectively, and our infrastructure and other expenditures were $157.8 million and $94.4 million , respectively, for totals of $1,207.4 million and
$496.0 million , respectively. Of these totals, $65.1 million and $53.2 million were associated with drilling, completions and facility buildout for proved
undeveloped reserves for the years ended December 31, 2017 and 2016, respectively. The amount and timing of 2018 capital expenditures is largely discretionary
and within our control. We could choose to defer a portion of these planned 2018 capital expenditures depending on a variety of factors, including, but not limited
to, the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital,
the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other
working interest owners.
Our Business Strategy
Our business strategy is to increase stockholder value through the following:
•
•
•
Grow
reserves,
production
and
cash
flow
by
developing
our
liquids
rich
resource
base
. We intend to selectively develop our acreage base in an effort to
maximize its value and resource potential. We intend to pursue drilling opportunities offering competitive returns that we believe are supported by
production history and industry activity in the area and repeatable as a result of well-defined geological properties over a large area. Through the
conversion of our resource base to developed reserves, we will seek to increase our reserves, production and cash flow while generating favorable returns
on invested capital.
Improve
operational
and
cost
efficiency
by
maintaining
control
of
our
production
. We currently operate approximately 80% of the horizontal wells in
which we have an interest and intend to maintain operational control of substantially all of our producing properties. We believe that retaining control of
our production will enable us to more efficiently manage the pace of drilling and completion activities, increase recovery rates, lower well costs, improve
drilling performance and increase ultimate hydrocarbon recovery through optimization of our drilling and completion techniques. Our management team
regularly evaluates our operating results against those of other operators in the area in an effort to improve our performance and implement best practices.
Our average horizontal working interest of 81% allows us to realize the majority of the benefits of these activities and cost efficiencies.
Optimizing
and
high-grading
our
leasehold
position
. We regularly evaluate and complete acquisitions of undeveloped leasehold and producing
properties that meet our strategic and financial objectives in the ordinary course of our business, while selectively adding to maintain adequate inventory
life. Our acreage position extends through what we believe are multiple oil and natural gas producing stratigraphic horizons in the Midland Basin and
Delaware Basin, and we believe we can economically and efficiently add and integrate additional acreage into our current operations. We have a proven
history of acquiring leasehold positions in the Permian Basin that have substantial oil-weighted resource potential and believe our management team’s
extensive experience operating in the Midland Basin and Delaware Basin provides us with a competitive advantage in identifying leasing opportunities
and acquisition targets and evaluating resource potential during 2018.
• Maintain
financial
flexibility
. We intend to maintain a conservative financial position to allow us to develop our exploration, drilling and production
activities and maximize the present value of our oil-weighted resource potential. We intend to fund our growth with cash flow from operations, liquidity
under our Revolving Credit Agreement (defined herein) and access to capital markets over time. As of December 31, 2017 , we had approximately
$1,700.8 million of liquidity, including $703.5 million of cash and cash equivalents and short-term investments. Our borrowing base under the Revolving
Credit Agreement currently stands at $1.8 billion , with a commitment level of $1.0 billion . There were no borrowings outstanding and $2.7 million in
letters of credit outstanding under our Revolving Credit Agreement as of December 31, 2017, resulting in availability of $997.3 million . Consistent with
our disciplined approach to financial management, we have an active commodity hedging program through which we seek to hedge a meaningful portion
of our expected oil production, reducing our exposure to downside commodity price fluctuations and enabling us to protect cash flows and maintain
liquidity to fund our capital program and investment opportunities.
7
Our Strengths
We believe that the following strengths will help us achieve our business goals:
•
•
•
•
•
Extensive
horizontal
development
potential
. We believe that the majority of our acreage offers stacked pay potential to develop oil and natural gas from
several prospective target zones, including, depending on the area, the Spraberry, Wolfcamp, and Bone Spring, and further, that some of these target zones
may be characterized by sufficient thickness and resource potential to accommodate more than one pay interval per zone. Through December 31, 2017 ,
we had drilled and completed 231 gross ( 216.2 net) horizontal wells in the Midland Basin and 37 gross ( 35.6 net) horizontal wells in the Delaware Basin.
As of December 31, 2017 , we had an inventory of 12,303 gross ( 8,040 net) identified horizontal drilling locations .
Established
resource
base
and
acreage
position
in
the
core
of
the
Permian
Basin
. Our production is exclusively from the Permian Basin in West
Texas, an area that has supported production since the 1940s. The Permian Basin has well established infrastructure from historical operations, and we
believe it also benefits from a relatively stable regulatory environment that has been established over time. As of December 31, 2017 , our estimated net
proved reserves were composed of approximately 60% oil and 18% natural gas, and 22% NGLs.
Incentivized
management
team
with
substantial
technical
and
operational
expertise
. Our management team has a proven track record of executing on
multi-rig development drilling programs and has extensive experience in the Spraberry and Wolfberry Trends of the Permian Basin. Our Chief Executive
Officer, Bryan Sheffield, is a third generation oil and natural gas executive, and our management team has an average of 21 years of experience. We have
also assembled a robust technical team of petroleum engineers and geologists with an average of 14 years of experience, which we believe will be of
strategic importance as we continue to expand our future exploration and development plans. As of December 31, 2017 , our executive officers held
approximately 13.0% of our outstanding equity interests. We believe the existence of this significant management ownership position provides
meaningful incentive to increase the value of our business for the benefit of all stockholders.
Operating
control
over
substantially
all
our
horizontal
production
. As of December 31, 2017 , we operated approximately 80% of the horizontal wells
in which we have an interest, which translates to a vast majority of our 2017 production. We believe that maintaining control of our production enables us
to dictate the pace of development and better manage the cost, type and timing of exploration and development activities.
Conservative
balance
sheet
. We expect to maintain financial flexibility that will allow us to continue our development activities and selectively pursue
acquisitions. As of December 31, 2017 , we had $997.3 million of available borrowing capacity under our Revolving Credit Agreement, with no
borrowings currently outstanding thereunder. We believe this borrowing capacity, along with cash on hand and cash flow from operations, will provide us
with sufficient liquidity to execute our current capital program.
Recent Events
5.625% Senior Unsecured Notes due 2027
On October 11, 2017, Parsley Energy, LLC (“Parsley LLC”) and Parsley Finance Corp. (“Finance Corp.”) issued $700.0 million aggregate principal amount
of 5.625% senior unsecured notes due 2027 (the “2027 Notes”) in an offering that was exempt from registration under the Securities Act (the “2027 Notes
Offering”). The 2027 Notes Offering resulted in net proceeds to us, after deducting the initial purchasers’ discount and offering expenses, of approximately $692.1
million . These net proceeds are being used to fund a portion of our capital program and for general corporate purposes.
Fifth Amendment to Revolving Credit Facility
On October 11, 2017, the Company, Parsley LLC, as borrower, each of the guarantors thereto, Wells Fargo Bank, National Association, as administrative
agent, and the other lenders party thereto entered into the Fifth Amendment (the “Fifth Amendment”) to our revolving credit agreement (as amended, the
“Revolving Credit Agreement”). The Fifth Amendment, among other things, modified the terms of the Revolving Credit Agreement to (i) increase the borrowing
base from $1.225 billion (to which it was reduced in connection with the closing of the 2027 Notes Offering) to $1.8 billion (although the aggregate elected
commitments remained at $1.0 billion), (ii) decrease the applicable margins for borrowings to a range of (A) 1.5% to 2.5% for LIBOR based borrowings and (B)
0.5% to 1.5% for alternative base rate based borrowings, with the specific
8
applicable margins determined by reference to borrowing base utilization, (iii) provide flexibility, subject to certain conditions, to enter into “reverse 1031
exchanges” under Section 1031 of the Internal Revenue Code of 1986, as amended, (iv) provide enhanced flexibility, subject to certain dollar limitations, to make
investments in unrestricted subsidiaries and joint ventures and to make other investments, and (v) provide enhanced flexibility, subject to certain conditions, to
dispose of oil and gas properties not evaluated in the reserve reports delivered to the lenders pursuant to the Revolving Credit Agreement.
CEO Succession Plan
On January 9, 2018, we announced a succession plan pursuant to which our current Chairman and Chief Executive Officer, Bryan Sheffield, will serve as
Chief Executive Officer through the end of 2018, in the newly-created position of Executive Chairman throughout 2019, and as Chairman of the Board thereafter.
Matt Gallagher, our President and Chief Operating Officer, will succeed Mr. Sheffield as Chief Executive Officer, effective January 1, 2019, and was appointed to
our board of directors concurrent with the announcement.
Tax Cuts and Jobs Act
On December 22, 2017, Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”), was enacted by the U.S. government.
The Tax Act significantly impacts our 2017 effective tax rate and makes broad and complex changes to the U.S. corporate income tax code. Among other changes,
the Tax Act: (i) reduces the U.S. federal corporate income tax rate from 35% to 21%; (ii) repeals the corporate alternative minimum tax and provides for a refund
of previously accrued alternative minimum tax credits; (iii) modifies the provisions relating to the limitations on deductions for executive compensation of publicly
traded corporations; (iv) enacts new limitations regarding the deductibility of interest expense and (v) imposes new limitations on the utilization of net operating
losses arising in taxable years beginning after December 31, 2017.
GAAP requires that the impact of tax legislation be recognized in the period in which the law was enacted. As a result of the Tax Act, we remeasured our
deferred tax assets and liabilities based on the federal income and state income tax rates at which they are now expected to reverse, and they now generally reflect a
federal income tax rate of 21%. The enacted rate change resulted in a noncash increase of approximately $23.9 million to our income tax provision, a
corresponding reduction of $23.9 million to our net noncurrent deferred tax asset balance and a reduction in valuation allowance of $24.3 million December 31,
2017 . As of December 31, 2017 , we have not finalized our accounting for the tax effect of the Tax Act. However, as described in Note 10—Income Taxes in the
notes to our consolidated financial statements, we have made a reasonable estimate of the tax effect of the Tax Act, including the impact on existing deferred tax
balances. Any adjustments recorded to these estimates through 2018 will be included in income from operations as an adjustment to tax expense. The ultimate
impact of the Tax Act may differ from our estimates based on our further analysis of the new law and additional regulatory guidance that may be issued. Further,
the amount of our future federal income tax will be dependent upon our future taxable income.
Organizational Structure
We are a holding company that was incorporated as a Delaware corporation on December 11, 2013 for the purpose of facilitating our initial public offering
(the “IPO”) and to become the sole managing member of Parsley LLC. As of December 31, 2017, our sole material asset consists of 252,260,300 PE Units,
constituting a controlling equity interest in Parsley LLC.
After the effective date of the registration statement but prior to the completion of the IPO, the limited liability company agreement of Parsley LLC was
amended and restated to modify its capital structure by replacing the different classes of interests previously held by Parsley LLC owners with a single new class of
units called “PE Units.” In addition, each holder of PE Units (“PE Unit Holder”) received one share of our Class B Common Stock, par value $0.01 per share
(“Class B Common Stock”). Pursuant to such amended and restated limited liability company agreement (as subsequently amended and restated by the Second
Amended and Restated Limited Liability Company Agreement, the “Parsley LLC Agreement”), the PE Unit Holders generally have the right to exchange (the
“Exchange Right”) their PE Units (and a corresponding number of shares of Class B Common Stock), for shares of our Class A Common Stock, par value $0.01
per share (“Class A Common Stock”) at an exchange ratio of one share of Class A Common Stock for each PE Unit (and a corresponding number of shares of
Class B Common Stock) exchanged (subject to conversion rate adjustments for stock splits, stock dividends and reclassifications), or, if either we or Parsley LLC
so elects, cash (the “Cash Option”). In addition, in connection with the IPO, on May 29, 2014, we entered into a Tax Receivable Agreement (the “TRA”) with
Parsley LLC and the initial PE Unit Holders and certain other holders of equity in us (each such person, a “TRA Holder”). This agreement generally provides for
the payment by us to a TRA Holder of 85% of the net cash savings, if any, in U.S. federal, state or local income tax that we actually realize (or are deemed
9
to realize in certain circumstances) in periods after our IPO as a result of (i) any tax basis increases resulting from the contribution in connection with our IPO by
such TRA Holder of all or a portion of its PE Units to us in exchange for shares of Class A Common Stock, (ii) the tax basis increases resulting from the exchange
by such TRA Holder of PE Units for shares of Class A Common Stock pursuant to the Exchange Right (or resulting from an exchange of PE Units for cash
pursuant to the Cash Option) and (iii) imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under
the TRA. We will retain the benefit of the remaining 15% of these cash savings. See “Item 13. Certain Relationships and Related Transactions, and Director
Independence.”
As a result of the IPO and the related reorganization transactions, we became the sole managing member of and have a controlling equity interest in
Parsley LLC. As the sole managing member of Parsley LLC, we operate and control all of the business and affairs of Parsley LLC and, through Parsley LLC and
its subsidiaries, conduct our business. We consolidate the financial and operating results of Parsley LLC and its subsidiaries and record noncontrolling interests for
the economic interest in Parsley LLC held by the PE Unit Holders.
The following diagram shows our organizational structure as of February 28, 2018 . This chart is provided for illustrative purposes only and does not
represent all legal entities affiliated with us.
10
Oil and Natural Gas Production Prices and Production Costs
Production
and
Price
History
The following table sets forth information regarding net production of oil, natural gas and NGLs and certain price and cost information for the periods
indicated:
Revenues (in thousands):
Oil sales
Natural gas sales
Natural gas liquids sales
Total revenues
Average realized prices (1) :
Oil, without realized derivatives (per Bbls)
Oil, with realized derivatives (per Bbls)
Natural gas, without realized derivatives (per Mcf)
Natural gas, with realized derivatives (per Mcf)
Natural gas liquids (per Bbls)
Average price per Boe, without realized derivatives
Average price per Boe, with realized derivatives
Production (2) :
Oil (MBbls)
Natural gas (MMcf)
Natural gas liquids (MBbls)
Total (MBoe)
Average daily production volume:
Oil (Bbls)
Natural gas (Mcf)
Natural gas liquids (Bbls)
Total (Boe)
$
$
$
Year Ended December 31,
2017
2016
2015
802,230 $
387,303 $
56,571
103,193
30,928
38,273
961,994 $
456,504 $
215,795
26,582
23,680
266,057
48.95 $
41.34 $
47.68
2.43
2.40
22.87
38.80
37.94
16,390
23,326
4,512
24,792
44,904
63,907
12,362
67,923
47.56
2.30
2.30
16.01
32.60
36.76
9,368
13,463
2,390
14,002
25,596
36,784
6,530
38,257
44.89
56.60
2.57
2.72
15.79
33.13
40.33
4,807
10,339
1,500
8,031
13,170
28,326
4,110
22,003
(1)
(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.
Approximately 88%, 90% and 98% of our total estimated proved reserves as of December 31, 2017, 2016 and 2015, respectively, were attributable to the
Midland Basin. Our production from the Midland Basin was 21,641 MBoe (14,082 MBbls oil, 20,835 MMcf natural gas, 4,087 MBbls natural gas
liquids), 13,222 MBoe (8,693 MBbls oil, 13,134 MMcf natural gas, 2,340 MBbls natural gas liquids) and 7,952 MBoe (4,740 MBbls oil, 10,309 MMcf
natural gas, 1,494 MBbls natural gas liquids) for the years ended December 31, 2017, 2016 and 2015, respectively.
Productive
Wells
As of December 31, 2017 , we owned an average 81% working interest in 372 gross ( 282.6 net) productive horizontal wells. As of December 31, 2017 , we
owned an average 61% working interest in 1,532 gross ( 749.0 net) productive vertical wells. Productive wells consist of producing wells and wells capable of
production, including oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest and
net wells are the sum of our fractional working interests owned in gross wells. As of December 31, 2017 , we owned an immaterial number of productive wells
related to the production of natural gas.
11
Well
Operations
As of December 31, 2017 , we operated approximately 80% of the horizontal wells in which we have an interest. As operator, we design and manage the
development of a well and supervise operation and maintenance activities on a day-to-day basis. Independent contractors engaged by us provide all the equipment
and personnel associated with these activities. We employ petroleum engineers, geologists and land professionals who work to improve production rates, increase
reserves and lower the cost of operating our oil and natural gas properties.
Marketing
and
Customers
We market the majority of the production from properties we operate for both our account and the account of the other working interest owners in these
properties. We sell our production to purchasers at market prices.
We normally sell production to a relatively small number of customers, as is customary in the exploration, development and production business. For the
year ended December 31, 2017 , two purchasers each accounted for more than 10% of our revenue during the period: Shell Trading (US) Company (“Shell”) and
Targa Pipeline Mid-Continent, LLC (“Targa”). For the year ended December 31, 2016 , three purchasers each accounted for more than 10% of our revenue during
the period: Shell, BML, Inc. (“BML”) and Targa. For the year ended December 31, 2015 , four purchasers each accounted for more than 10% of our revenue
during the period: Shell, BML, Targa and Transoil Marketing, LLC. No other customer accounted for more than 10% of our revenue during these periods. If a
major customer decided to stop purchasing oil and natural gas from us, our revenue could decline and our operating results and financial condition could be
harmed. However, we believe that the loss of any one or all of our major purchasers would not have a material adverse effect on our financial condition or results
of operations, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers. Please see Note 2—Summary of
Significant Accounting Policies—Significant Customers to our consolidated financial statements included elsewhere in this Annual Report for additional
information.
Transportation
During the initial development of our fields, we consider all gathering and delivery infrastructure in the areas of our production. Our oil is transported from
the wellhead to our tank batteries by our gathering systems. The purchaser then transports the oil by truck or pipeline to a tank farm, another pipeline or a refinery.
Our natural gas is transported from the wellhead to the purchaser’s meter and pipeline interconnection point through our gathering systems.
In addition, we move the majority of our produced water by pipeline connected to our operated salt water disposal wells rather than by truck. However, due
to the inaccessibility of certain of our wells, some produced water will likely always be required to be taken away by truck.
During the year ended December 31, 2016, we entered into a contract with a private midstream company that provides for firm pipeline transportation from
our acreage in Reagan, Upton and Midland Counties, Texas to Crane, Colorado City and Midland, Texas, which enables us to choose from multiple destinations for
a substantial portion of our crude oil production.
During the year ended December 31, 2017, we entered into a contract that provides firm transportation off one of the pipeline systems through which we transport
or sell crude oil. Under this contract, we are committed to deliver minimum average volumes of 45,000 Bbls/day from January 1, 2018 to December 31, 2018 and
37,500 Bbls/day from January 1, 2019 to June 30, 2020. Satisfaction of the volume requirements includes volumes produced by us and other third-party working,
royalty, and overriding royalty interest owners whose volumes we market on their behalf. Our consolidated statements of operations reflect our share of firm
transportation costs. This contract requires us to pay a deficiency fee if we fail to deliver the required volumes.
As of December 31, 2017, approximately 69% of our gross oil production was being transported by these pipeline systems and sold under these agreements.
We do not believe, however, that the termination of either of these agreements would materially impact our operating results, as crude oil and natural gas are
fungible products with well-established markets and numerous purchasers. We expect to fulfill our delivery commitments for the next one to three years with
existing proved developed and proved undeveloped reserves, which we regularly monitor to ensure sufficient availability. In addition, we monitor our current
production, our anticipated future production and our future development plans in order to meet our delivery commitments. If production is not sufficient to meet
contractual delivery commitments, we may purchase commodities in the market to satisfy our delivery commitments.
12
Competition
The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not
only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional,
national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define,
evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a
greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger or more integrated competitors may be able to
absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our
competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select
suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than
many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.
There is also competition between oil and natural gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be
substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments of the United States and the
jurisdictions in which we operate. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon
our future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent
or delay the commencement or continuation of a given operation. Our larger competitors may be able to absorb the burden of existing, and any changes to, federal,
state and local laws and regulations more easily than we can, which would adversely affect our competitive position.
Segment
Information
and
Geographic
Area
Operating segments are defined under GAAP as components of an enterprise that (i) engage in activities from which it may earn revenues and incur
expenses (ii) for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of
allocating resources and assessing performance.
Based on our organization and management, we have only one reportable operating segment, which is oil and natural gas exploration and production. We
consider drilling rig services ancillary to our oil and natural gas exploration and producing activities and manage these services to support such activities. All of our
operations are conducted in one geographic area of the United States. For additional information, see our consolidated financial statements in this Annual Report
beginning on page F-1.
Seasonality
of
Business
Weather conditions affect the demand for and prices of, oil and natural gas. Demand for oil and natural gas is typically higher in the first and fourth quarters,
resulting in higher prices. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be
realized on an annual basis. See “Item 1A. Risk Factors—Risks Related to the Oil and Natural Gas Industry and Our Business—“Extreme weather conditions could
adversely affect our ability to conduct drilling activities in the areas where we operate” for additional information.
Oil
and
Natural
Gas
Leases
Typically the oil and natural gas lease agreements covering our properties provide for the payment of royalties to the mineral owner for all oil and natural
gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from 20% to 25%,
resulting in a net revenue interest to us generally ranging from 75% to 80%. In cases where we own minerals underlying properties that we operate, our net revenue
interest will be higher.
Markets
for
Sale
of
Production
Our ability to market oil and natural gas found and produced, if any, will depend on numerous factors beyond our control, the effect of which cannot be
accurately predicted or anticipated. Some of these factors include, without limitation, the availability of other domestic and foreign production, the marketing of
competitive fuels, the proximity and capacity of pipelines, fluctuations in supply and demand, the availability of a ready market, the effect of United States federal
and state regulation of production, refining, transportation and sales and general national and worldwide economic conditions.
13
Additionally, we may experience delays in marketing natural gas production and fluctuations in natural gas prices and our marketing professionals may experience
short-term delays in marketing oil due to trucking and refining constraints. There is no assurance that we will be able to market any oil or natural gas produced, or,
if such oil or natural gas is marketed, that favorable prices can be obtained.
The United States natural gas market has undergone several significant changes over the past few decades. The majority of federal price ceilings were
removed in 1985 and the remainder were lifted by the Natural Gas Wellhead Decontrol Act of 1989. Thus, currently, the United States natural gas market is
operating in a free market environment in which the price of gas is determined by market forces rather than by regulations. At the same time, the domestic natural
gas industry has also seen a dramatic change in the manner in which gas is bought, sold and transported. In most cases, natural gas is no longer sold to a pipeline
company. Instead, the pipeline company now primarily serves the role of transporter and gas producers are free to sell their product to marketers, local distribution
companies, end users or a combination thereof.
In recent years, oil, natural gas and NGLs prices have been under considerable pressure due to oversupply and other market conditions. Specifically,
increased foreign production and increased efficiencies in horizontal drilling, combined with exploration of newly developed shale fields in North America, have
dramatically increased global oil and natural gas production, which has led to lower market prices for these commodities. Given the many uncertainties affecting
the supply and demand for oil, natural gas and NGLs, we are unable to accurately predict future oil, natural gas and NGLs prices or the overall effect, if any, that
the oversupply of such products and other market conditions will have on our financial condition or results of operations.
Regulation of the Oil and Natural Gas Industry
Our operations are substantially affected by federal, state and local laws and regulations. Failure to comply with applicable laws and regulations can result
in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in
substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to
predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by the
United States Congress (“Congress”), the states, the Federal Energy Regulatory Commission (the “FERC”) and the courts. We cannot predict when or whether any
such proposals may become effective. We do not believe that we would be affected by any such action materially differently than similarly situated competitors.
Regulation
Affecting
Production
Natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the
jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the exploration for and production of oil and
natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of
drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and
completion process and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the
size of drilling and spacing units or proration units, the number of wells which may be drilled in an area and the unitization or pooling of crude oil or natural gas
wells, as well as regulations that generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair
apportionment of production from fields and individual wells. These laws and regulations may limit the amount of oil and natural gas wells we can drill. Moreover,
each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. States do not
regulate wellhead prices or engage in other similar direct regulation, but there can be no assurance that they will not do so in the future. The effect of such future
regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells
or limit the number of locations we can drill.
The failure to comply with the rules and regulations of natural gas production and related operations can result in substantial penalties. Our competitors in
the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.
Regulation
Affecting
Sales
and
Transportation
of
Commodities
Sales prices of oil, natural gas and NGLs are not currently regulated and are made at market prices. Although prices of these energy commodities are
currently unregulated, Congress historically has been active in their regulation. We cannot predict whether new legislation to regulate oil and natural gas, or the
prices charged for these commodities might be proposed, what
14
proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, the proposals might have on our operations. Sales
of oil and natural gas may be subject to certain state and potentially federal reporting requirements.
The price and terms of service of transportation of the commodities, including access to pipeline transportation capacity, are subject to extensive federal and
state regulation. Such regulation may affect the marketing of oil and natural gas produced, as well as the revenues received for sales of such production. Gathering
systems may be subject to state ratable take and common purchaser statutes. Ratable take statutes generally require gatherers to take, without undue discrimination,
oil and natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase, or
accept for gathering, without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one
producer over another producer or one source of supply over another source of supply. These statutes may affect whether and to what extent gathering capacity is
available for oil and natural gas production, if any, of the drilling program and the cost of such capacity. Further, state laws and regulations govern rates and terms
of access to intrastate pipeline systems, which may similarly affect market access and cost.
The FERC regulates interstate natural gas pipeline transportation rates and service conditions. The FERC is continually proposing and implementing new
rules and regulations affecting interstate transportation. The stated purpose of many of these regulatory changes is to promote competition among the various
sectors of the natural gas industry and to promote market transparency. We do not believe that our drilling program will be affected by any such FERC action in a
manner materially differently than other similarly situated natural gas producers.
Gathering services, which occur upstream of FERC jurisdictional transmission services, are regulated by the states onshore and in state waters. Although the
FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, the
FERC’s determinations as to the classification of facilities is done on a case-by-case basis. State regulation of natural gas gathering facilities generally includes
various safety, environmental and, in some circumstances, nondiscriminatory take requirements. Although such regulation has not generally been affirmatively
applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.
In addition to the regulation of natural gas pipeline transportation, the FERC has jurisdiction over the purchase or sale of gas or the purchase or sale of
transportation services subject to the FERC’s jurisdiction pursuant to the Energy Policy Act of 2005. Under this law, it is unlawful for “any entity,” including
producers such as us, that are otherwise not subject to the FERC’s jurisdiction under the Natural Gas Act of 1938 to use any deceptive or manipulative device or
contrivance in connection with the purchase or sale of gas or the purchase or sale of transportation services subject to regulation by the FERC, in contravention of
rules prescribed by the FERC. The FERC’s rules implementing this provision make it unlawful, in connection with the purchase or sale of gas subject to the
jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or
employ any device, scheme or artifice to defraud, to make any untrue statement of material fact or omit to make any such statement necessary to make the
statements made not misleading, or to engage in any act or practice that operates as a fraud or deceit upon any person. The Energy Policy Act of 2005 also gives
the FERC authority to impose civil penalties for violations of the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978 up to $1,238,271 per day per
violation (adjusted annually based on inflation). The anti-manipulation rule applies to activities of otherwise non-jurisdictional entities to the extent the activities
are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which includes the annual reporting requirements under
Order 704 (defined below).
In December 2007, the FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing
(“Order 704”). Under Order 704, any market participant, including a producer such as us, that engages in wholesale sales or purchases of gas that equal or exceed
2.2 million MMBtus of physical natural gas in the previous calendar year, must annually report such sales and purchases to the FERC on Form No. 552 on May 1
of each year. Form No. 552 contains aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions
utilize or contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported
based on the guidance of Order 704. Order 704 is intended to increase the transparency of the wholesale gas markets and to assist the FERC in monitoring those
markets and in detecting market manipulation.
The FERC also regulates rates and service conditions for interstate transportation of liquids, including oil and NGLs, under the Interstate Commerce Act
(the “ICA”). Prices received from the sale of liquids may be affected by the cost of transporting those products to market. The ICA requires that pipelines maintain
a tariff on file with the FERC. The tariff sets forth the established rates as well as the rules and regulations governing the service. The ICA requires, among other
things, that rates and terms and conditions of service on interstate common carrier pipelines be “just and reasonable.” Such pipelines must
15
also provide jurisdictional service in a manner that is not unduly discriminatory or unduly preferential. Shippers have the power to challenge new and existing rates
and terms and conditions of service before the FERC.
Rates of interstate liquids pipelines are currently regulated by the FERC primarily through an annual indexing methodology, under which pipelines increase
or decrease their rates in accordance with an index adjustment specified by the FERC. For the five-year period beginning on July 1, 2016, the FERC established an
annual index adjustment equal to the change in the producer price index for finished goods plus 1.23%. This adjustment is subject to review every five years. Under
the FERC’s regulations, a liquids pipeline can request the authority to charge market-based rates for transportation service if it satisfies certain criteria, and also can
request a rate increase that exceeds the rate obtained through application of the indexing methodology by using a cost-of-service approach, but only after the
pipeline establishes that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing
methodology. Increases in liquids transportation rates may result in lower revenue and cash flows.
In addition, due to common carrier regulatory obligations of liquids pipelines, capacity must be prorated among shippers in an equitable manner in the event
there are nominations in excess of capacity. Therefore, requests for service by new shippers or increased volume by existing shippers may reduce the capacity
available to us. Any prolonged interruption in the operation or curtailment of available capacity of the pipelines that we rely upon for liquids transportation could
have a material adverse effect on our business, financial condition, results of operations and cash flows. However, we believe that access to liquids pipeline
transportation services generally will be available to us to the same extent as to our similarly situated competitors.
Intrastate liquids pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate liquids pipeline regulation
and the degree of regulatory oversight and scrutiny given to intrastate liquids pipeline rates, varies from state to state. We believe that the regulation of liquids
pipeline transportation rates will not affect our operations in any way that is materially different from the effects on our similarly situated competitors.
In addition to the FERC’s regulations, we are required to observe anti-market manipulation laws with regard to our physical sales of energy commodities. In
November 2009, the Federal Trade Commission (the “FTC”) issued regulations pursuant to the Energy Independence and Security Act of 2007 intended to prohibit
market manipulation in the petroleum industry. Violators of the regulations face civil penalties of up to $1,180,566 per violation per day (adjusted annually based
on inflation). In July 2010, Congress passed the Dodd-Frank Act, which incorporated an expansion of the authority of the Commodity Futures Trading Commission
(the “CFTC”) to prohibit market manipulation in the markets regulated by the CFTC. This authority, with respect to crude oil swaps and futures contracts, is
similar to the anti-manipulation authority granted to the FTC with respect to crude oil purchases and sales. In July 2011, the CFTC issued final rules to implement
its new anti-manipulation authority. The rules subject violators to a civil penalty of up to the greater of $1,116,156 (adjusted annually based on inflation) or triple
the monetary gain to the person for each violation.
Regulation of Environmental and Occupational Safety and Health Matters
Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge
of materials into the environment and occupational health and safety. These laws and regulations may, among other things: (i) require the acquisition of permits to
conduct exploration, drilling and production operations; (ii) restrict the types, quantities and concentration of various substances that can be released into the
environment or injected into formations in connection with oil and natural gas drilling and production activities; (iii) limit or prohibit drilling activities on certain
lands lying within wilderness, wetlands and other protected areas; (iv) require remedial measures to mitigate pollution from former and ongoing operations, such as
requirements to close pits and plug abandoned wells; and (v) impose substantial liabilities for pollution resulting from drilling and production operations. Any
failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of corrective or
remedial obligations and the issuance of orders enjoining performance of some or all of our operations.
These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory
burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and
federal and state agencies frequently revise environmental laws and regulations and any changes that result in more stringent and costly waste handling, disposal
and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs.
The clear trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment and thus any
changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage,
transportation, disposal, or remediation requirements could
16
have a material adverse effect on our financial position and results of operations. We may be unable to pass on such increased compliance costs to our purchasers.
Moreover, accidental releases or spills may occur in the course of our operations and we cannot assure you that we will not incur significant costs and liabilities as
a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. While compliance with existing
environmental laws and regulations has not had a material adverse effect on our operations, we can provide no assurance that this will continue in the future.
The following is a summary of the more significant existing and proposed environmental, occupational health and safety laws and regulations to which our
business operations are or may be subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or
financial position.
The
Resource
Conservation
and
Recovery
Act
The Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal
and cleanup of hazardous and non-hazardous wastes. Pursuant to rules issued by the U.S. Environmental Protection Agency (the “EPA”), the individual states
administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and
most of the other wastes associated with the exploration, development and production of crude oil or natural gas are currently regulated under RCRA’s non-
hazardous waste provisions. However, it is possible that certain oil and natural gas drilling and production wastes now classified as non-hazardous could be
classified as hazardous wastes in the future. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address the
EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and natural gas wastes
from regulation as hazardous wastes under RCRA. The consent decree requires the EPA to propose a rulemaking no later than March 15, 2019 for revision of
certain Subtitle D criteria regulations pertaining to oil and natural gas wastes or to sign a determination that revision of the regulations is not necessary. Removal of
RCRA’s exemption for exploration and production wastes has the potential to significantly increase our waste disposal costs to manage, which in turn will result in
increased operating costs and could adversely impact our results of operations and financial position. Also, in the course of our operations, we generate some
amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes if such wastes have hazardous
characteristics.
Comprehensive
Environmental
Response,
Compensation
and
Liability
Act
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several
liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the
environment. These persons include the current and former owners and operators of the site where the release occurred and anyone who disposed or arranged for
the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the
hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not
uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances
released into the environment.
We generate materials in the course of our operations that may be regulated as hazardous substances. Despite the “petroleum exclusion” of CERCLA, which
currently encompasses natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our
ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these
hazardous substances have been released into the environment. In addition, we currently own, lease, or operate numerous properties that have been used for oil and
natural gas exploration, production and processing for many years. Although we believe that we have utilized operating and waste disposal practices that were
standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on, under or from the properties owned or leased by us,
or on, under or from other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been
operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our
control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state and local laws.
Under such laws, we could be required to undertake investigatory, response, or corrective measures, which could include soil and groundwater sampling, the
removal of previously disposed substances and wastes, the cleanup of contaminated property, or performance of remedial plugging or pit closure operations to
prevent future contamination, the costs of which could be substantial.
17
Water
Discharges
The Federal Water Pollution Control Act, or the Clean Water Act (the “CWA”), and analogous state laws impose restrictions and strict controls with respect
to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated
waters, including wetland areas, is prohibited, except in accordance with the terms of a permit issued by the EPA, the U.S. Army Corps of Engineers (the
“USACE”) or an analogous state agency. In September 2015, the EPA and the USACE issued a final rule redefining the scope of the EPA’s and the USACE’s
jurisdiction under the CWA with respect to certain types of waterbodies and classifying these waterbodies as regulated wetlands. The 2015 rule was previously
stayed nationwide to determine whether federal district or appellate courts had jurisdiction to hear cases in the matter and, in January 2017, the U.S. Supreme Court
agreed to hear the case. The EPA and the USACE proposed a rulemaking in June 2017 to repeal the June 2015 rule and announced their intent to issue a new rule
defining the CWA’s jurisdiction. Recently, in January 2018, the U.S. Supreme Court issued a decision finding that jurisdiction to hear challenges to the 2015 rule
resides with the federal district courts; consequently, the previously-filed district court cases will be allowed to proceed. Following the Supreme Court’s decision,
the EPA and the USACE issued a final rule in January 2018 staying implementation of the 2015 rule for two years. As a result of these recent developments, future
implementation of the June 2015 rule is uncertain. To the extent the rule or any replacement rule expands the scope of the CWA’s jurisdiction, we could face
increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. In addition, federal and state regulatory agencies can
impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and
regulations. We do not expect the costs to comply with the requirements of the CWA to have a material adverse effect on our operations.
The Oil Pollution Act of 1990 amends the CWA and establishes strict liability for owners and operators of facilities that cause a release of oil into waters of
the United States. In addition, this law requires owners and operators of facilities that store oil above specified threshold amounts to develop and implement spill
prevention, control and countermeasures plans.
Safe
Drinking
Water
Act
In the course of our operations, we produce water in addition to oil and natural gas. Water that is not recycled or otherwise disposed of on the lease may be
sent to saltwater disposal wells for injection into subsurface formations. Underground injection operations are regulated under the federal Safe Drinking Water Act
and permitting and enforcement authority may be delegated to the states. In Texas, the Texas Railroad Commission (“RRC”) regulates the disposal of produced
water by injection well. The RRC requires operators to obtain a permit from the agency for the operation of saltwater disposal wells and establishes minimum
standards for injection well operations. In response to recent seismic events near underground injection wells used for the disposal of oil and natural gas-related
waste waters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down
or imposed moratoria on the use of such injection wells. In response to these concerns, regulators in some states are considering additional requirements related to
seismic safety. For example, the RRC has adopted new rules for injection wells to address these seismic activity concerns in Texas. Among other things, the rules
require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for
certain wells and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic
activity. These new rules could impact the availability of injection wells for disposal of wastewater from our operations. Increased costs associated with the
transportation and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may reduce our profitability;
however, these costs are commonly incurred by all oil and natural gas producers, and we do not believe that the costs associated with the disposal of produced
water will have a material adverse effect on our operations.
Air
Emissions
The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources, such as tank batteries and compressor
stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and
regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase
air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain
pollutants. The need to obtain permits has the potential to delay the development of oil and natural gas projects. Over the next several years, we may be required to
incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in October 2015, the EPA lowered the
National Ambient Air Quality Standard for ozone from 75 to 70 parts per billion. In November 2017, the EPA published a list of areas that are in compliance with
the new ozone standards and, separately in December 2017, issued responses to state recommendations for designating non-attainment areas. States have the
opportunity to submit new air quality monitoring to the EPA prior to the EPA finalizing any non-attainment
18
designations. State implementation of these revised air quality standards could result in stricter permitting requirements, delay or prohibit our ability to obtain such
permits and result in increased expenditures for pollution control equipment, the costs of which could be significant. More recently, in June 2016, the EPA
finalized a rule regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and
natural gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting
requirements, which in turn could result in operational delays or require us to install costly pollution control equipment. The EPA has also adopted new rules under
the Clean Air Act that require the reduction of volatile organic compound emissions from certain fractured and refractured natural gas wells for which well
completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations
also establish specific new requirements regarding emissions from production‑related wet seal and reciprocating compressors and from pneumatic controllers and
storage vessels. In addition, in June 2016, the EPA issued final rules that establish new air emission controls for emissions of methane from certain equipment and
processes in the oil and natural gas source category, including production, processing, transmission and storage activities. The final rules include first-time
standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well
completions. In addition, the rule package extends existing volatile organic compound standards under the EPA’s Subpart OOOO of the New Source Performance
Standards to include previously unregulated equipment within the oil and natural gas source category. However, in June 2017, the EPA published a proposed rule
to stay certain portions of the June 2016 standards for two years and re-evaluate the entirety of the 2016 standards but the EPA has not yet published a final rule
and, as a result, the June 2016 rule remains in effect but future implementation of the 2016 standards is uncertain at this time. To the extent fully implemented,
compliance with this rule will require enhanced record-keeping practices, the purchase of new equipment such as optical gas imaging instruments to detect leaks
and the increased frequency of maintenance and repair activities to address emissions leakage. The rules may also require hiring additional personnel to support
these activities or the engagement of third party contractors to assist with and verify compliance. These and other air pollution control and permitting requirements
have the potential to delay the development of oil and natural gas projects and increase our costs of development and production, which costs could be significant.
However, we do not believe that compliance with such requirements will have a material adverse effect on our operations.
Regulation
of
Greenhouse
Gas
Emissions
In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the
environment, the EPA has adopted regulations under existing provisions of the Clean Air Act that, among other things, establish Prevention of Significant
Deterioration (“PSD”), construction and Title V operating permit reviews for certain large stationary sources. Facilities required to obtain PSD permits for their
GHG emissions also will be required to meet “best available control technology” standards that will be established on a case-by-case basis. EPA rulemakings
related to GHG emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the
EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the
United States on an annual basis, which include gathering and boosting facilities as well as GHG emissions from completions and workovers from hydraulically
fractured oil wells. Also, as noted above, the EPA has proposed a New Source Performance Standard related to methane emissions from the oil and natural gas
source category.
While Congress has considered legislation related to the reduction of GHG emissions in the past, the possibility of federal legislation related to climate
change appears unlikely at this time. In the absence of such federal climate legislation, a number of state and regional cap and trade programs have emerged that
typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs.
At the international level, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention
on Climate Change in Paris, France that requires member countries to review and ‘‘represent a progression’’ in their intended nationally determined contributions,
which set GHG emission reduction goals every five years beginning in 2020. The Paris Agreement entered into force in November 2016. Although this agreement
does not create any binding obligations for nations to limit their GHG emissions, it does include pledges from participating nations to voluntarily limit or reduce
future emissions. In June 2017, President Trump stated that the United States would withdraw from the Paris Agreement, but may enter into a future international
agreement related to GHGs. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an
effective exit date of November 2020. The United States’ adherence to the exit process is uncertain and/or the terms on which the United States may reenter the
Paris Agreement or a separately negotiated agreement are unclear at this time. Although it is not possible at this time to predict how legislation or new regulations
that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting
emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations.
19
In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce and lower the value of our
reserves. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy
companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas
activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities. Notwithstanding potential risks related to climate
change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and gas will
continue to represent a substantial percentage of global energy use over that time. Finally, it should be noted that some scientists have concluded that increasing
concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of
storms, floods, droughts and other extreme climatic events; if any such effects were to occur, they could have an adverse effect on our exploration and production
operations.
Hydraulic
Fracturing
Activities
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock
formations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into target geological formations to
fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Recently, there has been increased public
concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies and proposals have been made to enact separate federal,
state and local legislation that would increase the regulatory burden imposed on hydraulic fracturing.
At the federal level, the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving
the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities. Also, in May 2014, the EPA issued an
Advance Notice of Proposed Rulemaking to collect data on chemicals used in hydraulic fracturing operations under Section 8 of the Toxic Substances Control Act
(“TSCA”). To date, no other action has been taken and the likelihood of any future rulemaking under TSCA appears remote at this time. Further, the EPA finalized
regulations under the CWA in June 2016 that prohibit wastewater discharges from hydraulic fracturing and certain other natural gas operations to publicly owned
wastewater treatment plants. Also, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources.
The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,”
noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or
more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids,
chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater
resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits.
At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well
construction requirements on hydraulic fracturing activities. For example in May 2013, the RRC adopted new rules governing well casing, cementing and other
standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. Local governments also may seek to adopt ordinances within
their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of
well drilling in general or hydraulic fracturing in particular. We believe that we follow applicable standard industry practices and legal requirements for
groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic
fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or
curtailment in the pursuit of exploration, development, or production activities and perhaps even be precluded from drilling wells.
If new federal, state or local laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays,
eliminate certain drilling and injection activities and make it more difficult or costly to perform fracturing. Any such regulations limiting or prohibiting hydraulic
fracturing could reduce oil and natural gas exploration and production activities and, therefore, adversely affect our business. Such laws or regulations could also
materially increase our costs of compliance and doing business by more strictly regulating how hydraulic fracturing wastes are handled or disposed.
Endangered
Species
Act
and
Migratory
Birds
The federal Endangered Species Act (“ESA”) and (in some cases) comparable state laws were established to protect endangered and threatened species.
Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be
20
imposed on activities adversely affecting that species’ habitat. We may conduct operations on oil and natural gas leases in areas where certain species that are listed
as threatened or endangered are known to exist and where other species, such as the sage grouse, that potentially could be listed as threatened or endangered under
the ESA may exist. The U.S. Fish and Wildlife Service (the “FWS”) may designate critical habitat and suitable habitat areas that it believes are necessary for the
survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and
may materially delay or prohibit land access for oil and natural gas development. Moreover, as a result of a 2011 settlement agreement, the FWS was required to
make a determination on listing of more than 250 species as endangered or threatened under the FSA by no later than completion of the agency’s 2017 fiscal year.
The FWS missed the deadline and continues to review new species for protected status under the ESA. Similar protections are offered to migratory birds under the
Migratory Bird Treaty Act. Recently, there have been renewed calls to review protections currently in place for the dunes sagebrush lizard, whose habitat includes
the Permian Basin, and to reconsider listing the species under the ESA. The identification or designation of previously unprotected species as threatened or
endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could
result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves. If we were to
have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.
OSHA
We are subject to the requirements of the Occupational Safety and Health Administration (“OSHA”) and comparable state statutes whose purpose is to
protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and
comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our
operations and that this information be provided to employees, state and local governmental authorities and citizens.
Related
Permits
and
Authorizations
Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling,
construction, production, operation, or other oil and natural gas activities and to maintain these permits and compliance with their requirements for on-going
operations. These permits are generally subject to protest, appeal, or litigation, which, in certain cases, can delay or halt projects and cease production or operation
of wells, pipelines and other operations.
Related
Insurance
We maintain insurance against some risks associated with above or underground contamination that may occur as a result of our exploration and production
activities. However, this insurance is limited to activities at the well site, and there can be no assurance that this insurance will continue to be commercially
available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or
indemnified against could have a material adverse effect on our financial condition and operations.
Although we have not experienced any material adverse effect from compliance with environmental requirements, there is no assurance that this will
continue. We did not have any material capital or other non-recurring expenditures in connection with complying with environmental laws or environmental
remediation matters in 2017 , nor do we anticipate that such expenditures will be material in 2018 .
Employees
As of December 31, 2017 , we employed 460 people. We consider our relations with employees to be satisfactory. Our future success will depend in part on
our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements and have not experienced any strikes or
work stoppages. We regularly utilize the services of independent contractors to perform various field and other services
Available Information
We file or furnish annual, quarterly and current reports, proxy statements and other documents with the SEC under the Exchange Act. The public may read
and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549, on official business days during
the hours of 10 a.m. to 3 p.m. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC
also maintains an
21
internet website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers, including us, that file
electronically with the SEC.
Our Class A Common Stock is listed and traded on the New York Stock Exchange (“NYSE”) under the symbol “PE.” Our reports, proxy statements and
other information filed with the SEC can also be inspected and copied at the offices of the NYSE, at 20 Broad Street, New York, New York 10005.
We also make available free of charge through our website, www.parsleyenergy.com , electronic copies of certain documents that we file with the SEC,
including our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished
pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.
ITEM 1A. RISK FACTORS
You should carefully consider the following risks and all of the information contained in this Annual Report. Our business, financial condition and results of
operations could be materially and adversely affected by any of these risks. The risks described below are not the only ones facing us. Additional risks not
presently known to us or which we consider immaterial also may adversely affect us.
Risks Related to the Oil and Natural Gas Industry and Our Business
Oil,
natural
gas
and
NGLs
prices
are
volatile.
A
substantial
or
extended
decline
in
commodity
prices
or
decrease
in
demand
for
hydrocarbons
may
adversely
affect
our
business,
financial
condition
or
results
of
operations
and
our
ability
to
meet
our
capital
expenditure
obligations
and
financial
commitments.
Our revenue, profitability, access to capital, future rate of growth and the carrying value of our oil and natural gas properties are heavily influenced by the
prices we receive for our oil and natural gas production and the prevailing market prices from time to time for oil, natural gas and NGLs. Historically, oil, natural
gas and NGLs prices have been volatile and subject to wide fluctuations in response to domestic and international changes in supply and demand, economic and
legal forces, events and uncertainties, and numerous other factors beyond our control, including those factors listed below (which list is not exhaustive):
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
worldwide and regional economic conditions impacting the global supply and demand for oil, natural gas and NGLs;
the level of global exploration and production;
the level of global inventories;
the price and quantity of imports of foreign oil, natural gas and NGLs;
political or economic conditions in or affecting other producing countries, including conflicts or instability in the Middle East, Africa, South America
and Russia;
actions of the Organization of the Petroleum Exporting Countries, its members and other state-controlled companies relating to oil price and production
controls;
prevailing prices on local price indices in the areas in which we operate and expectations about future commodity prices;
the proximity, capacity, cost and availability of gathering and transportation facilities;
localized and global supply and demand fundamentals and transportation availability;
weather conditions;
technological advances affecting energy consumption;
the effect of energy conservation efforts or activities by non-governmental organizations to restrict the exploration and production of oil and natural gas
so as to minimize emissions of carbon dioxide and methane GHGs;
the price and availability of alternative fuels and energy sources;
the impact of currency fluctuations; and
domestic, local and foreign governmental regulations and taxes.
22
These factors and the volatility of the energy markets, which we expect will continue, make it extremely difficult to predict future oil, natural gas and NGLs
price movements with any certainty. During the five years ended December 31, 2017, NYMEX WTI oil futures contract prices ranged from a high of $107.26 per
barrel on June 20, 2014 to a low of $26.21 per barrel on February 11, 2016, and NYMEX Henry Hub gas futures prices ranged from a high of $6.15 MMBtu on
February 19, 2014 to a low of $1.64 per MMBtu on March 3, 2016. As of December 31, 2017, NYMEX WTI oil futures contract prices and NYMEX Henry Hub
gas futures prices were $60.42 per barrel and $2.95 per MMBtu, respectively.
Although oil, natural gas and NGLs prices rose during 2017, a buildup in inventories, lower global demand, or other factors could cause prices for U.S.
crude oil to weaken, which could negatively affect our cash flows and results of operations. Under such conditions, we may be unable to obtain needed capital or
financing on satisfactory terms, which could lead to a decline in the present value of our reserves and our ability to develop future reserves. Lower commodity
prices may also reduce the amount of oil, natural gas and NGLs that we can produce economically.
If commodity prices decrease from current levels, a significant portion of our acquisition and development projects could become uneconomic. This may
result in our having to make significant downward adjustments to our estimated proved reserves. As a result, a substantial or extended decline in commodity prices
may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. In
addition, fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in
fuel economy and energy generation devices could reduce demand for oil and natural gas.
Our
development
and
exploratory
drilling
efforts
and
our
well
operations
may
not
be
profitable
or
achieve
our
targeted
returns.
We have acquired significant amounts of unproved property in order to further our development efforts and expect to continue to undertake acquisitions in
the future. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs
will be discovered. We acquire unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and improve our results of
operations over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our investments. Additionally, we
cannot assure you that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that wells drilled by us in prospects that
we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells.
Properties
we
acquire
may
not
produce
as
projected
and
we
may
be
unable
to
determine
reserve
potential,
identify
liabilities
associated
with
the
properties
that
we
acquire
or
obtain
protection
from
sellers
against
such
liabilities.
Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and
operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with each of these
assessments, we perform a review of the subject properties, but such a review will not reveal all existing or potential problems. In the course of our due diligence,
we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is
made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to
assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.
Our
acquisition
and
development
projects
require
substantial
capital
expenditures.
We
may
be
unable
to
obtain
required
capital
or
financing
on
satisfactory
terms,
which
could
lead
to
a
decline
in
our
reserves.
The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures for the acquisition and
development of oil and natural gas reserves. During the year ended December 31, 2017 , we incurred approximately $4.6 billion for acquisition, exploration and
development activities (excluding asset retirement obligations). Our 2018 budget for capital development expenditures is approximately $1,350.0 million to
$1,550.0 million . 85% to 90% of this estimate is expected to be used for drilling and completions and 10% to 15% of this estimate is expected to be used for
infrastructure and other expenditures. The amount and timing of 2018 capital expenditures is largely discretionary and within our control. We could choose to defer
a portion of these planned 2018 capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing
and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory
permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other working interest
23
owners. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Requirements and Sources of Liquidity.”
We intend to finance our future capital expenditures, other than significant acquisitions, with cash on hand, cash generated by operations and borrowings
under our Revolving Credit Agreement. As of December 31, 2017, we had approximately $1,700.8 million of liquidity, with $703.5 million of cash and cash
equivalents and short-term investments. Our borrowing base under the Revolving Credit Agreement currently stands at $1.8 billion , with a commitment level of
$1.0 billion . There were no borrowings outstanding and $2.7 million in letters of credit outstanding as of December 31, 2017, resulting in availability of $997.3
million .
Our cash flow from operations and access to capital, however, are subject to a number of variables beyond our control, including:
•
•
•
•
•
•
•
the volume of oil, natural gas and NGLs we are able to produce from existing wells;
the prices at which our production is sold;
our proved reserves;
our ability to acquire, locate and produce new reserves;
our ability to borrow under our Revolving Credit Agreement;
the global credit and securities markets; and
the ability and willingness of lenders and investors to provide capital and the cost of such capital.
If our revenues, liquidity or the borrowing base under our Revolving Credit Agreement decrease as a result of lower oil, natural gas and NGLs prices,
operating difficulties, declines in reserves or for any other reason, and we require additional capital for our capital expenditure needs, we may have limited ability
to obtain the capital necessary to sustain our operations and growth at current levels. If additional capital is needed, we may not be able to obtain debt or equity
financing on terms acceptable to us, if at all. If cash flow generated by our operations or available borrowings under our Revolving Credit Agreement are not
sufficient to meet our capital requirements, the failure to obtain additional financing could result in the curtailment of our operations relating to development of our
properties or the curtailment of acquisitions that may be favorable to us, which in each case could lead to a decline in our reserves and production, and could
adversely affect our business, financial condition and results of operations.
If
commodity
prices
decrease
to
a
level
such
that
our
future
undiscounted
cash
flows
from
our
properties
are
less
than
their
carrying
value
for
a
significant
period
of
time,
we
will
likely
be
required
to
take
write‑‑downs
of
the
carrying
values
of
our
properties.
Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and
circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors,
we may be required to write down the carrying value of our properties. A write-down constitutes a non-cash charge to earnings. See “Item 7. Management’s
Discussion and Analysis of Financial Condition and Results of Operations—Impairment of Oil and Gas Properties” for specific information regarding our
impairments. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such
charges are taken.
Drilling
for
and
producing
oil
and
natural
gas
are
high-risk
activities
with
many
uncertainties
that
could
adversely
affect
our
business,
financial
condition
or
results
of
operations.
Our future financial condition and results of operations will depend on the success of our acquisition and development activities, which are subject to
numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and natural gas production.
Our decisions to acquire and develop prospects or properties depend in part on the evaluation of data obtained through geophysical and geological analysis,
production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty
involved in these processes, see “—Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve
estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” In addition, the costs involved in drilling, completing
and operating our wells is often uncertain before we commence drilling.
24
Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:
•
•
•
•
•
•
•
•
•
•
•
•
•
delays imposed by or resulting from compliance with regulatory requirements, including limitations on wastewater disposal, discharge of GHGs,
hydraulic fracturing and other potential environmental impacts from our operations, including protections for threatened or endangered plant and
animal life;
pressure or irregularities in geological formations;
shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities;
equipment failures, accidents or other unexpected operational events;
lack of available gathering facilities or delays in construction of gathering facilities;
lack of available capacity on interconnecting transmission pipelines;
adverse weather conditions;
issues related to compliance with environmental regulations;
environmental hazards, such as oil and natural gas leaks, oil spills, pipeline and tank ruptures, the presence of naturally occurring radioactive materials
and the unauthorized discharge of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface
environment;
declines in oil, natural gas and NGLs prices;
limited availability of financing at acceptable terms;
loss of title or other title-related issues and disputes; and
limitations in the market for oil, natural gas and NGLs.
Our
identified
drilling
locations
are
scheduled
over
many
years,
making
them
susceptible
to
uncertainties
that
could
materially
alter
the
occurrence
or
timing
of
their
drilling.
In
addition,
we
may
not
be
able
to
raise
the
substantial
amount
of
capital
that
would
be
necessary
to
drill
such
locations.
Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our
existing acreage. These locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of
uncertainties, including oil, natural gas and NGLs prices, the availability and cost of capital, drilling and production costs, the availability of drilling services and
equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and the availability of water sourcing and
distribution systems, regulatory approvals and other factors. Because of these uncertainties, we do not know if our identified potential well locations will ever be
drilled or if we will be able to produce oil or natural gas from these or any other potential locations. In addition, unless production is established within the spacing
units covering the undeveloped acreage on which our potential drilling locations have been identified, certain of the leases for such acreage may expire. As such,
our actual drilling activities may materially differ from those presently identified.
We
may
not
be
able
to
generate
sufficient
cash
to
service
all
of
our
indebtedness
and
may
be
forced
to
take
other
actions
to
satisfy
our
obligations
under
the
applicable
debt
instruments,
which
may
not
be
successful.
Our ability to make scheduled payments on or to refinance our indebtedness obligations, including our Revolving Credit Agreement and our senior
unsecured notes, will depend on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and
certain financial, business and other factors beyond our control and can vary significantly from year to year. We may not be able to maintain a level of cash flows
from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.
If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay planned investments and
capital expenditures, or to sell assets, seek additional financing in the debt or equity markets or restructure or refinance our indebtedness. Our ability to restructure
or refinance our indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our indebtedness
could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. The terms of
existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on
our outstanding indebtedness on a timely basis would likely result in a reduction of our credit ratings, which could harm our ability to incur additional
indebtedness.
25
In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets
or operations to meet our debt service and other obligations. Our Revolving Credit Agreement and the indentures governing our senior unsecured notes restrict our
ability to dispose of assets and our use of the proceeds from such dispositions. We may not be able to consummate those dispositions or to obtain the proceeds that
we could have realized from them and any proceeds may not be adequate to meet any debt service obligations then due. These alternative measures may not be
successful and may not permit us to meet our debt service obligations.
Restrictions
in
our
existing
and
future
debt
agreements
could
limit
our
growth
and
our
ability
to
engage
in
certain
activities.
Our Revolving Credit Agreement and the indentures governing our senior unsecured notes contain a number of significant covenants, including restrictive
covenants that may limit our ability to, among other things:
•
•
•
incur or guarantee additional indebtedness or issue certain types of preferred stock;
pay dividends on capital stock or redeem, repurchase, or retire our capital stock or subordinated indebtedness;
transfer or sell assets;
• make investments;
•
•
•
•
•
create certain liens;
enter into agreements that restrict dividends or payments from our restricted subsidiaries to us;
consolidate, merge, or transfer all or substantially all of our assets;
engage in transactions with affiliates; and
create unrestricted subsidiaries.
In addition, our Revolving Credit Agreement requires us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with
such ratios. These restrictions may also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to
otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations
that the restrictive covenants under our Revolving Credit Agreement and the indentures governing our senior unsecured notes impose on us.
Our Revolving Credit Agreement also limits the amount we can borrow up to the lowest of (i) the borrowing base, (ii) the aggregate elected borrowing base
commitments and (iii) $2.5 billion. The lenders may, in their sole discretion, redetermine the borrowing base on a semi-annual basis based upon projected revenues
from the oil and natural gas properties securing our loan. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding
under our Revolving Credit Agreement. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments. If the requisite
number of lenders do not agree to a proposed borrowing base, then the borrowing base will be the highest borrowing base acceptable to such lenders. Outstanding
borrowings in excess of the borrowing base must be repaid.
If
we
are
unable
to
comply
with
the
restrictions
and
covenants
in
the
agreements
governing
our
indebtedness,
there
could
be
an
event
of
default
under
the
terms
of
these
agreements,
which
could
result
in
an
acceleration
of
payment
of
funds
that
we
have
borrowed.
If we are unable to comply with the various restrictions and covenants in the agreements governing our indebtedness, including our Revolving Credit
Agreement and the indentures governing our senior unsecured notes, there could be an event of default under the terms of these agreements. Our ability to comply
with these restrictions and covenants, including meeting certain financial ratios and tests, may be affected by events beyond our control. If market or other
economic conditions deteriorate or if oil, natural gas and NGLs prices decline, our ability to comply with these covenants may be impaired. We cannot assure that
we will be able to comply with these restrictions and covenants or meet such financial ratios and tests.
In the event of a default under the agreements governing our indebtedness, the lenders under our Revolving Credit Agreement could terminate their
commitments to lend and the holders of any of our indebtedness could elect to accelerate and declare all amounts borrowed to be immediately due and payable. A
default under our Revolving Credit Agreement could cause a cross-default under the indentures governing our senior unsecured notes, any other indebtedness
outstanding and the ISDA Agreements we enter into. See “Item 7A. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk” for
more information about our ISDA Agreements.
26
If any of these events occur, our assets might not be sufficient to repay in full all of our outstanding indebtedness and we may be unable to find alternative
financing. Even if we could obtain alternative financing, it might not be on terms that are favorable or acceptable to us. Additionally, we may not be able to amend
the agreements governing our indebtedness or obtain needed waivers on satisfactory terms.
Our
derivative
activities
could
result
in
financial
losses
or
could
reduce
our
earnings.
To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of the commodities we sell, we enter into commodity
derivative contracts for a significant portion of our production, with an emphasis on oil production, primarily consisting of put spreads, basis swaps and three-way
collars. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview—Realized Prices on the Sale of Oil,
Natural Gas and NGLs.” Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.
Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:
•
•
•
•
production is less than the volume covered by the derivative instruments;
the counterparty to the derivative instrument defaults on its contractual obligations;
there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or
there are issues with regard to legal enforceability of such instruments.
The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash
collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced which
could limit our ability to make future capital expenditures and make payments on our indebtedness and which could also limit the size of our borrowing base.
Future collateral requirements will depend on arrangements with our counterparties, volatile oil, natural gas and NGLs prices and interest rates. In addition,
derivative arrangements could limit the benefit we would receive from increases in the prices for oil, natural gas and NGLs, which could also have an adverse
effect on our financial condition.
Our commodity derivative contracts expose us to risk of financial loss if a counterparty fails to perform under a contract. Disruptions in the financial
markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the contract, and we may not be
able to realize the benefit of the contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do
accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.
During periods of declining commodity prices, our derivative contract receivable positions generally increase, which increases our counterparty credit
exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss with respect to our
commodity derivative contracts.
Reserve
estimates
depend
on
many
assumptions
that
may
turn
out
to
be
inaccurate.
Any
material
inaccuracies
in
reserve
estimates
or
underlying
assumptions
will
materially
affect
the
quantities
and
present
value
of
our
reserves.
The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including
assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could
materially affect the estimated quantities and present value of our reserves.
In order to prepare reserve estimates, we must project production rates and timing of development expenditures. We must also analyze available geological,
geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about
matters such as oil, natural gas and NGLs prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
Actual future production, oil, natural gas and NGLs prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil
and natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In
addition, we may adjust reserve estimates to reflect production history, results of exploration and development, existing commodity prices and other factors, many
of which are beyond our control.
27
The present value of future net revenues from our reserves may not be equal to the current market value of our estimated reserves. We generally base the
estimated discounted future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from
those used in the present value estimate.
Approximately
30%
of
our
net
leasehold
acreage
is
undeveloped
and
that
acreage
may
not
ultimately
be
developed
or
become
commercially
productive,
which
could
cause
us
to
lose
rights
under
our
leases
as
well
as
have
a
material
adverse
effect
on
our
oil
and
natural
gas
reserves
and
future
production
and,
therefore,
our
future
cash
flow
and
income.
As of December 31, 2017, approximately 30% of our net leasehold acreage was undeveloped or acreage on which wells have not been drilled or completed
to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. Unless
production is established on the undeveloped acreage covered by our leases, such leases will expire. Our future oil and natural gas reserves and production and,
therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage. Further, to the extent we determine
that it is not economic to develop particular undeveloped acreage, we may intentionally allow leases to expire.
Our
producing
properties
are
located
in
the
Permian
Basin
of
West
Texas,
making
us
vulnerable
to
risks
associated
with
operating
in
one
major
geographic
area.
All of our producing properties are geographically concentrated in the Permian Basin of West Texas. At December 31, 2017, all of our total estimated
proved reserves were attributable to properties located in this area. As a result of this concentration, we may be disproportionately exposed to the impact of
regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation
capacity constraints, market limitations, water shortages or other drought or extreme weather related conditions or interruption of the processing or transportation
of oil, natural gas or NGLs.
Extreme
weather
conditions
could
adversely
affect
our
ability
to
conduct
drilling
activities
in
the
areas
where
we
operate.
Our exploration, exploitation and development activities and equipment could be adversely affected by extreme weather conditions, such as winter storms,
which may cause a loss of production from temporary cessation of activity or lost or damaged facilities and equipment. Such extreme weather conditions could also
impact other areas of our operations, including access to our drilling and production facilities for routine operations, maintenance and repairs and the availability of
and our access to, necessary third-party services, such as gathering, processing, compression and transportation services. These constraints and the resulting
shortages or high costs could delay or temporarily halt our operations and materially increase our operation and capital costs, which could have a material adverse
effect on our business, financial condition and results of operations.
The
marketability
of
our
production
is
dependent
upon
vehicles,
transportation
facilities
and
other
facilities,
certain
of
which
we
do
not
control.
If
these
vehicles
or
facilities
are
unavailable,
or
if
we
are
unable
to
access
such
vehicles
or
facilities
on
commercially
reasonable
terms,
our
operations
could
be
interrupted
and
our
revenues
reduced.
The marketing of oil, natural gas and NGLs production depends in large part on the availability, proximity and capacity of trucks, pipelines and storage
facilities, gas gathering systems and other transportation, processing and refining facilities, as well as the existence of adequate markets. If there is insufficient
capacity available on these systems, or if these systems are unavailable to us, or if these systems are unavailable to us on commercially reasonable terms, the price
offered for our production could be significantly depressed, or we could be forced to shut in some production or delay or discontinue drilling plans and commercial
production following a discovery of hydrocarbons while we construct or purchase our own facility or system. We also rely (and expect to rely in the future) on
facilities developed and owned by third parties in order to store, process, transport and sell our oil, natural gas and NGLs production. Our plans to develop and sell
our oil and natural gas reserves could be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient transportation,
storage or processing facilities to us, especially in areas of planned expansion where such facilities do not currently exist, on commercially reasonable terms or
otherwise.
The volume of oil and natural gas that we can produce is subject to limitation in certain circumstances, such as pipeline interruptions due to scheduled and
unscheduled maintenance, excessive pressure, physical damage to the gathering, transportation, refining or processing facilities, or lack of capacity on such
facilities. The curtailments arising from these and similar circumstances may last from a few days to several months and, in many cases, we may be provided only
limited, if any, advance notice as to when these circumstances will arise and their duration.
28
We
may
incur
losses
as
a
result
of
title
defects
in
the
properties
in
which
we
invest.
It is generally our practice in acquiring oil and natural gas leases or interests not to incur the expense of retaining lawyers to examine the title to the leases
and underlying mineral interest at the time of acquisition. Rather, we rely upon the judgment of lease brokers or landmen who perform the fieldwork in examining
records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. The existence of a material title deficiency can
render a lease worthless and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing
drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to
produce all or a portion of the minerals under the property.
The
development
of
our
estimated
proved
undeveloped
reserves
may
take
longer
and
may
require
higher
levels
of
capital
expenditures
than
we
currently
anticipate.
Therefore,
our
estimated
proved
undeveloped
reserves
may
not
be
ultimately
developed
or
produced.
At December 31, 2017 , 50% of our total estimated proved reserves were classified as proved undeveloped. Our approximately 207.0 MMBoe of estimated
proved undeveloped reserves will require an estimated $2.1 billion of development capital over the next five years. Development of these undeveloped reserves
may take longer and require higher levels of capital expenditures than we currently anticipate. The future development of our proved undeveloped reserves is
dependent on future commodity prices, costs and economic assumptions that align with our internal forecast as well as access to liquidity sources, such as cash
flow from operations, capital markets and our Revolving Credit Agreement. Delays in the development of our reserves, increases in costs to drill and develop such
reserves, or decreases in commodity prices will reduce the value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves
and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved
undeveloped reserves as unproved reserves.
SEC
rules
could
limit
our
ability
to
book
additional
proved
undeveloped
reserves
in
the
future.
SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they are related to wells scheduled to be drilled
within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional proved undeveloped reserves as
we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those wells within the required
five-year timeframe.
Unless
we
replace
our
reserves
with
new
reserves
and
develop
those
reserves,
our
reserves
and
production
will
decline,
which
would
adversely
affect
our
future
cash
flows
and
results
of
operations.
Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and
other factors. Unless we conduct successful ongoing acquisition and development activities or continually acquire properties containing proved reserves, our
proved reserves will decline as those reserves are produced. Our future reserves and production, and therefore our future cash flow and results of operations, are
highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not
be able to acquire and develop or find sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future
production, the value of our reserves will decrease and our business, financial condition and results of operations would be adversely affected. Further, the
horizontal decline curve we use to project our future production is subject to numerous limitations.
29
We
depend
upon
several
significant
purchasers
for
the
sale
of
most
of
our
oil
and
natural
gas
production.
The
loss
of
one
or
more
of
these
purchasers
could,
among
other
factors,
limit
our
access
to
suitable
markets
for
the
oil
and
natural
gas
we
produce.
The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our management, including,
but not limited to, the extent of domestic production and imports of oil, the proximity and capacity of pipelines, the availability of skilled labor, materials and
equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of oil and natural gas sold in interstate commerce. In
addition, we depend upon several significant purchasers for the sale of most of our oil and natural gas production. See “Item 1. Business—Oil and Natural Gas
Production Prices and Production Costs—Marketing and Customers.” We cannot assure you that we will continue to have ready access to suitable markets for our
future oil and natural gas production.
We
may
incur
substantial
losses
and
be
subject
to
substantial
liability
claims
as
a
result
of
our
operations.
Additionally,
we
may
not
be
insured
for,
or
our
insurance
may
be
inadequate
to
protect
us
against,
these
risks.
We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our
business, financial condition or results of operations.
Our exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas. Any of these
risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:
•
•
•
•
•
•
injury or loss of life;
damage to and destruction of property, natural resources and equipment;
pollution and other environmental damage;
regulatory investigations and penalties;
suspension of our operations; and
repair and remediation costs.
We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented.
In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a
material adverse effect on our business, financial condition and results of operations.
Properties
that
we
decide
to
drill
may
not
yield
oil
or
natural
gas
in
commercially
viable
quantities.
Properties that we decide to drill that do not yield oil or natural gas in commercially viable quantities will adversely affect our results of operations and
financial condition. There is no way to predict with certainty in advance of drilling and testing whether any particular prospect will yield oil or natural gas in
sufficient quantities to recover drilling or completion costs or to be economically viable. The use of micro-seismic data and other technologies and the study of
producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or
natural gas will be present in commercial quantities. We cannot assure you that the analogues we draw from available data from other wells, more fully explored
prospects or producing fields will be applicable to our drilling prospects. Further, our drilling operations may be curtailed, delayed or canceled as a result of
numerous factors, including:
•
•
•
•
•
•
•
unexpected drilling conditions;
title problems;
pressure or lost circulation in formations;
equipment failure or accidents;
adverse weather conditions;
compliance with environmental and other governmental or contractual requirements; and
increases in the cost of, shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services.
30
Multi-well
pad
drilling
may
result
in
volatility
in
our
operating
results.
We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not brought into production until all wells on the pad are drilled and
completed and the drilling rig is moved from the location, multi-well pad drilling delays the commencement of production, which may cause volatility in our
quarterly operating results.
We
may
be
unable
to
make
attractive
acquisitions
or
successfully
integrate
acquired
businesses
and
any
inability
to
do
so
may
disrupt
our
business
and
hinder
our
ability
to
grow.
In the future we may make acquisitions of producing properties or businesses that complement or expand our current business. The successful acquisition of
producing properties requires an assessment of several factors, including:
•
•
•
•
recoverable reserves;
future oil, natural gas and NGLs prices and their applicable differentials;
operating costs; and
potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain, and we may not be able to identify attractive acquisition opportunities. In connection with these
assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing
or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections may not
always be performed on every well and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is
undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems.
We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis. Even if we do identify attractive
acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.
The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process
of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In
addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given
that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or
successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations
successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.
In addition, our Revolving Credit Agreement and the indentures governing our senior unsecured notes impose certain limitations on our ability to enter into
mergers or combination transactions. These agreements also limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in
acquisitions.
We
are
subject
to
complex
U.S.
federal,
state,
local
and
other
laws
and
regulations
related
to
environmental,
occupational,
health
and
safety
issues
that
could
adversely
affect
the
cost,
manner
or
feasibility
of
conducting
our
operations
or
expose
us
to
significant
liabilities.
Our operations are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment,
the occupational health and safety aspects of our operations, or otherwise relating to environmental protection. These laws and regulations may impose numerous
obligations applicable to our operations, including: (i) the acquisition of a permit before conducting regulated drilling activities; (ii) the restriction of types,
quantities and concentration of materials that can be released into the environment; (iii) the limitation or prohibition of drilling activities on certain lands lying
within wilderness, wetlands and other protected areas; (iv) the application of specific health and safety criteria addressing worker protection; and (v) the imposition
of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the EPA and analogous state agencies, have the
power to enforce compliance with these laws and regulations and the permits issued under them. Such enforcement actions often involve taking difficult and costly
compliance measures or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative,
civil or criminal penalties, the imposition of investigatory or remedial obligations and the issuance of orders limiting or prohibiting some or all of our operations. In
addition, we may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations and limit our growth and
revenue. In addition, the trend in environmental regulation has been to place more restrictions and limitations on activities
31
that may affect the environment; if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations,
our costs of compliance may increase. Failure to comply with laws and regulations applicable to our operations, including any evolving interpretation and
enforcement by governmental authorities, could have a material adverse effect on our business, financial condition and results of operations.
Certain environmental laws impose strict as well as joint and several liability for costs required to remediate and restore sites where hazardous substances,
hydrocarbons, or solid wastes have been stored or released. We may be required to remediate contaminated properties currently or formerly operated by us or
facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from
consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons
or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Moreover, public interest in the protection
of the environment has increased dramatically in recent years, and many environmental statutes contain citizen suit provisions that allow private parties to sue to
enforce environmental laws and regulations. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent
and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially
adversely affected. See “Item 1. Business—Regulation of the Oil and Natural Gas Industry” for a further description of the laws and regulations that affect us.
Concerns
over
general
economic,
business
or
industry
conditions
may
have
a
material
adverse
effect
on
our
results
of
operations,
liquidity
and
financial
condition.
Concerns about global economic growth have had and may continue to have a significant adverse impact on the stability of global financial markets and
commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could
impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely
impact our results of operations, liquidity and financial condition.
A
downgrade
in
our
credit
ratings
could
negatively
impact
our
cost
of
and
ability
to
access
capital.
As of December 31, 2017 , our long-term debt was rated B2 with a stable outlook by Moody’s Investors Service, Inc. and BB- with a positive outlook by
Standard & Poor’s Ratings Services. Since this date, no changes in our credit ratings have occurred; however, we cannot be assured that our credit ratings will not
be downgraded in the future.
A downgrade in our credit ratings could negatively impact our costs of capital or our ability to effectively execute aspects of our strategy. Further, a
downgrade in our credit ratings could affect our ability to raise debt in the public debt markets and the cost of any new debt could be much higher than our
outstanding debt. These and other impacts of a downgrade in our credit ratings could have a material adverse effect on our business, financial condition and results
of operations.
The
unavailability
or
high
cost
of
additional
drilling
rigs,
equipment,
supplies,
personnel
and
oilfield
services
could
adversely
affect
our
ability
to
execute
our
exploration
and
development
plans
within
our
budget
and
on
a
timely
basis.
The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other
professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil, natural gas and NGLs prices, causing periodic shortages.
Historically, there have been shortages of drilling and workover rigs, pipe and other equipment as demand for rigs and equipment has increased along with the
number of wells being drilled. Further, to the extent our suppliers source their products or raw materials from foreign markets, the cost of such equipment could be
impacted if the United States imposes tariffs on imported goods from countries where these goods are produced. We cannot predict whether these conditions will
exist in the future and, if so, what their timing and duration will be. Such shortages or cost increases could delay or cause us to incur significant expenditures that
are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.
Should
we
fail
to
comply
with
all
applicable
regulatory
agency
administered
statutes,
rules,
regulations
and
orders,
we
could
be
subject
to
substantial
penalties
and
fines.
Under the Energy Policy Act of 2005, the FERC has civil penalty authority under the Natural Gas Act of 1938 to impose penalties for current violations of
up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our operations have not been regulated by the FERC as
a natural gas company under this law, the FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC
annual reporting requirements. We also must comply with the anti-market manipulation rules enforced by the FERC. Additional rules and
32
legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Additionally, the FTC has regulations intended to
prohibit market manipulation in the petroleum industry with authority to fine violators of the regulations civil penalties of up to $1 million per day and the CFTC
prohibits market manipulation in the markets regulated by the CFTC, including similar anti-manipulation authority with respect to crude oil swaps and futures
contracts as that granted to the CFTC with respect to crude oil purchases and sales. The CFTC rules subject violators to a civil penalty of up to the greater of $1
million or triple the monetary gain to the person for each violation. Failure to comply with those regulations in the future could subject us to civil penalty liability,
as described in “Item 1. Business—Regulation of the Oil and Natural Gas Industry.”
Climate
change
laws
and
regulations
restricting
emissions
of
greenhouse
gases
could
result
in
increased
operating
costs
and
reduced
demand
for
the
oil
and
natural
gas
that
we
produce.
In
addition,
the
potential
physical
effects
of
climate
change
could
disrupt
our
production
and
cause
us
to
incur
significant
costs
in
preparing
for
or
responding
to
those
effects.
In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA
has adopted regulations under existing provisions of the Clean Air Act that, among other things, establish PSD, construction and Title V operating permit reviews
for certain large stationary sources. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control
technology” standards that will be established on a case-by-case basis. EPA rulemakings related to GHG emissions could adversely affect our operations and
restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG
emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include gathering and boosting
facilities as well as completions and workovers from hydraulically fractured oil wells.
Furthermore, in June 2016, the EPA finalized rules that establish new controls for emissions of methane from new, modified or reconstructed sources in the
oil and natural gas source category, including production, processing, transmission and storage activities. The rules include first-time standards to address
emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions, and impose
additional requirements related to pollution control equipment, record-keeping practices, and leak detection and repair programs. However, over the past year the
EPA has taken several steps to delay implementation of the methane standards, and the agency proposed a rulemaking in June 2017 to stay the requirements for a
period of two years and revisit implementation of the methane rules in their entirety. The EPA has not yet published a final rule but, as a result of these
developments, future implementation of the 2016 standards is uncertain at this time. However, given the long-term trend towards increasing regulation, future
regulation of methane and other greenhouse gas emission from the oil and gas industry remains a possibility.
While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted
legislation to reduce GHG emissions at the federal level in recent years and future legislation remains unlikely. In the absence of such federal climate legislation, a
number of state and regional cap and trade programs have emerged that typically require major sources of GHG emissions, such as electric power plants, to acquire
and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may
be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of
GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. In addition, substantial
limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce and lower the value of our reserves.
Demand for our products may also be adversely affected by conservation plans and efforts undertaken in response to global climate change, including plans
developed in connection with the recent Paris climate conference agreement reached in December 2015, which entered into force in November 2016. The United
States is one of over 70 nations that ratified or otherwise indicated its intent to comply with the agreement. However, the agreement is not binding on the United
States and, in June 2017, President Trump stated that the United States would withdraw from the Paris Agreement, but may enter into a future international
agreement related to GHGs. In August 2017, the U.S. State Department officially informed the United Nations of the intent of the United States to withdraw from
the Paris Climate Agreement. The United States’ adherence to the exit process is uncertain and/or the terms on which the United States may reenter the Paris
Agreement or a separately negotiated agreement are unclear at this time. Recently, activists concerned about the potential effects of climate change have directed
their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital
restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and
production activities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue
to rise and will not peak until after 2040 and that oil and gas will continue to represent a substantial percentage of global energy use over that time. Finally, it
should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have
significant physical effects, such as increased frequency and severity of storms, floods, droughts and
33
other extreme climatic events; if any such effects were to occur, they could have an adverse effect on our exploration and production operations.
Federal,
state
and
local
legislative
and
regulatory
initiatives
relating
to
hydraulic
fracturing
as
well
as
governmental
reviews
of
such
activities
could
result
in
increased
costs
and
additional
operating
restrictions
or
delays
in
the
completion
of
oil
and
natural
gas
wells
and
adversely
affect
our
production.
Hydraulic fracturing is a common industry practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations.
Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into target geological formations to fracture the
surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Recently, there has been increased public concern
regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies, resulting in new legislative and regulatory initiatives that seek to
increase the regulatory burden imposed on hydraulic fracturing.
At the federal level, the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities
involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities. Also, in May 2014, the EPA
issued an Advance Notice of Proposed Rulemaking to collect data on chemicals used in hydraulic fracturing operations under Section 8 of the TSCA. To date, no
further action has been taken and future regulation under the TSCA appears unlikely at this time. Further, the EPA finalized regulations under the CWA in June
2016 prohibiting wastewater discharges from hydraulic fracturing and certain other natural gas operations to publicly owned wastewater treatment plants. Also, in
December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that
“water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic
fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals
for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of
fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately
treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. The report does not appear to provide a basis for
additional federal regulation of hydraulic fracturing at this time.
At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well
construction requirements on hydraulic fracturing activities. For example in May 2013, the RRC adopted new rules governing well casing, cementing and other
standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. Local governments also may seek to adopt ordinances within
their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of
well drilling in general or hydraulic fracturing in particular. We believe that we follow applicable standard industry practices and legal requirements for
groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic
fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or
curtailment in the pursuit of exploration, development, or production activities and perhaps even be precluded from drilling wells.
Further regulation of hydraulic fracturing at the federal, state and local level could subject our operations to additional permitting requirements and result in
permitting delays as well as potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are
ultimately able to produce from our reserves. Please read “Item 1. Business—Regulation of the Oil and Natural Gas Industry” for a further description of the laws
and regulations that affect us.
Competition
in
the
oil
and
natural
gas
industry
is
intense,
making
it
more
difficult
for
us
to
acquire
properties
and
market
oil
or
natural
gas.
Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties
and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also,
there is substantial competition for capital available for investment in the oil and natural gas industry. We may not be able to compete successfully in the future in
acquiring prospective reserves, developing reserves, marketing hydrocarbons and raising additional capital, which could have a material adverse effect on our
business.
34
We
operate
in
areas
of
high
industry
activity,
which
may
affect
our
ability
to
hire,
train
or
retain
qualified
personnel
needed
to
manage
and
operate
our
assets.
Our operations and drilling activity are concentrated in the Permian Basin in West Texas, an area in which industry activity has remained relatively steady
during the recent period of commodity price volatility. As a result, demand for qualified personnel in this area, and the cost to attract and retain such personnel, has
continued to be competitive and would be expected to increase substantially in the future if commodity prices rebound. Moreover, our competitors may be able to
offer better compensation packages to attract and retain qualified personnel than we are able to offer.
Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development activities could result in oil and
natural gas production volumes being below our forecasted volumes. In addition, any such negative effect on production volumes, or significant increases in costs,
could have a material adverse effect on our results of operations, liquidity and financial condition.
The
loss
of
senior
management
or
technical
personnel
could
adversely
affect
operations.
We depend on the services of our senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss
of any of these individuals. The loss of the services of our senior management or technical personnel could have a material adverse effect on our business, financial
condition and results of operations.
We
are
susceptible
to
the
potential
difficulties
associated
with
rapid
growth
and
expansion
and
have
a
limited
operating
history.
We have grown rapidly over the last several years. Our management believes that our future success depends on our ability to manage the rapid growth that
we have experienced and the demands from increased responsibility on management personnel. The following factors could present difficulties:
•
•
•
•
increased responsibilities for our executive level personnel;
increased administrative burdens;
increased capital requirements; and
increased organizational challenges common to large, expansive operations.
Our operating results could be adversely affected if we do not successfully manage these potential difficulties. The historical financial information
incorporated herein is not necessarily indicative of the results that may be realized in the future. In addition, our operating history is limited and the results from our
current producing wells are not necessarily indicative of success from our future drilling operations.
Part
of
our
strategy
involves
drilling
in
existing
or
emerging
shale
plays
using
the
latest
available
horizontal
drilling
and
completion
techniques,
which
involve
risks
and
uncertainties
in
their
application.
Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. As of December 31, 2017 , we
had drilled and completed 268 gross ( 251.8 net) horizontal wells and therefore are subject to increased risks associated with horizontal drilling as compared to
companies that have greater experience in horizontal drilling activities. Risks that we face while drilling include, but are not limited to, failing to land our wellbore
in the desired drilling zone, not staying in the desired drilling zone while drilling horizontally through the formation, not running our casing the entire length of the
wellbore and not being able to run tools and other equipment consistently through the horizontal wellbore. Risks that we face while completing our wells include,
but are not limited to, not being able to fracture stimulate the planned number of stages, not being able to run tools the entire length of the wellbore during
completion operations and not successfully cleaning out the wellbore after completion of the final fracture stimulation stage. Ultimately, the success of these
drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time
period. If our drilling results are worse than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to
gathering systems and/or commodity price declines, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any
of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the
future.
35
Factors
affecting
the
cost
and
availability
of
credit
could
adversely
affect
our
business.
Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in our
credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for
drilling and place us at a competitive disadvantage. Potential disruptions and volatility in the global financial markets may lead to a contraction in credit
availability impacting our ability to finance our operations. We require continued access to capital and a significant increase in the cost of, or reduction in the
availability of, credit could materially and adversely affect our ability to achieve our planned growth and operating results.
The
final
impact
of
the
Tax
Act
on
us
could
be
different
from
our
current
estimates
and
could
have
an
adverse
effect
on
our
tax
obligations
and
effective
tax
rate,
which
may
adversely
affect
our
business,
results
of
operations,
financial
condition
and
cash
flow.
On December 22, 2017, the Tax Act was enacted by the U.S. government. The Tax Act significantly impacts our 2017 effective tax rate and makes broad
and complex changes to the U.S. corporate income tax code. Among other changes, the Tax Act: (i) reduces the U.S. federal corporate income tax rate from 35% to
21%; (ii) repeals the corporate alternative minimum tax and provides for a refund of previously accrued alternative minimum tax credits; (iii) modifies the
provisions relating to the limitations on deductions for executive compensation of publicly traded corporations; (iv) enacts new limitations regarding the
deductibility of interest expense; and (v) imposes new limitations on the utilization of net operating losses arising in taxable years beginning after December 31,
2017.
The Tax Act is complex and far-reaching, and we cannot predict with certainty the resulting impact its enactment will have on us. The net benefits of the
Tax Act, as recorded as provisional amounts as of December 31, 2017, represent our best estimate using information available to us as of February 28, 2018 . We
are still evaluating, among other things, the application of limitations for executive compensation related to contracts existing prior to November 2, 2017, and
provisions in the Tax Act addressing the deductibility of interest expense after January 1, 2018. Furthermore, the Tax Act is subject to interpretation. The
presentation of our financial condition and results of operations is based upon our current interpretation of the provisions contained in the Tax Act. In the future,
the Treasury Department and the Internal Revenue Service are expected to release regulations relating to and interpretive guidance of the legislation contained in
the Tax Act.
We will refine our estimates to incorporate new or better information as it becomes available through the filing date of our 2017 U.S. income tax returns in
the fourth quarter of 2018. The ultimate impact of the Tax Act may differ from our estimates based on our actual results in 2018, our further analysis of the new
law, and additional regulatory guidance that may be issued. Because we are in the process of fully quantifying the impact of the Tax Act on us, we expect to record
any adjustments in 2018 in accordance with the guidance provided in SEC Staff Accounting Bulletin No. 118. These adjustments could be material and could have
an adverse effect on our business, results of operations, financial condition and cash flow. The final impact of the Tax Act on our business, operations, and
financial statements cannot be predicted at this time, and we make no assurances in this regard. See Note 10—Income Taxes to our consolidated financial
statements included elsewhere in this Annual Report.
Our
ability
to
use
our
net
operating
loss
carryforwards
may
be
limited.
As of December 31, 2017, we had approximately $229.1 million of U.S. federal net operating loss carryforwards (“NOLs”), which begin to expire in 2034.
Utilization of these NOLs depends on many factors, including our future income, which cannot be assured. In addition, Section 382 of the Internal Revenue Code
of 1986, as amended (“Section 382”), generally imposes an annual limitation on the amount of NOLs that may be used to offset taxable income when a corporation
has undergone an “ownership change” (as determined under Section 382). An ownership change generally occurs if one or more shareholders (or groups of
shareholders) who are each deemed to own at least 5% of our stock change their ownership by more than 50 percentage points over their lowest ownership
percentage within a rolling three-year period. In the event that an ownership change has occurred, or were to occur, utilization of our NOLs would be subject to an
annual limitation under Section 382, determined by multiplying the value of our stock at the time of the ownership change by the applicable long-term tax-exempt
rate as defined in Section 382, subject to certain adjustments. Any unused annual limitation may be carried over to later years. We cannot assure you that we will
not undergo an ownership change in 2018. However, even if we did have an ownership change in 2018, we do not believe that the resulting Section 382 annual
limitation would prevent our utilization of our NOLs prior to their expiration. Future ownership changes or future regulatory changes could limit our ability to
utilize our NOLs. To the extent we are not able to offset our future income with our NOLs, this would adversely affect our operating results and cash flows if we
attain profitability.
36
Our
use
of
seismic
data
is
subject
to
interpretation
and
may
not
accurately
identify
the
presence
of
oil
and
natural
gas,
which
could
adversely
affect
the
results
of
our
drilling
operations.
Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying
subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In
addition, the use of 3-D seismic and other advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies and we could incur
losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.
Derivatives
legislation
could
have
an
adverse
effect
on
our
ability
to
use
derivative
instruments
to
reduce
the
effect
of
commodity
prices,
interest
rates
and
other
risks
associated
with
our
business.
The Dodd-Frank Act, among other things, establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us,
that participate in that market. The CFTC has finalized certain of its regulations under the Dodd-Frank Act, but others remain to be finalized or implemented. It is
not possible at this time to predict when this will be accomplished or what the terms of the final rules will be, so the impact of those rules is uncertain at this time.
The CFTC has designated certain types of swaps (thus far, only certain interest rate swaps and credit default swaps) for mandatory clearing and exchange
trading, and may designate other types of swaps for mandatory clearing and exchange trading in the future. To the extent we engage in such transactions or
transactions that become subject to such rules in the future, we will be required to comply or to take steps to qualify for an exemption to such requirements.
Although we are availing ourselves of the end-user exception to the mandatory clearing and exchange trading requirements for swaps designed to hedge our
commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the
cost and availability of the swaps that we use for hedging. If any of our swaps do not qualify for the commercial end-user exception, or if the cost of entering into
uncleared swaps becomes prohibitive, we may be required to clear such transactions or execute them on a derivatives contract market or swap executive facility.
In addition, certain banking regulators and the CFTC have adopted final rules establishing minimum margin requirements for uncleared swaps. Although
we expect to qualify for the end-user exception from margin requirements for swaps to other market participants, such as swap dealers, these rules may change the
cost and availability of the swaps we use for hedging. If any of our swaps do not qualify for the commercial end-user exception, we could be required to post initial
or variation margin, which would impact liquidity and reduce our cash. This would in turn reduce our ability to execute hedges to reduce risk and protect cash
flows.
The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative
contracts, reduce the availability of derivatives to protect against risks we encounter and reduce our ability to monetize or restructure our existing commodity price
contracts. If we reduce our use of commodity price contracts as a result of the legislation and regulations, our results of operations may become more volatile and
our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and make cash distributions to our
unitholders. Further, to the extent our revenues are unhedged, they could be adversely affected if a consequence of the Dodd-Frank Act and implementing
regulations is to lower commodity prices.
We
may
not
be
able
to
keep
pace
with
technological
developments
in
our
industry.
The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using
new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to
implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel
resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be
able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use
now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.
Our
business
could
be
negatively
affected
by
security
threats,
including
cybersecurity
threats
and
other
disruptions.
As an oil and natural gas producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or
to render data or systems unusable, threats to the security of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and
pipelines, and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material adverse
effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to
37
increase security for our information, data, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that
such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to
losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial
position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious
software, attempts to gain unauthorized access to data and systems and other electronic security breaches that could lead to disruptions in critical systems,
unauthorized release of confidential or otherwise protected information and corruption of data. These events could lead to financial losses from remedial actions,
loss of business or potential liability.
Risks Related to our Class A Common Stock
We
are
a
holding
company.
Our
sole
material
asset
is
our
equity
interest
in
Parsley
LLC
and
we
are
accordingly
dependent
upon
distributions
from
Parsley
LLC
to
pay
taxes,
make
payments
under
the
TRA
and
cover
our
corporate
and
other
overhead
expenses.
We are a holding company and have no material assets other than our equity interest in Parsley LLC. We have no independent means of generating revenue.
To the extent Parsley LLC has available cash, we intend to cause Parsley LLC to make distributions to its unit holders, including us, in an amount sufficient to
cover all applicable taxes at assumed tax rates and payments under the TRA and to reimburse us for our corporate and other overhead expenses. We are limited,
however, in our ability to cause Parsley LLC and its subsidiaries to make these and other distributions to us due to the restrictions under our Revolving Credit
Agreement and the indentures governing our senior unsecured notes. To the extent that we need funds and Parsley LLC or its subsidiaries are restricted from
making such distributions under applicable law or regulation or under the terms of their financing arrangements, or are otherwise unable to provide such funds, it
could materially adversely affect our liquidity and financial condition.
Our
management
collectively
holds
a
significant
percentage
of
the
voting
power
of
our
common
stock.
Holders of our Class A Common Stock and Class B Common Stock vote together as a single class on all matters presented to our stockholders for their vote
or approval, except as otherwise required by applicable law or our certificate of incorporation. As of December 31, 2017 , our executive officers held
approximately 13.0% of our outstanding common stock. The existence of this significant management ownership position may have the effect of deterring hostile
takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they
may deem to be in the best interests of our company.
So long as the members of our management team continue to control a significant percentage of the voting power of our common stock, they will continue
to be able to strongly influence all matters requiring stockholder approval, regardless of whether or not other stockholders believe that a potential transaction is in
their own best interests. In any of these matters, the interests of our management team may differ or conflict with the interests of our other stockholders.
We
have
engaged
in
transactions
with
our
affiliates
and
expect
to
do
so
in
the
future.
The
terms
of
such
transactions
and
the
resolution
of
any
conflicts
that
may
arise
may
not
always
be
in
our
or
our
stockholders’
best
interests.
We have engaged in transactions and expect to continue to engage in transactions with affiliated companies, as described under the caption “Item 13.
Certain Relationships and Related Transactions and Director Independence.”
Our
amended
and
restated
certificate
of
incorporation
and
amended
and
restated
bylaws,
as
well
as
Delaware
law,
contain
provisions
that
could
discourage
acquisition
bids
or
merger
proposals,
which
may
adversely
affect
the
market
price
of
our
Class
A
Common
Stock.
Our amended and restated certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of
directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated
certificate of incorporation and our amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control
would be beneficial to our stockholders, including:
•
•
limitations on the removal of directors;
limitations on the ability of our stockholders to call special meetings;
38
•
•
providing that the board of directors is expressly authorized to adopt, or to alter or repeal our amended and restated bylaws; and
establishing advance notice and certain information requirements for nominations for election to our board of directors and for proposing matters that
can be acted upon by stockholders at stockholder meetings.
In addition, certain change of control events have the effect of accelerating any payments due under our Revolving Credit Agreement and the TRA, and
could, in certain defined circumstances, accelerate payments required by the indentures governing our senior unsecured notes, which could be substantial and
accordingly serve as a disincentive to a potential acquirer of our company. Please see “—In certain cases, payments under the TRA may be accelerated and/or
significantly exceed the actual benefits, if any, we realize in respect of the tax attributes subject to the TRA.”
Our
amended
and
restated
certificate
of
incorporation
designates
the
Court
of
Chancery
of
the
State
of
Delaware
as
the
sole
and
exclusive
forum
for
certain
types
of
actions
and
proceedings
that
may
be
initiated
by
our
stockholders,
which
could
limit
our
stockholders’
ability
to
obtain
a
favorable
judicial
forum
for
disputes
with
us
or
our
directors,
officers,
employees
or
agents.
Our amended and restated certificate of incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of
Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding
brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our
stockholders, (iii) any action asserting a claim against us or any director or officer or other employee of ours arising pursuant to any provision of the Delaware
General Corporation Law, our amended and restated certificate of incorporation or our amended and restated bylaws, or (iv) any action asserting a claim against us
or any director or officer or other employee of ours that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having
personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of
our capital stock will be deemed to have notice of and consented to, the provisions of our amended and restated certificate of incorporation described in the
preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us
or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these
provisions of our amended and restated certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or
proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial
condition or results of operations.
We
do
not
intend
to
pay
dividends
on
our
Class
A
Common
Stock
or
Class
B
Common
Stock
in
the
near
future,
and
our
Revolving
Credit
Agreement
and
the
indentures
governing
our
senior
unsecured
notes
place
certain
restrictions
on
our
ability
to
do
so.
Consequently,
your
only
opportunity
to
achieve
a
return
on
your
investment
is
if
the
price
of
our
Class
A
Common
Stock
appreciates.
We have never declared or paid any dividends to holders of our Class A Common Stock or Class B Common Stock. We currently intend to retain all
available funds, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon
various factors, including our results of operations, financial condition, capital requirements and investment opportunities. Additionally, our Revolving Credit
Agreement and the indentures governing our senior unsecured notes place certain restrictions on our ability to pay cash dividends. Consequently, your only
opportunity to achieve a return on your investment in us will be if you sell your Class A Common Stock at a price greater than you paid for it. There is no
guarantee that the price of our Class A Common Stock that will prevail in the market will ever exceed the price at which you purchased your shares of Class A
Common Stock.
Future
sales
of
our
Class
A
Common
Stock
in
the
public
market,
or
the
perception
that
such
sales
may
occur,
could
reduce
our
stock
price,
and
any
additional
capital
raised
by
us
through
the
sale
of
equity
or
convertible
securities
may
dilute
your
ownership
in
us.
We may sell additional shares of Class A Common Stock or securities convertible into shares of our Class A Common Stock in subsequent offerings. We
cannot predict the size of future issuances of our Class A Common Stock or securities convertible into Class A Common Stock or the effect, if any, that such future
issuances will have on the market price of our Class A Common Stock. Sales of substantial amounts of our Class A Common Stock (including shares issued in
connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A Common Stock.
39
On May 27, 2014, we filed a registration statement with the SEC on Form S-8 providing for the registration of 12,727,273 shares of our Class A Common
Stock issued or reserved for issuance under our equity incentive plan. Subject to the satisfaction of vesting conditions, the expiration or waiver of lock-up
agreements and the requirements of Rule 144 under the Securities Act, shares registered under the registration statement on Form S-8 are available for resale
immediately in the public market without restriction.
On June 5, 2015, we filed an automatically effective registration statement with the SEC on Form S-3 providing for (i) the continued registration of
14,885,797 shares of our Class A Common Stock listed on the Form S-1 we filed with the SEC on March 11, 2015, which are available for resale immediately in
the public market without restriction, and (ii) the registration of an additional 53,112,831 shares of our Class A Common Stock and certain other of our securities.
On May 3, 2017, we filed an automatically effective registration statement with the SEC on Form S-3 providing for the registration of 39,848,518 shares of
our Class A Common Stock that may be issued from time to time to certain members of Parsley LLC upon the exchange of such members’ PE Units, together with
an equal number of shares of our Class B Common Stock, which will be available for resale in the public market without restriction.
We
are
required
to
make
payments
under
the
Tax
Receivable
Agreement
for
certain
tax
benefits
we
may
claim,
and
the
amounts
of
such
payments
could
be
significant.
The PE Unit Holders generally have the right to exchange their PE Units (and a corresponding number of shares of Class B Common Stock) for shares of
our Class A Common Stock at an exchange ratio of one share of Class A Common Stock for each PE Unit exchanged (subject to conversion rate adjustments for
stock splits, stock dividends and reclassifications), or, if either we or Parsley LLC so elects, cash.
We have entered into the TRA with Parsley LLC and the TRA Holders. The TRA generally provides for the payment by us to each TRA Holder of 85% of
the net cash savings, if any, in U.S. federal, state and local income tax or franchise tax that we actually realize (or are deemed to realize in certain circumstances) in
periods after our IPO as a result of certain increases in tax basis and certain benefits attributable to imputed interest. We will retain the benefit of the remaining
15% of these cash savings. Payments we make under the TRA will be increased by any interest accrued from the due date (without extensions) of the
corresponding tax return.
The term of the TRA commenced upon the completion of our IPO and will continue until all tax benefits that are subject to the TRA have been utilized or
have expired, unless we exercise our right to terminate the TRA (or the TRA is terminated due to other circumstances, including our breach of a material obligation
thereunder or certain mergers or other changes of control), and we make the termination payment specified in the TRA.
Estimating the amount and timing of payments that may become due under the TRA is by its nature imprecise. For purposes of the TRA, cash savings in tax
generally are calculated by comparing our actual tax liability to the amount we would have been required to pay had we not been able to utilize any of the tax
benefits subject to the TRA. The amount and timing of any payments under the TRA are dependent upon significant future events and assumptions, including the
timing of the exchanges of PE Units, the price of Class A Common Stock at the time of each exchange, the extent to which such exchanges are taxable, the amount
of the exchanging TRA Holder’s tax basis in its PE Units at the time of the relevant exchange, the depreciation and amortization periods that apply to the increase
in tax basis, the amount and timing of the taxable income we generate in the future and the tax rate then applicable, and the portion of our payments under the TRA
constituting imputed interest or giving rise to depletable, depreciable or amortizable basis.
The payment obligations under the TRA are our obligations and not obligations of Parsley LLC, and we expect that the payments we will be required to
make under the TRA could be substantial. We are a holding company with no independent means of generating revenue. Therefore, to the extent Parsley LLC has
available cash, we intend to cause Parsley LLC to make distributions to the PE Unit Holders, including us, in an amount sufficient to cover all such obligations.
The ability of Parsley LLC and its subsidiaries to make such distributions will be subject to, among other things, the applicable provisions of Delaware law (or
other applicable instruments issued by Parsley LLC or its subsidiaries). To the extent that we are unable to make payments under the TRA for any reason, such
payments will be deferred and will accrue interest until paid. The payments under the TRA are not conditioned upon a holder of rights under the TRA having a
continued ownership interest in us.
40
In
certain
cases,
payments
under
the
TRA
may
be
accelerated
and/or
significantly
exceed
the
actual
benefits,
if
any,
we
realize
in
respect
of
the
tax
attributes
subject
to
the
TRA.
If we experience a change of control (as defined under the TRA, which includes certain mergers, asset sales and other forms of business combinations) or
the TRA terminates early (at our election or due to a material breach of the TRA), we would be required to make a substantial, immediate lump-sum payment equal
to the present value of hypothetical future payments that could be required to be paid under the TRA (determined by applying a discount rate equal to the long-term
Treasury rate in effect on the applicable date plus 300 basis points). The calculation of hypothetical future payments will be based upon certain assumptions and
deemed events as set forth in the TRA, including that we have sufficient taxable income to fully utilize such benefits and that any PE Units that the TRA Holders or
their permitted transferees own on the termination date are deemed to be exchanged on the termination date. Any early termination payment may be made
significantly in advance of, and may materially exceed, the actual realization, if any, of the future tax benefits to which the termination payment relates.
In these situations, our obligations under the TRA could have a substantial negative impact on our liquidity and could have the effect of delaying, deferring
or preventing certain mergers, asset sales, other forms of business combinations or other changes of control due to the additional transaction costs a potential
acquirer may attribute to satisfying such obligations. For example, if the TRA were terminated at December 31, 2017, the estimated termination payment would be
approximately $157.8 million (calculated using a discount rate equal to the long-term Treasury rate in effect on the applicable date, plus 300 basis points, applied
against an undiscounted liability of $312.8 million). The foregoing number is merely an estimate and the actual payment could differ materially. There can be no
assurance that we will be able to finance our obligations under the TRA.
In
the
event
that
our
payment
obligations
under
the
TRA
are
accelerated
upon
certain
mergers,
other
forms
of
business
combinations
or
other
changes
of
control,
the
consideration
payable
to
holders
of
our
Class
A
Common
Stock
could
be
substantially
reduced.
If we experience a change of control (as defined under the TRA, which includes certain mergers, asset sales and other forms of business combinations), we
would be obligated to make a substantial, immediate lump-sum payment, and such payment may be significantly in advance of, and may materially exceed, the
actual realization, if any, of the future tax benefits to which the payment relates. As a result of this payment obligation, holders of our Class A Common Stock
could receive substantially less consideration in connection with a change of control transaction than they would receive in the absence of such obligation. Further,
our payment obligations under the TRA will not be conditioned upon the TRA Holders’ having a continued interest in us or Parsley LLC. Accordingly, the TRA
Holders’ interests may conflict with those of the holders of our Class A Common Stock.
We
will
not
be
reimbursed
for
any
payments
made
under
the
TRA
in
the
event
that
any
tax
benefits
are
subsequently
disallowed
.
Payments under the TRA will be based on the tax reporting positions that we will determine. The TRA Holders will not reimburse us for any payments
previously made under the TRA if any tax benefits that have given rise to payments under the TRA are subsequently disallowed, except that excess payments made
to any TRA Holder will be netted against payments that would otherwise be made, if any, to such holder after our determination of such excess. As a result, in such
circumstances, we could make payments that are greater than our actual cash tax savings, if any and may not be able to recoup those payments, which could
adversely affect our liquidity.
In
certain
circumstances,
Parsley
LLC
will
be
required
to
make
tax
distributions
to
the
PE
Unit
Holders,
including
us,
and
such
tax
distributions
may
be
substantial.
To
the
extent
we
receive
tax
distributions
in
excess
of
our
tax
liabilities
and
obligations
to
make
payments
under
the
TRA
and
do
not
distribute
such
cash
balances
as
dividends
on
our
Class
A
Common
Stock,
the
holders
of
the
Exchange
Right
would
benefit
from
such
accumulated
cash
balances
if
they
exercise
their
Exchange
Right.
Parsley LLC is treated as a partnership for U.S. federal income tax purposes and, as such, is not subject to U.S. federal income tax. Instead, any taxable
income is allocated to the PE Unit Holders, including us. Pursuant to the Parsley LLC Agreement, Parsley LLC will generally make pro rata cash distributions, or
tax distributions, to the PE Unit Holders, including us, calculated using an assumed tax rate, to allow each of the PE Unit Holders to pay its respective taxes on
such holder’s allocable share of any taxable income of Parsley LLC. Under applicable tax rules, Parsley LLC is required to allocate net taxable income
disproportionately to its members in certain circumstances. Because tax distributions are determined based on the PE Unit Holder who is allocated the largest
amount of taxable income on a per unit basis and on an assumed tax rate that is the highest possible rate applicable to any PE Unit Holder, but are made pro rata
based on ownership, Parsley LLC may be
41
required to make tax distributions that, in the aggregate, exceed the amount of taxes that Parsley LLC would have paid if it were taxed on its net income at the
assumed rate. The pro rata distribution amounts may also be increased to the extent necessary, if any, to ensure that the amount distributed to Parsley Inc. is
sufficient to enable Parsley Inc. to pay any amounts payable under the TRA.
Funds used by Parsley LLC to satisfy its tax distribution obligations will not be available for reinvestment in our business. Moreover, the tax distributions
Parsley LLC will be required to make may be substantial, and may exceed (as a percentage of Parsley LLC’s income) the overall effective tax rate applicable to a
similarly situated corporate taxpayer. In addition, because these payments will be calculated with reference to an assumed tax rate, and because of the
disproportionate allocation of net taxable income, these payments may significantly exceed the actual tax liability for many of the PE Unit Holders, including us.
As a result of potential differences in the amount of net taxable income allocable to us and to the other PE Unit Holders, as well as the use of an assumed tax
rate in calculating Parsley LLC’s tax distribution obligations, we may receive distributions significantly in excess of our tax liabilities and obligations to make
payments under the TRA. If we do not distribute such cash balances as dividends on our Class A Common Stock and instead, for example, hold such cash balances
or lend them to Parsley LLC, the holders of the Exchange Right would benefit from any value attributable to such accumulated cash balances as a result of their
ownership of Class A Common Stock following an exchange of their Parsley LLC Units pursuant to the Exchange Right or their receipt of an equivalent amount of
cash.
We
may
issue
preferred
stock
whose
terms
could
adversely
affect
the
voting
power
or
value
of
our
Class
A
Common
Stock.
Our amended and restated certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of
preferred stock having such designations, preferences, limitations and relative rights, including preferences over our Class A Common Stock respecting dividends
and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or
value of our Class A Common Stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the
happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign
to holders of preferred stock could affect the residual value of the Class A Common Stock.
We
are
subject
to
certain
requirements
of
Section
404
of
the
Sarbanes-Oxley
Act.
If
we
fail
to
comply
with
the
requirements
of
Section
404
or
if
we
or
our
auditors
identify
and
report
material
weaknesses
in
internal
control
over
financial
reporting,
our
investors
may
lose
confidence
in
our
reported
information
and
our
stock
price
may
be
negatively
affected.
We are required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”). Section 404 requires that
we document and test our internal control over financial reporting and issue our management’s assessment of our internal control over financial reporting. This
section also requires that our independent registered public accounting firm issue an attestation report on such internal control. If we fail to comply with the
requirements of Section 404 of the Sarbanes-Oxley Act, or if we or our auditors identify and report material weaknesses in our internal control over financial
reporting, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose
confidence in our reported financial information, which could have a negative effect on the trading price of our Class A Common Stock. In addition, a material
weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our
ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our
business, results of operations and financial condition.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
42
ITEM 2. PROPERTIES
Our properties are located in the West Texas portion of the Permian Basin. As of December 31, 2017 , our acreage position consisted of 351,857 gross (
219,747 net) acres, approximately 72% of which is held by production. As of December 31, 2017 , we had interests in 372 gross ( 282.6 net) producing horizontal
wells, of which we operate 80% , and interests in 1,532 gross ( 749.0 net) producing vertical wells, of which we also operate 70% .
The Permian Basin extends through multiple counties in Southeast New Mexico and West Texas and covers an area some 250 miles wide and 300 miles
long. It is comprised of three main sub-areas, the Delaware Basin, the Central Basin Platform and the Midland Basin. Historically, conventional reservoirs have
been targeted and successfully produced in all three sub-areas. Over the past 30 years, there has been an increase in multi-stage fracturing treatments targeting and
commingling production from multiple tight, stacked pay, unconventional target zones. With the advent of horizontal drilling and the application of multi-stage
fracture treatments within one horizontal wellbore, activity has significantly increased, with operators generally targeting one zone at a time.
Core
Area
Descriptions
We group our assets by area based on similar geologic, economic and technical requirements. We split our assets into two areas, the Midland Basin and the
Delaware Basin.
Midland
Basin
Throughout the middle and late Pennsylvanian period, the Midland Basin was a very shallow and generally poorly defined area dominated by marine shale
and limestone deposition. Organic content of the marine shale increased as the basin slowly subsided. Tectonic uplift of the Central Basin Platform and the
coincident emergence of the Eastern Shelf during the early Permian period brought greater definition to the Midland Basin as a distinct physiographic feature. Slow
subsidence and basin filling with organic shale and limestone continued to dominate deposition. During the middle Permian period, more emergent surrounding
shelf areas to the northwest and south-southwest contributed thick volumes of clastic sand that molded with the shale and limestone and formed the widespread
Spraberry target zone throughout the Permian Basin. In the later Permian period, there was basin-wide infilling and subsequent burial with massive evaporate
deposition.
The Midland Basin has historically been characterized by production from its most prolific field, the Spraberry Trend Area. The Spraberry Trend Area has
been heavily drilled since the discovery of the Seaboard No. 2-D Lee well in Dawson County, Texas in 1949. The zone stretches over 150 miles north to south and
over 75 miles east to west. Additionally, activity targeting the deeper Wolfcamp zone increased dramatically after Henry Petroleum started drilling fully through
the Wolfcamp zone in the early 2000s. In the late 2000s and early 2010s, many operators, including us, had success commingling still deeper production from the
Upper Pennsylvanian (Cline), Strawn and Atoka zones. Concurrently, operators started testing zones singularly with horizontal wells and multi-stage treatments.
To date, operators have drilled horizontal wells in multiple zones within the Midland Basin.
As of December 31, 2017 , we held 301,160 gross ( 174,392 net) acres in our Midland Basin area. Approximately 73% of our acreage in this area is held by
production. We had interests in 319 gross ( 241.0 net) producing horizontal wells in the Midland Basin as of December 31, 2017 , and we operated 78% of the
horizontal wells in the Midland Basin in which we had an interest. We also had interests in 1,444 gross ( 731.5 net) producing vertical wells.
43
Since commencing our horizontal program in 2013, through December 31, 2017 we have drilled and completed 231 gross (216.1 net) horizontal wells in the
Midland Basin. The table below summarizes the horizontal and vertical productive development wells drilled and completed in the Midland Basin in the periods
indicated:
Horizontal
Vertical
Total (1)(2)
Year ended December 31,
2017
2016
2015
Gross
Net
Gross
Net
Gross
Net
95
2
97
89.1
2.0
91.1
70
4
74
67.8
3.9
71.7
46
13
59
43.5
12.9
56.4
(1)
(2)
Although a well may be classified as productive upon completion, future changes in oil and natural gas prices, operating costs and production may result in the well
becoming uneconomical, particularly exploratory wells for which there is no production history.
During the periods presented, we have not drilled any dry development wells, productive exploratory wells or dry exploratory wells.
Delaware
Basin
From the mid-Pennsylvanian period to the early Permian period, the Delaware Basin was a slowly subsiding area that was characterized by shallow marine
shales and limestone. Influxes of clastic sands generally occurred as turbidite deposits formed during periodic sea-level changes. Records indicate a rapid
deepening of the Delaware Basin relative to the emergent Central Basin Platform, during the early Permian period. Marine shale deposition continued to dominate
the basin during this period. Episodic pulses of carbonate and clastic debris and density flows punctuated the shale deposition and eventually became significant
reservoirs. Through the late Permian period, the basin became increasingly more clastic dominated as emergent shelf areas to the north shed sands into the basin.
As of December 31, 2017 , we held 50,697 gross ( 45,355 net) acres in our Delaware Basin area. Approximately 63% of our acreage in this area is held by
production; however, we hold mineral interests in a significant portion of our Delaware Basin leasehold acreage, which ensures our ability to continue producing
from this area. As of December 31, 2017 , we had interests in 53 gross ( 41.6 net) producing horizontal wells in the Delaware Basin, of which we operate 87% . We
also have interest in 88 gross ( 17.5 net) producing vertical wells.
Since commencing our horizontal program in 2013 through December 31, 2017 , we have drilled and completed 37 gross (35.6 net) horizontal wells in the
Delaware Basin. The table below summarizes the horizontal and vertical wells drilled and completed in the Delaware Basin in the periods indicated:
Horizontal
Vertical
Total (1)(2)
Year ended December 31,
2017
2016
2015
Gross
Net
Gross
Net
Gross
Net
31
—
31
29.8
—
29.8
5
—
5
4.8
—
4.8
1
1
2
1.0
1.0
2.0
(1)
(2)
Although a well may be classified as productive upon completion, future changes in oil and natural gas prices, operating costs and production may result in the well
becoming uneconomical, particularly exploratory wells for which there is no production history.
During the periods presented, we have not drilled any dry development wells, productive exploratory wells or dry exploratory wells.
Production
Status
For the year ended December 31, 2017 , our average daily net sales from our wells on our Midland Basin acreage was 59,291 Boe/d, of which 65% was
from oil, 16% was from natural gas and 19% was from NGLs. Over the same period, our average daily net sales from our wells on our Delaware Basin acreage was
8,632 Boe/d, of which 73% was from oil, 13% was from natural gas and 14% was from NGLs.
44
Operational
Facilities
Our land-based oil and natural gas processing facilities are typical of those found in the Permian Basin. Our facilities located at well locations or centralized
lease locations include storage tank batteries, oil/natural gas/water separation equipment, and pumping units. In addition, throughout our acreage, we own and
operate facilities with significant water sourcing, transfer, and disposal capacity.
Recent
Activity
During the year ended December 31, 2017 , we spud 112 gross (108.5 net) horizontal wells and seven gross (6.9 net) vertical wells on our Midland Basin
acreage. We also spud 43 gross (41.4 net) horizontal wells on our Delaware Basin acreage.
During the year ended December 31, 2017 , we incurred costs of approximately $714.5 million and $8.0 million for horizontal drilling and completions and
vertical drilling and completions, respectively, on our Midland Basin acreage. We incurred costs of approximately $325.8 million and $1.3 million for horizontal
drilling and completions and vertical recompletions, respectively, on our Delaware Basin acreage. We also incurred costs of approximately $157.8 million
associated with facilities and infrastructure.
The amount and timing of our future capital expenditures is largely discretionary and within our control. We could choose to defer a portion of planned
capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing and anticipated prices for oil
and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal
conditions, drilling and acquisition costs and the level of participation by other working interest owners.
Production,
Price
and
Cost
Data
The following table sets forth information regarding our production of oil, natural gas and NGLs and certain price and cost information, for the periods
indicated:
Average daily production volume:
Oil (Bbls/d)
Natural gas (Mcf/d)
Natural gas liquids (Bbls/d)
Total (Boe/d)
Average realized prices:
Oil, without realized derivatives (per Bbls)
Oil, with realized derivatives (per Bbls)
Natural gas, without realized derivatives (per Mcf)
Natural gas, with realized derivatives (per Mcf)
Natural gas liquids (per Bbls)
Average price per Boe, without realized derivatives
Average price per Boe, with realized derivatives
Average production costs (per Boe):
Lease operating expenses
Production and ad valorem taxes:
Production
Ad valorem
Total
Depreciation, depletion and amortization
Year ended December 31,
2017
2016
2015
44,904
63,907
12,362
67,923
25,596
36,784
6,530
38,257
$
48.95 $
41.34 $
47.68
2.43
2.40
22.87
38.80
37.94
47.56
2.30
2.30
16.01
32.60
36.76
4.12 $
4.23 $
1.98 $
0.43
2.41 $
14.21 $
1.64 $
0.35
1.99 $
16.70 $
$
$
$
$
45
13,170
28,326
4,110
22,003
44.89
56.60
2.57
2.72
15.79
33.13
40.33
7.83
1.71
0.51
2.22
22.20
Evaluation
and
Review
of
Proved
Reserves
Estimates of our proved reserves as of December 31, 2017 and 2016 were based on evaluations prepared by our internal staff of petroleum engineers and
audited by NSAI, with respect to our major properties. We have no oil and natural gas reserves from non-traditional sources. Additionally, we do not provide
optional disclosure of probable or possible reserves. Our historical proved reserve estimates as of December 31, 2015 were prepared based on reports by NSAI.
NSAI does not own an interest in any of our properties, nor is it employed by us on a contingent basis.
Reserve estimation procedures. We maintain an internal staff of petroleum engineers and geoscience professionals (the “Reserves Group”) to ensure the
integrity, accuracy and timeliness of the data used in our reserves estimation process. We have established internal controls over reserve estimation processes and
procedures to support the accurate and timely preparation and disclosure of reserve estimates in accordance with SEC requirements. These controls include
oversight of the reserves estimation reporting process by our Senior Vice President—Development Operations who reports directly to our President and Chief
Operating Officer as well as annual external audits of our proved reserves by NSAI.
The reserve estimates are summarized in reserve reconciliations that quantify reserve changes since the previous year end as revisions of previous estimates,
purchases of minerals-in-place, improved recovery, extensions and discoveries, production and sales of minerals-in-place. All reserve estimates, material
assumptions and inputs used in reserve estimates and significant changes in reserve estimates are reviewed for engineering and financial appropriateness and
compliance with SEC and GAAP standards by the Reserves Group, in consultation with our accounting and financial management personnel. Annually, our
President and Chief Operating Officer reviews the reserve estimates and any differences with the reserve auditors on a consolidated basis before these estimates are
approved.
Reserve information as well as models used to estimate such reserves are stored on secured databases. Non-technical information used in reserve estimation
models, including oil, natural gas and NGLs prices, production costs, transportation costs, future capital expenditures and our net ownership percentages are
obtained from other departments. Internally, we conduct testing with respect to such non-technical inputs.
Proved reserves audits. The proved reserve audits performed by NSAI for the year ended December 31, 2017 , in the aggregate, represented 100% of our
year-end 2017 proved reserves; and 100% of our year-end 2017 associated pre-tax present value of proved reserves discounted at ten percent.
NSAI follows the general principles set forth in the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information” promulgated
by the Society of Petroleum Engineers (the “SPE”). A reserve audit as defined by the SPE is not the same as a financial audit. The SPE’s definition of a reserve
audit includes the following concepts:
•
•
•
A reserve audit is an examination of reserve information that is conducted for the purpose of expressing an opinion as to whether such reserve
information, in the aggregate, is reasonable and has been presented in conformity with the 2007 SPE publication entitled “Standards Pertaining to
the Estimating and Auditing of Oil and Gas Reserves Information.”
The estimation of reserves is an imprecise science due to the many unknown geologic and reservoir factors that cannot be estimated through
sampling techniques. Since reserves are only estimates, they cannot be audited for the purpose of verifying exactness. Instead, reserve
information is audited for the purpose of reviewing in sufficient detail the policies, procedures and methods used by a company in estimating its
reserves so that the reserve auditors may express an opinion as to whether, in the aggregate, the reserve information furnished by a company is
reasonable.
The methods and procedures used by a company and the reserve information furnished by a company must be reviewed in sufficient detail to
permit the reserve auditor, in its professional judgment, to express an opinion as to the reasonableness of the reserve information. The auditing
procedures require the reserve auditor to prepare their own estimates of reserve information for the audited properties.
In conjunction with the audit of our proved reserves and associated pre-tax present value discounted at 10%, the Reserves Group provided to NSAI its
external and internal engineering and geoscience technical data and analyses. NSAI accepted without independent verification the accuracy and completeness of
the historical information and data furnished by us with respect to ownership interest, oil and natural gas production, well test data, commodity prices, operating
and development costs, and any agreements relating to current and future operations of the properties and sales of production. However, if in the course of its
evaluations something came to its attention that brought into question the validity or sufficiency of any such
46
information or data, NSAI did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified
such information or data.
In the course of its evaluations, NSAI prepared, for all of the audited properties, its own estimates of our proved reserves and the pre-tax present values of
such reserves discounted at 10%. NSAI reviewed its audit differences with us, and, as necessary, held meetings with us to review additional reserves work
performed by our technical teams and any updated performance data related to the proved reserve differences. Such data was incorporated, as appropriate, by both
parties into the proved reserve estimates. NSAI’s estimates, including any adjustments resulting from additional data, of those proved reserves and the pre-tax
present value of such reserves discounted at 10% did not differ from our estimates by more than 10% in the aggregate. However, when compared on a lease-by-
lease basis, some of our estimates were greater than those of the reserve auditors and some were less than the estimates of the reserve auditors. When such
differences do not exceed 10% in the aggregate and NSAI is satisfied that the proved reserves and pre-tax present values of such reserves discounted at 10% are
reasonable and that its audit objectives have been met, NSAI will issue an unqualified audit opinion. Any remaining differences are not resolved due to the limited
cost benefit of continuing such analyses. At the conclusion of the audit process, it was NSAI’s opinion, as set forth in its audit letter, which is included as an exhibit
to this Annual Report, that our estimates of our proved oil and natural gas reserves and associated pre-tax present values discounted at 10% are, in the aggregate,
reasonable and have been prepared in accordance with the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated
by the SPE.
Qualifications of proved reserves preparers and auditors. The Reserves Group is staffed by petroleum and geoscience professionals with extensive industry
experience and the process is managed by our Senior Vice President—Development Operations, the technical person primarily responsible for overseeing the
preparation of all of our reserve estimates. The qualifications of our Senior Vice President—Development Operations include over 32 years of reservoir and
operations experience. He holds a Bachelor of Science in Petroleum Engineering and a graduate certificate in finance. He is also a member of multiple professional
industry organizations. Our Senior Vice President—Development Operations reports directly to our President and Chief Operating Officer, whose qualifications
include over 12 years of reservoir and operations experience. He graduated with a Bachelor of Science in Petroleum Engineering and is a member of various
professional industry organizations. Our Reserves Group has an average of approximately 14 years of industry experience per person.
As described above, following the preparation of our reserves estimates, these estimates are audited for their reasonableness by NSAI. NSAI provides
worldwide petroleum property analysis services for energy clients, financial organizations and government agencies. NSAI was founded in 1961 and performs
consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. The technical person primarily responsible for
auditing our reserves estimates has been a practicing consulting petroleum engineer at NSAI since 1998 and has over 36 years of practical experience in petroleum
engineering and meets or exceeds the education, training and experience requirements set forth in the “Standards Pertaining to the Estimating and Auditing of Oil
and Gas Reserves Information” promulgated by the board of directors of the SPE.
Estimation of Proved Reserves . Under SEC rules, proved reserves are 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. If deterministic methods are
used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves
as of December 31, 2017 and 2016 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first
determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination results in the estimation of the uncertainty
associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable
oil and natural gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or
methods: (1) production performance-based methods; (2) material balance-based methods; (3) volumetric-based methods; and (4) analogy. These methods may be
used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves for proved developed producing wells
were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were
forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of
accuracy. Non-producing reserve estimates, for developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination
of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for our
properties, due to the mature nature of the properties targeted for development and an abundance of subsurface control data.
47
To audit our estimates of economically recoverable proved reserves and related future net cash flows, NSAI considered many factors and assumptions,
including the use of reservoir parameters derived from geological and engineering data which cannot be measured directly, economic criteria based on current costs
and the SEC pricing requirements and forecasts of future production rates. The current pricing environment could impact future economics.
Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same
reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or
more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency
and repeatability in the target zone being evaluated or in an analogous target zone. To establish reasonable certainty with respect to our estimated proved reserves,
the technologies and economic data used in the estimation of our proved reserves have been demonstrated to yield results with consistency and repeatability and
include production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, historical well cost and
operating expense data.
The following table sets forth the combined production volumes and reserves by area (in MBoe):
Midland Basin
Delaware Basin
Total
Year Ended
December 31, 2017
December 31, 2017
Production Volumes
Proved Developed Reserves
Proved Reserves
21,641
3,151
24,792
185,395
24,004
209,399
366,169
50,278
416,447
Summary of Oil, Natural Gas and NGLs Reserves . The following table presents our estimated net proved oil, natural gas and NGLs reserves as of the
periods indicated:
Proved developed reserves:
Oil (MBbls)
Natural gas (MMcf)
Natural gas liquids (MBbls)
Combined (MBoe)
Proved undeveloped reserves:
Oil (MBbls)
Natural gas (MMcf)
Natural gas liquids (MBbls)
Combined (MBoe)
Proved reserves:
Oil (MBbls)
Natural gas (MMcf)
Natural gas liquids (MBbls)
Combined (MBoe)
2017
December 31,
2016
2015
119,591
240,337
49,751
209,399
128,940
211,366
42,881
207,048
248,531
451,703
92,632
416,447
61,133
123,946
24,306
106,097
75,403
99,659
24,237
116,250
136,536
223,605
48,543
222,347
27,628
77,612
10,890
51,453
46,249
79,563
12,848
72,358
73,877
157,175
23,738
123,811
Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be
measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation.
As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates.
Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and
natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic
interpretation, prices and future production rates and costs. Please read “Item 1A. Risk Factors.”
48
Proved
Reserves
As of December 31, 2017 , our proved reserves were composed of 248,531 MBbls of oil, 451,703 MMcf of natural gas and 92,632 MBbls of NGLs, for a
total of 416,447 MBoe.
The following table summarizes the changes in our proved reserves during the year ended December 31, 2017 (in MBoe):
Balance, December 31, 2016
Purchases of reserves in place
Divestures of reserves in place
Extensions and discoveries
Revisions of previous estimates
Production
Balance, December 31, 2017
222,347
55,814
(6,467)
160,340
9,205
(24,792)
416,447
Changes in our proved reserves during the year ended December 31, 2017 primarily resulted from the following significant factors:
Purchases of reserves. During the year ended December 31, 2017 , we added 55,814 MBoe of proved reserves, primarily as a result of the acquisition of
incremental working interests in properties and undeveloped acreage in both the Midland and Delaware Basins. For the year ended December 31, 2017 , we
acquired 53,105 MBoe of proved reserves in the Midland Basin and 2,709 MBoe of proved reserves in the Delaware Basin.
Divestiture of reserves. During the year ended December 31, 2017 , we divested 6,467 MBoe of proved reserves, which includes 5,936 MBoe of proved
reserves in the Midland Basin and 531 MBoe of proved reserves in the Delaware Basin.
Extensions and discoveries. Extensions and discoveries of 160,340 MBoe during the year ended December 31, 2017 resulted primarily from our successful
horizontal drilling program in the Midland Basin and Delaware Basin.
Revisions of previous estimates. During the year ended December 31, 2017 , we experienced total positive revisions of previous estimates of 9,205 MBoe.
The main driver of this adjustment was related to positive revisions due to better than expected performance from our wells for a total of 8,134 MBoe.
Additionally, positive revisions of 2,752 MBoe and 3,044 MBoe were recorded due to increases in oil prices and production, respectively, when compared to the
year ended December 31, 2016. This was offset by the reclassification of certain PUD reserves to unproved reserves, which accounted for a 4,725 MBoe downward
revision to previous estimates related to the removal of reserves for locations determined to be outside of our five-year capital expenditure plan.
Production . During the year ended December 31, 2017, our production volumes were 24,792 MBoe resulting in a corresponding decrease in our proved
reserves.
As of December 31, 2017 , 2,178 MBoe, or less than 1% of our total proved reserves, were classified as proved developed non-producing.
Proved
Undeveloped
Reserves
(PUDs)
As of December 31, 2017 , our proved undeveloped reserves were composed of 128,940 MBbls of oil, 211,366 MMcf of natural gas and 42,881 MBbls of
NGLs, for a total of 207,048 MBoe. PUDs will be converted from undeveloped to developed as the applicable wells begin production.
49
The following table summarizes the changes in our PUDs during the year ended December 31, 2017 (in MBoe):
Balance, December 31, 2016
Purchases of reserves
Divestiture of reserves
Extensions and discoveries
Revisions of previous estimates
Transfers to proved developed
Balance, December 31, 2017
116,250
23,441
(5,228)
86,094
(6,371)
(7,138)
207,048
Changes in our PUDs during the year ended December 31, 2017 primarily resulted from the following significant factors:
Purchases of reserves. During the year ended December 31, 2017 , we added 23,441 MBoe of PUDs, primarily as a result of the acquisition of undeveloped
acreage in the Midland Basin.
Divestiture of reserves. During the year ended December 31, 2017 , we divested 5,228 MBoe of PUDs, which includes 4,697 MBoe of proved reserves in
the Midland Basin and 531 MBoe of proved reserves in the Delaware Basin.
Extensions and discoveries. Extensions and discoveries of 86,094 MBoe during the year ended December 31, 2017 resulted primarily from the drilling of
new wells during the year and from new proved undeveloped locations added during the year.
Revisions of previous estimates. During the year ended December 31, 2017 , we experienced total negative revisions to previous PUD reserve estimates of
6,371 MBoe. The main driver of this adjustment was the reclassification of certain PUD reserves to unproved reserves, which accounted for a 4,725 MBoe
downward revision to previous estimates associated with the removal of reserves for locations determined to be outside of our five-year capital expenditure plan.
We also experienced negative revisions of 679 MBoe related to production and pricing and negative revisions of 967 MBoe associated with changes to our type
curves, shrinkage and yield, lease operating expenses and capital expenditures.
Transfers to proved developed. During the year ended December 31, 2017 , we transferred 7,138 MBoe of PUDs to proved developed, all of which were
transferred to proved developed producing reserves.
At the end of each year, we schedule a five-year capital expenditure plan based on our best available data and financial feasibility at the time the plan is
developed. Our capital expenditure plan includes only PUD reserves that we are reasonably certain will be drilled within five years of booking based upon
management's evaluation of a number of qualitative and quantitative factors, including: estimated risk-based returns; estimated well density; commodity prices and
cost forecasts; recent drilling, recompletion or re-stimulation results and well performance; anticipated availability of services, equipment, supplies and personnel;
seasonal weather; and changes in drilling and completion techniques and technology. Our PUD reserves do not include reserves associated with non-operated
properties. This process is intended to ensure that PUD reserves are only booked for locations where a final investment decision has been made by us. Our five-
year development plan generally does not contemplate a uniform conversion of PUD reserves in all of its producing areas. Our board of directors annually reviews
our expenditure plan and approves the capital budget for the first year of the development plan.
We review and revise the capital expenditure plan throughout the year and modify the plan after evaluating a number of factors, including: operational
results; current and expected future commodity prices; estimated risk-based returns; cost and availability of services, equipment and resources; acquisition and
divestiture activity; and our current and projected financial condition and liquidity. If there are changes that result in certain PUD reserves no longer being
scheduled for development within five years from the date of initial booking, we reclassify those PUD reserves to non-proved reserve categories. In addition, PUD
locations and reserves may be removed from the development plan ahead of their five-year life expiration as a result of the changes in our development plan related
to the factors enumerated above.
Costs incurred relating to the development of locations that were classified as PUDs at December 31, 2016 were approximately $65.1 million during the
year ended December 31, 2017 . Additionally, during 2017 , we spent approximately $770.0 million drilling and completing other in-field wells which were not
classified as proved as of December 31, 2016 . Estimated future development costs relating to the development of PUDs at December 31, 2017 were projected to be
approximately $313.2 million in 2018 , $472.8 million in 2019 , $498.9 million in 2020 , $441.9 million in 2021 and $402.1 million in future periods. As we
continue to develop our properties and have more well production and completion data, we
50
believe we will continue to realize cost savings and experience lower relative drilling and completion costs as we convert PUDs into proved developed reserves in
upcoming years. As of December 31, 2017 , all of our PUD drilling locations were scheduled to be drilled within five years of their initial booking.
Additional information regarding our proved reserves can be found in the notes to our consolidated financial statements included elsewhere in this Annual
Report and the audit letter relating to the proved reserve report as of December 31, 2017 , which is included as an exhibit to this Annual Report.
Developed
and
Undeveloped
Acreage
The following tables set forth information as of December 31, 2017 relating to our leasehold acreage.
Midland Basin
Delaware Basin
Total
Developed Acreage (1)
Undeveloped Acreage (2)
Total Acreage
Gross (3)
Net (4)
Gross (3)
Net (4)
Gross (3)
Net (4)
220,989
31,820
252,809
124,958
29,733
154,691
80,171
18,877
99,048
49,434
15,622
65,056
301,160
50,697
351,857
174,392
45,355
219,747
(1)
(2)
(3)
(4)
Developed acreage is acreage spaced or assigned to productive wells and does not include undrilled acreage held by production under the terms of the
applicable lease.
Undeveloped acreage is acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities
of oil or natural gas, regardless of whether such acreage contains proved reserves.
A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.
A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of
the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
In addition to the leasehold acreage described above, as of December 31, 2017 , we held mineral rights in 33,221 acres, with an average royalty interest of
21% . These mineral rights and associated royalty interests boost net revenue interest in our applicable properties.
Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production
from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. Most of the
leases governing our acreage have continuous development clauses that permit us to continue to hold the acreage under such leases after the expiration of the
primary term if we initiate additional development within 60 to 180 days of the expiration date, without the requirement of a lease extension payment. Thereafter,
generally the leases are held with additional development every 60 to 180 days until the entire lease is held by production. The following table sets forth the gross
and net undeveloped acreage, as of December 31, 2017 , that will expire over the next four years unless production is established within the spacing units covering
the acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates. There are currently no expirations
for the year ended December 31, 2022.
2018
2019
2020
2021
Gross
Net
Gross
Net
Gross
Net
Gross
Net
Midland Basin
Delaware Basin
Total
36,198
2,208
38,406
18,852
1,506
20,358
25,613
11,094
36,707
51
9,253
7,224
10,827
399
16,477
11,226
5,156
194
5,350
3,364
640
4,004
2,029
480
2,509
Drilling
Results
The following table sets forth information with respect to the number of wells completed during the periods indicated. The information should not be
considered indicative of future performance, nor should it be assumed that there is any correlation between the number of productive wells drilled, quantities of
reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of
return.
2017
2016
2015
Gross
Net
Gross
Net
Gross
Net
Year ended December 31,
Horizontal:
Development Wells:
Productive (1)
Dry holes
Exploratory Wells:
Productive (1)
Dry holes
Vertical:
Development Wells:
Productive (1)
Dry holes
Exploratory Wells:
Productive (1)
Dry holes
Total:
Productive (1)
Dry holes
126
—
119
—
—
—
2
—
—
—
128
—
128
—
—
2
—
—
—
121
—
121
75
—
—
—
4
—
—
—
79
—
79
73
—
—
—
4
—
—
—
77
—
77
46
—
1
—
13
—
1
—
61
—
61
43
—
1
—
13
—
1
—
58
—
58
(1) Although a well may be classified as productive upon completion, future changes in oil and natural gas prices, operating costs and production may result
in the well becoming uneconomical, particularly exploratory wells for which there is no production history.
As of December 31, 2017 , in the Midland Basin, we had nine gross ( 8.8 net) horizontal wells in the process of being drilled, ten ( 9.8 net) horizontal wells
awaiting hydraulic fracturing procedures and eight gross ( 8.0 net) horizontal wells in the process of being completed that are not reflected in the above table. In the
Delaware Basin, we had four gross ( 4.0 net) horizontal wells in the process of being drilled, eight gross ( 7.7 net) horizontal wells awaiting hydraulic fracturing
procedures and six gross ( 5.3 net) horizontal wells in the process of being completed that are not reflected in the above table.
Title
to
Properties
As is customary in the oil and natural gas industry, when we acquire leasehold acreage, we conduct title due diligence on the subject properties but may not
have title opinions covering the properties prior to entering into a purchase and sale agreement. At the time we determine to conduct drilling operations on those
properties, we conduct a thorough title examination and perform curative work with respect to significant defects prior to commencing drilling operations. To the
extent title opinions or other investigations completed after the closing of an acquisition reflect title defects on those properties, we are typically responsible for
curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such
property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in
accordance with standards generally accepted in the oil and natural gas industry.
52
Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the
materiality of properties, we may obtain a title opinion, obtain an updated title review or opinion or review previously obtained title opinions. Our oil and natural
gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with our
use of or affect the carrying value of the properties.
We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to encumbrances in some cases, such as
customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens
under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements,
restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and
encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these
properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and
private parties for us to operate our business in all material respects as described in this Annual Report.
Facilities
As of December 31, 2017 , we leased corporate office space in Austin, Texas at 303 Colorado Street, where our corporate headquarters is located, and at
certain other locations in downtown Austin. We also leased corporate office space in Midland, Texas and owned field operation facilities in Midland and Fort
Stockton, Texas. We believe that our facilities are adequate for our current operations.
During the fourth quarter of 2017, we entered into a lease agreement with an affiliate of Cousins Properties to design and develop an office building at 300
Colorado Street, Austin, Texas. Upon its completion, we expect to move our corporate headquarters to this location.
ITEM 3. LEGAL PROCEEDINGS
From time to time, we are a party to ongoing legal proceedings in the ordinary course of business, including workers’ compensation claims and
employment-related disputes. We do not believe the results of these proceedings, individually or in the aggregate, will have a material adverse effect on our
business, financial condition, results of operations, or liquidity.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
53
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY
SECURITIES
Our Class A Common Stock began trading on the NYSE under the symbol “PE” on May 29, 2014. Prior to that, there was no public market for our Class A
Common Stock. The following table sets forth high and low sales prices of our Class A Common Stock for the periods indicated:
PART II
Fourth Quarter
Third Quarter
Second Quarter
First Quarter
2017
Price Range
2016
Price Range
High
Low
High
Low
$
$
$
$
30.61 $
30.38 $
33.07 $
37.72 $
23.20 $
22.98 $
25.17 $
28.73 $
39.82 $
35.00 $
28.01 $
23.00 $
31.74
26.40
21.23
14.51
On February 23, 2018, the closing sales price of our Class A Common Stock as reported by the NYSE was $26.21 per share and we had approximately 37
holders of record of our Class A Common Stock. This number does not include owners for whom shares of our Class A Common Stock may be held in “street”
name.
There is no public market for our Class B Common Stock. On February 23, 2018, we had 72 holders of record of our Class B Common Stock.
Dividends
We have never declared or paid any dividends to holders of our Class A Common Stock or Class B Common Stock. We currently intend to retain all
available funds, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon
various factors, including our results of operations, financial condition, capital requirements and investment opportunities. In addition, our debt agreements restrict
our ability to pay cash dividends to holders of our Class A Common Stock or Class B Common Stock.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
The following table sets forth information with respect to our repurchases of shares of Class A Common Stock during the quarter ended December 31, 2017
.
Period
October 2017
November 2017
December 2017
Total
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
— $
— $
1,793 $
1,793 $
—
—
29.72
29.72
— $
— $
— $
— $
—
—
—
—
(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.
Sales of Unregistered Equity Securities
We did not have any sales of unregistered equity securities during the fiscal year ended December 31, 2017 that we have not previously reported on a
Quarterly Report on Form 10-Q or a Current Report on Form 8-K.
54
ITEM 6. SELECTED FINANCIAL DATA
The following tables show selected historical financial data for the periods and as of the periods indicated. For the years ended December 31, 2017, 2016
and 2015, the financial statements are consolidated and for all prior years the financial statements are consolidated and combined. The following selected financial
and operating data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and
“Item 8. Financial Statements and Supplementary Data.”
Year ended December 31,
2017
2016
2015
2014
2013
(in thousands, except per share data)
$
802,230 $
387,303 $
215,795 $
232,554 $
REVENUES
Oil sales
Natural gas sales
Natural gas liquids sales
Other
Total revenues
OPERATING EXPENSES
Lease operating expenses
Production and ad valorem taxes
Depreciation, depletion and amortization
General and administrative expenses
Exploration and abandonment costs
Impairment
Acquisition costs (1)
Accretion of asset retirement obligations
Rig termination costs
Other operating expenses
Total operating expenses
OPERATING INCOME (LOSS)
OTHER (EXPENSE) INCOME
Interest expense, net
(Loss) gain on sale of property
Prepayment premium on extinguishment of debt
Derivative (loss) gain
Change in TRA liability
Interest income
Other income (expense)
Total other (expense) income, net
INCOME (LOSS) BEFORE INCOME TAXES
INCOME TAX (EXPENSE) BENEFIT (2)
NET INCOME (LOSS)
LESS: NET (INCOME) LOSS ATTRIBUTABLE TO
NONCONTROLLING INTERESTS
NET INCOME (LOSS) ATTRIBUTABLE TO
PARSLEY ENERGY, INC. STOCKHOLDERS
Net income (loss) per common share:
Basic
Diluted
Weighted average common shares outstanding:
Basic
Diluted
56,571
103,193
5,050
967,044
102,169
59,641
352,247
124,255
40,415
—
10,977
971
—
9,568
700,243
266,801
(97,381)
(14,332)
(3,891)
(66,135)
35,847
7,936
783
(137,173)
129,628
(5,708)
123,920
97,839
23,179
—
91
30,928
38,273
1,269
26,582
23,680
417
30,642
38,561
672
457,773
266,474
302,429
121,109
59,293
27,916
233,766
84,591
13,931
—
1,081
732
—
5,316
426,626
31,147
(56,225)
(119)
(36,335)
(50,835)
7,351
992
(2,317)
(137,488)
(106,341)
17,424
(88,917)
62,913
17,800
178,281
55,294
13,865
950
—
826
8,970
1,696
340,595
(74,121)
(45,581)
(34,374)
—
60,818
—
28
(3,556)
(22,665)
(96,786)
23,755
(73,031)
38,071
18,941
94,297
87,949
3,136
—
2,527
512
765
—
246,198
56,231
(39,940)
(2,097)
(5,107)
83,858
—
316
(71)
36,959
93,190
(36,468)
56,722
16,572
7,081
28,152
16,553
—
—
—
181
—
—
68,539
52,570
(14,006)
36
—
(9,800)
—
235
381
(23,154)
29,416
(1,906)
27,510
$
$
$
(17,146)
14,735
22,547
(33,293)
—
106,774
$
(74,182)
$
(50,484)
$
23,429
$
27,510
0.44 $
0.42 $
(0.46) $
(0.46) $
(0.45) $
(0.45) $
0.65
0.65
240,733
296,512
161,793
161,793
111,271
111,271
93,168
93,271
(1)
(2)
On April 20, 2017, we completed the Double Eagle Acquisition (defined herein) for total consideration of approximately $2.6 billion, which is discussed further in Note 5—
Acquisitions of Oil and Natural Gas Properties to our consolidated financial statements included elsewhere in this Annual Report.
Parsley Energy, Inc. is a subchapter C corporation (“C-Corp”) under the Internal Revenue Code of 1986, as amended and is subject to federal and State of Texas income taxes.
Our predecessor was not subject to U.S. federal income taxes. As a result, the consolidated net income in our historical financial statements for periods prior to our May 29,
2014 IPO does not reflect the tax expense we would have incurred as a C-Corp during such periods.
55
Production
Oil (MBbls)
Natural gas (MMcf)
Natural gas liquids (MBbls) (1)
Combined (MBoe)
Average daily production volume:
Oil (Bbls/d)
Natural gas (Mcf/d)
Natural gas liquids (MBbls) (1)
Total (Boe/d)
Average realized prices:
Oil, without realized derivatives (per Bbls)
Oil, with realized derivatives (per Bbls)
Natural gas, without realized derivatives (per Mcf)
Natural gas, with realized derivatives (per Mcf)
NGLs (per MBbls) (1)
Average price per Boe, without realized derivatives
Average price per Boe, with realized derivatives
Expense per Boe:
Lease operating expenses
Production and ad valorem taxes
Depreciation, depletion and amortization
General and administrative expenses
Exploration and abandonment costs
Impairment
Acquisition costs
Accretion of asset retirement obligations
Rig termination costs
Other operating expenses
Year ended December 31,
2017
2016
2015
2014
2013
(in thousands, except per unit data)
16,390
23,326
4,512
24,792
44,904
63,907
12,362
67,923
9,368
13,463
2,390
14,002
25,596
36,784
6,530
38,257
4,807
10,339
1,500
8,031
13,170
28,326
4,110
22,003
2,839
7,245
1,140
5,186
7,778
19,849
3,123
14,207
$
48.95
$
41.34
$
44.89
$
81.91 $
$
47.68
2.43
2.40
22.87
38.80
37.94
4.12
2.41
14.21
5.01
1.63
$
—
0.44
0.04
—
0.39
47.56
2.30
2.30
16.01
32.60
36.76
4.23
1.99
16.70
6.04
0.99
$
—
0.08
0.05
—
0.38
56.60
2.57
2.72
15.79
33.13
40.33
7.83
2.22
22.20
6.89
1.73
0.12
$
—
0.10
1.12
0.21
81.33
4.23
4.32
33.83
58.19
58.00
7.34 $
3.65
18.18
16.96
0.60
—
0.49
0.10
0.15
—
47.47 $
Total operating expenses per Boe
$
28.25
$
30.46
$
42.42
$
Consolidated statements of cash flows data:
Net cash provided by (used in):
Operating activities
Investing activities
Financing activities
Proved reserves:
Oil (MBbls)
Natural gas (MMcf)
NGLs (MBbls)
Combined (MBoe)
Consolidated balance sheet data:
$
694,040
$
228,191
$
172,290
$
190,090 $
(3,456,860)
3,183,630
(1,885,366)
1,447,470
248,531
451,703
92,632
416,447
136,536
223,605
48,543
222,347
(427,165)
547,409
73,877
157,175
23,738
123,811
(1,247,677)
1,088,744
47,617
123,645
22,667
90,891
Cash and cash equivalents and short-term investments
$
703,472
$
133,379
$
343,084
$
50,550 $
Total assets (2)
Long-term debt
Total equity
8,793,198
2,179,525
5,880,706
3,938,782
1,041,324
2,430,306
2,505,100
546,832
1,586,641
2,040,490
666,257
992,489
(1)
(2)
For the year ended December 31, 2013, NGLs production volumes and realized sales prices are included in the natural gas line item.
On April 20, 2017, we completed the Double Eagle Acquisition (defined herein) for total consideration of approximately $2.6 billion. which is
discussed further in Note 5—Acquisitions of Oil and Natural Gas Properties to our consolidated financial statements included elsewhere in this
Annual Report.
56
1,049
4,680
—
1,829
2,874
12,822
—
5,011
93.28
87.91
4.95
4.95
—
66.17
63.09
9.06
3.87
15.39
9.05
—
—
—
0.10
—
—
37.47
53,235
(425,611)
378,096
29,507
77,818
12,357
54,834
19,393
742,407
429,822
108,032
Non-GAAP Financial Measures
Adjusted
EBITDAX
Adjusted EBITDAX is not a measure of net income as determined by GAAP. Adjusted EBITDAX is a supplemental non-GAAP financial measure that is
used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. We define
Adjusted EBITDAX as net income (loss) before depreciation, depletion and amortization (“DD&A”), exploration and abandonment costs, net interest expense,
income tax expense (benefit), change in TRA liability, stock-based compensation, impairment, acquisition costs, asset retirement obligation accretion expense, rig
termination costs, loss (gain) on sale of property, loss on early extinguishment of debt, inventory write down, loss (gain) on derivative instruments, net settlements
on derivative instruments, and premium realization on options that settled during the period.
Management believes Adjusted EBITDAX is useful because it allows them to more effectively evaluate our operating performance and compare the results
of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving
at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book
values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more
meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance. Certain items excluded from Adjusted
EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as
well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our computations of Adjusted EBITDAX may not be
comparable to other similarly titled measure of other companies. We believe that Adjusted EBITDAX is useful to investors as a widely followed measure of
operating performance.
The following table presents a reconciliation of Adjusted EBITDAX to the GAAP financial measure of net income for each of the periods indicated.
Adjusted EBITDAX reconciliation to net income (loss):
Net income (loss) attributable to Parsley Energy, Inc. stockholders’
$
106,774 $
(74,182) $
(50,484) $
23,429 $
27,510
Year Ended December 31,
2017
2016
2015
2014
2013
(in thousands)
Net income (loss) attributable to noncontrolling interests
Depreciation, depletion and amortization
Exploration and abandonment costs
Interest expense, net
Income tax expense (benefit)
EBITDAX
Change in TRA liability
Stock-based compensation
Impairment
Acquisition costs
Accretion of asset retirement obligations
Rig termination costs
Loss (gain) on sale of property
Loss on early extinguishment of debt
Inventory write down
Loss (gain) on derivatives
Net settlements on derivative instruments
Premium realization on options that settled during the period
17,146
(14,735)
(22,547)
352,247
233,766
178,281
40,415
89,445
13,931
55,233
13,865
45,553
5,708
(17,424)
(23,755)
33,293
94,297
3,136
39,624
36,468
611,735
196,589
140,913
230,247
(35,847)
19,619
—
10,977
971
—
14,332
3,891
1,060
66,135
15,670
(37,103)
(7,351)
12,871
—
1,081
732
—
119
36,335
—
50,835
26,441
31,757
—
—
8,133
53,297
950
—
826
8,970
34,374
—
4,147
—
2,527
512
765
2,097
5,107
—
(60,818)
(83,858)
46,456
11,406
3,311
(6,928)
9,800
(198)
(5,434)
—
28,152
—
13,771
1,906
71,339
—
1,233
—
—
181
—
(36)
—
—
Adjusted EBITDAX
$
671,440 $
349,409 $
195,357 $
207,077 $
76,885
57
PV-10
PV-10 is a non-GAAP financial measure and generally differs from the Standardized Measure, the most directly comparable GAAP financial measure,
because it does not include the effects of income taxes on future net reserves. Neither PV-10 nor Standardized Measure represents an estimate of the fair market
value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by
companies without regard to the specific tax characteristics of such companies.
The following table provides a reconciliation of PV-10 to the GAAP financial measure of Standardized Measure as of December 31, 2017 :
PV-10 of proved reserves
Present value of future income tax discounted at 10%
Standardized Measure
58
As of December 31, 2017
(in millions)
3,918.0
(902.5)
3,015.5
$
$
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes appearing in “Item 8.
Financial Statements and Supplementary Data.” The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and
expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results
could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not
limited to, market prices for oil and natural gas, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions,
regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report, particularly in “Item 1A. Risk Factors”
and “Cautionary Note Regarding Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the
forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise
required by applicable law.
Overview
Parsley Energy, Inc. was formed in December 2013 to succeed our predecessor, which began operations in August 2008 when it acquired operator rights to
wells producing from the Spraberry Trend in the Midland Basin from Joe Parsley, a co-founder of Parker and Parsley Petroleum Company.
We are an independent oil and natural gas company focused on the acquisition and development of unconventional oil, natural gas and NGLs reserves in the
Permian Basin. The Permian Basin is located in West Texas and Southeastern New Mexico and is comprised of three primary sub-areas: the Midland Basin, the
Central Basin Platform and the Delaware Basin. These areas are characterized by high oil and liquids-rich natural gas content, multiple vertical and horizontal
target horizons, extensive production histories, long-lived reserves and historically high drilling success rates. Our properties are located in the Midland and
Delaware Basins, where, given the associated returns, we focus predominantly on horizontal development drilling.
As a holding company and the sole managing member of Parsley LLC, (i) our sole material asset consists of 252,260,300 PE Units as of December 31,
2017, (ii) we are responsible for all operational, management and administrative decisions of Parsley LLC, and (iii) we consolidate the financial and operating
results of Parsley LLC and its subsidiaries.
Our
Properties
The following table sets forth information as of December 31, 2017 relating to our leasehold acreage:
Area
Midland Basin
Delaware Basin
Total
Developed Acreage
Undeveloped Acreage
Total Acreage
Gross
220,989
31,820
Net
124,958
29,733
252,809
154,691
Gross
Net
80,171
18,877
99,048
49,434
15,622
65,056
Gross
301,160
50,697
351,857
Net
174,392
45,355
219,747
In addition to the leasehold acreage described above, as of December 31, 2017 , we held mineral rights in 33,221 acres, with an average royalty interest of
21% . These mineral rights and associated royalty interests boost our net revenue interest in the applicable properties.
The majority of our identified horizontal drilling locations are located in Upton, Reagan, Midland, Howard, Martin and Glasscock Counties, Texas, in the
Midland Basin, and Pecos and Reeves Counties, Texas, in the Delaware Basin.
As of December 31, 2017 , we operated the following wells:
Area
Midland Basin
Delaware Basin
Total
Vertical Wells
Horizontal Wells
Total
Gross
Net
Gross
Net
Gross
Net
671.6
17.5
689.1
250
46
296
229.4
41.1
270.5
1,301
68
1,369
901.0
58.6
959.6
1,051
22
1,073
59
As of December 31, 2017 , we held an interest in 1,904 gross (1,031.7 net) wells, including wells that we did not operate. As of December 31, 2017 , we
owned an immaterial number of productive wells related to the production of natural gas.
Since commencing our horizontal drilling program in 2013 through December 31, 2017 , we have drilled and completed 231 gross (216.1 net) horizontal
wells in the Midland Basin and 37 gross (35.6 net) horizontal wells in the Delaware Basin. The table below summarizes the horizontal wells drilled and completed
in the periods indicated:
Area
Midland Basin
Delaware Basin
Total
How
We
Evaluate
Our
Operations
Year Ended December 31,
2017
2016
2015
Gross
Net
Gross
Net
Gross
Net
95
31
89.1
29.8
126
118.9
70
5
75
67.8
4.8
72.6
46
1
47
43.5
1.0
44.5
We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:
•
•
•
•
•
•
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;
completion activities; and
certain unit costs.
Sources
of
Our
Revenues
Our production revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs that are extracted from our natural gas
during processing, and do not include the effects of derivatives. Our production revenues may vary significantly from period to period as a result of changes in
volumes of production sold or changes in commodity prices.
The following table presents the breakdown of our production revenues for the periods indicated:
Oil sales
Natural gas sales
Natural gas liquids sales
Year Ended December 31,
2017
2016
2015
83%
6%
11%
85%
7%
8%
81%
10%
9%
Other revenues include fees charged by certain of our subsidiaries, Pacesetter Drilling, LLC (“Pacesetter”) and Parsley Minerals, LLC, to third parties for
drilling services and surface use in the normal course of business. In addition, other revenues include saltwater disposal and gathering system income.
60
Production
Volumes
The following table presents historical production volumes for our properties for the periods indicated:
Oil (MBbls)
Natural gas (MMcf)
Natural gas liquids (MBbls)
Total (MBoe)
Average net production (Boe/d)
Year Ended December 31,
2017
2016
2015
16,390
23,326
4,512
24,792
67,923
9,368
13,463
2,390
14,002
38,257
4,807
10,339
1,500
8,031
22,003
Production
Volumes
Directly
Impact
Our
Results
of
Operations
As reservoir pressures decline, production from a given well or formation decreases. Growth in our future production and reserves will depend on our ability
to continue to add proved reserves in excess of our production. Accordingly, we plan to maintain our focus on adding reserves through the development of our
properties as well as through acquisitions. Our ability to add reserves through development projects and acquisitions is dependent on many factors, including our
ability to raise capital, obtain regulatory approvals, procure contract drilling rigs and personnel and successfully identify and consummate acquisitions. Please read
“Item 1A. Risk Factors—Risks Related to the Oil and Natural Gas Industry and Our Business” for a discussion of these and other risks affecting our proved
reserves and production.
Realized
Prices
on
the
Sale
of
Oil,
Natural
Gas
and
NGLs
Historically, oil, natural gas and NGLs prices have been extremely volatile, and we expect this volatility to continue. Because our production consists
primarily of oil, our production revenues are more sensitive to fluctuations in the price of oil than they are to fluctuations in the price of natural gas or NGLs.
The following table provides the high and low prices for NYMEX WTI and NYMEX Henry Hub prompt month contract prices and our differentials to the
average of those benchmark prices for the periods indicated.
Oil
NYMEX WTI High
NYMEX WTI Low
Differential to Average NYMEX WTI
Natural Gas
NYMEX Henry Hub High
NYMEX Henry Hub Low
Differential to Average NYMEX Henry Hub
NGLs
NYMEX WTI High
NYMEX WTI Low
Differential to Average NYMEX WTI
Year Ended December 31,
2017
2016
2015
$
$
$
$
$
$
$
$
$
60.42 $
42.53 $
(2.53) $
3.42 $
2.56 $
(0.56) $
60.42 $
42.53 $
(28.61) $
54.06 $
26.21 $
1.20 $
3.93 $
1.64 $
(0.49) $
54.06 $
26.21 $
(24.13) $
61.43
34.73
(3.19)
3.23
1.76
0.07
61.43
34.73
(32.29)
To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in commodity prices, we enter into derivative arrangements for a
portion of our production, with an emphasis on our oil production. By removing a significant portion of price volatility associated with our oil production, we
believe we will mitigate, but not eliminate, the potential negative effects of reductions in oil prices on our cash flow from operations for the relevant periods. See
“Item 7A. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk” for information regarding our exposure to market risk, including
the effects of changes in commodity prices and our commodity derivative contracts.
61
We will continue to use commodity derivative instruments to hedge our price risk in the future. Our hedging strategy and future hedging transactions will be
determined at our discretion and may be different than what we have done on a historical basis. We are not under an obligation to hedge a specific portion of our
oil, natural gas or NGLs production.
The volumes and terms of our derivative instruments as of December 31, 2017 were as follows:
Description and Production Period
Crude Oil Put Spreads (1) :
Jan 2018 - Mar 2018
Jan 2018 - Mar 2018
Jan 2018 - Jun 2018
Jan 2018 - Jun 2018
Apr 2018 - Jun 2018
Jul 2018 - Dec 2018
Jul 2018 - Dec 2018
Oct 2018 - Dec 2018
Jan 2019 - Jun 2019
Total
Crude Oil Three-Way Collars (2) :
Jan 2018 - Mar 2018
Jan 2018 - Mar 2018
Jan 2018 - Mar 2018
Jan 2018 - Jun 2018
Jan 2018 - Jun 2018
Jan 2018 - Dec 2018
Jan 2018 - Dec 2018
Apr 2018 - Jun 2018
Apr 2018 - Jun 2018
Jul 2018 - Dec 2018
Jul 2018 - Dec 2018
Jul 2018 - Dec 2018
Jan 2019 - Dec 2019
Jan 2019 - Dec 2019
Total
Crude Oil Collars (3) :
Apr 2018 - Dec 2018
Apr 2018 - Dec 2018
Apr 2018 - Dec 2018
Apr 2018 - Dec 2018
VOLUME
(MBbls)
SHORT PUT
PRICE ($/Bbl)
LONG PUT
PRICE ($/Bbl)
SHORT CALL PRICE
($/Bbl)
300 $
300 $
600 $
1,200 $
600 $
6,000 $
900 $
600 $
2,100 $
12,600
600 $
300 $
750 $
1,500 $
600 $
2,400 $
2,400 $
600 $
1,650 $
600 $
1,200 $
1,500 $
1,800 $
1,200 $
17,100
138
275
138
274
825
42.50 $
40.00 $
37.50 $
42.50 $
45.00 $
40.00 $
37.50 $
40.00 $
40.00 $
40.00 $
42.50 $
40.00 $
40.00 $
40.00 $
40.00 $
40.00 $
40.00 $
40.00 $
40.00 $
40.00 $
40.00 $
40.00 $
40.00 $
$
$
$
$
55.00
52.50
47.50
52.50
55.00
50.00
47.50
50.00
50.00
52.50
55.00
50.00
50.00
50.00
50.00
50.00
50.00
50.00
50.00
50.00
50.00
50.00
50.00
45.00
47.00
45.00
45.00
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
62.50
62.50
62.50
60.00
62.50
74.75
74.00
77.10
65.00
76.93
76.80
76.25
80.00
81.00
60.85
59.40
60.00
64.10
When the NYMEX price is above the put price, we receive the NYMEX price. When the NYMEX price is between the put price and the short put price,
we receive the 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 put price.
Functions similarly to put spreads, except that when the index price is at or above the call price, we receive the call price
(1)
(2)
(3)
When the NYMEX price is below the put price, we receive the put price. When the NYMEX price is between the put and call prices, we receive the
NYMEX price. When the NYMEX price is above the call price, we receive the call price.
62
Description and Production Period
Crude Oil Basis Swaps (2) :
Jan 2018 - Dec 2018
Jan 2018 - Dec 2018
Jan 2018 - Dec 2018
Jan 2018 - Dec 2018
Jan 2018 - Dec 2018
Jan 2018 - Dec 2018
Jan 2018 - Dec 2018
Total
VOLUME
(MBbls)
913
182
360
183
840
600
1,080
4,158
PRICE
(0.80)
(1.30)
(0.95)
(1.00)
(0.85)
(0.50)
(1.00)
$
$
$
$
$
$
$
(2)
We receive the differential price on our crude oil basis swaps.
Description and Production Period
Natural Gas Three-Way Collars (3) :
Jan 2018 - Mar 2018
Jan 2018 - Dec 2018
Total
Natural Gas Swaps:
Jan 2018 - Mar 2018
VOLUME
(MMBtu)
SHORT PUT
PRICE ($/MMBtu)
LONG PUT
PRICE ($/MMBtu)
SHORT CALL
PRICE ($/MMBtu)
PRICE
2,400 $
3,000 $
5,400
450
2.60 $
2.75 $
3.25 $
3.00 $
4.70
3.60
$
3.50
(3)
Functions similarly to put spreads, except that when index price is at or above the call price, we receive the call price.
We will recognize the following losses in the line item (Loss) gain on derivatives on our consolidated statements of operations from net cash premiums paid
on options that will settle during the following periods (in thousands):
Q1 2018
Q2 2018
Q3 2018
Q4 2018
Q1 2019
Q2 2019
Q3 2019
Q4 2019
$
$
(18,497)
(16,598)
(18,178)
(19,438)
(5,865)
(5,865)
(1,500)
(1,500)
(87,441)
Principal
Components
of
Our
Cost
Structure
Lease
operating
expenses
. Lease operating expenses are the costs incurred in the operation of producing properties and workover costs. Expenses for direct
labor, water injection and disposal, utilities, materials and supplies comprise the most significant portion of our lease operating expenses. Lease operating expenses
do not include general and administrative expenses or production or ad valorem taxes. Certain items, such as direct labor and materials and supplies, generally
remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to
our pumping equipment or surface facilities result in increased lease operating expenses in periods during which they are performed. Certain of our operating cost
components are variable and increase or decrease as the level of produced hydrocarbons and water increases or decreases. For example, we incur power costs in
connection with various production related activities such as pumping to recover oil and natural gas and separation and treatment of water produced in connection
with our oil and natural gas production.
63
Production
and
ad
valorem
taxes
. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from production sold at
fixed rates established by federal, state or local taxing authorities. In general, the production taxes we pay year-to-year correlate to the changes in our oil, natural
gas and NGLs revenues. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the
valuation of our oil and natural gas properties.
Depletion,
depreciation
and
amortization
. DD&A is the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil and
natural gas. We use the successful efforts method of accounting for oil and natural gas activities and, as such, we capitalize all costs associated with our acquisition
and development efforts and all successful exploration efforts, which are then allocated to each unit of production using the unit of production method. Please read
“—Critical Accounting Policies and Estimates—Successful Efforts Method of Accounting for Oil and Natural Gas Activities” for further discussion.
Exploration
and
abandonment
costs.
Exploration and abandonment costs, other than exploration drilling costs, are charged to expense as incurred. These
costs include seismic expenditures and other geological and geophysical costs, exploratory dry holes, amortization and impairment of unproved leasehold costs and
lease rentals. The costs of exploratory wells and exploratory-type stratigraphic wells are initially capitalized pending a determination of whether proved reserves
have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have
been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of
proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are
expensed if a determination of proved reserves has not been made within a 12-month period after drilling is complete.
General
and
administrative
expenses
. These are costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our
office facilities, costs of managing our production and development operations (including numerous software applications), audit and other fees for professional
services and legal compliance. Also included in general and administrative expenses is stock-based compensation. See “—Factors Affecting the Comparability of
Our Financial Condition and Results of Operations.”
(Loss)
gain
on
derivatives
. We utilize commodity derivative contracts to reduce our exposure to fluctuations in the price of oil. None of our derivative
contracts are designated as hedges for accounting purposes. Consequently, our derivative contracts are marked-to-market each quarter with fair value gains and
losses recognized currently as a gain or loss in our results of operations. The amount of future gain or loss recognized on our derivative instruments is dependent
upon future oil prices, which will affect the value of the contracts. Cash flow is only impacted to the extent the actual settlements under the contracts result in
making a payment to or receiving a payment from the counterparty.
Interest
expense
. We finance a portion of our working capital requirements and capital expenditures through offerings of fixed-rate senior unsecured notes
and, in the future, could also borrow from our floating-rate Revolving Credit Agreement. As a result, we incur interest expense that is affected by our financing
decisions and, in the future, may be affected by fluctuations in interest rates. As and when applicable, we reflect interest paid to the lenders under our Revolving
Credit Agreement and to the holders of our senior unsecured notes in interest expense.
Impairment
of
Oil
and
Gas
Properties
Proved oil and gas properties are reviewed for impairment quarterly or when events and circumstances indicate a possible decline in the recoverability of the
carrying amount of such property. We estimate the expected future cash flows of our oil and gas properties and compare the undiscounted cash flows to the
carrying amount of the oil and gas properties, on a field-by-field basis, to determine if the carrying amount is recoverable. If the carrying amount exceeds the
estimated undiscounted future cash flows, we will write down the carrying amount of the oil and gas properties to estimated fair value.
Given the level of commodity prices in recent years and their impact on our estimated future cash flows, we regularly review our proved oil and natural gas
properties for impairment. During the years ended December 31, 2017 and 2016, we did not recognize an impairment of our proved oil and natural gas properties,
and during the year ended December 31, 2015, we recognized an impairment of $1.0 million of our proved oil and natural gas properties. At December 31, 2017 ,
in our significant fields that comprise 100% of our carrying value, our expected undiscounted future cash flows exceeded the carrying value of our proved oil and
gas properties by an average of 83% and individually by a minimum of 66%. At December 31, 2016 , in our significant fields that comprise 100% of our carrying
value, our expected undiscounted future cash flows exceeded the carrying value of our proved oil and gas properties by an average of 143% and individually by a
minimum of 70%.
64
The key assumptions used to determine the undiscounted future cash flows include, but are not limited to, future commodity prices, based on five-year WTI
futures price index for oil and NGLs and five-year Henry Hub futures price index for natural gas, price differentials, future production estimates, estimated future
capital expenditures and estimated future operating expenses. All inputs remained relatively consistent in the undiscounted future cash flow estimate from
December 31, 2016 to December 31, 2017 , except commodity price estimates. Future commodity pricing for oil and NGLs is based on five-year WTI futures
prices, which increased from December 31, 2016 to December 31, 2017 and on five-year Henry Hub futures prices, which decreased from December 31, 2016 to
December 31, 2017 . In terms of the reduction in value of undiscounted cash flows from December 31, 2016 to December 31, 2017 , the effect of the decrease in
pricing has been mitigated to a certain extent by the addition of both proved developed and proved undeveloped reserves through our continued drilling and
completion of previously unproved oil and natural gas properties.
As part of our year-end reserves estimation process for future periods, we expect changes in the key assumptions used, which could be significant, including
updates to future pricing estimates or differentials, future production estimates to align with our anticipated five-year drilling plan and changes in our capital costs
and operating expense assumptions, which we expect to decrease further as a result of sustained lower commodity prices. There is a significant degree of
uncertainty with the assumptions used to estimate future undiscounted cash flows due to, but not limited to, the risk factors referred to in “Item 1A. Risk Factors”
included elsewhere in this Annual Report.
Any decrease in pricing, negative change in price differentials or increase in capital or operating costs could negatively impact the estimated undiscounted
cash flows related to our proved oil and natural gas properties. A decrease of 10% in estimated future pricing of oil and natural gas commodities as of
December 31, 2017 , however, would have not have resulted in an impairment of proved oil and gas properties.
Factors Affecting the Comparability of Our Financial Condition and Results of Operations
Our historical financial condition and results of operations for the periods presented may not be comparable, either from period to period or going forward,
for the following reasons:
Recent
Transactions
Double Eagle Acquisition
On April 20, 2017, we, and our subsidiary, Parsley LLC, completed the acquisition (the “Double Eagle Acquisition”) of all of the interests in Double Eagle
Lone Star LLC, DE Operating LLC, and Veritas Energy Partners, LLC (which were subsequently renamed Parsley DE Lone Star LLC, Parsley DE Operating LLC,
and Parsley Veritas Energy Partners, LLC, respectively) from Double Eagle Energy Permian Operating LLC (“DE Operating”), Double Eagle Energy Permian
LLC (“DE Permian”), and Double Eagle Energy Permian Member LLC (together with DE Operating and DE Permian, “Double Eagle”), as well as certain related
transactions with an affiliate of Double Eagle. The aggregate purchase price for the Double Eagle Acquisition consisted of approximately (i) $1,395.6 million in
cash and (ii) 39,848,518 PE Units and a corresponding 39,848,518 shares of Class B Common Stock. The Double Eagle Acquisition is discussed in further detail in
Note 5—Acquisitions of Oil and Natural Gas Properties to our consolidated financial statements included elsewhere in this Annual Report .
5.625% Senior Unsecured Notes due 2027
On October 11, 2017, Parsley LLC and Finance Corp. issued $700.0 million aggregate principal amount of the 2027 Notes in the 2027 Notes Offering. The
2027 Notes Offering resulted in net proceeds to us, after deducting the initial purchasers’ discount and offering expenses, of approximately $692.1 million . These
net proceeds are being used to fund a portion of our capital program and for general corporate purposes.
Fifth Amendment to Revolving Credit Facility
On October 11, 2017, the Company, Parsley LLC, each of the guarantors thereto, Wells Fargo Bank, National Association, as administrative agent, and the
other lenders party thereto entered into the Fifth Amendment to the Revolving Credit Agreement. The Fifth Amendment, among other things, modified the terms of
the Revolving Credit Agreement to (i) increase the borrowing base from $1.225 billion (to which it was reduced in connection with the closing of the 2027 Notes
Offering) to $1.8 billion (although the aggregate elected commitments remained at $1.0 billion), (ii) decrease the applicable margins for borrowings to a range of
(A) 1.5% to 2.5% for LIBOR based borrowings and (B) 0.5% to 1.5% for alternative base rate based borrowings, with the specific applicable margins determined
by reference to borrowing base utilization, (iii) provide
65
flexibility, subject to certain conditions, to enter into “reverse 1031 exchanges” under Section 1031 of the Internal Revenue Code of 1986, as amended, (iv) provide
enhanced flexibility, subject to certain dollar limitations, to make investments in unrestricted subsidiaries and joint ventures and to make other investments, and (v)
provide enhanced flexibility, subject to certain conditions, to dispose of oil and gas properties not evaluated in the reserve reports delivered to the lenders pursuant
to the Revolving Credit Agreement.
CEO Succession Plan
On January 9, 2018, we announced a succession plan pursuant to which our current Chairman and Chief Executive Officer, Bryan Sheffield, will serve as
Chief Executive Officer through the end of 2018, in the newly-created position of Executive Chairman throughout 2019, and as Chairman of the Board thereafter.
Matt Gallagher, our President and Chief Operating Officer, will succeed Mr. Sheffield as Chief Executive Officer, effective January 1, 2019, and was appointed to
our board of directors concurrent with the announcement.
Income
Taxes
On December 22, 2017, the Tax Act was enacted by the U.S. government. The Tax Act significantly impacts our 2017 effective tax rate and makes broad
and complex changes to the U.S. corporate income tax code. Among other changes, the Tax Act: (i) reduces the U.S. federal corporate income tax rate from 35% to
21%; (ii) repeals the corporate alternative minimum tax and provides for a refund of previously accrued alternative minimum tax credits; (iii) modifies the
provisions relating to the limitations on deductions for executive compensation of publicly traded corporations; (iv) enacts new limitations regarding the
deductibility of interest expense; and (v) imposes new limitations on the utilization of net operating losses arising in taxable years beginning after December 31,
2017.
GAAP requires that the impact of tax legislation be recognized in the period in which the law was enacted. As a result of the Tax Act, we remeasured our
deferred tax assets and liabilities based on the federal income and state income tax rates at which they are now expected to reverse, and they now generally reflect a
federal income tax rate of 21%. The enacted rate change resulted in a noncash increase of approximately $23.9 million to our income tax provision, a
corresponding reduction of $23.9 million to our net noncurrent deferred tax asset balance and a reduction in valuation allowance of $24.3 million December 31,
2017 . As of December 31, 2017 , we have not finalized our accounting for the tax effect of the Tax Act. However, as described in Note 10—Income Taxes in the
notes to our consolidated financial statements, we have made a reasonable estimate of the tax effect of the Tax Act, including the impact on existing deferred tax
balances. Any adjustments recorded to these estimates through 2018 will be included in income from operations as an adjustment to tax expense. The ultimate
impact of the Tax Act may differ from our estimates based on our further analysis of the new law and additional regulatory guidance that may be issued. Further,
the amount of our future federal income tax will be dependent upon our future taxable income.
Our operations located in Texas are subject to an entity-level tax, the Texas margin tax, at a statutory rate of up to 0.75% of revenues less operating
expenses attributable to operations in Texas.
Capital
Expenditures
Our drilling, completions and infrastructure activities are capital intensive and require us to make substantial capital expenditures, which vary from year to
year. For further information about our capital expenditures, see “Item 1. Business—Overview” and “—Capital Requirements and Sources of Liquidity.”
The amount and timing of our future capital expenditures is largely discretionary and within our control. We could choose to defer a portion of planned
capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing and anticipated prices for oil
and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal
conditions, drilling and acquisition costs and the level of participation by other working interest owners.
66
Results of Operations
Revenues
The following table provides the components of our production revenues for the periods indicated, as well as each period’s respective average prices and
production volumes:
Production revenues (in thousands):
Oil sales
Natural gas sales
Natural gas liquids sales
Total revenues
Average realized prices (1) :
Oil, without realized derivatives (per Bbls)
Oil, with realized derivatives (per Bbls)
Natural gas, without realized derivatives (per Mcf)
Natural gas, with realized derivatives (per Mcf)
Natural gas liquids (per Bbls)
Average price per Boe, without realized derivatives
Average price per Boe, with realized derivatives
Production:
Oil (MBbls)
Natural gas (MMcf)
Natural gas liquids (MBbls)
Total (MBoe)
Average daily production volume:
Oil (Bbls)
Natural gas (Mcf)
Natural gas liquids (Bbls)
Total (Boe)
Year Ended December 31,
2017
2016
2015
$
802,230 $
387,303 $
56,571
103,193
30,928
38,273
$
961,994 $
456,504 $
215,795
26,582
23,680
266,057
$
48.95 $
41.34 $
47.68
2.43
2.40
22.87
38.80
37.94
16,390
23,326
4,512
24,792
44,904
63,907
12,362
67,923
47.56
2.30
2.30
16.01
32.60
36.76
9,368
13,463
2,390
14,002
25,596
36,784
6,530
38,257
44.89
56.60
2.57
2.72
15.79
33.13
40.33
4,807
10,339
1,500
8,031
13,170
28,326
4,110
22,003
(1) 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.
The table below shows, for the periods indicated, the relationship between our average realized oil price as a percentage of the average NYMEX oil price,
the relationship between our average realized natural gas price as a percentage of the average NYMEX gas price, and the relationship between our average realized
NGLs price as a percentage of the average NYMEX oil price. Management uses the realized price to NYMEX margin analysis to analyze trends in our oil, natural
gas and NGLs revenues. Realized oil, natural gas and NGLs prices are the actual prices realized at the wellhead adjusted for quality, transportation fees and costs,
differentials, marketing premiums or deductions and other factors that affect the price received at the wellhead.
67
Average realized oil price ($/Bbl)
Average NYMEX ($/Bbl)
Differential to NYMEX
Average realized oil price as a percentage of average NYMEX oil price
Average realized natural gas price ($/Mcf)
Average NYMEX ($/Mcf)
Differential to NYMEX
Average realized natural gas price as a percentage of average NYMEX gas price
Average realized NGLs price ($/Bbl)
Average NYMEX ($/Bbl)
Differential to NYMEX
Average realized NGLs price as a percentage of average NYMEX oil price
Year Ended December 31,
2017
2016
2015
48.95
51.48
(2.53)
$
$
$
95%
2.43
2.99
(0.56)
$
$
$
81%
22.87
51.48
(28.61)
$
$
$
44%
41.34
40.14
1.20
$
$
$
103%
2.30
2.79
(0.49)
$
$
$
82%
16.01
40.14
(24.13)
$
$
$
40%
44.89
48.08
(3.19)
93%
2.57
2.50
0.07
103%
15.79
48.08
(32.29)
33%
$
$
$
$
$
$
$
$
$
Oil, natural gas and NGLs revenues. Our oil, natural gas and NGLs revenues totaled $962.0 million , $456.5 million and $266.1 million during the years
ended December 31, 2017 , 2016 and 2015 , respectively.
Our oil, natural gas and NGLs revenues increased by $505.5 million , or 111% , to $962.0 million for the year ended December 31, 2017 from $456.5
million for the year ended December 31, 2016 .
As shown in the following tables, from the year ended December 31, 2016 to the year ended December 31, 2017 , the net dollar effect of the increase in oil,
natural gas, and NGLs prices was $158.5 million and the net dollar effect of the increase in production volumes of oil, natural gas and NGLs was $347.0 million .
Effect of change in price:
Oil (per Bbls)
Natural gas (per Mcf)
Natural gas liquids (per Bbls)
Total revenues due to change in price
Effect of change in production volumes:
Oil (MBbls)
Natural gas (MMcf)
Natural gas liquids (MBbls)
Total revenues due to change in production volumes
Change in prices
Production volumes
Total net dollar effect of change
(in thousands)
(in thousands)
$
7.61
0.13
6.86
16,390 $
23,326
4,512
$
124,615
2,983
30,939
158,537
Change in production
volumes
(in thousands)
Prior period average prices
Total net dollar effect of change
(in thousands)
7,022 $
9,863
2,122
41.34 $
2.30
16.01
$
290,312
22,660
33,981
346,953
68
Our oil, natural gas and NGLs revenues increased by $190.4 million , or 72% , to $456.5 million for the year ended December 31, 2016 from $266.1 million
for the year ended December 31, 2015 .
As shown in the following tables, from the year ended December 31, 2015 to the year ended December 31, 2016 , the net dollar effect of the decrease in oil
and natural gas prices and increase in NGLs prices was $36.4 million and the net dollar effect of the increase in production volumes of oil, natural gas and NGLs
was approximately $226.8 million .
Effect of change in price:
Oil (per Bbls)
Natural gas (per MMcf)
Natural gas liquids (per Bbls)
Total revenues due to change in price
Effect of change in production volumes:
Oil (MBbls)
Natural gas (MMcf)
Natural gas liquids (MBbls)
Total revenues due to change in production volumes
Change in prices
Production volumes
Total net dollar effect of change
(in thousands)
(in thousands)
$
(3.55)
(0.27)
0.22
9,368 $
13,463
2,390
$
(33,243)
(3,686)
543
(36,386)
Change in production
volumes
(in thousands)
Prior period average prices
Total net dollar effect of change
(in thousands)
4,561 $
3,124
890
44.89 $
2.57
15.79
$
204,751
8,032
14,050
226,833
69
Operating
expenses
The following table summarizes our operating expenses for the periods indicated:
Operating expenses (in thousands) :
Lease operating expenses
Production and ad valorem taxes
Depreciation, depletion and amortization
General and administrative expenses (1)
Exploration and abandonment costs
Impairment
Acquisition costs
Accretion of asset retirement obligations
Rig termination costs
Other operating expenses
Total operating expenses
Operating expenses per Boe:
Lease operating expenses
Production and ad valorem taxes
Depreciation, depletion and amortization
General and administrative expenses
Exploration and abandonment costs
Impairment
Acquisition costs
Accretion of asset retirement obligations
Rig termination costs
Other operating expenses
Total operating expenses per Boe
Year ended December 31,
2017
2016
2015
$
102,169 $
59,293 $
59,641
352,247
124,255
40,415
—
10,977
971
—
9,568
27,916
233,766
84,591
13,931
—
1,081
732
—
5,316
62,913
17,800
178,281
55,294
13,865
950
—
826
8,970
1,696
$
700,243 $
426,626 $
340,595
$
4.12 $
4.23 $
2.41
14.21
5.01
1.63
—
0.44
0.04
—
0.39
1.99
16.70
6.04
0.99
—
0.08
0.05
—
0.38
7.83
2.22
22.20
6.89
1.73
0.12
—
0.10
1.12
0.21
$
28.25 $
30.46 $
42.42
(1)
General and administrative expenses include stock-based compensation expense of $19.7 million, $12.9 million and $8.1 million for the years ended
December 31, 2017, 2016 and 2015, respectively.
Lease operating expenses . Lease operating expenses increased 72% to $102.2 million during the year ended December 31, 2017 from $59.3 million during
the year ended December 31, 2016 . The increase is primarily due to the increase in the number of our operated and non-operated wells during 2017. On a per Boe
basis, lease operating expenses decreased $0.11 per Boe, or 3% , to $4.12 per Boe for the year ended December 31, 2017 from $4.23 per Boe for the year ended
December 31, 2016 . The decrease in lease operating expenses per Boe is partially attributable to a greater portion of our production coming from horizontal wells.
The decrease in lease operating expense per Boe is also partially attributable to a 77% increase in production during the same period.
Lease operating expenses decreased 6% to $59.3 million during the year ended December 31, 2016 from $62.9 million during the year ended December 31,
2015. The decrease is primarily due to the cost reduction initiatives implemented by management. On a per Boe basis, lease operating expenses decreased $3.60
per Boe, or 46%, to $4.23 per Boe for the year ended December 31, 2016 from $7.83 per Boe for the year ended December 31, 2015. The decrease in lease
operating expenses per Boe is partially attributable to a greater portion of our production coming from horizontal wells. The decrease in lease operating expense
per Boe is also partially attributable to a 74% increase in production during the same period.
Production and ad valorem taxes . Production and ad valorem taxes increased 114% to $59.6 million during the year ended December 31, 2017 from $27.9
million during the year ended December 31, 2016 . On a per Boe basis, production and ad valorem taxes increased 21% to $2.41 per Boe for the year ended
December 31, 2017 from $1.99 per Boe for the year ended
70
December 31, 2016 . Overall, production taxes increased by approximately $26.0 million, reflecting increased production volumes, and ad valorem taxes increased
$5.7 million, reflecting increased property assessments.
Production and ad valorem taxes increased 57% to $27.9 million during the year ended December 31, 2016 from $17.8 million during the year ended
December 31, 2015. On a per Boe basis, production and ad valorem taxes decreased 10%, to $1.99 per Boe for the year ended December 31, 2016 from $2.22 per
Boe for the year ended December 31, 2015. Overall, production taxes increased by approximately $9.4 million, reflecting increased production volumes, and ad
valorem taxes increased $0.7 million, reflecting increased property assessments.
Depreciation, depletion and amortization . DD&A expense increased 51% to $352.2 million for the year ended December 31, 2017 from $233.8 million for
the year ended December 31, 2016 . On a per Boe basis, DD&A decreased 15% to $14.21 for the year ended December 31, 2017 from $16.70 per Boe for the year
ended December 31, 2016 . The increases are due to an increase in proved capitalized costs primarily related to development costs incurred during the year ended
December 31, 2017 , as well as increased production.
DD&A expense increased 31% to $233.8 million for the year ended December 31, 2016 from $178.3 million for the year ended December 31, 2015. On a
per Boe basis, DD&A decreased 25% to $16.70 for the year ended December 31, 2016 from $22.20 per Boe for the year ended December 31, 2015. The increases
are due to an increase in proved capitalized costs primarily related to development costs incurred during the year ended December 31, 2016, as well as increased
production.
General and administrative expenses . General and administrative expenses increased 47% to $124.3 million during the year ended December 31, 2017
from $84.6 million during the year ended December 31, 2016 , primarily as a function of personnel growth associated with increased development activity on an
expanded asset base. On a per Boe basis, general and administrative expenses decreased 17% to $5.01 per Boe for the year ended December 31, 2017 from $6.04
per Boe for the year ended December 31, 2016 , which primarily relates to the 77% increase in total production volume.
General and administrative expenses increased 53% to $84.6 million during the year ended December 31, 2016 from $55.3 million during the year ended
December 31, 2015, primarily due to higher payroll and stock-based compensation expenses. On a per Boe basis, general and administrative expenses decreased
12% to $6.04 per Boe for the year ended December 31, 2016 from $6.89 per Boe for the year ended December 31, 2015, which primarily relates to the 74%
increase in total production volume.
Exploration and abandonment costs . The following table provides a breakdown of exploration and abandonment costs incurred during the periods indicated
(in thousands):
Leasehold abandonments
Geological and geophysical costs
Idle drilling rig fees
Unproved leasehold amortization
Total exploration and abandonment costs
Year Ended December 31,
2017
2016
2015
32,872 $
6,063 $
5,429
1,070
1,044
3,015
4,304
549
8,227
5,459
—
179
40,415 $
13,931 $
13,865
$
$
During the years ended December 31, 2017 and 2016, we recognized leasehold abandonment expenses of approximately $32.9 million and $6.1 million ,
respectively, which primarily relates to expired acreage and expiring acreage determined to be outside of our economically productive reserves. During the year
ended December 31, 2015, we recognized leasehold abandonment expenses of approximately $8.2 million , of which $6.4 million primarily relates to expired
acreage and expiring acreage determined to be outside of our economically productive reserves. We also recognized a $1.8 million expense in the year ended
December 31, 2015 for costs incurred to prepare certain locations for drilling that, based on our historical results, our estimates of reduced future commodity
prices, and low rates of return, we determined were not economical to develop.
During the years ended December 31, 2017, 2016 and 2015, we incurred geological and geophysical expenses of approximately $5.4 million , $3.0 million
and $5.5 million , respectively. Our geological and geophysical expenses consist of the costs of acquiring and processing seismic data, geophysical data and core
analysis, primarily relating to increased geoscientific analysis of our acreage.
Exploration and abandonment costs include idle drilling rig fees of $1.1 million and $4.3 million that are not chargeable to our joint operations during the
years ended December 31, 2017 and 2016, respectively. The applicable drilling rig contract
71
expired on March 31, 2017, resulting in a decrease in idle drilling rig fees during the year ended December 31, 2017 compared to the year ended December 31,
2016. There were no such expenses incurred during the year ended December 31, 2015.
We recognized unproved leasehold amortization expense during the years ended December 31, 2017, 2016 and 2015 of $1.0 million , $0.5 million and $0.2
million , respectively, which relates to amortization of unproved leasehold costs.
Impairment. We regularly review our long-lived assets to be held and used, including proved oil and natural gas properties accounted for under the
successful efforts method of accounting. Due primarily to a decrease in our estimated future cash flows related to management’s outlook of future commodity
prices and costs as of December 31, 2015, we recognized a charge against earnings of $1.0 million during the year ended December 31, 2015, which was primarily
attributable to properties in Upton County, Texas in our Midland Basin core area. There were no such costs incurred during the years ended December 31, 2017 or
2016.
Acquisition Costs . During the years ended December 31, 2017 and 2016, we incurred $11.0 million and $1.1 million , respectively, of acquisition costs,
which include legal and other due diligence fees associated with the acquisitions described in Note 5—Acquisitions of Oil and Natural Gas Properties to our
consolidated financial statements included elsewhere in this Annual Report. There were no such costs incurred during the year ended December 31, 2015.
Rig Termination . During the year ended December 31, 2015, we paid a total of $9.0 million in rig termination expenses, which is comprised of
approximately $4.4 million related to the termination of drilling rig contracts entered into in 2014 and approximately $4.6 million for stacking fees associated with
certain drilling rig contracts. There were no such expenses incurred during the years ended December 31, 2017 or 2016.
Other operating expenses. During the years ended December 31, 2017 , 2016 and 2015, other operating expenses, which are primarily related to operating
expenses incurred during the normal course of business of our majority-owned subsidiary, Pacesetter, were $9.6 million , $5.3 million , and $1.7 million ,
respectively.
Other
income
(expense)
The following table summarizes our other income and expenses for the periods indicated (in thousands):
Other income (expense):
Interest expense, net
Loss on sale of property
Loss on early extinguishment of debt
(Loss) gain on derivatives
Change in TRA liability
Interest income
Other income (expense)
Total other expense, net
Year ended December 31,
2017
2016
2015
$
(97,381) $
(56,225) $
(14,332)
(3,891)
(66,135)
35,847
7,936
783
(119)
(36,335)
(50,835)
7,351
992
(2,317)
$
(137,173) $
(137,488) $
7,936
(45,581)
(34,374)
—
60,818
—
28
(3,556)
(22,665)
Interest expense . Interest expense increased 73% to $97.4 million in the year ended December 31, 2017 from $56.2 million during the year ended
December 31, 2016 , primarily due to interest under our 6.250% senior unsecured notes due 2024 (the “2024 Notes”), 5.375% senior unsecured notes due 2025 (the
“2025 Notes”), 5.250% senior unsecured notes due 2025 (the “New 2025 Notes”), and the 2027 Notes.
Interest expense increased 23% to $56.2 million in the year ended December 31, 2016 from $45.6 million during the year ended December 31, 2015,
primarily due to higher weighted-average outstanding borrowings under our credit facilities and interest under our then outstanding 7.500% senior unsecured notes
due 2022 (the “2022 Notes”) and the 2024 Notes, partially offset by our repayment of borrowings outstanding under our Revolving Credit Agreement in September
2015.
Loss on sale of property. Loss on sale of property increased $14.2 million in the year ended December 31, 2017 to $14.3 million from $0.1 million during
the year ended December 31, 2016 . This increase is attributable to our divestiture of 21,939 gross ( 7,476 net) acres for total proceeds of $30.5 million, for which
we recognized a $14.3 million loss.
72
Loss on sale of property decreased $34.3 million in the year ended December 31, 2016 to $0.1 million from $34.4 million during the year ended December
31, 2015 . This decrease is attributable to the following divestiture activity:
During December 2015, we sold our interest in 91 net operated wells and 11,664 gross (7,155 net) acres for net proceeds of $39.4 million and realized a
$36.7 million loss, net of estimated purchase price adjustments. During July 2015, we sold 13,413 gross (9,164 net) acres for total proceeds of $9.3 million and
recognized a gain on the sale of $3.2 million. In addition, during July 2015, Pacesetter sold certain noncurrent assets for net proceeds of $1.2 million and realized a
$2.0 million loss on the sale.
Loss on early extinguishment of debt . We recorded a $3.9 million loss on early extinguishment of debt during the year ended December 31, 2017 due to the
redemption of the 2022 Notes. During December 2016, we incurred a $36.3 million charge related to a prepayment penalty on our then outstanding 2022 Notes. No
similar expenses were incurred during the year ended December 31, 2015.
(Loss) gain on derivatives . Loss on derivatives increased $15.3 million to a loss of $66.1 million during the year ended December 31, 2017 as compared to
a $50.8 million loss during the year ended December 31, 2016 , as higher commodity prices reduced the value of our derivative portfolio.
Loss on derivatives increased $111.7 million to a loss of $50.8 million during the year ended December 31, 2016 as compared to a $60.8 million gain during
the year ended December 31, 2015 as higher commodity prices reduced the value of our derivative portfolio.
Change in TRA liability. We recorded income of $35.8 million during the year ended December 31, 2017 associated with a net decrease in the TRA liability
associated with a write off of deferred tax assets associated with the TRA. This write off primarily results from the change in corporate tax rates from 35% to 21%
offset by a decrease in the valuation allowance recorded during 2016. We recorded a $7.4 million deferred tax asset valuation allowance associated with a write off
of deferred tax assets associated with the TRA during the year ended December 31, 2016. There was no such activity for the year ended December 31, 2015.
Interest income. Interest income increased $6.9 million to $7.9 million during the year ended December 31, 2017 as compared to $1.0 million during the
year ended December 31, 2016 , which is a function of interest income received on larger investments in commercial paper and money market funds, which are
included in cash and cash equivalents and short-term investments on our consolidated balance sheet.
Interest income of $1.0 million during the year ended December 31, 2016 represented an increase of $1.0 million relative to interest income during the year
ended December 31, 2015, during which time we held no investments in commercial paper or money market funds.
Other income (expense) . Other income (expense) increased $3.1 million to income of $0.8 million during the year ended December 31, 2017 as compared
to an expense of $2.3 million during the year ended December 31, 2016 . The increase is attributable a $1.4 million increase in income from our equity investment
in Spraberry Production Services LLC (“SPS”), a $0.8 million increase in in geological and geophysical license fee income and a $0.4 million increase in fair value
adjustments associated with money market accounts, which was offset by a current period downward fair market value adjustment of $1.1 million. Additionally,
during the year ended December 31, 2016, we recorded expense of $1.6 million associated with the sale or auction of certain inventory items.
Other expense decreased $1.2 million to an expense of $2.3 million during the year ended December 31, 2016 as compared to an expense of $3.6 million
during the year ended December 31, 2015. The decrease is attributable to a $2.8 million expense associated with the sale or fair market value adjustment of
inventory. This was offset by a $1.2 million decrease in geological and geophysical license fee income and a $0.4 million decrease in income from our equity
investment in SPS.
Income Tax Expense
For the years ended December 31, 2017 , 2016 and 2015 , our operations were taxed at a combined U.S. federal and state effective tax rate of 4.4%, 16.4%
and 24.5%, respectively. During the year ended December 31, 2017 , we recognized an income tax expense of $5.7 million , an increase of $23.1 million , or
133% , as compared to the income tax benefit of $17.4 million we recognized during the year ended December 31, 2016 . These changes were attributable to the
changes in our results
73
of operations, discussed above, as well as the impact of net income attributable to noncontrolling ownership interests, the impact of state income taxes, reduction in
TRA liability due the change in corporate tax rates from 35% to 21%, and the partial reversal of a valuation allowance that was recorded in 2016 described in Note
10—Income Taxes to our consolidated financial statements included elsewhere in this Annual Report. During the year ended December 31, 2016, we recognized
an income tax benefit of $17.4 million , a decrease of $6.3 million , or 27% , as compared to the income tax benefit of $23.8 million we recognized during the year
ended December 31, 2015. This decrease was attributable to the deferred tax asset valuation allowance described in Note 10—Income Taxes to our consolidated
financial statements included elsewhere in this Annual Report.
Capital Requirements and Sources of Liquidity
The following table sets forth our capital expenditures for drilling, completions and infrastructure for the periods indicated (in thousands):
Capital expenditures
Year Ended December 31,
2017
1,207,401 $
2016
495,971
$
Our 2018 budget for capital development expenditures is approximately $1,350.0 million to $1,550.0 million , 85% to 90% of which is expected to be used
for drilling and completions and 10% to 15% of which is expected to be used for infrastructure and other expenditures. We expect approximately 20% of the total
budget to be associated with drilling and completions for proved undeveloped reserves as of December 31, 2017 . Our capital budget excludes any amounts that
may be paid for acquisitions. For the years ended December 31, 2017 and 2016, our aggregate drilling and completion expenditures were $1,049.6 million and
$401.6 million , respectively, and our infrastructure and other expenditures were $157.8 million and $94.4 million , respectively, for totals of $1,207.4 million and
$496.0 million , respectively. Of these totals, $65.1 million and $53.2 million were associated with drilling, completion and facility buildout for proved
undeveloped reserves for the years ended December 31, 2017 and 2016, respectively. The amount and timing of 2018 capital expenditures is largely discretionary
and within our control. We could choose to defer a portion of these planned 2018 capital expenditures depending on a variety of factors, including, but not limited
to, the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital,
the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other
working interest owners.
To fund a portion of our capital requirements for the year ended December 31, 2017 , we issued shares of our Class A Common Stock and conducted
offerings of senior unsecured notes. During the year ended December 31, 2017 , we received aggregate net proceeds of $2,123.3 million from these equity
issuances and issued aggregate net debt in excess of debt payments of $1,060.6 million .
Based upon current oil and natural gas price expectations for fiscal year 2018 , we believe that our cash on hand, cash flow from operations and borrowings
under our Revolving Credit Agreement will be sufficient to fund our operations through 2018 . However, as more fully described below, future cash flows are
subject to a number of variables, including the level of our oil and natural gas production and prices, and the significant capital expenditures required to more fully
develop our properties. As of December 31, 2017 , our liquidity is as follows (in millions):
Cash and cash equivalents
Short-term investments
Revolving Credit Agreement Availability
Liquidity
$
$
554.2
149.3
997.3
1,700.8
Future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and the significant capital
expenditures required to more fully develop our properties. For example, we expect a portion of our future capital expenditures to be financed with cash flows from
operations derived from wells drilled in drilling locations not associated with proved reserves on our December 31, 2017 reserve report. The failure to achieve
anticipated production and cash flows from operations from such wells could result in a reduction in future capital spending. Further, our capital expenditure
budget for the year ended December 31, 2018 does not allocate any amounts for acquisitions of oil and natural gas properties. In the event we make additional
acquisitions and the amount of capital required is greater than the amount we have available for acquisitions at that time, we could be required to reduce the
expected level of capital expenditures and/or seek additional capital. If we require additional capital for that or other reasons, we may seek such capital through
traditional reserve
74
base borrowings, joint venture partnerships, production payment financings, asset sales, offerings of debt or equity securities or other means. We cannot assure you
that needed capital will be available on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may be required to
curtail our current drilling programs, which could result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that
may be favorable to us or finance the capital expenditures necessary to replace our reserves. We may from time to time seek to retire or purchase our outstanding
debt through cash purchases and/or exchanges for other debt or equity securities, in open market purchases, privately negotiated transactions or otherwise. Such
repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts
involved may be material.
Cash Flows
The following table summarizes our cash flows for the periods indicated (in thousands):
Net cash provided by operating activities
Net cash used in investing activities
Net cash provided by financing activities
Year Ended December 31,
2017
2016
2015
$
694,040 $
228,191 $
(3,456,860)
3,183,630
(1,885,366)
1,447,470
172,290
(427,165)
547,409
Cash flows provided by operating activities . Net cash provided by operating activities was approximately $694.0 million , $228.2 million and $172.3
million for the years ended December 31, 2017 , 2016 and 2015 , respectively.
Net cash provided by operating activities increased $465.8 million to $694.0 million during the year ended December 31, 2017 from $228.2 million during
the year ended December 31, 2016 , primarily due to a $509.3 million increase in total revenues, offset by a $387.6 million increase cash based operating expenses,
including lease operating expenses, production and ad valorem taxes, cash general and administrative expenses and acquisition costs.
Net cash provided by operating activities increased $55.9 million to $228.2 million during the year ended December 31, 2016 from $172.3 million during
the year ended December 31, 2015, largely due to a $36.3 million increase in total cash based operating expense, which includes lease operating expenses,
production and ad valorem taxes, general and administrative expenses (excluding stock-based compensation) and other operating expenses, offset by an increase in
production revenues directly related to the 74% increase in total production volumes. Additionally, cash received for derivative settlements and cash received for
option premiums decreased $62.4 million for the year ended December 31, 2016 from the year ended December 31, 2015.
Cash flows used in investing activities . Net cash used in investing activities was approximately $3.5 billion , $1.9 billion and $0.4 billion for the years
ended December 31, 2017 , 2016 and 2015 , respectively.
The increased amount of cash used in investing activities in the year ended December 31, 2017 as compared to the year ended December 31, 2016 was due
primarily to the $845.9 million increase in costs to acquire certain oil and gas properties and the $583.5 million increase in development costs during the year
ended December 31, 2017 .
The increased amount of cash used in investing activities in the year ended December 31, 2016 as compared to the year ended December 31, 2015 was due
to the $1.3 billion increase in costs to acquire certain oil and natural gas properties.
Cash flows provided by financing activities . Net cash provided by financing activities was approximately $3.2 billion , $1.4 billion and $0.5 billion for the
years ended December 31, 2017 , 2016 and 2015 , respectively.
Net cash provided by financing activities increased by $1.7 billion during the year ended December 31, 2017 , primarily due to increased debt and equity
related activity. During the year ended December 31, 2017 , we received net proceeds from equity offerings of $2.1 billion and net proceeds from debt offerings of
$1.1 billion , which was offset by payments on long-term debt of $74.8 million , excluding accrued and unpaid interest.
Net cash provided by financing activities increased during the year ended December 31, 2016, primarily due to increased debt and equity related activity.
During the year ended December 31, 2016 , we received net proceeds from equity offerings of $930.3 million and net proceeds from debt offerings of $1.0 billion ,
which was offset by payments on long-term debt of $521.9 million , excluding accrued and unpaid interest.
75
Capital
Sources
Revolving Credit Agreement. See Note 7—Debt to our consolidated financial statements included elsewhere in this Annual Report for a description of the
Revolving Credit Agreement.
7.500% Senior Unsecured Notes due 2022. See Note 7—Debt to our consolidated financial statements included elsewhere in this Annual Report for a
description of the previously outstanding 2022 Notes.
6.250% Senior Unsecured Notes due 2024. See Note 7—Debt to our consolidated financial statements included elsewhere in this Annual Report for
information regarding the 2024 Notes.
5.375% Senior Unsecured Notes due 2025. See Note 7—Debt to our consolidated financial statements included elsewhere in this Annual Report for
information regarding the 2025 Notes.
5.250% Senior Unsecured Notes due 2025 . See Note 7 —Debt to our consolidated financial statements included elsewhere in this Annual Report for
information regarding the New 2025 Notes.
5.625% Senior Unsecured Notes due 2027 . See Note 7 —Debt to our consolidated financial statements included elsewhere in this Annual Report for
information regarding the 2027 Notes.
Derivative Activity. We plan to continue our practice of entering into hedging arrangements to reduce the impact of commodity price volatility on our cash
flow from operations. Under this strategy, we intend to continue our historical practice of entering into commodity derivative contracts at times and on terms
desired to maintain a portfolio of commodity derivative contracts covering a portion of our projected oil production.
Working Capital. Our working capital totaled $307.4 million , ($45.5) million and $259.8 million at December 31, 2017 , 2016 and 2015 , respectively. Our
collection of receivables has historically been timely and losses associated with uncollectible receivables have historically not been significant. Our cash and cash
equivalents and short-term investments totaled $703.5 million , $133.4 million and $343.1 million at December 31, 2017 , 2016 and 2015 , respectively. The
$570.1 million increase in cash and cash equivalents and short-term investments is attributable to our increased debt and equity offering activity as described in
Note 7—Debt to our consolidated financial statements included elsewhere in this Annual Report, offset by the $2.2 billion in costs to acquire certain oil and gas
properties described in Note 5—Acquisition of Oil and Natural Gas Properties . Due to the amounts that we accrue related to our drilling program, we may incur
working capital deficits in the future. We believe that our cash on hand, cash flow from operations and availability under our Revolving Credit Agreement, will be
sufficient to fund our working capital needs. We expect that our pace of development, production volumes, commodity prices and differentials to NYMEX prices
for our oil and natural gas production will be the largest variables affecting our working capital.
Contractual Obligations
Our contractual obligations include long-term debt, cash interest expense on debt, operating lease obligations, drilling commitments, derivative liabilities
and other obligations. Firm transportation commitments are not included in the table below because we anticipate satisfying all volume requirements in accordance
with the firm transportation and processing agreement we entered into during the year ended December 31, 2017. See Note 12—Commitments and Contingencies
for a description of our firm transportation and processing agreements.
76
We had the following contractual obligations at December 31, 2017 :
Revolving Credit Agreement (1)
$
Notes (2)
Interest (3)
Capital lease obligations (4)
Operating lease obligations (5)
Drilling commitments (6)
Asset retirement obligations (7)
Derivative obligations (8)
Total (9)
Payments Due by Period
For the Year Ended December 31,
2018
2019
2020
2021
2022
Thereafter
Total
— $
—
— $
—
— $
—
— $
—
— $
—
— $
—
2,200,000
2,200,000
122,421
122,421
122,421
122,421
122,421
356,705
968,810
2,352
8,965
30,752
6,297
49,601
1,906
9,702
46,150
774
14,730
617
9,644
—
824
—
17
9,220
—
834
—
14
9,102
—
929
—
—
20,219
—
17,512
—
4,906
66,852
76,902
27,170
64,331
$
220,388 $
195,683 $
133,506 $
132,492 $
132,466 $
2,594,436 $ 3,408,971
(1)
(2)
(3)
Does not include future commitment fees, amortization of deferred financing costs, interest expense or other fees related to the Revolving Credit
Agreement because obligations thereunder are floating rate instruments and we cannot determine with accuracy the timing of future loan advances,
repayments or future interest rates to be charged.
Includes principal only.
Includes fixed rate interest on the 2024 Notes, the 2025 Notes, the New 2025 Notes and the 2027 Notes.
(4) We periodically enter into capital lease agreements payable in connection with the lease of vehicles for operations and field personnel.
(5) We lease equipment and office facilities under non-cancellable operating leases.
(6) We periodically enter into contractual arrangements under which we are committed to expend funds to drill wells in the future, including agreements to
secure drilling rig services, which require us to make future minimum payments to the rig operators. We record drilling commitments in the periods in
which well capital is incurred or rig services are provided.
(7)
Amounts represent estimates of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future
costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of
inflation, changing technology and the political and regulatory environment.
(8) We enter into derivative agreements to hedge future production. We have deferred payment of the premium for certain agreements until the period of
settlement.
(9)
These amounts do not include any contractual obligations incurred after December 31, 2017.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been
prepared in accordance with GAAP. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of
assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties
to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different
assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other
assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of
assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in the preparation of our
consolidated financial statements. See below for an expanded discussion of our significant accounting policies and estimates made by management.
Successful
Efforts
Method
of
Accounting
for
Oil
and
Natural
Gas
Activities
Oil and natural gas exploration, development and production activities are accounted for in accordance with the successful efforts method of
accounting. Under this method, costs of acquiring properties, costs of drilling successful exploration wells and development costs are capitalized.
77
The provision for DD&A of oil and natural gas properties is calculated on a reservoir basis using the unit-of-production method. All capitalized well costs
and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and total proved reserves,
respectively. Natural gas is converted to barrel equivalents at the rate of six thousand cubic feet of natural gas to one barrel of oil. The calculation for the unit-of-
production DD&A method takes into consideration estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values.
We capitalize interest on expenditures made in connection with long-term projects that are not subject to current depletion. Interest is capitalized only for
the period that activities are in progress to bring these projects to their intended use and only to the extent we have incurred interest expense.
On the sale of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated DD&A are removed from
the property accounts and any gain or loss is recognized.
Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major
betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts. Estimated dismantlement and abandonment costs for
oil and natural gas properties are capitalized, net of salvage value, at their estimated net present value and amortized on a unit-of-production basis over the
remaining life of the related proved developed reserves.
Exploration and abandonment costs, other than exploration drilling costs, are charged to expense as incurred. These costs include seismic expenditures and
other geological and geophysical costs, exploratory dry holes, amortization and impairment of unproved leasehold costs and lease rentals. The costs of exploratory
wells and exploratory-type stratigraphic wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of
drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have
been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the
completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved
reserves has not been made within a 12-month period after drilling is complete. Under the successful efforts method, if an exploratory well does not find proved
reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive.
Unproved oil and natural gas properties are assessed quarterly for impairment by considering future drilling plans, the results of exploration activities,
commodity price outlooks, planned future sales or expiration of all or a portion of such projects.
Unproved properties consist of costs incurred to acquire unproved leases, or lease acquisition costs. Unproved lease acquisition costs are capitalized until
the leases expire or when we specifically identify leases that will revert to the lessor, at which time we expense the associated unproved lease acquisition costs. The
expensing of the unproved lease acquisition costs is recorded in Exploration and abandonment costs in our consolidated statement of operations. Lease acquisition
costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis.
For sales of entire working interests in unproved properties, gain or loss is recognized to the extent of the difference between the proceeds received and the
net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds
exceed the entire cost of the property.
Oil
and
Natural
Gas
Reserves
and
Standardized
Measure
of
Discounted
Net
Future
Cash
Flows
This Annual Report presents estimates of our proved reserves as of December 31, 2017 , which have been prepared and presented in accordance with SEC
guidelines. The pricing that was used for estimates of our reserves as of December 31, 2017 was based on an unweighted first day of the month average 12-month
WTI Phillips 66 posted price, net of differential, of $49.17 per Bbl for oil and $22.20 per Bbl for NGLs and a WAHA spot natural gas price, net of differential, of
$2.53 per MMBtu for natural gas.
Our internal reserve engineers and technical staff prepare the estimates of our oil and natural gas reserves and associated future net cash flows, which are
then audited by NSAI, our independent reserve engineers. Even though our internal reserve engineers, technical staff and independent reserve engineers are
knowledgeable and follow authoritative guidelines for estimating and auditing reserves, they must make a number of subjective assumptions based on professional
judgments in developing and auditing the reserve estimates. Reserve estimates are updated at least annually and consider recent production
78
levels and other technical information about each field. Periodic revisions to the estimated reserves and future net cash flows may be necessary as a result of a
number of factors, including reservoir performance, new drilling, oil and natural gas prices, cost changes, technological advances, new geological or geophysical
data, or other economic factors. We cannot predict the amounts or timing of future reserve revisions. If such revisions are significant, they could significantly alter
future depletion and result in impairment of long-lived assets that may be material.
It should not be assumed that the Standardized Measure included in this Annual Report as of December 31, 2017 is the current market value of our
estimated proved reserves. In accordance with SEC requirements, we based the 2017 Standardized Measure on a 12-month average of commodity prices on the
first day of the month and prevailing costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs
utilized in the estimate. See “Item 1A. Risk Factors” and “Item 2. Properties” for additional information regarding estimates of proved reserves.
Our estimates of proved reserves materially impact depletion expense. If the estimates of proved reserves decline, the rate at which we record depletion
expense will increase, reducing future earnings. Such a decline may result from lower commodity prices, which may make it uneconomical to drill and produce
higher cost fields. In addition, a decline in proved reserve estimates may impact the outcome of our assessment of our proved properties for impairment.
Allocation
of
Purchase
Price
in
Business
Combinations
As part of our business strategy, we regularly pursue the acquisition of oil and natural gas properties. The purchase price in an acquisition is allocated to the
assets acquired and liabilities assumed based on their relative fair values as of the acquisition date, which may occur many months after the announcement date.
Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period
between the announcement date and the acquisition date. Our most significant estimates in our allocation typically relate to the value assigned to future recoverable
oil and natural gas reserves and unproved properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the
accuracy of this assessment is inherently uncertain.
Impairment
of
Long-Lived
Assets
All of our long-lived assets are monitored for potential impairment when circumstances indicate that the carrying value of an asset may be greater than its
future net cash flows, including cash flows from risk adjusted proved reserves. The evaluations involve a significant amount of judgment since the results are based
on estimated future events, such as future sales prices for oil and natural gas, future costs to produce these products, estimates of future oil and natural gas reserves
to be recovered and the timing thereof, the economic and regulatory climates and other factors. The need to test an asset for impairment may result from significant
declines in sales prices or downward revisions in estimated quantities of oil and natural gas reserves. Any assets held for sale are reviewed for impairment when we
approve the plan to sell. Estimates of anticipated sales prices are highly judgmental and subject to material revision in future periods. Because of the uncertainty
inherent in these factors, we cannot predict when or if future impairment charges will be recorded.
Income
Taxes
We account for income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences
attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and
tax credit carry forwards. Deferred tax assets and liabilities are calculated by applying existing tax laws and the rates expected to apply to taxable income in the
years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is
recognized in income in the period that includes the enactment date. The tax returns and the amount of taxable income or loss are subject to examination by federal
and state taxing authorities.
SEC Staff Accounting Bulletin No. 118 provides guidance for companies that have not completed their accounting for the income tax effects of the Tax Act
in the period of enactment and allows for a measurement period of up to one year after the enactment date to finalize the recording of the related tax impacts. As of
February 28, 2018 , we have substantially completed our accounting for the tax effects of the enactment of the Tax Act. We have made a reasonable estimate of the
effects on our deferred tax balances. We are still analyzing certain aspects of the Tax Act and we are refining our calculations, which could potentially affect the
measurement of related deferred tax balances or potentially give rise to new deferred tax amounts. We do not expect that a material adjustment to our deferred tax
position will result from the completion of our computation, which we expect to finalize by the fourth quarter of 2018.
79
To account for the effects of the Tax Act, we remeasured our deferred tax assets and liabilities based on the new federal income and state income tax rates,
and they now generally reflect a federal income tax rate of 21%. The enacted rate change resulted in a noncash increase of approximately $23.9 million to our
income tax provision, a corresponding reduction of $23.9 million to our net noncurrent deferred tax asset balance and a reduction in valuation allowance of $24.3
million December 31, 2017 . Any adjustments recorded to these estimates through 2018 will be included in income from operations as an adjustment to tax
expense.
We periodically assess whether it is more likely than not that we will generate sufficient taxable income to realize our deferred income tax assets, including
net operating losses. In making this determination, we consider all available positive and negative evidence and make certain assumptions. We consider, among
other things, our deferred tax liabilities, the overall business environment, our historical earnings and losses, current industry trends and its outlook for future years.
Inflation
Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended
December 31, 2017 , 2016 and 2015 . Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we
tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and natural gas prices increase drilling activity in our areas
of operations.
Off-Balance Sheet Arrangements
We do not maintain off-balance sheet transactions, arrangements, obligations or other relationships with unconsolidated entities or others that are reasonably
likely to have a material current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity,
capital expenditures or capital resources which are not disclosed in the notes to our consolidated financial statements.
Recent Accounting Pronouncements
In May 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers , which supersedes the
revenue recognition requirements in Accounting Standards Codification (“ASC”) Topic 605, Revenue Recognition, and most industry-specific guidance. This
revenue recognition model provides a five-step analysis for determining when and how revenue is recognized, and requires an entity (i) to recognize revenue when
it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those
goods or services and (ii) provide expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with
customers. In August 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers , which deferred the effective date of ASU 2014‑09 by one
year.
We adopted this standard effective January 1, 2018 using the modified retrospective approach. During the fourth quarter of 2017, we completed a detailed
review of various contracts that represent our material revenue streams and, based on such review, we do not expect the standard to materially affect our results of
operations, liquidity or financial position in 2018. Additionally, we will begin recognizing revenues based on the entitlement method rather than the sales method;
this change will not have a material impact on our results of operations or financial position in 2018. We also implemented processes and controls to ensure new
contracts are reviewed for the appropriate accounting treatment and to generate the required disclosures under the standards. As described above, beginning with
our Form 10-Q for the three months ended March 31, 2018, additional disclosures will be required to describe the nature, amount, timing and certainty of revenue
and cash flows from contracts with customers, including a disaggregation of revenue and remaining performance obligations.
As an example of this evaluation and disclosure, under our natural gas processing contracts, we deliver natural gas to midstream processing companies at the
wellhead or their system inlets. The midstream processing companies gather and process the delivered natural gas and, in turn, remit proceeds to us for sales of
NGLs and residue gas. In these scenarios, we evaluate whether the midstream processing company is acting as the principal or the agent. For those contracts where
it is concluded the midstream processing company is acting as an agent and the ultimate third party is our customer, we recognize revenue on a gross basis, with
transportation, gathering, processing and compression fees presented as an expense in its Statement of Operations. For those contracts where it is concluded the
midstream processing company is acting as the principal and we are the customer, we recognize natural gas and NGLs revenues based on the net amount of
proceeds received.
80
In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments-Overall , which addresses the fair value measurements, impairment assessment
and disclosure requirements of equity securities, equity investments and other financial instruments and also clarifies current guidance to aid in the reduction of
diversity in practice. For public business entities, the amended guidance is effective for fiscal years beginning after December 15, 2017 and for interim periods
within those years. The amended guidance should be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year
of adoption. The amendments related to equity securities without readily determinable fair values should be applied prospectively. We have completed our
evaluation of the effect of the standard on our ongoing financial reporting and have determined the ASU will not materially impact our consolidated financial
statements.
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) , which modifies lessees’ recognition of lease assets and lease liabilities for those
leases classified as operating leases under previous GAAP. In January 2018, the FASB issued ASU No. 2018-01, Land Easement Practical Expedient for
Transition to Topic 842 , which permits an entity to elect an optional transition practical expedient to not evaluate under land easements that exist or expired before
the entity's adoption of this ASU and that were not previously accounted for as leases. The amended guidance will be effective for annual periods beginning after
December 15, 2018. Early adoption is permitted. We are currently evaluating all existing leases and agreements that are covered by this standard and will continue
to evaluate the impact on our financial statements and related disclosures.
In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230) , which provides guidance on eight specific cash flow issues,
including cash payments associated with debt and debt modification, contingent consideration payments made after a business combination, proceeds from the
settlement of insurance claims and corporate-owned life insurance policies, distributions made from equity method investees, beneficial interests in securitization
transactions and separately identifiable cash flows and application of the predominance principle. The amended guidance will be effective for annual periods
beginning after December 15, 2017. The amendments should be applied using a retrospective transition method to each period presented. Early adoption is
permitted for any entity in any interim or annual period. We have completed our evaluation of the ASU and have determined the standard will not materially affect
our consolidated financial statements or notes to our consolidated financial statements, with the exception of our presentation on our statement of cash flows.
In October 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740) , which requires an entity to recognize the income tax consequences of an
intra-entity transfer of an asset other than inventory when the transfer occurs. This ASU also eliminates the exception for an intra-entity transfer of an asset other
than inventory. The amended guidance does not include new disclosure requirements; however, existing disclosure requirements might be applicable when
accounting for the current and deferred income taxes. The amended guidance will be effective for annual periods beginning after December 15, 2017. The
amendments should be applied using a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the
period of adoption. Early adoption is permitted for any entity as of the beginning of an annual reporting period for which financial statements have not been issued
or been made available for issuance. We have completed our evaluation of the ASU and have determined the standard will not materially affect our consolidated
financial statements or the notes to our consolidated financial statements.
In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230) , which requires that a statement of cash flows explain the
total change during the period in cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. The amounts generally
described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-
period total amounts shown on the statements of cash flows. The amended guidance will be effective for annual periods beginning after December 15, 2017. The
amendments should be applied using a retrospective transition method to each period presented. The amendments should be applied using a retrospective transition
method to each period presented. Early adoption is permitted for any entity in any interim or annual period. We will implement the new guidance on January 1,
2018. The amended guidance is not expected to materially affect our consolidated financial statements or the notes to our consolidated financial statement, with the
exception of the presentation of restricted cash and restricted cash equivalents on the consolidated statements of cash flows.
In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805) , which clarifies the definition of a business with the objective of
adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The
amendments in this ASU provide a framework which specifies the minimum inputs and processes required for an integrated set of assets and activities to meet the
definition of a business. The amended guidance will be effective for annual periods beginning after December 15, 2017, including interim periods within those
periods. The amendments should be applied prospectively on or after their effective date and no disclosures are required at transition. Early adoption is permitted
for transactions when the acquisition date or disposal date occurs before the issuance date or effective date of the amendment, but only when the transaction has not
been reported in financial statements that have been issued or made available for issuance. We plan to implement the new guidance on January 1, 2018 and because
the ASU
81
will be implemented on a prospective basis, it will only affect the consolidated financial statements and the notes to our consolidated financial statements in future
periods.
In May 2017, the FASB issued ASU 2017-09, Scope of Modification Accounting , to provide clarity and reduce both (i) diversity in practice and (ii) cost and
complexity when applying the guidance in Topic 718, Compensation—Stock Compensation, to a change to the terms or conditions of a share-based payment
award. The standard has an effective date for fiscal years beginning after December 31, 2017, and interim periods within those fiscal years, with early adoption
permitted. We elected to early adopt this standard in the fourth quarter ended December 31, 2017. The amendments in this standard are to be applied prospectively
to any award modified on or after the adoption date. Adopting this standard had no impact on our consolidated financial statements.
82
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of
the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the
risk of loss arising from adverse changes in the prices of the commodities we sell. The disclosures are not meant to be precise indicators of expected future losses,
but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.
Commodity Price Risk
Our major market risk exposure is in the pricing that we receive for our oil and natural gas production. Pricing for our production has been volatile and
unpredictable for several years, and this volatility is expected to continue in the future. The prices we receive for our production depend on many factors outside of
our control, such as the strength of the global economy and global supply and demand for the commodities we produce.
To reduce the impact of price fluctuations on our production revenues, we periodically enter into commodity derivative contracts with respect to portions of
our oil and natural gas production through various transactions that limit the downside of future prices received. We plan to continue our practice of entering into
such transactions to reduce the impact of commodity price volatility on our cash flow from operations. Future transactions may include price swaps whereby we
will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into collars, whereby we
receive the excess, if any, of the fixed floor over the floating rate or pay the excess, if any, of the floating rate over the fixed ceiling price. These hedging activities
are intended to support oil prices at targeted levels and to manage our exposure to oil price fluctuations. For a description of our open derivative positions at
December 31, 2017 , see Note 3—Derivative Financial Instruments to our consolidated financial statements included elsewhere in this Annual Report.
We do not require collateral from our counterparties for entering into derivative instruments, so in order to mitigate the credit risk associated with such
derivative instruments, we typically enter into an International Swap Dealers Association Master Agreement (“ISDA Agreement”) with our counterparties. The
ISDA Agreement is a standardized, bilateral contract between a given counterparty and us. Instead of treating each derivative transaction between the counterparty
and us separately, the ISDA Agreement enables the counterparty and us to aggregate all trades under such agreement and treat them as a single agreement. This
arrangement is intended to benefit us in two ways: (i) default by a counterparty under a single trade can trigger rights to terminate all trades with such counterparty
that are subject to the ISDA Agreement; and (ii) netting of settlement amounts reduces our credit exposure to a given counterparty in the event of close-out.
As of December 31, 2017 , the fair market value of our oil and natural gas derivative contracts was a net liability of $47.9 million , including deferred
premium payables of $64.3 million. The deferred premium payable is a fixed amount and is not marked to fair market value. As of December 31, 2017 , the fair
market value of our oil derivative contracts was a net liability of $49.6 million. Based on our open oil derivative positions at December 31, 2017 , a 10% increase in
the NYMEX WTI price would increase our net oil derivative liability by approximately $40.9 million, while a 10% decrease in the NYMEX WTI price would
decrease our net oil derivative liability by approximately $32.6 million. As of December 31, 2017 , the fair market value of our natural gas derivative contracts was
a net asset of $1.7 million. Based on our open natural gas derivative positions at December 31, 2017 , a 10% increase in the NYMEX Henry Hub price would
decrease our net natural gas derivative asset by approximately $1.0 million, while a 10% decrease in the NYMEX Henry Hub price would increase our natural gas
derivative asset by approximately $0.7 million. Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—
Overview—Realized Prices on the Sale of Oil, Natural Gas and NGLs.”
Counterparty Risk
Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require our counterparties to our
derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. This evaluation includes reviewing a
counterparty’s credit rating and latest financial information. We plan to continue to evaluate the credit standings of our counterparties in a similar manner. The
majority of our derivative contracts currently in place are with lenders under our Revolving Credit Agreement, each of whom has an investment grade rating.
83
Interest Rate Risk
Our market risk exposure related to changes in interest rates relates primarily to debt obligations and the amount of interest we earn on our short-term
investments. As of December 31, 2017 , we had $2.2 billion (excluding capital lease obligations) of fixed-rate long-term debt outstanding with a weighted average
interest rate of 5.6%. Although near term changes may impact the fair value of our fixed-rate debt, they do not expose us to interest rate risk or cash flow loss. We
are exposed to interest rate risk as a result of our Revolving Credit Agreement, which requires us to pay higher interest rate margins as we utilize a larger
percentage of our available commitments. As of December 31, 2017 , however, we had no outstanding borrowings under our Revolving Credit Agreement and
therefore an increase in interest rates will not result in increased interest expense until such time that we determine to make borrowings under our Revolving Credit
Agreement. We are also exposed to interest rate risk related to our interest-bearing cash and cash equivalents and short-term investment balances. As of
December 31, 2017 , our cash and cash equivalents and short-term investments were $703.5 million and $149.3 million , respectively, approximately 93% of which
was invested in money market funds and commercial paper with major financial institutions. A change in the interest rate applicable to our Revolving Credit
Agreement or short-term investments would have a de minimis impact.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Our consolidated financial statements and supplementary data are included in this Annual Report beginning on page F-1.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
In accordance with Exchange Act Rules 13a-15 and 15d-15, we have evaluated, under the supervision and with the participation of our management,
including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as
defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2017 . Our disclosure controls and procedures are designed to provide
reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated
to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure
and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal
executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2017 , at the reasonable
assurance level.
Management’s Annual Report on Internal Control over Financial Reporting and Attestation Report of the Registered Public Accounting Firm
Our management, including our principal executive officer and principal financial officer, is responsible for establishing and maintaining adequate internal
control over financial reporting as defined in Rule 13a-15(f) under the Exchange Act. Our internal control over financial reporting is designed to provide
reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance
with GAAP.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with
the policies or procedures may deteriorate.
Our management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2017 , using the criteria in
Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this
evaluation, our management believes that our internal control over financial reporting was effective as of December 31, 2017 .
This Annual Report includes an attestation report of KPMG LLP, our independent registered public accounting firm, on our internal control over financial
reporting as of December 31, 2017 , which is included in this Annual Report on page F-3.
Changes in Internal Control over Financial Reporting
There were no changes in our system of internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act)
during the quarter ended December 31, 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
85
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
PART III
The information required in response to this item will be set forth in our definitive proxy statement for the 2018 annual meeting of stockholders and is
incorporated herein by reference.
Section 16(a) Beneficial Ownership Reporting Compliance
The information required in response to this item will be set forth in our definitive proxy statement for the 2018 annual meeting of stockholders and is
incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
The information required in response to this item will be set forth in our definitive proxy statement for the 2018 annual meeting of stockholders and is
incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required in response to this item will be set forth in our definitive proxy statement for the 2018 annual meeting of stockholders and is
incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required in response to this item will be set forth in our definitive proxy statement for the 2018 annual meeting of stockholders and is
incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required in response to this item will be set forth in our definitive proxy statement for the 2018 annual meeting of stockholders and is
incorporated herein by reference.
86
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
1.
The following documents are filed as part of this Annual Report or incorporated by reference:
a.
Financial Statements:
PART IV
Our consolidated financial statements are included under Part II, Item 8 of this Annual Report. For a listing of these statements and
accompanying footnotes, see “Index to Consolidated Financial Statements” on page F-1 of this Annual Report.
b.
Financial Statement Schedules:
All financial statement schedules have been omitted because they are not applicable or the required information is presented in the consolidated
financial statements and related notes.
2.
Exhibits
The exhibits required to be filed by this Item 15 are set forth in the Exhibit Index included below.
87
EXHIBIT INDEX
Exhibit No.
2.1#
Asset Purchase Agreement, dated October 20, 2015, by and between Parsley Energy, L.P. and ExL Petroleum Management, LLC
(incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on
December 16, 2015).
2.2#
2.3#
2.4#
2.5#
2.6#
2.7#
3.1
3.2
3.3
4.1
4.2
4.3
4.4
4.5
Purchase and Sale Agreement, dated August 15, 2016, by and between Parsley Energy, L.P. and BTA Oil Producers, LLC, et al.
(incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on
October 5, 2016).
First Amendment to Purchase and Sale Agreement, dated October 4, 2016, by and between Parsley Energy, L.P. and BTA Oil Producers,
LLC, et al. (incorporated by reference to Exhibit 2.2 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the
SEC on October 5, 2016).
Contribution Agreement, dated as of February 7, 2017, by and between Parsley Energy, LLC, Parsley Energy, Inc., Double Eagle Energy
Permian Operating LLC, Double Eagle Energy Permian LLC and Double Eagle Energy Permian Member LLC (incorporated by reference
to Exhibit 2.1 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on February 7, 2017).
First Amendment to Contribution Agreement, dated as of March 10, 2017, by and among Parsley Energy, LLC, Parsley Energy, Inc.,
Double Eagle Energy Permian Operating LLC, Double Eagle Energy Permian LLC and Double Eagle Energy Permian Member LLC
(incorporated by reference to Exhibit 2.2 to the Company’s Quarterly Report on Form 10-Q, File No. 001-36463, filed with the SEC on
May 5, 2017).
Second Amendment to Contribution Agreement, dated as of April 7, 2017, by and among Parsley Energy, LLC, Parsley Energy, Inc.,
Double Eagle Energy Permian Operating LLC, Double Eagle Energy Permian LLC and Double Eagle Energy Permian Member LLC
(incorporated by reference to Exhibit 2.3 to the Company’s Quarterly Report on Form 10-Q, File No. 001-36463, filed with the SEC on
May 5, 2017).
Third Amendment to Contribution Agreement, dated as of April 19, 2017, by and among Parsley Energy, LLC, Parsley Energy, Inc.,
Double Eagle Energy Permian Operating LLC, Double Eagle Energy Permian LLC and Double Eagle Energy Permian Member LLC
(incorporated by reference to Exhibit 2.4 to the Company’s Quarterly Report on Form 10-Q, File No. 001-36463, filed with the SEC on
May 5, 2017).
Amended and Restated Certificate of Incorporation of Parsley Energy, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s
Current Report on Form 8-K, File No. 001-36463, filed with the SEC on June 4, 2014).
Amended and Restated Bylaws of Parsley Energy, Inc., dated October 28, 2016 (incorporated by reference to Exhibit 3.1 to the
Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on November 2, 2016).
First Amendment to the Amended and Restated Bylaws of Parsley Energy, Inc. (incorporated by reference to Exhibit 3.1 to the
Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on June 5, 2017).
Specimen Class A Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 2 to the Company’s
Registration Statement on Form S-1, File No. 333-195230, filed with the SEC on May 12, 2014).
Indenture, dated May 27, 2016, by and among Parsley Energy, LLC, Parsley Finance Corp., the subsidiary guarantors named therein and
U.S. Bank National Association, as trustee, related to the 6.250% Senior Notes due 2024 (incorporated by reference to Exhibit 4.1 to the
Company’s Current Report on Form 8-K, File No. 001‑36463, filed with the SEC on May 27, 2016).
First Supplemental Indenture, dated August 18, 2016, by and among Parsley Energy, LLC, Parsley Finance Corp., the subsidiary
guarantors named therein and U.S. Bank National Association, as trustee, related to the 6.250% Senior Notes due 2024 (incorporated by
reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on August 19, 2016).
Second Supplemental Indenture, dated October 27, 2016, by and among Parsley Energy, LLC, Parsley Finance Corp., the subsidiary
guarantors named therein and U.S. Bank National Association, as trustee, related to the 6.250% Senior Notes due 2024 (incorporated by
reference to Exhibit 4.5 to the Company’s Quarterly Report on Form 10-Q, File No. 001-36463, filed with the SEC on November 4,
2016).
Third Supplemental Indenture, dated April 20, 2017, by and among Parsley Energy, LLC, Parsley Finance Corp., the subsidiary
guarantors named therein and U.S. Bank National Association, as trustee, related to the 6.250% Senior Notes due 2024 (incorporated by
reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on April 20, 2017).
88
Exhibit No.
4.6
4.7
4.8
4.9
4.10
4.11
4.12
10.1
10.2
10.3
10.4
10.5
Indenture, dated December 13, 2016, by and among Parsley Energy, LLC, Parsley Finance Corp., the subsidiary guarantors named therein
and U.S. Bank National Association, as trustee, related to the 5.375% Senior Notes due 2025 (incorporated by reference to Exhibit 4.1 to
the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on December 13, 2016).
First Supplemental Indenture, dated April 20, 2017, by and among Parsley Energy, LLC, Parsley Finance Corp., the subsidiary guarantors
named therein and U.S. Bank National Association, as trustee, related to the 5.375% Senior Notes due 2025 (incorporated by reference to
Exhibit 4.4 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on April 20, 2017).
Indenture, dated February 13, 2017, by and among Parsley Energy, LLC, Parsley Finance Corp., the subsidiary guarantors named therein
and U.S. Bank National Association, as trustee, related to the 5.250% Senior Notes due 2025 (incorporated by reference to Exhibit 4.1 to
the Company’s Current Report on Form 8-K, File No. 001‑36463, filed with the SEC on February 13, 2017).
First Supplemental Indenture, dated April 20, 2017, by and among Parsley Energy, LLC, Parsley Finance Corp., the subsidiary guarantors
named therein and U.S. Bank National Association, as trustee, related to the 5.250% Senior Notes due 2025 (incorporated by reference to
Exhibit 4.5 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on April 20, 2017).
Indenture, dated October 11, 2017, by and among Parsley Energy, LLC, Parsley Finance Corp., the subsidiary guarantors named therein
and U.S. Bank National Association, as trustee, related to the 5.625% Senior Notes due 2027 (incorporated by reference to Exhibit 4.1 to
the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on October 11, 2017).
Registration Rights and Lock-Up Agreement, dated as of April 20, 2017, by and between Parsley Energy, Inc. and the Holders party
thereto (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC
on April 20, 2017).
Second Amended and Restated Registration Rights Agreement, dated as of April 20, 2017, by and among Parsley Energy, LLC, Parsley
Energy, Inc. and each of the parties listed as Owners on the signature pages thereto (incorporated by reference to Exhibit 4.2 to the
Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on April 20, 2017).
Credit Agreement, dated October 28, 2016, among Parsley Energy, LLC, as borrower, Parsley Energy, Inc., Wells Fargo Bank, National
Association, as administrative agent, JPMorgan Chase Bank, N.A., as syndication agent, BMO Harris Bank, N.A., as documentation agent
and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 001-
36463, filed with the SEC on November 2, 2016) .
First Amendment to Credit Agreement, dated as of February 13, 2017, among Parsley Energy, LLC, as borrower, Parsley Energy, Inc.,
each of the guarantors party thereto, Wells Fargo Bank, National Association, as administrative agent, JPMorgan Chase Bank, N.A., as
syndication agent, BMO Harris Bank, N.A., as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit
10.1 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on May 1, 2017).
Second Amendment to Credit Agreement, dated as of April 11, 2017, among Parsley Energy, LLC, as borrower, Parsley Energy, Inc.,
each of the guarantors party thereto, Wells Fargo Bank, National Association, as administrative agent, JPMorgan Chase Bank, N.A., as
syndication agent, BMO Harris Bank, N.A., as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit
10.2 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on May 1, 2017).
Third Amendment to Credit Agreement, dated as of April 28, 2017, among Parsley Energy, LLC, as borrower, Parsley Energy, Inc., each
of the guarantors party thereto, Wells Fargo Bank, National Association, as administrative agent, JPMorgan Chase Bank, N.A., as
syndication agent, BMO Harris Bank, N.A., as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit
10.3 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on May 1, 2017).
Fourth Amendment to Credit Agreement, dated as of May 22, 2017, among Parsley Energy, LLC, as borrower, Parsley Energy, Inc., each
of the guarantors party thereto, Wells Fargo Bank, National Association, as administrative agent, JPMorgan Chase Bank, N.A., as
syndication agent, BMO Harris Bank, N.A., as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit
10.3 to the Company’s Quarterly Report on Form 10-Q, File No. 001-36463, filed with the SEC on August 4, 2017).
89
Exhibit No.
10.6
10.7
10.8
10.9
10.10
10.11
10.12†
10.13†
10.14†
10.15†
10.16†
10.17†
10.18†
10.19†
Fifth Amendment to Credit Agreement, dated as of October 11, 2017, among Parsley Energy, LLC, as borrower, Parsley Energy, Inc.,
each of the guarantors party thereto, Wells Fargo Bank, National Association, as administrative agent, JPMorgan Chase Bank, N.A., as
syndication agent, BMO Harris Bank, N.A., as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit
10.2 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on October 11, 2017).
Purchase Agreement, dated May 24, 2016, by and among Parsley Energy, LLC, Parsley Finance Corp., the subsidiary guarantors named
therein and Credit Suisse Securities (USA) LLC, as representative of the several initial purchasers named therein (incorporated by
reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on May 27, 2016).
Purchase Agreement, dated August 16, 2016, by and among Parsley Energy, LLC, Parsley Finance Corp., the subsidiary guarantors named
therein and J.P. Morgan Securities LLC, as representative of the several initial purchasers named therein (incorporated by reference to
Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on August 19, 2016).
Purchase Agreement, dated December 6, 2016, by and among Parsley Energy, LLC, Parsley Finance Corp., the subsidiary guarantors
named therein and Credit Suisse Securities (USA) LLC, as representative of the several initial purchasers named therein (incorporated by
reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on December 7, 2016).
Purchase Agreement, dated February 8, 2017, by and among Parsley Energy, LLC, Parsley Finance Corp., the subsidiary guarantors
named therein and Credit Suisse Securities (USA) LLC, as representative of the several initial purchasers named therein (incorporated by
reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on February 13, 2017).
Purchase Agreement, dated October 5, 2017, by and among Parsley Energy, LLC, Parsley Finance Corp., the subsidiary guarantors named
therein and Credit Suisse Securities (USA) LLC, as representative of the several initial purchasers named therein (incorporated by
reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on October 11, 2017).
Employment Agreement, dated as of January 23, 2014, by and between Parsley Energy Operations, LLC and Bryan Sheffield
(incorporated by reference to Exhibit 10.8 to the Company’s Registration Statement on Form S‑1, File No. 333-195230, filed with the
SEC on April 11, 2014).
First Amendment to Employment, Confidentiality and Non-Competition Agreement, dated as of September 30, 2016, by and between
Parsley Energy Operations, LLC and Bryan Sheffield (incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on
Form 10-Q, File No. 001-36463, filed with the SEC on November 4, 2016).
Employment, Confidentiality and Non-Competition Agreement, dated as of February 4, 2014, by and between Parsley Energy Operations,
LLC and Ryan Dalton (incorporated by reference to Exhibit 10.12 to the Company’s Annual Form 10-K, File No. 001-36463, filed with
the SEC on February 29, 2016).
First Amendment to Employment, Confidentiality and Non-Competition Agreement, dated as of September 30, 2016, by and between
Parsley Energy Operations, LLC and Ryan Dalton (incorporated by reference to Exhibit 10.4 to the Company’s Quarterly Report on Form
10-Q, File No. 001-36463, filed with the SEC on November 4, 2016).
Amended and Restated Employment Agreement, dated as of December 8, 2014, by and between Parsley Energy Operations, LLC and
Colin Roberts (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with
the SEC on December 9, 2014).
First Amendment to Employment, Confidentiality and Non-Competition Agreement, dated as of September 30, 2016, by and between
Parsley Energy Operations, LLC and Colin Roberts (incorporated by reference to Exhibit 10.6 to the Company’s Quarterly Report on
Form 10-Q, File No. 001-36463, filed with the SEC on November 4, 2016).
Employment Agreement, dated as of February 13, 2014, by and between Parsley Energy Operations, LLC and Matthew Gallagher
(incorporated by reference to Exhibit 10.10 to the Company’s Registration Statement on Form S-1, File No. 333-195230, filed with the
SEC on April 11, 2014).
First Amendment to Employment, Confidentiality and Non-Competition Agreement, dated as of September 30, 2016, by and between
Parsley Energy Operations, LLC and Matthew Gallagher (incorporated by reference to Exhibit 10.5 to the Company’s Quarterly Report on
Form 10-Q, File No. 001-36463, filed with the SEC on November 4, 2016).
90
Exhibit No.
10.20*†
10.21*†
10.22†
10.23
10.24
10.25†
10.26†
10.27†
10.28†
10.29†
10.30†
10.31†
10.32†
10.33†
10.34†
10.35†
10.36†
10.37†
Employment, Confidentiality and Non-Competition Agreement, dated as of February 26, 2014, by and between Parsley Energy
Operations, LLC and Michael Hinson.
First Amendment to Employment, Confidentiality and Non-Competition Agreement, dated as of September 30, 2016, by and between
Parsley Energy Operations, LLC and Michael Hinson.
Form of Vice President Employment, Confidentiality and Non-Competition Agreement (incorporated by reference to Exhibit 10.11 to the
Company’s Quarterly Report on Form 10-Q, File No. 001-36463, filed with the SEC on November 4, 2016).
Second Amended and Restated Limited Liability Company Agreement of Parsley Energy, LLC, dated as of April 20, 2017 (incorporated
by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on April 20, 2017).
Tax Receivable Agreement, dated as of May 29, 2014, by and among Parsley Energy, Inc., certain members of Parsley Energy, LLC and
Bryan Sheffield (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with
the SEC on June 4, 2014).
Indemnification Agreement, dated as of May 14, 2014, by and between Parsley Energy, Inc. and Bryan Sheffield (incorporated by
reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on June 4, 2014).
Indemnification Agreement, dated as of May 14, 2014, by and between Parsley Energy, Inc. and Ryan Dalton (incorporated by reference
to Exhibit 10.4 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on June 4, 2014).
Indemnification Agreement, dated as of May 14, 2014, by and between Parsley Energy, Inc. and Michael Hinson (incorporated by
reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on June 4, 2014).
Indemnification Agreement, dated as of May 14, 2014, by and between Parsley Energy, Inc. and Matt Gallagher (incorporated by
reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on June 4, 2014).
Indemnification Agreement, dated as of May 14, 2014, by and between Parsley Energy, Inc. and Paul Treadwell (incorporated by
reference to Exhibit 10.7 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on June 4, 2014).
Indemnification Agreement, dated as of May 14, 2014, by and between Parsley Energy, Inc. and Thomas Layman (incorporated by
reference to Exhibit 10.8 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on June 4, 2014).
Indemnification Agreement, dated as of May 14, 2014, by and between Parsley Energy, Inc. and Colin Roberts (incorporated by reference
to Exhibit 10.9 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on June 4, 2014).
Indemnification Agreement, dated as of May 14, 2014, by and between Parsley Energy, Inc. and Chris Carter (incorporated by reference to
Exhibit 10.10 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on June 4, 2014).
Indemnification Agreement, dated as of May 14, 2014, by and between Parsley Energy, Inc. and David Smith (incorporated by reference
to Exhibit 10.11 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on June 4, 2014).
Indemnification Agreement, dated as of May 14, 2014, by and between Parsley Energy, Inc. and A.R. Alameddine (incorporated by
reference to Exhibit 10.12 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on June 4, 2014).
Indemnification Agreement, dated as of May 14, 2014, by and between Parsley Energy, Inc. and Randy Newcomer (incorporated by
reference to Exhibit 10.13 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on June 4, 2014).
Indemnification Agreement, dated as of July 23, 2014, by and between Parsley Energy, Inc. and Hemang Desai (incorporated by reference
to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on July 24, 2014).
Indemnification Agreement, dated as of August 19, 2014, by and between Parsley Energy, Inc. and William Browning (incorporated by
reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on August 25, 2014).
91
Exhibit No.
10.38†
10.39†
10.40†
10.41†
10.42†
10.43†
10.44†
10.45†
10.46†
10.47†
10.48†
10.49†
10.50†
10.51†
10.52†
10.53†
10.54†
10.55†
Indemnification Agreement, dated as of August 1, 2015, by and between Parsley Energy, Inc. and Brad Smith (incorporated by reference
to Exhibit 10.32 to the Company’s Annual Report on Form 10-K, File No. 001-36463, filed with the SEC on February 29, 2016).
Indemnification Agreement, dated as of January 1, 2016, by and between Parsley Energy, Inc. and Cecilia Camarillo (incorporated by
reference to Exhibit 10.33 to the Company’s Annual Report on Form 10-K, File No. 001-36463, filed with the SEC on February 29, 2016).
Indemnification Agreement, dated as of March 23, 2016, by and between Parsley Energy, Inc. and Ronald Brokmeyer (incorporated by
reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on March 23, 2016).
Indemnification Agreement, dated as of April 1, 2016, by and between Parsley Energy, Inc. and Stephanie Reed (incorporated by
reference to Exhibit 10.13 to the Company’s Quarterly Report on Form 10-Q, File No. 001-36463, filed with the SEC on November 4,
2016).
Indemnification Agreement, dated as of July 26, 2016, by and between Parsley Energy, Inc. and Larry Parnell (incorporated by reference
to Exhibit 10.14 to the Company’s Quarterly Report on Form 10-Q, File No. 001-36463, filed with the SEC on November 4, 2016).
Indemnification Agreement, dated as of December 21, 2016, by and between Parsley Energy, Inc. and Jerry Windlinger (incorporated by
reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on December 21, 2016).
Indemnification Agreement, dated as of January 5, 2017, by and between Parsley Energy, Inc. and Kristin McClure (incorporated by
reference to Exhibit 10.39 to the Company’s Annual Report on Form 10-K, File No. 001-36463, filed with the SEC on February 27, 2017).
Indemnification Agreement, dated as of January 5, 2017, by and between Parsley Energy, Inc. and Mark Timmons (incorporated by
reference to Exhibit 10.40 to the Company’s Annual Report on Form 10-K, File No. 001-36463, filed with the SEC on February 27, 2017).
Indemnification Agreement, dated as of January 5, 2017, by and between Parsley Energy, Inc. and Mark Brown (incorporated by reference
to Exhibit 10.41 to the Company’s Annual Report on Form 10-K, File No. 001-36463, filed with the SEC on February 27, 2017).
Indemnification Agreement, dated as of August 1, 2017, by and between Parsley Energy, Inc. and Karen Hughes (incorporated by
reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on August 3, 2017).
Amended and Restated Parsley Energy, Inc. 2014 Long Term Incentive Plan (incorporated by reference to Exhibit 10.30 to the Company’s
Annual Report on Form 10-K, File No. 001-36463, filed with the SEC on March 11, 2015).
Form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.16 to Amendment No. 2 to the Company’s Registration
Statement on Form S-1, File No. 333-195230, filed with the SEC on May 12, 2014).
First Amendment to Form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.9 to the Company’s Quarterly Report
on Form 10-Q, File No. 001-36463, filed with the SEC on November 4, 2016).
Form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.8 to the Company’s Quarterly Report on Form 10-Q, File
No. 001-36463, filed with the SEC on November 4, 2016).
Form of Notice of Grant of Restricted Stock (Time-Based) (incorporated by reference to Exhibit 10.10 to the Company’s Quarterly Report
on Form 10-Q, File No. 001-36463, filed with the SEC on November 4, 2016).
Form of Notice of Grant of Restricted Stock (Performance-Based) (incorporated by reference to Exhibit 10.18 to Amendment No. 2 to the
Company’s Registration Statement on Form S-1, File No. 333-195230, filed with the SEC on May 12, 2014).
Form of Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.34 to the Company’s Annual Report on Form 10-K,
File No. 001-36463, filed with the SEC on March 11, 2015).
Form of Notice of Grant of Restricted Stock Units (Time-Based) (incorporated by reference to Exhibit 10.35 to the Company’s Annual
Report on Form 10-K, File No. 001-36463, filed with the SEC on March 11, 2015).
92
Exhibit No.
10.56†
Form of Notice of Grant of Restricted Stock Units (Performance-Based) (incorporated by reference to Exhibit 10.36 to the Company’s
Annual Report on Form 10-K, File No. 001-36463, filed with the SEC on March 11, 2015).
10.57†
Letter Agreement, dated as of January 9, 2018, by and between Parsley Energy, Inc. and Bryan Sheffield (incorporated by reference to
Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on January 9, 2018).
10.58*†
Form of Notice of Grant of Restricted Stock (Performance-Based)
10.59*†
Form of Restricted Stock Agreement
21.1*
List of Subsidiaries of Parsley Energy, Inc.
23.1*
Consent of KPMG LLP.
23.2*
Consent of Netherland, Sewell & Associates, Inc.
31.1*
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**
32.2**
Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002.
Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002.
99.1*
Netherland, Sewell & Associates, Inc. Audit Letter.
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 Labels Linkbase Document.
Management contract or compensatory plan or agreement
Filed herewith.
Furnished herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this Annual Report on Form 10-K 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 of 1933, except to the extent that the
registrant specifically incorporates it by reference.
Schedules and similar attachments have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The registrant will furnish a supplemental copy of
any omitted schedule or similar attachment to the Commission upon request.
93
†
*
**
#
ITEM 16. FORM 10-K SUMMARY
None.
94
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
SIGNATURES
February 28, 2018
By:
/s/ Bryan Sheffield
Bryan Sheffield
Chairman and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant
and in the capacities and on the dates indicated.
February 28, 2018
February 28, 2018
February 28, 2018
February 28, 2018
February 28, 2018
February 28, 2018
February 28, 2018
February 28, 2018
February 28, 2018
February 28, 2018
By:
/s/ Bryan Sheffield
Bryan Sheffield
Chairman and Chief Executive Officer
(Principal Executive Officer)
By:
/s/ Ryan Dalton
Ryan Dalton
Executive Vice President—Chief Financial Officer
(Principal Accounting and Financial Officer)
By:
/s/ A.R. Almeddine
A.R. Alameddine
Director
By:
/s/ Ronald Brokmeyer
Ronald Brokmeyer
Director
By:
/s/ William Browning
William Browning
Director
By:
/s/ Hemang Desai
Hemang Desai
Director
By:
/s/ Matt Gallagher
Matt Gallagher
Director
By:
/s/ Karen Hughes
Karen Hughes
Director
By:
/s/ David H. Smith
David H. Smith
Director
By:
/s/ Jerry Windlinger
Jerry Windlinger
Director
95
Index to Consolidated Financial Statements
Reports of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Changes in Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
F-1
Page
F-2
F-4
F-6
F-7
F-9
F-10
Report of Independent Registered Public Accounting Firm
The stockholders and board of directors
Parsley Energy, Inc.:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Parsley Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2017 and 2016, the
related consolidated statements of operations, changes in equity, and cash flows for each of the years in the three‑year period ended December 31, 2017, and the
related notes (collectively, the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the
financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the three‑year
period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal
control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee
of Sponsoring Organizations of the Treadway Commission, and our report dated February 28, 2018 expressed an unqualified opinion on the effectiveness of the
Company’s internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the
Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing
procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that
respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial
statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall
presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
We have served as the Company’s auditor since 2013.
Dallas, Texas
February 28, 2018
(signed) KPMG LLP
F-2
Report of Independent Registered Public Accounting Firm
The stockholders and board of directors
Parsley Energy, Inc.:
Opinion on Internal Control Over Financial Reporting
We have audited Parsley Energy, Inc. and subsidiaries’ (the “Company”) internal control over financial reporting as of December 31, 2017, based on criteria
established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion,
the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in
Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance
sheets of the Company as of December 31, 2017 and 2016, the related consolidated statements of operations, changes in equity, and cash flows for each of the
years in the three-year period ended December 31, 2017, and the related notes (collectively, the “consolidated financial statements”), and our report dated February
28, 2018 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal
control over financial reporting, included in the accompanying consolidated financial statements. Our responsibility is to express an opinion on the Company’s
internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with
respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission
and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance
about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting
included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the
design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered
necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial
reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of
financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in
accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with
the policies or procedures may deteriorate.
Dallas, Texas
February 28, 2018
(signed) KPMG LLP
F-3
PARSLEY ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31, 2017
December 31, 2016
(In thousands, except share data)
ASSETS
CURRENT ASSETS
Cash and cash equivalents
Short-term investments
Restricted cash
Accounts receivable:
Joint interest owners and other
Oil, natural gas and NGLs
Related parties
Short-term derivative instruments
Assets held for sale
Other current assets
Total current assets
PROPERTY, PLANT AND EQUIPMENT
Oil and natural gas properties, successful efforts method
Accumulated depreciation, depletion, amortization and impairment
Total oil and natural gas properties, net
Other property, plant and equipment net
Total property, plant and equipment, net
NONCURRENT ASSETS
Assets held for sale, net
Long-term derivative instruments
Other noncurrent assets
Total noncurrent assets
TOTAL ASSETS
The accompanying notes are an integral part of these consolidated financial statements.
F-4
$
554,189
$
149,283
—
42,174
123,147
388
41,957
1,790
6,558
919,486
8,551,314
(822,459)
7,728,855
106,587
7,835,442
14,985 54
15,732
7,553
38,270
133,379
—
3,290
12,698
59,174
290
39,708
—
50,949
299,488
4,063,417
(506,175)
3,557,242
59,318
3,616,560
—
16,416
6,318
22,734
$
8,793,198
$
3,938,782
PARSLEY ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
December 31, 2017
December 31, 2016
(In thousands, except share data)
$
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable and accrued expenses
Revenue and severance taxes payable
Current portion of long-term debt
Short-term derivative instruments
Current portion of asset retirement obligations
Total current liabilities
NONCURRENT LIABILITIES
Liabilities related to assets held for sale
Long-term debt
Asset retirement obligations
Deferred tax liability, net
Payable pursuant to tax receivable agreement
Long-term derivative instruments
Total noncurrent liabilities
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS’ EQUITY
Preferred stock, $0.01 par value, 50,000,000 shares authorized, none issued and
outstanding
Common stock
Class A, $0.01 par value, 600,000,000 shares authorized, 252,419,601 shares issued and
252,260,300 shares outstanding at December 31, 2017 and 179,730,033 shares issued
and 179,590,617 shares outstanding at December 31, 2016
Class B, $0.01 par value, 125,000,000 shares authorized, 62,128,257 and 28,008,573
issued and outstanding at December 31, 2017 and December 31, 2016
Additional paid in capital
Retained earnings (accumulated deficit)
Treasury stock, at cost, 159,301 shares and 139,416 at December 31, 2017 and
December 31, 2016
Total stockholders’ equity
Noncontrolling interest
Total equity
TOTAL LIABILITIES AND EQUITY
$
The accompanying notes are an integral part of these consolidated financial statements.
F-5
407,698 $
109,917
2,352
84,919
7,203
612,089
405
2,179,525
19,967
21,403
58,479
20,624
2,300,403
162,317
69,452
67,214
44,153
1,818
344,954
—
1,041,324
9,574
5,483
94,326
12,815
1,163,522
—
—
2,524
622
4,666,365
43,519
(735)
4,712,295
1,168,411
5,880,706
8,793,198 $
1,797
280
2,151,197
(63,255)
(381)
2,089,638
340,668
2,430,306
3,938,782
PARSLEY ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year ended December 31,
2017
2016
2015
(In thousands, except per share data)
REVENUES
Oil sales
Natural gas sales
Natural gas liquids sales
Other
Total revenues
OPERATING EXPENSES
Lease operating expenses
Production and ad valorem taxes
Depreciation, depletion and amortization
General and administrative expenses (including stock-based compensation of $19,619, $12,871 and
$8,133 for the years ended December 31, 2017, 2016 and 2015)
Exploration and abandonment costs
Impairment
Acquisition costs
Accretion of asset retirement obligations
Rig termination costs
Other operating expenses
Total operating expenses
OPERATING INCOME (LOSS)
OTHER (EXPENSE) INCOME
Interest expense, net
Loss on sale of property
Loss on early extinguishment of debt
(Loss) gain on derivatives
Change in TRA liability
Interest income
Other income (expense)
Total other expense, net
INCOME (LOSS) BEFORE INCOME TAXES
INCOME TAX (EXPENSE) BENEFIT
NET INCOME (LOSS)
LESS: NET (INCOME) LOSS ATTRIBUTABLE TO
NONCONTROLLING INTERESTS
NET INCOME (LOSS) ATTRIBUTABLE TO PARSLEY ENERGY,
INC. STOCKHOLDERS
Net income (loss) per common share:
Basic
Diluted
Weighted average common shares outstanding:
Basic
Diluted
The accompanying notes are an integral part of these consolidated financial statements.
F-6
$
802,230 $
387,303 $
56,571
103,193
5,050
967,044
102,169
59,641
352,247
124,255
40,415
—
10,977
971
—
9,568
700,243
266,801
(97,381)
(14,332)
(3,891)
(66,135)
35,847
7,936
783
(137,173)
129,628
(5,708)
123,920
30,928
38,273
1,269
457,773
59,293
27,916
233,766
84,591
13,931
—
1,081
732
—
5,316
426,626
31,147
(56,225)
(119)
(36,335)
(50,835)
7,351
992
(2,317)
(137,488)
(106,341)
17,424
(88,917)
215,795
26,582
23,680
417
266,474
62,913
17,800
178,281
55,294
13,865
950
—
826
8,970
1,696
340,595
(74,121)
(45,581)
(34,374)
—
60,818
—
28
(3,556)
(22,665)
(96,786)
23,755
(73,031)
$
$
$
(17,146)
14,735
22,547
106,774 $
(74,182) $
(50,484)
0.44 $
0.42 $
(0.46) $
(0.46) $
240,733
296,512
161,793
161,793
(0.45)
(0.45)
111,271
111,271
PARSLEY ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(In thousands)
Balance at 12/31/2014
Issuance of Class A Common Stock, net
of underwriters discount and expenses
Change in equity due to issuance of PE Units by Parsley
LLC
Increase in net deferred tax liability due to issuance of PE
Units by Parsley LLC
Tax benefit from tax receivable agreement
Initial noncontrolling interest allocation attributable to
Pacesetter
Issuance of restricted stock
Restricted stock forfeited
Vesting of restricted stock units
Stock-based compensation
Net loss
Balance at 12/31/2015
Adoption of
ASU 2016-09
Restated balance
Issuance proceeds, net of underwriters discount and
expenses
Change in equity due to issuance of PE Units by Parsley
LLC
Increase in net deferred tax liability due to issuance of PE
Units by Parsley LLC
Exchange of PE Units and Class B Common Stock for
Class A Common Stock
Change in net deferred tax liability due to exchange of PE
Units and Class B Common Stock for Class A Common
Stock
Tax benefit from tax receivable agreement
Issuance of restricted stock
Vesting of restricted stock units
Repurchase of common stock
Restricted stock forfeited
Stock-based
compensation
Net loss
Issued Shares
Shares
Class A
Common Stock
Class B
Common
Stock
Class A
Common
Stock
Class B
Common
Stock
Additional
paid in capital
(Accumulated
deficit) retained
earnings
Treasury
stock
Treasury
stock
Total
stockholders’
equity
Noncontrolling
interest
Total equity
93,937
32,145
$
932
$
321
$
644,636
$
61,352
37
$
— $
707,241
$
285,248
$
992,489
42,748
—
—
—
—
42
—
2
—
—
—
—
—
—
—
—
—
—
—
—
136,729
32,145
—
—
136,729
32,145
38,812
—
—
—
—
—
4,137
(4,137)
—
—
37
15
—
—
—
—
—
—
—
—
—
—
—
—
428
—
—
—
—
—
—
—
—
—
1,360
—
1,360
388
—
—
41
—
—
—
8
—
—
—
—
—
—
—
—
—
—
—
—
—
—
321
—
321
—
—
—
668,990
(56,856)
(18,383)
5,500
—
—
(293)
—
8,426
—
1,252,020
—
1,252,020
929,927
(80,255)
(13,215)
(41)
47,001
—
—
—
—
—
—
—
—
(5,999)
8,855
—
(8)
—
(105)
12,976
—
—
—
—
—
—
—
—
—
—
(50,484)
10,868
59
10,927
—
—
—
—
—
—
—
—
—
—
—
(74,182)
—
—
—
—
—
—
68
—
—
—
105
—
105
—
—
—
—
—
—
—
—
12
22
—
—
—
—
—
—
—
—
(71)
(6)
—
—
(77)
—
(77)
—
—
—
—
—
—
—
(91)
(213)
—
—
—
669,418
—
669,418
(56,856)
56,856
—
(18,383)
5,500
—
—
(364)
(6)
8,426
—
—
2,592
—
—
—
—
(50,484)
(22,547)
(18,383)
5,500
2,592
—
(364)
(6)
8,426
(73,031)
1,264,492
322,149
1,586,641
59
—
59
1,264,551
322,149
1,586,700
930,315
—
930,315
(80,255)
80,255
—
(13,215)
—
(13,215)
47,001
(47,001)
—
(5,999)
8,855
—
(91)
(213)
(105)
12,976
(74,182)
—
—
—
—
—
—
—
(14,735)
(5,999)
8,855
—
(91)
(213)
(105)
12,976
(88,917)
Balance at 12/31/2016
179,730
28,008
$
1,797
$
280
$
2,151,197
$
(63,255)
139
$
(381) $
2,089,638
$
340,668
$
2,430,306
F-7
PARSLEY ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(In thousands) (continued)
Issuance proceeds, net of underwriters discount and
expenses
Shares of Class B Common Stock issued for acquisition
Change in equity due to issuance of PE Units by Parsley
LLC
Exchange of PE Units and Class B Common Stock for
Class A Common Stock
Issuance of restricted stock
Vesting of restricted stock units
Repurchase of common stock
Restricted stock forfeited
Stock-based compensation
Net income
Balance at 12/31/2017
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
66,700
—
—
5,729
228
33
—
—
—
—
—
39,849
—
(5,729)
—
—
—
—
—
—
667
—
—
57
3
—
—
—
—
—
2,122,860
1,182,919
(915,749)
105,522
(3)
—
—
(14)
19,633
—
399
—
(57)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
106,774
—
—
—
—
—
—
12
8
—
—
—
—
—
—
—
—
(354)
—
—
—
Total
stockholders’
equity
2,123,527
1,183,318
Noncontrolling
interest
Total equity
—
—
2,123,527
1,183,318
(915,749)
915,749
105,522
(105,522)
—
—
(354)
(14)
19,633
106,774
370
—
—
—
—
17,146
—
—
370
—
(354)
(14)
19,633
123,920
252,420
62,128
$
2,524
$
622
$
4,666,365
$
43,519
159
$
(735) $
4,712,295
$
1,168,411
$
5,880,706
The accompanying notes are an integral part of these consolidated financial statements.
F-8
PARSLEY ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization
Impairment expense
Inventory write down
Accretion of asset retirement obligations
Loss on sale of property
Loss on early extinguishment of debt
Amortization and write off of deferred loan origination costs
Amortization of bond premium
Deferred income tax expense (benefit)
Change in TRA liability
Stock-based compensation expense
Loss (gain) on derivatives
Net cash received for derivative settlements
Net cash (paid) received for option premiums
Net premiums (paid) received on options that settled during the period
Other
Changes in operating assets and liabilities, net of acquisitions:
Restricted cash
Accounts receivable
Accounts receivable—related parties
Materials and supplies
Other current assets
Other noncurrent assets
Accounts payable and accrued expenses
Revenue and severance taxes payable
Other noncurrent liabilities
Net cash provided by operating activities
CASH FLOWS FROM INVESTING ACTIVITIES:
Development of oil and natural gas properties
Acquisitions of oil and natural gas properties
Acquisition of Pacesetter Drilling, LLC
Additions to other property and equipment
Proceeds from sale of property
Purchases of short-term investments
Other
Net cash used in investing activities
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under long-term debt
Payments on long-term debt
Debt issue costs
Proceeds from issuance of common stock, net
Purchases of common stock
Vesting of restricted stock units
Net cash provided by financing activities
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of year
Year Ended December 31,
2017
2016
(In thousands)
2015
$
123,920
$
(88,917)
$
(73,031)
352,247
—
1,060
971
14,332
3,891
4,720
(516)
5,752
(35,847)
19,619
66,135
16,172
(28,426)
(37,103)
33,719
3,290
(95,239)
(98)
—
82,520
(536)
122,992
40,465
—
233,766
—
—
732
119
36,335
3,190
(874)
(17,582)
(7,351)
12,871
50,835
32,364
(10,334)
31,757
6,169
(2,151)
(35,774)
100
—
(71,052)
748
20,897
32,343
—
694,040
228,191
(1,089,256)
(2,192,093)
—
(54,896)
30,537
(149,283)
(1,869)
(505,802)
(1,346,190)
—
(33,374)
—
—
—
178,281
950
4,147
826
34,374
—
2,702
(764)
(24,041)
—
8,133
(60,818)
43,767
40,656
11,406
7,310
(1,139)
24,103
3,675
3,767
(22,793)
(588)
(7,001)
(1,257)
(375)
172,290
(382,550)
(73,807)
(2,408)
(19,755)
51,355
—
—
(3,456,860)
(1,885,366)
(427,165)
1,152,780
(74,769)
(17,371)
2,123,344
(354)
—
3,183,630
420,810
133,379
1,057,500
(521,944)
(18,097)
930,315
(213)
(91)
1,447,470
(209,705)
343,084
105,000
(225,794)
(1,138)
669,418
(71)
(6)
547,409
292,534
50,550
Cash and cash equivalents at end of year
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for interest
Cash paid for income taxes
SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES:
Asset retirement obligations incurred, including changes in estimate
Additions (reductions) to oil and natural gas properties - change in capital accruals
Additions to other property and equipment funded by capital lease borrowings
Common stock issued for oil and natural gas properties
The accompanying notes are an integral part of these consolidated financial statements.
F-9
$
$
$
$
$
$
$
554,189
$
133,379
$
343,084
63,170
350
15,428
118,145
3,904
1,183,501
$
$
$
$
$
$
65,513
315
$
$
(6,646)
(9,831)
$
$
$
— $
2,758
43,993
—
3,441
18,300
939
—
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
NOTE 1. ORGANIZATION AND NATURE OF OPERATIONS
Parsley Energy, Inc. (either individually or together with its subsidiaries, as the context requires, the “Company”) was formed on December 11, 2013,
pursuant to the laws of the State of Delaware to succeed the Company’s predecessor, which began operations in August 2008 when it acquired operator rights to
wells producing from the Spraberry Trend in the Midland Basin. The Company is engaged in the acquisition and development of unconventional oil and natural gas
reserves located in the Permian Basin, which is located in West Texas and Southeastern New Mexico.
Double Eagle Acquisition
On April 20, 2017, the Company, and its subsidiary, Parsley Energy LLC (“Parsley LLC”), completed the acquisition (the “Double Eagle Acquisition”) of
all of the interests in Double Eagle Lone Star LLC, DE Operating LLC, and Veritas Energy Partners, LLC (which were subsequently renamed Parsley DE Lone
Star LLC, Parsley DE Operating LLC, and Parsley Veritas Energy Partners, LLC, respectively) from Double Eagle Energy Permian Operating LLC (“DE
Operating”), Double Eagle Energy Permian LLC (“DE Permian”), and Double Eagle Energy Permian Member LLC (together with DE Operating and DE Permian,
“Double Eagle”), as well as certain related transactions with an affiliate of Double Eagle. The aggregate purchase price for the Double Eagle Acquisition consisted
of approximately (i) $1,395.6 million in cash and (ii) 39,848,518 units of Parsley LLC (“PE Units”) and a corresponding 39,848,518 shares of the Company’s Class
B common stock, par value $0.01 per share (“Class B Common Stock”). The Double Eagle Acquisition is discussed in further detail in Note 5—Acquisitions of Oil
and Natural Gas Properties.
As described in Note 8—Equity , under the Second Amended and Restated Limited Liability Company Agreement of Parsley LLC (the “Parsley LLC
Agreement”), the holders of PE Units generally have the right to exchange their PE Units (and a corresponding number of shares of Class B Common Stock) for
shares of the Company’s Class A common stock, par value $0.01 per share (“Class A Common Stock”), at an exchange ratio of one share of Class A Common
Stock for each PE Unit (and corresponding share of Class B Common Stock) exchanged, subject to conversion rate adjustments for stock splits, stock dividends
and reclassifications.
Public Offerings of Common Stock
During 2015, the Company entered into multiple underwriting agreements to sell a total of 42,747,161 shares of Class A Common Stock (including
1,950,000 shares issued pursuant to the underwriters’ option to purchase additional shares) in multiple underwritten public offerings (the “2015 Equity
Offerings”). The 2015 Equity Offerings resulted in gross proceeds of approximately $683.7 million to the Company and net proceeds to the Company, after
deducting underwriting discounts and commissions and offering expenses, of approximately $669.4 million . The Company used a portion of the net proceeds to
repay outstanding borrowings under the Company’s Revolving Credit Agreement (as defined in Note 7—Debt ), to fund certain acquisitions of oil and natural gas
interests and for general corporate purposes.
During 2016, the Company entered into multiple underwriting agreements to sell a total of 38,812,500 shares of Class A Common Stock (including
5,062,500 shares issued pursuant to the underwriters’ option to purchase additional shares) in multiple underwritten public offerings (the “2016 Equity Offerings”).
The 2016 Equity Offerings resulted in gross proceeds to the Company of approximately $962.2 million and net proceeds to the Company, after deducting
underwriting discounts and commissions and offering expenses, of approximately $930.3 million . The Company used a portion of the net proceeds to fund certain
acquisitions of oil and natural gas interests and the remaining net proceeds to fund a portion of its capital program and for general corporate purposes, including
acquisitions.
On January 10, 2017 , the Company entered into an underwriting agreement to sell 25,300,000 shares of Class A Common Stock (including 3,300,000
shares issued pursuant to the underwriters’ option to purchase additional shares) at a price of $35.00 per share in an underwritten public offering (the “January
Offering”). The January Offering closed on January 17, 2017 and resulted in gross proceeds to the Company of approximately $885.5 million and net proceeds to
the Company, after deducting underwriting discounts and commissions and offering expenses, of approximately $863.0 million . The Company used a portion of
the net proceeds from the January Offering to fund the aggregate purchase price for certain acquisitions of oil and natural gas interests in the Midland and Delaware
Basins and the remaining net proceeds to fund a portion of its capital program and for general corporate purposes, including acquisitions.
F-10
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
On February 7, 2017 , the Company entered into an underwriting agreement to sell 41,400,000 shares of Class A Common Stock (including 5,400,000
shares issued pursuant to the underwriters’ option to purchase additional shares), at a price of $31.00 per share in an underwritten public offering (the “February
Offering,” and together with the January Offering, the “2017 Equity Offerings”). The February Offering closed on February 13, 2017 and resulted in gross
proceeds to the Company of approximately $1,283.4 million and net proceeds to the Company, after deducting underwriting discounts and commissions and
offering expenses of approximately $1,260.5 million . As discussed in Note 5— Acquisitions of Oil and Natural Gas Properties , a portion of the net proceeds was
used to partially fund the cash portion of the purchase price for the Double Eagle Acquisition.
NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
These consolidated financial statements include the accounts of (i) the Company, (ii) Parsley LLC, (iii) the direct and indirect wholly owned subsidiaries of
Parsley LLC, and (iv) an indirect, majority owned subsidiary of Parsley LLC, Pacesetter Drilling, LLC, of which Parsley LLC owns, indirectly, a 63.0% interest.
Parsley LLC also owns, indirectly, a 42.5% noncontrolling interest in Spraberry Production Services, LLC (“SPS”). The Company accounts for its investment in
SPS using the equity method of accounting. All significant intercompany and intra-company balances and transactions have been eliminated.
Use of Estimates
These consolidated financial statements and related notes are presented in accordance with GAAP. Preparation in accordance with GAAP requires the
Company to (i) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and by the SEC and (ii) make
estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the reporting periods. The Company’s management believes the major estimates and
assumptions impacting the Company’s consolidated financial statements are the following:
•
•
•
•
•
•
•
•
•
estimates of proved reserves of oil and natural gas, which affect the calculations of depletion, depreciation and amortization and impairment of capitalized
costs of oil and natural gas properties;
operating costs accrued and volumes and prices for revenues accrued;
estimates of asset retirement obligations;
estimates of the fair value assets acquired and liabilities assumed in business combinations;
evaluations of impairment of proved and unproved properties are subject to number uncertainties including, among others, estimates of future recoverable
reserves and commodity price outlooks;
impairment of other assets;
depreciation of property and equipment;
valuation of commodity derivative instruments; and
estimates of the fair value of stock-based compensation.
Although management believes these estimates are reasonable, actual results may differ from estimates and assumptions of future events and these revisions
could be material. Future production may vary materially from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price
assumptions used for determining proved reserves and for financial reporting.
F-11
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
Cash and Cash Equivalents
The Company considers all cash on hand, depository accounts held by banks, money market accounts and investments with an original maturity of three
months or less to be cash equivalents. The Company’s cash and cash equivalents are held in financial institutions in amounts that exceed the insurance limits of the
Federal Deposit Insurance Corporation. However, management believes that the Company’s counterparty risks are minimal based on the reputation and history of
the institutions selected.
Restricted Cash
The Company’s restricted cash at December 31, 2016 of $3.3 million consisted of cash deposited into an escrow account that was contractually restricted
involving a non-related party. The restricted cash included revenues associated with an operated well. During December 2017, the matter was resolved, resulting in
the release of $4.8 million , including all of the escrowed funds, and the Company’s recognition of $3.6 million of sales, net of production taxes. As of
December 31, 2017 , the Company had no restricted cash.
Short-term Investments
Periodically, the Company invests in commercial paper with investment grade rated entities. The Company also periodically enters into time deposits with
financial institutions. Commercial paper and time deposits are included in cash and cash equivalents if they have maturity dates that are less than three months at
the date of purchase; otherwise, investments are reflected as short-term investments in the accompanying consolidated balance sheets based on their maturity dates.
As of December 31, 2017, all of the Company’s short-term investments mature within one year.
Accounts Receivable
Accounts receivable consist of receivables from joint interest owners on properties the Company operates and crude oil, natural gas and NGLs production
delivered to purchasers. The purchasers remit payment for production directly to the Company. Most payments are received within three months after the
production date.
Amounts due from joint interest owners or purchasers are stated net of an allowance for doubtful accounts when the Company believes collection is
doubtful. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of
joint interest billings. Accounts receivable outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance
by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability
to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when
they become uncollectible and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. No allowance was deemed
necessary at December 31, 2017 or December 31, 2016 .
Significant Customers
For the years ended December 31, 2017 , 2016 and 2015 , each of the following purchasers accounted for more than 10% of the Company’s revenue:
Shell Trading (US) Company
BML, Inc.
Targa Pipeline Mid-Continent, LLC
TransOil Marketing, LLC
2017
62%
2%
13%
1%
Year Ended December 31,
2016
44%
13%
13%
8%
2015
23%
19%
12%
13%
The Company does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and
natural gas are fungible products with well-established markets and numerous purchasers.
F-12
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
Oil and Natural Gas Properties
Oil and natural gas exploration, development and production activities are accounted for in accordance with the successful efforts method of
accounting. Under this method, costs of acquiring properties, costs of drilling successful exploration wells and development costs are capitalized.
As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties and mineral
interests are subject to depreciation, depletion and amortization (“DD&A”). Depletion of capitalized costs is provided using the units-of-production method based
on proved oil and gas reserves related to the associated reservoir.
The Company capitalizes interest on expenditures made in connection with long term projects that are not subject to current depletion. Interest is capitalized
only for the period that activities are in progress to bring these projects to their intended use and only to the extent the company has incurred interest expense.
On the sale of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated DD&A are removed from
the property accounts and any gain or loss is recognized.
For sales of entire working interests in unproved properties, gain or loss is recognized to the extent of the difference between the proceeds received and the
net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds
exceed the entire cost of the property.
Oil and Gas Reserves
The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated financial statements are estimated in accordance with the
rules established by the SEC and the FASB. These rules require that reserve estimates be prepared under existing economic and operating conditions using a
trailing first day of the month 12-month average price, net of historical differentials, with no provision for price and cost escalations in future years except by
contractual arrangements.
Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. Oil and gas
properties are depleted by field using the units-of-production method. Capitalized drilling and development costs of producing oil and natural gas properties are
depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. It is possible that, because of changes in market conditions or
the inherent imprecision of reserve estimates, the estimates of future cash inflows, the amount of oil and natural gas reserves, the remaining estimated lives of oil
and natural gas properties, or any combination of the above may be increased or decreased. Increases in recoverable economic volumes generally reduce per unit
depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.
Asset Retirement Obligations
For the Company, asset retirement obligations represent the future abandonment costs of tangible assets, namely the plugging and abandonment of wells and
land remediation. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair
value can be made and the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present
value each period. If the liability is settled for an amount other than the recorded amount, the difference is recorded in other income (expense) in the consolidated
statements of operations.
Inherent to the present value calculation are numerous estimates, assumptions and judgments, including, but not limited to: the ultimate settlement amounts,
inflation factors, credit-adjusted risk-free rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent
future revisions to these assumptions affect the present value of the abandonment liability, the Company makes corresponding adjustments to both the asset
retirement obligation and the related oil and natural gas property asset balance. These revisions result in prospective changes to DD&A expense and accretion of
the discounted abandonment liability.
F-13
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
The following table summarizes the changes in the Company’s asset retirement obligation for the periods indicated (in thousands):
Asset retirement obligations, beginning of year
Additional liabilities incurred
Disposition of wells
Accretion expense
Liabilities settled upon plugging and abandoning wells
Revision of estimates
Liabilities related to assets held for sale
Asset retirement obligations, end of year
Allocation of Purchase Price in Business Combinations
Year ended December 31,
2017
2016
$
11,392 $
9,081
(432)
971
(189)
6,752
(405)
$
27,170 $
18,220
3,290
(858)
732
(56)
(9,936)
—
11,392
As part of its business strategy, the Company regularly pursues the acquisition of oil and natural gas properties. The purchase price in an acquisition is
allocated to the assets acquired and liabilities assumed based on their relative fair values as of the acquisition date, which may occur many months after the
announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change
during the period between the announcement date and the acquisition date. The Company’s most significant estimates in its allocation typically relate to the value
assigned to future recoverable oil and natural gas reserves and unproved properties. As the allocation of the purchase price is subject to significant estimates and
subjective judgments, the accuracy of this assessment is inherently uncertain.
Impairment of Oil and Natural Gas Properties
The Company reviews its long-lived assets to be held and used, including proved oil and natural gas properties by field. Whenever events or circumstances
indicate that the carrying value of those assets may not be recoverable, an impairment loss is indicated if the sum of the expected future cash flows related to
proved properties in the applicable field is less than the carrying amount of the assets. In this circumstance, the Company recognizes an impairment loss for the
amount by which the carrying amount of the asset exceeds the estimated fair value of the asset. The Company reviews its oil and natural gas properties by
amortization base or by individual well for those wells not constituting part of an amortization base. For each property determined to be impaired, an impairment
loss equal to the difference between the carrying value of the properties and the estimated fair value (discounted future cash flows) of the properties would be
recognized at that time. Estimating future cash flows involves the use of judgments, including estimation of the proved oil and natural gas reserve quantities, timing
of development and production, expected future commodity prices, capital expenditures and production costs. See Note 13— Disclosures about Fair Value of
Financial Instruments for additional information regarding the Company’s impairment of proved oil and natural gas properties.
Exploration and Abandonment Costs
Exploration and abandonment costs, other than exploration drilling costs, are charged to expense as incurred. These costs include seismic expenditures and
other geological and geophysical costs, exploratory dry holes, impairment and amortization of unproved leasehold costs and lease rentals. The costs of exploratory
wells and exploratory-type stratigraphic wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of
drilling activities, the costs of exploratory wells remain capitalized if determination is made that proved reserves have been found. If no proved reserves have been
found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the
completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved
reserves has not been made within a 12-month period after drilling is complete.
Unproved oil and natural gas properties are assessed quarterly for impairment by considering future drilling plans, the results of exploration activities,
commodity price outlooks, planned future sales or expiration of all or a portion of such projects.
F-14
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
The following table summarizes exploration and abandonment costs incurred by the Company for the periods indicated (in thousands):
Leasehold abandonments
Geological and geophysical costs
Idle drilling rig fees
Unproved leasehold amortization
Total exploration and abandonment costs
Other Property and Equipment, net
Year Ended December 31,
2017
2016
2015
32,872 $
5,429
1,070
1,044
40,415 $
6,063 $
3,015
4,304
549
13,931 $
8,227
5,459
—
179
13,865
$
$
Other property and equipment is recorded at cost. The Company expenses maintenance and repairs in the period incurred. Upon retirements or disposition of
assets, the cost and related accumulated depreciation are removed from the consolidated balance sheet with the resulting gains or losses, if any, reflected in
operations. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three years
to 15 years . Depreciation expense on other property and equipment was $11.5 million , $6.6 million and $4.7 million for the years ended December 31, 2017 ,
2016 and 2015 , respectively.
Materials and supplies are stated at the lower of cost or market and consists of oil and gas drilling or repair items such a tubing, casing and pumping
units. These items are primarily acquired for use in future drilling or repair operations and are carried at lower of cost or market. “Market,” in the context of
valuation, represents net realizable value, which is the amount that the Company is allowed to bill to the joint account under joint operating agreements to which
the Company is a party. The Company evaluated materials and supplies based on current operations and determined that these materials and supplies would not be
utilized in the current year and includes them in noncurrent assets as non-depreciable other property, plant and equipment. See Note 13—Disclosures about Fair
Value of Financial Instruments for additional information regarding the Company’s impairment of materials and supplies.
Equity Investments
Equity investments in which the Company exercises significant influence but does not control are accounted for using the equity method. Under the equity
method, generally the Company’s share of investees’ earnings or loss, after elimination of intra-company profit or loss, is recognized in the consolidated statement
of operations. The Company reviews its investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred,
the Company would recognize an impairment provision. There was no impairment for the Company’s equity investments for the years ended December 31, 2017 ,
2016 and 2015 .
Derivative Instruments
The Company uses derivative financial instruments to reduce exposure to fluctuations in commodity prices. These transactions are in the form of crude
options and collars.
The Company reports the fair value of derivatives on the consolidated balance sheets in derivative instrument assets and derivative instrument liabilities as
either current or noncurrent. The Company determines the current and noncurrent classification based on the timing of expected future cash flows of individual
trades. The Company reports these on a gross basis by contract.
The Company’s derivative instruments were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in
fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses resulting from the changes in fair value of
derivatives are included in cash flows from operating activities.
F-15
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
Fair Value of Financial Instruments
Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants at
the reporting date. The Company’s assets and liabilities that are measured at fair value at each reporting date are classified according to a hierarchy that prioritizes
inputs and assumptions underlying the valuation techniques. This fair value hierarchy gives the highest priority to quoted prices in active markets for identical
assets or liabilities and the lowest priority to unobservable inputs and consists of three broad levels:
Level
1
:
Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.
Level
2
:
Level
3
:
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.
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.
Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority
level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires
judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. Reclassifications of fair value between Level 1, Level 2
and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter.
Deferred Loan Costs
Deferred loan costs are stated at cost, net of amortization and are amortized to interest expense using the effective interest method over the life of the loan.
Revenue Recognition
Revenues from the sale of crude oil, natural gas and NGLs are recognized when the production is sold, net of any royalty interest. Because final settlement
of the Company’s hydrocarbon sales can take up to two months, the expected sales volumes and prices for those properties are estimated and accrued using
information available at the time the revenue is recorded. Natural gas revenues are recorded using the entitlement method of accounting whereby revenue is
recognized based on the Company’s proportionate share of natural gas production. At December 31, 2017 , 2016 and 2015 , the Company did not have any natural
gas imbalances. Transportation expenses are included as a reduction of natural gas revenue and are not material.
Defined Contribution Plan
The Company sponsors a 401(k) defined contribution plan for the benefit of all employees at their date of hire. The plan allows eligible employees to
contribute a portion of their annual compensation, not to exceed annual limits established by the federal government. The Company makes matching contribution
of up to a certain percentage of an employee’s contributions. For the years ended December 31, 2017 , 2016 and 2015 , the Company made contributions to the
plan of $2.8 million , $1.9 million and $1.4 million , respectively.
Income Taxes
The Company accounts for income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and
operating loss and tax credit carryforwards. Deferred tax assets and liabilities are calculated by applying existing tax laws and the rates expected to apply to taxable
income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and
liabilities is recognized in income in the period that includes the enactment date. The tax returns and the amount of taxable income or loss are subject to
examination by federal and state taxing authorities.
SEC Staff Accounting Bulletin No. 118 provides guidance for companies that have not completed their accounting for the income tax effects of Public Law
No. 115-97, commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”), in the
F-16
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
period of enactment and allows for a measurement period of up to one year after the enactment date to finalize the recording of the related tax impacts. As of
February 28, 2018 , the Company has substantially completed its accounting for the tax effects of the enactment of the Tax Act. The Company has made a
reasonable estimate of the effects on its deferred tax balances. The Company is still analyzing certain aspects of the Tax Act and the Company is refining its
calculations, which could potentially affect the measurement of related deferred tax balances or potentially give rise to new deferred tax amounts. The Company
does not expect that a material adjustment to its deferred tax position will result from the completion of its computations, which the Company expects to finalize by
the fourth quarter of 2018.
To account for the effects of the Tax Cut and Jobs Act, the Company remeasured its deferred tax assets and liabilities based on the federal income and state
income tax rates at which they are now expected to reverse, and they now generally reflect a federal income tax rate of 21%. The enacted rate change resulted in a
noncash increase of approximately $23.9 million to the Company’s income tax provision, a corresponding reduction of $23.9 million to the Company’s net
noncurrent deferred tax asset balance and a reduction in valuation allowance of $24.3 million December 31, 2017 . Any adjustments recorded to these estimates
through 2018 will be included in income from operations as an adjustment to tax expense.
The Company periodically assesses whether it is more likely than not that it will generate sufficient taxable income to realize its deferred income tax assets,
including net operating losses. In making this determination, the Company considers all available positive and negative evidence and makes certain assumptions.
The Company considers, among other things, its deferred tax liabilities, the overall business environment, its historical earnings and losses, current industry trends
and its outlook for future years.
Earnings per Share
The Company uses the “if-converted” method to determine the potential dilutive effect of its Class B Common Stock and the treasury stock method to
determine the potential dilutive effect of outstanding restricted stock and restricted stock units.
Comprehensive Income
The Company has no elements of comprehensive income other than net income.
Segment Reporting
Operating segments are defined as components of an enterprise (i) that engage in activities from which it may earn revenues and incur expenses and (ii) for
which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating
resources and assessing performance.
Based on the organization and management of the Company, the Company has only one reportable operating segment, which is oil and natural gas
exploration and production. The Company considers drilling rig services ancillary to its oil and gas exploration and production activities and manages these
services to support such activities.
Reclassifications
Certain reclassifications have been made to prior period amounts to conform to the current presentation.
Recent Accounting Pronouncements
In May 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers, which supersedes the
revenue recognition requirements in Accounting Standards Codification (“ASC”) Topic 605, Revenue Recognition, and most industry-specific guidance. This
revenue recognition model provides a five-step analysis for determining when and how revenue is recognized, and requires an entity (i) to recognize revenue when
it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those
goods or services and (ii) provide expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with
customers. In August 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers , which deferred the effective date of ASU 2014-09 by one
year.
F-17
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
The Company adopted this standard effective January 1, 2018 using the modified retrospective approach. During the fourth quarter of 2017, the Company
completed a detailed review of various contracts that represent its material revenue streams and, based on such review, does not expect the standard to materially
affect the Company’s results of operations, liquidity or financial position in 2018. Additionally, the Company will begin recognizing revenues based on the
entitlement method rather than the sales method; this change will not have a material impact on the Company’s results of operations or financial position in 2018.
The Company has also implemented processes and controls to ensure new contracts are reviewed for the appropriate accounting treatment and to generate the
required disclosures under the standards. As described above, beginning with the Company’s Form 10-Q for the three months ended March 31, 2018, additional
disclosures will be required to describe the nature, amount, timing and certainty of revenue and cash flows from contracts with customers, including a
disaggregation of revenue and remaining performance obligations.
As an example of this evaluation and disclosure, under the Company’s natural gas processing contracts, the Company delivers natural gas to midstream
processing companies at the wellhead or their system inlets. The midstream processing companies gather and process the delivered natural gas and, in turn, remit
proceeds to the Company for sales of NGLs and residue gas. In these scenarios, the Company evaluates whether the midstream processing company is acting as the
principal or the agent. For those contracts where it is concluded the midstream processing company is acting as an agent and the ultimate third party is the
Company’s customer, the Company recognizes revenue on a gross basis, with transportation, gathering, processing and compression fees presented as an expense
in its Statement of Operations. For those contracts where it is concluded the midstream processing company is acting as the principal and the Company is the
customer, the Company recognizes natural gas and NGLs revenues based on the net amount of proceeds received.
In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments—Overall , which addresses the fair value measurements, impairment
assessment and disclosure requirements of equity securities, equity investments and other financial instruments and also clarifies current guidance to aid in the
reduction of diversity in practice. For public business entities, the amended guidance is effective for fiscal years beginning after December 15, 2017 and for interim
periods within those years. The amended guidance should be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the
fiscal year of adoption. The amendments related to equity securities without readily determinable fair values should be applied prospectively. The Company has
completed its evaluation of the effect of the standard on its ongoing financial reporting and has determined the ASU will not materially impact its consolidated
financial statements.
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) , which modifies lessees’ recognition of lease assets and lease liabilities for those
leases classified as operating leases under previous GAAP. In January 2018, the FASB issued ASU No. 2018-01, Land Easement Practical Expedient for
Transition to Topic 842, which permits an entity to elect an optional transition practical expedient to not evaluate under land easements that exist or expired before
the entity's adoption of this ASU and that were not previously accounted for as leases. The amended guidance will be effective for the Company for annual periods
beginning after December 15, 2018. Early adoption is permitted. The Company is currently evaluating all existing leases and agreements that are covered by this
standard and will continue to evaluate the impact on the financial statements and related disclosures.
In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230) , which provides guidance on eight specific cash flow issues,
including cash payments associated with debt and debt modification, contingent consideration payments made after a business combination, proceeds from the
settlement of insurance claims and corporate-owned life insurance policies, distributions made from equity method investees, beneficial interests in securitization
transactions and separately identifiable cash flows and application of the predominance principle. The amended guidance will be effective for the Company for
annual periods beginning after December 15, 2017. The amendments should be applied using a retrospective transition method to each period presented. Early
adoption is permitted for any entity in any interim or annual period. The Company has completed their evaluation of the ASU and has determined the standard will
not materially affect the Company’s consolidated financial statements or notes to the consolidated financial statements, with the exception of presentation on the
Company’s statement of cash flows.
In October 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740) , which requires an entity to recognize the income tax consequences of an
intra-entity transfer of an asset other than inventory when the transfer occurs. This ASU also eliminates the exception for an intra-entity transfer of an asset other
than inventory. The amended guidance does not include new disclosure requirements; however, existing disclosure requirements might be applicable when
accounting for the current and deferred income taxes. The amended guidance will be effective for the Company for annual periods beginning after December 15,
2017. The amendments should be applied using a modified retrospective basis through a cumulative-effect
F-18
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
adjustment directly to retained earnings as of the beginning of the period of adoption. Early adoption is permitted for any entity as of the beginning of an annual
reporting period for which financial statements have not been issued or been made available for issuance. The Company has completed their evaluation of the ASU
and has determined the standard will not materially affect the Company’s consolidated financial statements or notes to the consolidated financial statements.
In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230) , which requires that a statement of cash flows explain the
total change during the period in cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. The amounts generally
described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-
period total amounts shown on the statements of cash flows. The amended guidance will be effective for the Company for annual periods beginning after December
15, 2017. The amendments should be applied using a retrospective transition method to each period presented. The amendments should be applied using a
retrospective transition method to each period presented. Early adoption is permitted for any entity in any interim or annual period. The Company will implement
the new guidance on January 1, 2018. The amended guidance is not expected to materially affect the Company’s consolidated financial statements or notes to the
consolidated financial statement, with the exception of the presentation of restricted cash and restricted cash equivalents on the consolidated statements of cash
flows.
In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805) , which clarifies the definition of a business with the objective of
adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The
amendments in this ASU provide a framework which specifies the minimum inputs and processes required for an integrated set of assets and activities to meet the
definition of a business. The amended guidance will be effective for the Company for annual periods beginning after December 15, 2017, including interim periods
within those periods. The amendments should be applied prospectively on or after their effective date and no disclosures are required at transition. Early adoption is
permitted for transactions when the acquisition date or disposal date occurs before the issuance date or effective date of the amendment, but only when the
transaction has not been reported in financial statements that have been issued or made available for issuance. The Company plans to implement the new guidance
on January 1, 2018 and because the ASU will be implemented on a prospective basis, it will only affect the consolidated financial statements and notes to the
consolidated financial statements in future periods.
In May 2017, the FASB issued ASU 2017-09, Scope of Modification Accounting to provide clarity and reduce both (1) diversity in practice and (2) cost and
complexity when applying the guidance in Topic 718, Compensation-Stock Compensation, to a change to the terms or conditions of a share-based payment award.
The standard has an effective date for fiscal years beginning after December 31, 2017, and interim periods within those fiscal years, with early adoption permitted.
The Company elected to early adopt this standard in the fourth quarter ended December 31, 2017. The amendments in this standard are to be applied prospectively
to an award modified on or after the adoption date. Adopting this standard had no impact on the Company’s consolidated financial statements.
NOTE 3. DERIVATIVE FINANCIAL INSTRUMENTS
Commodity Derivative Instruments and Concentration of Risk
Objective
and
Strategy
The Company utilizes put spread options, three-way collars, two-way collars, commodity swap contracts and basis swap contracts to (i) reduce the effect of
price volatility on the commodities the Company produces and sells or consumes, (ii) support the Company’s annual capital budgeting and expenditure plans and
(iii) reduce commodity price risk associated with certain capital projects.
The Company uses put spread options and collars to manage commodity price risk for NYMEX WTI. A put spread option is a combination of two options: a
purchased put and a sold put. The purchased put establishes the minimum price that the Company will receive for the contracted volumes unless the market price
for the commodity falls below the sold put strike price, at which point the minimum price equals the reference price plus the excess of the purchased put strike
price over the sold put strike price. A two-way collar is a combination of options: a sold call and a purchased put. The purchased put establishes a minimum price
(floor) and the sold call establishes a maximum price (ceiling) the Company will receive for the volumes under contract. A three-way collar is a combination of
options: a sold call, a purchased put and a sold put. The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-
floor), at which point
F-19
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
the minimum price would be the NYMEX index price plus the difference between the purchased put and the sold put strike price. The sold call establishes a
maximum price (ceiling) the Company will receive for the volumes under contract.
Additionally, the Company uses basis swap contracts to mitigate basis risk caused by the volatility of the Company’s basis differentials. The basis swap
contracts establish the differential between Cushing WTI prices and the relevant price index at which oil production is sold.
Oil
Production
Derivative
Activities
The Company’s material physical sales contracts governing its oil production are tied directly to, or are typically correlated with, NYMEX WTI oil prices.
The Company uses put spread options, collars and three-way collars to manage oil price volatility and basis swap contracts to reduce basis risk between NYMEX
WTI prices and the actual index prices at which the oil is sold.
F-20
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
The following table sets forth the volumes associated with the Company’s outstanding oil derivative contracts expiring during the periods indicated and the
weighted average oil prices for those contracts:
Crude Options
Put spread
Purchased:
Puts (1)
Notional (MBbl)
Weighted average strike price
Sold:
Puts (1)
Notional (MBbl)
Weighted average strike price
Three-way collars
Purchased:
Puts
Notional (MBbl)
Weighted average strike price
Sold:
Puts
Notional (MBbl)
Weighted average strike price
Calls
Notional (MBbl)
Weighted average strike price
Two-way Collars
Purchased:
Puts
Notional (MBbl)
Weighted average strike price
Sold:
Calls
Notional (MBbl)
Weighted average strike price
Basis swap contracts: (2)
Midland-Cushing index swap volume (MBbl) (3)
Price differential ($/Bbl)
Year Ending December 31,
2018
2019
$
$
$
$
$
$
$
$
10,500
50.43 $
(10,500)
40.29 $
14,100
50.21 $
(14,100)
40.05 $
(14,100)
70.54 $
825
45.67 $
(825)
61.31 $
4,158
(0.86) $
2,100
50.00
(2,100)
40.00
3,000
50.00
(3,000)
40.00
(3,000)
80.40
—
—
—
—
—
—
(1)
(2)
Excludes 1,818 notional MBbls with a fair value of $1.4 million related to amounts recognized under master netting agreements with derivative
counterparties.
Represents swaps that fix the basis differentials between the index prices at which the Company sells its oil produced in the Permian Basin and the Cushing
WTI price.
F-21
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
Natural
Gas
Production
Derivative
Activities
All material physical sales contracts governing the Company’s natural gas production are tied directly or indirectly to NYMEX Henry Hub natural gas
prices or regional index prices where the natural gas is sold. The Company uses three-way collars and swaps to manage natural gas price volatility.
The following table sets forth the volumes associated with the Company’s outstanding natural gas derivative contracts expiring during the periods indicated and the
weighted average natural gas prices for those contracts:
Natural Gas
Three-Way Collars
Purchased:
Puts
Notional (MMbtu)
Weighted average strike price
Sold:
Puts
Notional (MMbtu)
Weighted average strike price
Calls
Notional (MMbtu)
Weighted average strike price
Swaps
Volume (MMbtu)
Strike price ($/MMbtu)
Year Ending December
31,
2018
$
$
$
$
5,400
3.11
(5,400)
2.68
(5,400)
4.09
450
3.50
Effect of Derivative Instruments on the Consolidated Financial Statements
All of the Company’s derivatives are accounted for as non-hedge derivatives and therefore all changes in the fair values of its derivative contracts are
recognized as gains or losses in the earnings of the periods in which they occur. The table below summarizes the Company’s gains (losses) on derivative
instruments for the years ended December 31, 2017 , 2016 and 2015 (in thousands):
Changes in fair value of derivative instruments
Net derivative settlements
Net premiums realization on options that settled during the period
(Loss) gain on derivatives
Year Ending December 31,
2017
2016
2015
$
$
(44,702) $
(109,033)
15,670
(37,103)
26,441
31,757
(66,135) $
(50,835) $
2,958
46,454
11,406
60,818
The Company classifies the fair value amounts of derivative assets and liabilities as gross current or noncurrent derivative assets or gross current or
noncurrent derivative liabilities, whichever the case may be, excluding those amounts netted under master netting agreements. The fair value of the derivative
instruments is discussed in Note 13—Disclosures about Fair Value of Financial Instruments. The Company has agreements in place with all of its counterparties
that allow for the financial right of offset for derivative assets and liabilities at settlement or in the event of default under the agreements. Additionally, the
Company maintains accounts with its brokers to facilitate financial derivative transactions in support of its risk management activities. Based on the value of the
Company’s positions in these accounts and the associated margin requirements, the Company may be required to deposit cash into these broker accounts. During
the years ended December 31,
F-22
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
2017 , 2016 and 2015 , the Company did not receive or post any margins in connection with collateralizing its derivative positions.
The following table presents the Company’s net exposure from its offsetting derivative asset and liability positions, as well as option premiums payable and
receivable as of the reporting dates indicated (in thousands):
December 31, 2017
Derivative assets with right of offset or
master netting agreements
Derivative liabilities with right of offset or
master netting agreements
December 31, 2016
Derivative assets with right of offset or
master netting agreements
Derivative liabilities with right of offset or
master netting agreements
Concentration of Credit Risk
Gross Amount
Netting
Adjustments
Net
Exposure
$
59,132 $
(1,443) $
57,689
(106,986)
1,443
(105,543)
$
66,417 $
(10,293) $
56,124
(67,261)
10,293
(56,968)
The financial integrity of the Company’s exchange-traded contracts is assured by NYMEX through systems of financial safeguards and transaction
guarantees and is therefore subject to nominal credit risk. Over-the-counter traded options expose the Company to counterparty credit risk. These over-the-counter
options are entered into with a large multinational financial institution with investment grade credit rating or through brokers that require all the transaction parties
to collateralize their open option positions. The gross and net credit exposure from the Company’s commodity derivative contracts as of December 31, 2017 and
2016 is summarized in the preceding table.
The Company monitors the creditworthiness of its counterparties, established credit limits according to the Company’s credit policies and guidelines and
assesses the impact on fair values of its counterparties’ creditworthiness. The Company typically enters into International Swap Dealers Association Master
Agreements (“ISDA Agreements”) with its derivative counterparties. The terms of the ISDA Agreements provide the Company and its counterparties and brokers
with rights of net settlement of gross commodity derivative assets against gross commodity derivative liabilities. The Company routinely exercises its contractual
right to offset realized gains against realized losses when settling with derivative counterparties. The Company did not incur any losses due to counterparty
bankruptcy filings during any of the years ended December 31, 2017 , 2016 or 2015 .
Credit Risk Related Contingent Features in Derivatives
Certain commodity derivative instruments contain provisions that require the Company to either post additional collateral or immediately settle any
outstanding liability balances upon the occurrence of a specified credit risk related event. These events, which are defined by the existing commodity derivative
contracts, are primarily downgrades in the credit ratings of the Company and its affiliates. None of the Company’s commodity derivative instruments, excluding
net premiums payable, were in a net liability position with respect to any individual counterparty at December 31, 2017 or 2016 .
F-23
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
NOTE 4. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment includes the following (in thousands):
Oil and natural gas properties:
Subject to depletion
Not subject to depletion
Incurred in 2017
Incurred in 2016
Incurred in 2015 and prior
Total not subject to depletion
Oil and natural gas properties, successful efforts method
Less accumulated depreciation, depletion and impairment
Total oil and natural gas properties, net
Other property, plant and equipment
Less accumulated depreciation
Other property, plant and equipment, net
Total property, plant and equipment, net
December 31, 2017
December 31, 2016
$
4,492,802 $
2,376,712
2,837,766
947,210
273,536
4,058,512
8,551,314
(822,459)
7,728,855
131,115
(24,528)
106,587
—
1,215,920
470,785
1,686,705
4,063,417
(506,175)
3,557,242
73,382
(14,064)
59,318
$
7,835,442 $
3,616,560
Costs subject to depletion are proved costs and costs not subject to depletion are unproved costs and current drilling projects. At December 31, 2017 and
2016 , the Company had excluded $4,058.5 million and $1,686.7 million of capitalized costs from depletion.
As the Company’s exploration and development work progresses, and the reserves on the Company’s properties are proven, capitalized costs attributed to
the properties and mineral interests are subject to DD&A. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and
gas reserves related to the associated reservoir. Depletion expense on capitalized oil and gas properties was $340.8 million , $227.2 million and $173.6 million for
the years ended December 31, 2017 , 2016 and 2015 , respectively. The Company had no exploratory wells in progress at December 31, 2017 , 2016 or 2015 .
Costs not subject to depletion primarily include leasehold costs, broker and legal expenses and capitalized internal costs associated with developing oil and
natural gas prospects on these properties. Leasehold costs are transferred into costs subject to depletion on an ongoing basis as these properties are evaluated and
proved reserves are established.
Costs not subject to depletion also include costs associated with development wells in progress or awaiting completion at year-end. These costs are
transferred into costs subject to depletion on an ongoing basis as these wells are completed and proved reserves are established or confirmed. These costs totaled
$94.4 million and $49.4 million at December 31, 2017 and 2016, respectively. The Company anticipates that the $94.4 million associated with the wells in progress
at December 31, 2017 will be transferred to costs subject to depletion during 2017. The $49.4 million associated with the wells in progress at December 31, 2016
was transferred to costs subject to depletion during 2017.
The Company capitalizes interest on expenditures made in connection with long term projects that are not subject to current depletion. Interest is capitalized
only for the period that activities are in progress to bring these projects to their intended use and only to the extent the company has incurred interest
expense. There was no capitalized interest recorded during the year ended December 31, 2017 , 2016 or 2015 .
NOTE 5. ACQUISITIONS OF OIL AND NATURAL GAS PROPERTIES
The Company incurred costs of $194.5 million , $79.1 million and $38.8 million related to the acquisition of leasehold acreage during the years ended
December 31, 2017 , 2016 and 2015 , respectively, which are included as part of costs not subject to depletion. During the year ended December 31, 2017 , the
Company reflected $176.5 million , as part of costs not subject to depletion and $18.0 million , as part of costs subject to depletion within its oil and natural gas
properties.
F-24
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
During 2017, the Company acquired, from unaffiliated individuals and entities, interests in certain oil and natural gas properties through a number of
separate, individually negotiated transactions, including the Double Eagle Acquisition (as defined in Note—1 Organization and Nature of Operations ), for total
consideration of $3,181.1 million . These acquisitions were accounted for using the acquisition method under ASC Topic 805, “Business Combinations,” which
requires the acquired assets and liabilities to be recorded at fair values as of the respective acquisition dates. The Company reflected $464.2 million of the total
consideration paid as part of its costs subject to depletion within its oil and natural gas properties and $2,716.9 million , as unproved leasehold costs within its oil
and natural gas properties for year ended December 31, 2017. Excluding the Double Eagle Acquisition, the revenues and operating expenses attributable to these
acquisitions during the year ended December 31, 2017 were not material.
As described in Note—1 Organization and Nature of Operations, on April 20, 2017, the Company and Parsley LLC completed the Double Eagle
Acquisition, as well as certain related transactions with an affiliate of Double Eagle. The aggregate consideration for the Double Eagle Acquisition, following post-
closing adjustments, was $2,579.1 million , which consisted of (i) approximately $1,395.6 million in cash and (ii) 39,848,518 PE Units and a corresponding
39,848,518 shares of Class B Common Stock. Of the aggregate consideration transferred, approximately $172.3 million in cash and approximately 4,921,557 PE
Units (and a corresponding approximately 4,921,557 shares of Class B Common Stock) were deposited in an indemnity holdback escrow account.
The Company is in the process of identifying and determining the fair values of the assets acquired and liabilities assumed in the Double Eagle Acquisition,
and as a result, the estimates for fair value are subject to change. The Company anticipates certain changes, including, but not limited to, adjustments to working
capital that are expected to be finalized prior to the measurement period’s expiration. The following table summarizes the estimated fair value of the assets
acquired and liabilities assumed as a result of the Double Eagle Acquisition (in thousands):
Cash
Receivables
Derivatives
Proved oil and natural gas properties
Unproved oil and natural gas properties
Total assets acquired
Accounts payable
Deferred tax liability
Total liabilities assumed
Estimated fair value of net assets acquired
$
2,469
20,413
3,970
353,000
2,257,289
2,637,141
(47,859)
(10,167)
(58,026)
$
2,579,115
The Company has included in its consolidated statements of operations revenues of $75.9 million and earnings of $25.9 million for the period of April 20,
2017 to December 31, 2017 due to the Double Eagle Acquisition.
The Double Eagle Acquisition was deemed material for purposes of the following pro forma disclosures. The Double Eagle Acquisition was not included in
the Company’s consolidated results until its closing date.
F-25
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
The following unaudited pro forma information for the years ended December 31, 2017 and 2016 represents the results of the Company’s consolidated
operations as if the Double Eagle Acquisition had occurred on January 1, 2016. This information is based on historical results of operations, adjusted for certain
estimated accounting adjustments and does not purport to show the Company’s actual results of operations if the transaction would have occurred on January 1,
2016, nor is it necessarily indicative of future results. The financial information was derived from the Company’s unaudited historical consolidated financial
statements for the years ended December 31, 2017 and 2016 and Double Eagle’s unaudited interim financial statements from January 1, 2016 to April 20, 2017.
(in thousands, except per share data)
Revenues
Operating income
Net income (loss)
Net income (loss) attributable to Parsley Energy, Inc. Stockholders
Net income (loss) per common share:
Basic
Diluted
Year Ending December 31,
2017
2016
$
986,168 $
494,073
276,015
138,912
105,629
19,284
(116,696)
(86,280)
$
$
0.43 $
0.41 $
(0.44)
(0.44)
During 2016 , the Company acquired from unaffiliated individuals and entities, interests in certain oil and natural gas properties through a number of
separate, individually negotiated transactions for total cash consideration of $1,267.1 million . The Company reflected $261.4 million of the total consideration
paid as part of its costs subject to depletion and $1,005.7 million as unproved leasehold costs within its oil and gas properties. The revenues and operating expenses
attributable to the working interest acquisitions during the years ended December 31, 2017 and 2016 were not material.
During 2017 and 2016, the Company exchanged certain unproved acreage and oil and natural gas properties with a third party, with no gain or loss
recognized.
During 2015 , the Company acquired from unaffiliated individuals and entities, interests in certain oil and natural gas properties through a number of
separate, individually negotiated transactions for total cash consideration of $35.0 million . The Company reflected $16.4 million of the total consideration paid as
part of its costs subject to depletion and $18.6 million as unproved leasehold costs within its oil and gas properties. The revenues and operating expenses
attributable to the working interest acquisitions during the years ended December 31, 2017 , 2016 and 2015 were not material.
NOTE 6. SALES OF OIL AND NATURAL GAS PROPERTIES
In 2017, the Company sold 21,939 gross ( 7,476 net) acres for total proceeds of $30.5 million and recognized a $14.3 million loss on the divestitures.
In 2016, there was no such divestiture activity.
In 2015, the Company sold its interest in 91 net operated wells and 25,077 gross ( 16,319 net) acres for total proceeds of $48.7 million and recognized a
$33.5 million loss on the divestitures.
Assets Held For Sale
As of December 31, 2017 , certain assets and related liabilities (the “Assets Held For Sale”) were classified as held for sale due to a pending divestiture.
Upon the classification change occurring on December 31, 2017 , the Company ceased recording depletion on the Assets Held For Sale. Based on the Company’s
anticipated sales price and historical cost, the Company will not recognize an impairment charge at December 31, 2017 .
F-26
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
The following table presents balance sheet information related to the Assets Held for Sale:
Assets:
Accounts receivable, net
Oil and natural gas properties
Proved oil and natural gas properties
Less: Accumulated depreciation, depletion and amortization
Oil and natural gas properties, net
Total assets held for sale, net
Liabilities:
Asset retirement obligations
Total liabilities related to assets held for sale
NOTE 7. DEBT
The Company’s debt consists of the following (in thousands):
Revolving Credit Agreement
7.500% senior unsecured notes due 2022
6.250% senior unsecured notes due 2024
5.375% senior unsecured notes due 2025
5.250% senior unsecured notes due 2025
5.625% senior unsecured notes due 2027
Capital leases
Other
Total debt
Debt issuance costs on senior unsecured notes
Premium on senior unsecured notes
Less: current portion
Total long-term debt
Revolving Credit Agreement
$
$
$
1,790
18,435
(3,450)
14,985
16,775
405
405
$
December 31, 2017
December 31, 2016
— $
—
400,000
650,000
450,000
700,000
4,906
—
—
61,846
400,000
650,000
—
—
3,752
3,500
2,204,906
1,119,098
(26,341)
3,312
(2,352)
(14,388)
3,828
(67,214)
$
2,179,525 $
1,041,324
On October 28, 2016, the Company and its subsidiary Parsley LLC entered into a new revolving credit agreement with, among others, Wells Fargo Bank,
National Association, as administrative agent (the “New Revolving Credit Agreement”), providing for an initial borrowing base of $900.0 million and an initial
commitment level of $600.0 million . The Revolving Credit Agreement replaced the Company’s previously existing amended and restated revolving credit
agreement with, among others, Wells Fargo Bank, National Association, as administrative agent, which was terminated concurrently with entry into the New
Revolving Credit Agreement. As used in these consolidated financial statements, the term “Revolving Credit Agreement” refers, prior to October 28, 2016, to the
previously existing amended and restated credit agreement and, subsequent to October 28, 2016, to the New Revolving Credit Agreement.
The Revolving Credit Agreement provides for a five -year senior secured revolving credit facility, maturing on October 28, 2021, with a borrowing capacity
of the lesser of (i) the borrowing base, (ii) aggregate elected borrowing base commitments and (iii) $2.5 billion . The Revolving Credit Agreement is secured by
substantially all of Parsley LLC’s and its restricted subsidiaries’ assets.
F-27
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
As of December 31, 2017 , the Revolving Credit Agreement, as amended to date, provides for a borrowing base of $1.8 billion , which will continue to be
redetermined by the lenders on a semi-annual basis each April 1 and October 1, with a commitment level of $1.0 billion . There were no borrowings outstanding
and $2.7 million in letters of credit outstanding under the Revolving Credit Agreement as of December 31, 2017 , resulting in availability of approximately $997.3
million . The amount Parsley LLC is able to borrow under the Revolving Credit Agreement is subject to compliance with the financial covenants, satisfaction of
various conditions precedent to borrowing and other provisions of the Revolving Credit Agreement.
Borrowings under the Revolving Credit Agreement can be made in Eurodollars or at the alternate base rate. Eurodollar loans bear interest at a rate per
annum equal to an adjusted LIBO rate plus an applicable margin ranging from 1.5% to 2.5% , depending on the percentage of the borrowing base utilized.
Alternate base rate loans bear interest at a rate per annum equal to the greater of (i) the prime rate of Wells Fargo, (ii) the federal funds effective rate plus 0.5% and
(iii) the adjusted LIBO rate plus 1.0% , plus an applicable margin ranging from 0.5% to 1.5% , depending on the percentage of the borrowing base utilized. The
Revolving Credit Agreement also provides for a commitment fee ranging from 0.375% to 0.500% , depending on the percentage of the borrowing base utilized. As
of December 31, 2017 , letters of credit outstanding under the Revolving Credit Agreement had a weighted average interest rate of 1.50% . The Company may
repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs.
The Revolving Credit Agreement is subject to various financial covenants, which include, for example, the maintenance of the following financial ratios:
• a minimum current ratio (based on the ratio of consolidated current assets to consolidated current liabilities) of not less than 1.0 to 1.0 as of the last
day of any fiscal quarter; and
• a maximum Consolidated Leverage Ratio of not more than 4.0 to 1.0 as of the last day of any fiscal quarter for the four fiscal quarters ending on
such date.
The Revolving Credit Agreement places restrictions on Parsley LLC and certain of its subsidiaries with respect to, for example, additional indebtedness,
liens, dividends and other payments, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters. The
Revolving Credit Agreement also places customary “holding company” restrictions on the activities of the Company.
Redemption of 2022 Notes
On December 6, 2016, Parsley LLC commenced a cash tender offer (the “Tender Offer”) to purchase any and all of the Company’s 7.500% senior
unsecured notes due 2022 (the “2022 Notes”). On December 13, 2016, the Tender Offer expired and, at such time, $487.7 million aggregate principal amount of
the 2022 Notes was validly tendered (which did not include $1.2 million aggregate principal amount of the 2022 Notes that remained subject to guaranteed delivery
procedures). Parsley LLC accepted all of the 2022 Notes validly tendered and not validly withdrawn in the Tender Offer and, on December 13, 2016, made a cash
payment of $537.1 million , which included principal of $487.7 million , a prepayment premium on the extinguishment of debt of $32.5 million , accrued interest
of $12.0 million and other debt issuance costs of $4.9 million . On December 15, 2016, Parsley LLC made a cash payment of $0.5 million for the tender of an
additional $0.4 million aggregate principal amount of the 2022 Notes and $0.1 million of prepayment premium on the extinguishment of debt and accrued interest.
On January 5, 2017, Parsley LLC redeemed $61.8 million aggregate principal of the 2022 Notes that remained outstanding and made a cash payment of $67.5
million to the remaining holders of the 2022 Notes, which included principal of $61.8 million , prepayment premium on the extinguishment of debt of $3.9 million
and accrued interest of $1.8 million . During the years ended December 31, 2017 and 2016, the Company recognized a loss on extinguishment of debt of $3.9
million and $36.3 million , respectively, which are included in Prepayment premium on extinguishment of debt on the Company’s consolidated statements of
operations and in operating activities on the Company’s statements of cash flows.
6.250% Senior Unsecured Notes due 2024
On May 27, 2016, Parsley LLC and Parsley Finance Corp. (the “Issuers”) issued $200.0 million aggregate principal amount of 6.250% senior unsecured
notes due 2024 (the “Initial 2024 Notes”) in an offering that was exempt from registration under the Securities Act (the “Initial 2024 Notes Offering”). The Initial
2024 Notes Offering resulted in net proceeds to the Company, after deducting initial purchaser discounts and commissions and offering expenses, of approximately
$195.4 million .
F-28
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
On August 19, 2016, the Issuers issued an additional $200.0 million aggregate principal amount of 6.250% senior notes due 2024 (the “New 2024 Notes”
and together with the Initial 2024 Notes, the “2024 Notes”) at 102.000% of par, plus accrued and unpaid interest from May 27, 2016, in an offering that was
exempt from registration under the Securities Act (the “New 2024 Notes Offering”). The New 2024 Notes were issued as additional notes under the indenture
governing the Initial 2024 Notes. The New 2024 Notes have identical terms, other than the issue date, as the Initial 2024 Notes and the New 2024 Notes and Initial
2024 Notes will be treated as a single class of securities under the indenture governing the 2024 Notes. Interest is payable on the 2024 Notes semi-annually in
arrears on each June 1 and December 1 and commenced December 1, 2016. The 2024 Notes are fully and unconditionally guaranteed on a senior unsecured basis
by all of the subsidiaries of Parsley LLC that guarantee the indebtedness under the Revolving Credit Agreement, other than Finance Corp. (the “Guarantor
Subsidiaries”). The 2024 Notes are not guaranteed by the Company and the Company is not subject to the terms of the indenture governing the 2024 Notes. The
New 2024 Notes Offering resulted in gross proceeds to the Company of $206.8 million , including a $4.0 million premium and $2.8 million of accrued and unpaid
interest and net proceeds to the Company, after deducting accrued and unpaid interest, initial purchaser discounts and commissions and offering expenses, of
approximately $199.6 million . The interest received is included in Accounts payable and accrued expenses on the Company’s consolidated balance sheets and as
an operating activity on the consolidated statements of cash flows.
At any time prior to June 1, 2019, the Issuers may, from time to time, redeem up to 35% of the aggregate principal amount of the 2024 Notes with an
amount of cash not greater than the net cash proceeds of certain equity offerings at a redemption price equal to 106.250% of the principal amount of the 2024 Notes
redeemed, plus accrued and unpaid interest, if any, to the date of redemption, provided that at least 65% of the aggregate principal amount issued under the
indenture governing the 2024 Notes remains outstanding immediately after such redemption and the redemption occurs within 120 days of the closing date of such
equity offering. Prior to June 1, 2019, the Issuers may, on any one or more occasions, redeem all or a part of the 2024 Notes for cash at a redemption price equal to
100% of the principal amount of the 2024 Notes redeemed, plus a “make-whole” premium as of and accrued and unpaid interest, if any, to, the date of redemption.
On and after June 1, 2019, the Issuers may redeem the 2024 Notes, in whole or in part, at redemption prices (expressed as percentages of principal amount) equal to
104.688% for the 12-month period beginning on June 1, 2019, 103.125% for the 12-month period beginning June 1, 2020, 101.563% for the 12-month period
beginning on June 1, 2021 and 100% beginning on June 1, 2022, plus accrued and unpaid interest to the redemption date.
The indenture governing the 2024 Notes contains covenants that, among other things and subject to certain exceptions and qualifications, limit the Issuers’
ability and the ability of their restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends on
capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens;
(vi) enter into agreements that restrict dividends or other payments from their subsidiaries to them; (vii) consolidate, merge or transfer all or substantially all of
their assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries.
5.375% Senior Unsecured Notes due 2025
On December 13, 2016, the Issuers issued $650.0 million aggregate principal amount of 5.375% senior unsecured notes due 2025 (the “2025 Notes”) in an
offering that was exempt from registration under the Securities Act (the “2025 Notes Offering”). Interest is payable on the 2025 Notes semi-annually in arrears on
each January 15 and July 15, commencing July 15, 2017. The 2025 Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Guarantor
Subsidiaries. The 2025 Notes are not guaranteed by the Company and the Company is not subject to the terms of the indenture governing the 2025 Notes. The 2025
Notes Offering resulted in gross proceeds to the Company of $650.0 million and net proceeds to the Company, after deducting initial purchaser discounts and
commissions and offering expenses, of approximately $644.1 million .
At any time prior to January 15, 2020, the Issuers may, from time to time, redeem up to 35% of the aggregate principal amount of the 2025 Notes with an
amount of cash not greater than the net cash proceeds of certain equity offerings at a redemption price equal to 105.375% of the principal amount of the 2025 Notes
redeemed, plus accrued and unpaid interest, if any, to the date of redemption, provided that at least 65% of the aggregate principal amount issued under the
indenture governing the 2025 Notes remains outstanding immediately after such redemption and the redemption occurs within 120 days of the closing date of such
equity offering. Prior to January 15, 2020, the Issuers may, on any one or more occasions, redeem all or a part of the 2025 Notes at a redemption price equal to
100% of the principal amount of the 2025 Notes redeemed, plus a “make-whole” premium as of and accrued and unpaid interest, if any, to, the date of redemption.
On and after January 15, 2020, the Issuers may redeem the 2025 Notes, in whole or in part, at redemption prices (expressed as percentages of principal amount)
equal to 104.031% for the 12-month period beginning on January 15, 2020, 103.750% for the 12-month period
F-29
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
beginning January 15, 2021, 101.344% for the 12-month period beginning on January 15, 2022 and 100% beginning on January 15, 2023, plus accrued and unpaid
interest to the redemption date.
The indenture governing the 2025 Notes contains covenants that, among other things and subject to certain exceptions and qualifications, limit the Issuers’
ability and the ability of their restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends on
capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens;
(vi) enter into agreements that restrict dividends or other payments from their subsidiaries to them; (vii) consolidate, merge or transfer all or substantially all of
their assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries.
5.250% Senior Unsecured Notes due 2025
On February 13, 2017, the Issuers issued $450.0 million aggregate principal amount of 5.250% senior unsecured notes due 2025 (the “New 2025 Notes”) in
an offering that was exempt from registration under the Securities Act (the “New 2025 Notes Offering”). Interest is payable on the New 2025 Notes semi-annually
in arrears on each February 15 and August 15, commencing August 15, 2017. The New 2025 Notes are fully and unconditionally guaranteed on a senior unsecured
basis by the Guarantor Subsidiaries. The New 2025 Notes are not guaranteed by the Company and the Company is not subject to the terms of the indenture
governing the New 2025 Notes. The New 2025 Notes Offering resulted in net proceeds to the Company, after deducting initial purchaser discounts and
commissions and offering expenses, of approximately $444.1 million .
At any time prior to August 15, 2020, the Issuers may, from time to time, redeem up to 35% of the aggregate principal amount of the New 2025 Notes
with an amount of cash not greater than the net cash proceeds of certain equity offerings at a redemption price equal to 105.250% of the principal amount of the
New 2025 Notes redeemed, plus accrued and unpaid interest, if any, to the date of redemption, provided that at least 65% of the aggregate principal amount issued
under the indenture governing the New 2025 Notes remains outstanding immediately after such redemption and the redemption occurs within 120 days of the
closing date of such equity offering. Prior to August 15, 2020, the Issuers may, on any one or more occasions, redeem all or a part of the New 2025 Notes at a
redemption price equal to 100% of the principal amount of the New 2025 Notes redeemed, plus a “make-whole” premium as of and accrued and unpaid interest, if
any, to, the date of redemption. On and after January 15, 2020, the Issuers may redeem the New 2025 Notes, in whole or in part, at redemption prices (expressed as
percentages of principal amount) equal to 103.938% for the 12-month period beginning on August 15, 2020, 102.625% for the 12-month period beginning
August 15, 2021, 101.313% for the 12-month period beginning on August 15, 2022 and 100% beginning on August 15, 2023, plus accrued and unpaid interest to
the redemption date.
The indenture governing the New 2025 Notes contains covenants that, among other things and subject to certain exceptions and qualifications, limit the
Issuers’ ability and the ability of their restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay
dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create
certain liens; (vi) enter into agreements that restrict dividends or other payments from their subsidiaries to them; (vii) consolidate, merge or transfer all or
substantially all of their assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries.
5.625% Senior Unsecured Notes due 2027
On October 11, 2017, the Issuers issued $700.0 million aggregate principal amount of 5.625% senior unsecured notes due 2027 (the “2027 Notes” and
together with the 2024 Notes, the 2025 Notes and the New 2025 Notes, the “Notes”) in an offering that was exempt from registration under the Securities Act (the
“2027 Notes Offering”). Interest is payable on the 2027 Notes semi-annually in arrears on each April 15 and October 15, commencing April 15, 2018. The 2027
Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Guarantor Subsidiaries. The 2027 Notes are not guaranteed by the Company and
the Company is not subject to the terms of the indenture governing the 2027 Notes. The 2027 Notes Offering resulted in gross proceeds to the Company of $700.0
million and net proceeds to the Company, after deducting initial purchaser discounts and commissions and offering expenses, of approximately $692.1 million .
At any time prior to October 15, 2020, the Issuers may, from time to time, redeem up to 35% of the aggregate principal amount of the 2027 Notes with an
amount of cash not greater than the net cash proceeds of certain equity offerings at a redemption price equal to 105.625% of the principal amount of the 2027 Notes
redeemed, plus accrued and unpaid interest, if any, to the date of redemption, provided that at least 65% of the aggregate principal amount issued under the
indenture
F-30
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
governing the 2027 Notes remains outstanding immediately after such redemption and the redemption occurs within 120 days of the closing date of such equity
offering. Prior to October 15, 2020, the Issuers may, on any one or more occasions, redeem all or a part of the 2027 Notes at a redemption price equal to 100% of
the principal amount of the 2027 Notes redeemed, plus a “make-whole” premium as of and accrued and unpaid interest, if any, to, the date of redemption. On and
after October 15, 2022, the Issuers may redeem the 2027 Notes, in whole or in part, at redemption prices (expressed as percentages of principal amount) equal to
102.813% for the 12-month period beginning on October 15, 2022, 101.875% for the 12-month period beginning October 15, 2023, 100.938% for the 12-month
period beginning on October 15, 2024 and 100% beginning on October 15, 2025, plus accrued and unpaid interest to the redemption date.
The indenture governing the 2027 Notes contains covenants that, among other things and subject to certain exceptions and qualifications, limit the Issuers’
ability and the ability of their restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends on
capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens;
(vi) enter into agreements that restrict dividends or other payments from their subsidiaries to them; (vii) consolidate, merge or transfer all or substantially all of
their assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries.
At December 31, 2017 , the Company was in compliance with all required covenants under the Revolving Credit Agreement and each of the indentures
governing the Notes. The Revolving Credit Agreement is subject to customary events of default, including a change in control (as defined in the Revolving Credit
Agreement). If an event of default occurs and is continuing, the administrative agent or the Majority Lenders (as defined in the Revolving Credit Agreement) may
accelerate any amounts outstanding and terminate lender commitments. If at any time when the Notes are rated investment grade by either Moody’s Investors
Service, Inc. or Standard & Poor’s Ratings Services and no default or event of default (as defined in the indentures governing the Notes) has occurred and is
continuing, many of such covenants will be suspended. If the ratings on the Notes were to decline subsequently to below investment grade, the suspended
covenants would be reinstated.
Principal Maturities of Debt
Principal maturities debt outstanding at December 31, 2017 are as follows (in thousands):
2018
2019
2020
2021
2022
Thereafter
Total
Interest Expense
$
$
2,352
1,906
617
17
14
2,200,000
2,204,906
The following amounts have been incurred and charged to interest expense for the year ended December 31, 2017 , 2016 and 2015 (in thousands):
Cash payments for interest
Change in interest accrual
Amortization of deferred loan origination costs
Write-off of deferred loan origination costs
Amortization of bond premium
Total interest expense, net
Year ended December 31,
2017
2016
2015
$
63,170 $
30,007
3,985
735
(516)
65,513 $
(11,604)
2,739
451
(874)
$
97,381 $
56,225 $
43,993
(350)
2,170
532
(764)
45,581
F-31
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
NOTE 8. EQUITY
Preferred Stock
Pursuant to the Company’s amended and restated bylaws, the Company’s board of directors, subject to any limitations prescribed by law, may, without
further stockholder approval, establish and issue from time to time one or more classes or series of preferred stock, par value $0.01 per share, covering up to an
aggregate of 50.0 million shares of preferred stock. The Company had no shares of preferred stock outstanding at December 31, 2017 and 2016 .
Class A Common Stock
The Company has 252.3 million shares of its Class A Common Stock outstanding as of December 31, 2017 , which includes 0.8 million shares of restricted
stock. Holders of Class A Common Stock are entitled to one vote per share on all matters to be voted upon by the stockholders and are entitled to ratably receive
dividends when and if declared by the Company’s board of directors. Upon liquidation, dissolution, distribution of assets or other winding up, the holders of Class
A Common Stock are entitled to receive ratably the assets available for distribution to the stockholders after payment of liabilities and the liquidation preference of
any of the Company’s outstanding shares of preferred stock.
Class B Common Stock
The Company has 62.1 million shares of its Class B Common Stock outstanding as of December 31, 2017 . Holders of the Class B Common Stock are
entitled to one vote per share on all matters to be voted upon by the stockholders. Holders of Class A Common Stock and Class B Common Stock vote together as
a single class on all matters presented to the Company’s stockholders for their vote or approval, except with respect to the amendment of certain provisions of the
Company’s certificate of incorporation that would alter or change the powers, preferences or special rights of the Class B Common Stock so as to affect them
adversely, which amendments must be by a majority of the votes entitled to be cast by the holders of the shares affected by the amendment, voting as a separate
class, or as otherwise required by applicable law.
Holders of Class B Common Stock do not have any right to receive dividends, unless the dividend consists of shares of Class B Common Stock or of rights,
options, warrants or other securities convertible or exercisable into or exchangeable for shares of Class B Common Stock paid proportionally with respect to each
outstanding share of Class B Common Stock and a dividend consisting of shares of Class A Common Stock or of rights, options, warrants or other securities
convertible or exercisable into or exchangeable for shares of Class A Common Stock on the same terms is simultaneously paid to the holders of Class A Common
Stock. Holders of Class B Common Stock do not have any right to receive a distribution upon a liquidation or winding up of the Company.
Earnings per Share
Basic earnings per share (“EPS”) measures the performance of an entity over the reporting period. Diluted earnings per share measures the performance of
an entity over the reporting period while giving effect to all potentially dilutive common shares that were outstanding during the period. The Company uses the “if-
converted” method to determine the potential dilutive effect of exchanges of outstanding PE Units (and corresponding shares of its outstanding Class B Common
Stock), and the treasury stock method to determine the potential dilutive effect of vesting of its outstanding restricted stock and restricted stock units. For the years
ended December 31, 2016 and 2015, Class B Common Stock and time-based restricted stock were not recognized in dilutive EPS calculations as they would have
been antidilutive.
F-32
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
The following table reflects the allocation of net income (loss) to common stockholders and EPS computations for the periods indicated based on a weighted
average number of common stock outstanding for the period:
December 31, 2017
December 31, 2016
December 31, 2015
Basic EPS (in thousands, except per share data)
Numerator:
Basic net income (loss) attributable to Parsley Energy, Inc.
Stockholders
Denominator:
Basic weighted average shares outstanding
Basic EPS attributable to Parsley Energy, Inc. Stockholders
$
$
Diluted EPS
Numerator:
106,774 $
(74,182) $
(50,484)
240,733
0.44 $
161,793
(0.46) $
111,271
(0.45)
(50,484)
—
(50,484)
Net income (loss) attributable to Parsley Energy, Inc. Stockholders
Effect of conversion of the shares of Company’s Class B Common
Stock to shares of the Company’s Class A Common Stock
Diluted net income (loss) attributable to Parsley Energy, Inc.
106,774
17,646
(74,182)
—
Stockholders
Denominator:
$
124,420 $
(74,182) $
Basic weighted average shares outstanding
240,733
161,793
111,271
Effect of dilutive securities:
Class B Common Stock
Time-Based Restricted Stock and Time-Based Restricted Stock
Units
Diluted weighted average shares outstanding (1)
Diluted EPS attributable to Parsley Energy, Inc. Stockholders
$
54,665
1,114
296,512
0.42 $
—
—
161,793
(0.46) $
—
—
111,271
(0.45)
Approximately 640,062 , 453,863 and 211,935 shares related to performance-based restricted stock units that could be converted to common shares in
(1)
the future based on predetermined performance and market goals were not included in the computation of EPS for the year ended December 31, 2017 , 2016 and
2015, because the performance and market conditions had not been met, assuming the end of the reporting period was the end of the contingency period.
Noncontrolling Interest
Concurrent with the closing of the Pacesetter Acquisition, Pacesetter’s President acquired a 37.0% interest in Pacesetter, with Parsley Energy Operations,
LLC (“Operations”), a wholly owned subsidiary of Parsley LLC, retaining 63.0% of Pacesetter. As a result, the Company has consolidated the financial position
and results of operations of Pacesetter due to Operations’ ownership interest. The 37.0% interest retained by Pacesetter’s President is reflected as a noncontrolling
interest.
As a result of the 2015 Equity Offerings, the Company’s ownership of Parsley LLC increased from 74.3% to 81.0% and the ownership of the other holders
of PE Units (the “PE Unit Holders”) of Parsley LLC decreased from 25.7% to 19.0% of Parsley LLC. During the year ended December 31, 2015, no PE Unit
Holders elected to exchange pursuant to their Exchange Right (as defined in Note 11—Related Party Transactions ).
During the year ended December 31, 2016, certain PE Unit Holders exercised their Exchange Right under the Parsley LLC Agreement, collectively electing
to exchange an aggregate of 4.1 million PE Units (and a corresponding number of shares of Class B Common Stock) for an aggregate of 4.1 million shares of Class
A Common Stock (collectively, the “2016 Exchanges”). In turn, the Company exercised its call right under the Parsley LLC Agreement, electing to issue Class A
Common Stock directly to each of the exchanging PE Unit Holders in satisfaction of their election notices. As a result of the
F-33
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
2016 Equity Offerings and the 2016 Exchanges, the Company’s ownership of Parsley LLC increased from 81.0% to 86.5% and the PE Unit Holders’ ownership of
Parsley LLC decreased from 19.0% to 13.5% .
As a result of the 2017 Equity Offerings, the Company’s ownership of Parsley LLC increased from 86.5% to 89.8% and the PE Unit Holders’ ownership of
Parsley LLC decreased from 13.5% to 10.2% . Subsequently, as a result of the consummation of the Double Eagle Acquisition, the Company’s ownership of
Parsley LLC decreased from 89.8% to 78.4% and the PE Unit Holders’ ownership of Parsley LLC increased from 10.2% to 21.6% . Any impact to additional paid
in capital as a result of the 2017 Equity Offerings was completely offset by a valuation allowance.
During the year ended December 31, 2017, certain PE Unit Holders exercised their Exchange Right under the Parsley LLC Agreement, collectively electing
to exchange an aggregate of 5.7 million PE Units (and a corresponding number of shares of Class B Common Stock) for an aggregate of 5.7 million shares of Class
A Common Stock (collectively, the “2017 Exchanges”). In turn, the Company exercised its call right under the Parsley LLC Agreement, electing to issue Class A
Common Stock directly to each of the exchanging PE Unit Holders in satisfaction of their election notices. As a result of the 2017 Exchanges, the Company’s
ownership of Parsley LLC increased from 78.4% to 80.2% and the PE Unit Holders’ ownership of Parsley LLC decreased from 21.6% to 19.8% .
Because the changes in the Company’s ownership interest of Parsley LLC do not result in a change of control, the transaction is accounted for as an equity
transaction under ASC Topic 810, Consolidation , which requires that any differences between the amount by which the carrying value of the Company’s basis in
Parsley LLC is adjusted and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest.
The Company has consolidated the financial position and results of operations of Parsley LLC and reflected that portion retained by the PE Unit Holders as
a noncontrolling interest.
The following table summarizes the net income (loss) attributable to noncontrolling interests:
Net income (loss) attributable to the noncontrolling interests of:
Parsley LLC
Pacesetter Drilling, LLC
Total net income (loss) attributable to noncontrolling interests
NOTE 9. STOCK-BASED COMPENSATION
Year ended December 31,
2017
2016
2015
(in thousands)
$
$
17,645 $
(14,953) $
(499)
218
17,146 $
(14,735) $
(21,870)
(677)
(22,547)
In connection with the Company’s initial public offering (“IPO”), the Company adopted the Parsley Energy, Inc. 2014 Long Term Incentive Plan (“LTIP”)
for employees and directors of the Company who perform services for the Company. The shares to be delivered under the LTIP shall be made available from (i)
authorized but unissued shares, (ii) shares held as treasury stock or (iii) previously issued shares reacquired by the Company including shares purchased on the
open market. A total of 12.7 million shares of Class A Common Stock have been authorized for issuance under the LTIP. At December 31, 2017 , the Company
had 10.0 million shares of Class A Common Stock available for future grant.
F-34
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
The following table reflects stock-based compensation expense recorded for each type of stock-based compensation award for the years ended
December 31, 2017 , 2016 and 2015 (in thousands):
Time-based restricted stock
Time-based restricted stock units
Performance-based restricted stock units
Total stock-based compensation expense
Year ended December 31,
2017
2016
2015
$
$
5,492 $
7,778
6,349
19,619 $
3,523 $
5,677
3,671
12,871 $
3,856
2,710
1,567
8,133
(1) Stock-based compensation expense on time-based restricted stock units with graded vesting is recognized on a straight-line basis over the requisite service
period for each separately vesting portion of the award as if the award was, in-substance, multiple awards.
Stock-based compensation is included in General and administrative expenses on the Company’s consolidated statement of operations.
Time-Based Restricted Stock
Time-based restricted stock are awards of Class A Common Stock that are legally issued and outstanding (“RSA”). RSAs are subject to restrictions on
transfer and to a risk of forfeiture if the award recipient is no longer an employee or director of the Company for any reason prior to the lapse of the restrictions.
The stock-based compensation expense for these awards was determined using the closing price on the date of grant applied to the total number of shares that were
anticipated to fully vest. The following table summarizes the RSA activity for the year ended December 31, 2017 :
Outstanding at January 1, 2017
Awards granted
Forfeited
Vested
Outstanding at December 31, 2017
Time-Based Restricted Stock Units
Time-Based Restricted
Stock
Grant Date Fair Value
600,761 $
227,564 $
(41,014) $
(7,965) $
779,346 $
19.02
31.55
26.84
18.14
22.30
Time-based restricted stock units (“RSU”) represent the right to receive Class A Common Stock at the end of the vesting period equal to the number of
RSUs granted. RSUs are subject to restrictions on transfer and are generally subject to a risk of forfeiture if the award recipient is no longer an employee or director
of the Company for any reason prior to the lapse of the restriction. The stock-based compensation expense of such RSUs was determined using the closing price on
the date of grant applied to the total number of shares that were anticipated to fully vest. The following table summarizes the RSU activity for the year ended
December 31, 2017 :
Outstanding at January 1, 2017
Awards granted
Forfeited
Vested
Outstanding at December 31, 2017
Time-Based Restricted
Stock Units
Grant Date Fair Value
1,045,786 $
209,186 $
(33,170) $
(22,083) $
1,199,719 $
16.96
31.86
22.69
22.77
19.36
F-35
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
Performance-Based Restricted Stock Units
During 2017 , 2016 and 2015 , performance-based, stock-settled restricted stock unit awards (“PSU”) were granted with a performance period of three years
. The number of shares of Class A Common Stock actually delivered pursuant to these PSUs depends on the performance of the Company’s Class A Common
Stock over the performance period in relation to the performance of the common stock of a predetermined peer group. The conditions of the grants allow for an
actual payout ranging between no payout and 200% of target. The payout level is calculated based on actual performance achieved during the performance period
compared to a defined peer group. The fair value of such PSUs was determined using a Monte Carlo simulation and will be recognized over the next three
years. The Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award
grant and calculates the fair value of the award. Expected volatilities in the model were estimated using a historical period consistent with the performance period
of approximately three years. The risk-free interest rate was based on the United States Treasury rate for a term commensurate with the expected life of the grant.
The Company used the following assumptions to estimate the fair value of PSUs granted during the periods indicated:
Risk-free interest rate
Range of volatilities
The following table summarizes the PSU activity for the year ended December 31, 2017 :
Year Ended December 31,
2017
2016
2015
1.45%
0.88%
1.05%
37.7% - 79.5%
35.0% - 65.1%
42.2% - 84.8%
Outstanding at January 1, 2017
Awards granted
Outstanding at December 31, 2017
Performance-Based
Restricted Units
Grant Date Fair Value
25.06
453,863 $
186,199 $
640,062 $
42.40
30.11
The following table reflects the future stock-based compensation expense to be recorded for the stock-based compensation awards that were outstanding at
December 31, 2017 (in thousands):
2018
2019
2020
Total
Incentive Units
Time-Based Restricted
Stock
Time-Based Restricted
Stock Units
Performance-Based
Restricted Units
Total
$
$
3,537 $
1,977
255
5,769 $
5,292 $
2,403
259
7,954 $
4,923 $
2,753
8
7,684 $
13,752
7,133
522
21,407
Pursuant to the Parsley LLC Agreement, certain incentive units were issued to legacy investors, management and employees of Parsley LLC. The incentive
units were intended to be compensation for services rendered to Parsley LLC. The original terms of the incentive units were as follows: Tier I incentive units vested
ratably over three years , but were subject to forfeiture if payout was not achieved. In addition, all unvested Tier I incentive units vested immediately upon Tier I
payout. Tier I payout was realized upon the return of the Preferred Holders’ invested capital and a specified rate of return. Tier II, III and IV incentive units vested
only upon the achievement of certain payout thresholds for each such tier and each tier of the incentive units was subject to forfeiture if the applicable required
payouts were not achieved. In addition, vested and unvested incentive units would be forfeited if an incentive unit holder’s employment was terminated for any
reason or if the incentive unit holder voluntarily terminated their employment.
The incentive units were accounted for as liability-classified awards pursuant to ASC Topic 718, Compensation—Stock Compensation, as achievement of
the payout conditions required the settlement of such awards by transferring cash to the incentive unit holder. As such, the fair value of the incentive unit was
remeasured each reporting period through the date of
F-36
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
settlement, with the percentage of such fair value recorded to compensation expense each period being equal to the percentage of the requisite explicit or implied
service period that has been rendered at that date.
NOTE 10. INCOME TAXES
The Company is a corporation and is subject to U.S. federal income tax and the Texas Margins Tax. On December 22, 2017, the Tax Act was enacted by the
U.S. government. The Tax Act significantly impacts the Company’s 2017 effective tax rate and made broad and complex changes to the U.S. corporate income tax
code. Among other changes, the Tax Act: (i) reduces the U.S. federal corporate income tax rate from 35% to 21%; (ii) repeals the corporate alternative minimum
tax and provides for a refund of previously accrued alternative minimum tax credits; (iii) modifies the provisions relating to the limitations on deductions for
executive compensation of publicly traded corporations; (iv) enacts new limitations regarding the deductibility of interest expense and (v) imposes new limitations
on the utilization of net operating losses arising in taxable years beginning after December 31, 2017.
GAAP requires that the impact of tax legislation be recognized in the period in which the law was enacted. As a result of the Tax Act, the Company
remeasured its deferred tax assets and liabilities based on the federal income and state income tax rates at which they are now expected to reverse, and they now
generally reflect a federal income tax rate of 21%. The enacted rate change resulted in a noncash increase of approximately $23.9 million to the Company’s income
tax provision, a corresponding reduction of $23.9 million to the Company’s net noncurrent deferred tax asset balance and a reduction in valuation allowance of
$24.3 million December 31, 2017 . Any adjustments recorded to these estimates through 2018 will be included in income from operations as an adjustment to tax
expense. The ultimate impact of the Tax Act may differ from the Company’s estimates based on the Company’s further analysis of the new law and additional
regulatory guidance that may be issued. Further, the amount of the Company’s future federal income tax will be dependent upon its future taxable income.
The Company’s effective combined U.S. federal and state income tax rate as of December 31, 2017 , 2016 and 2015 was 4.4% , 16.4% and 24.5%
respectively.
During the years ended December 31, 2017 , 2016 and 2015 , the Company recognized an income tax expense of $5.7 million and income tax benefits of
$17.4 million and $23.8 million , respectively. Total income tax differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income
due primarily to the change in the valuation allowance, the change in the TRA liability, state taxes and the impact of income (loss) attributable to noncontrolling
ownership interests.
At December 31, 2017 , the Company did not have any accrued liability for uncertain tax positions and does not anticipate recognition of any significant
liabilities for uncertain tax positions during the next 12 months. The Company’s policy is to record interest and penalties relating to uncertain tax positions in
income tax expense.
The components of the income tax expense (benefit) were as follows for the periods indicated (in thousands):
Federal:
Current
Deferred
Total federal
State, net of federal benefit:
Deferred
Total state
Income tax expense (benefit)
Year Ended December 31,
2017
2016
2015
$
(44) $
(423)
(467)
6,175
6,175
158 $
(18,461)
(18,303)
879
879
286
(27,535)
(27,249)
3,494
3,494
$
5,708 $
(17,424) $
(23,755)
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PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
The following table reconciles the income tax expense (benefit) with income tax expense at the federal statutory rate for the periods indicated (in
thousands):
Income (loss) before income taxes
Less: net loss (income) before income taxes attributable
to noncontrolling interest
Income (loss) attributable to Parsley Energy, Inc. Stockholders before income taxes
Income taxes at the federal statutory rate
State income taxes, net of federal benefit
Provision to return adjustment
Permanent and other
TRA Liability change
Valuation allowance
Valuation allowance charged to equity
Valuation allowance due to the reduction in federal statutory rate
Income tax provision due to change in federal statutory rate
Income tax expense (benefit)
Net income (loss) attributable to Parsley Energy, Inc. Stockholders
Net income (loss) attributable to noncontrolling interest
Year Ended December 31,
2017
2016
2015
$
129,628 $
(106,341) $
(96,785)
(18,725)
110,903
38,816
6,175
178
166
(12,547)
(26,657)
—
(24,356)
23,933
14,579
(91,762)
(32,120)
879
(237)
(61)
(2,573)
32,215
(15,527)
—
—
22,438
(74,347)
(26,022)
3,494
(1,217)
(10)
—
—
—
—
—
$
$
$
5,708 $
(17,424) $
(23,755)
106,774 $
17,146 $
(74,182) $
(14,735) $
(50,484)
(22,547)
As of December 31, 2017 , the Company had approximately $0.4 million of alternative minimum tax credits available that are expected to be refunded
between 2018 and 2021 as a result of the Tax Act. In addition, the Company had approximately $229.1 million of federal net operating loss carryovers that expire
during the years 2034 through 2037 . The tax benefits of carryforwards are recorded as an asset to the extent that management assesses the utilization of such
carryforwards to be more likely than not. When the future utilization of some portion of the carryforwards is determined not be more likely than not, a valuation
allowance is provided to reduce the recorded tax benefits from such assets. As of December 31, 2017 , the Company had a valuation allowance of $9.3 million as a
result of management’s assessment of the realizability of deferred tax assets.
Internal Revenue Code (“IRC”) Section 382 addresses company ownership changes and specifically limits the utilization of certain deductions and other tax
attributes on an annual basis following an ownership change. The Company does not believe it experienced an ownership change within the meaning of IRC
Section 382 during 2017. Even if the Company did experience an ownership change in 2017, any resulting limitation on the use of the Company’s net operating
loss carryforwards under IRC Section 382 would not result in a current federal tax liability at December 31, 2017, and the Company does not believe that the
resulting Section 382 annual limitation would prevent its utilization of NOLs prior to their expiration
.
F-38
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities were as follows (in
thousands):
Assets:
Asset retirement obligations
Deferred stock-based compensation
Derivative fair value loss
Accrued compensation
Net operating loss carryforward
Other
Total deferred tax assets
Less: Valuation allowance
Net deferred tax assets
Liabilities:
Book basis of oil and natural gas properties
in excess of tax basis
Earnings in investment in subsidiary
Other
Total deferred tax liabilities
Net deferred tax liability
December 31,
2017
2016
$
4,854 $
7,874
12,493
4,241
48,666
78
78,206
(9,264)
68,942
(89,299)
(828)
(218)
(90,345)
(21,403) $
$
3,535
6,868
8,252
3,398
44,407
166
66,626
(32,215)
34,411
(38,489)
(1,116)
(289)
(39,894)
(5,483)
With respect to income taxes, the Company’s policy is to account for interest charges as interest expense, net and any penalties as Other income (expense) in
the Company’s consolidated statements of operations. The Company files income tax returns in the U.S. federal jurisdiction and the Texas state jurisdiction, a
number of which remain open for examination. The Company’s earliest open years in its key jurisdictions are as follows:
U.S. federal
State of Texas
2014
2013
The Company has evaluated all tax positions for which the statute of limitations remains open and believes that the material positions taken would more
likely than not be sustained by examination. Therefore, at December 31, 2017 , the Company had not established any reserves for, nor recorded any unrecognized
benefits related to, uncertain tax positions.
Tax Receivable Agreement
In connection with the IPO, on May 29, 2014, the Company entered into a Tax Receivable Agreement (the “TRA”) with Parsley LLC and certain PE Unit
Holders prior to the IPO (each such person a “TRA Holder”), including certain executive officers. The TRA generally provides for the payment by the Company of
85% of the net cash savings, if any, in U.S. federal, state, and local income tax or franchise tax that the Company actually realizes (or is deemed to realize in certain
circumstances) in periods after the IPO as a result of (i) any tax basis increases resulting from the contribution in connection with the IPO by such TRA Holder of
all or a portion of its PE Units to the Company in exchange for shares of Class A Common Stock, (ii) the tax basis increases resulting from the exchange by such
TRA Holder of PE Units for shares of Class A Common Stock or, if either the Company or Parsley LLC so elects, cash, and (iii) imputed interest deemed to be
paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the TRA. The term of the TRA commenced on
May 29, 2014, and continues until all such tax benefits have been utilized or expired, unless the Company exercises its right to terminate the TRA. If the Company
elects to terminate the TRA early, it would be required to make an immediate payment equal to the present value of the anticipated future tax benefits subject to the
TRA (based upon certain assumptions and deemed events set forth in the TRA). In addition, payments due under the TRA will be similarly accelerated following
certain mergers or other changes of control.
The actual amount and timing of payments to be made under the TRA will depend upon a number of factors, including the amount and timing of taxable
income generated in the future, changes in future tax rates, the use of loss carryovers and the
F-39
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
portion of the Company’s payments under the TRA constituting imputed interest. As of December 31, 2017 , there have been no payments associated with the
TRA.
As a result of the Tax Act corporate rate reduction from 35% to 21% and the reduction in the valuation allowance recorded in 2016, during the year ended
December 31,2017, the Company recorded a net decrease to the TRA liability of $35.8 million , which is comprised of a decrease of $55.9 million associated with
the corporate rate reduction and an increase of $20.1 million related to the change in valuation allowance.
As of December 31, 2017 and December 31, 2016 , the Company had recorded a TRA liability of $58.5 million and $94.3 million , respectively, for the
estimated payments that will be made to the PE Unit Holders who have exchanged shares along with corresponding deferred tax assets, net of valuation allowance,
of $68.8 million and $111.0 million , respectively, as a result of the increase in tax basis arising from such exchanges and decrease in tax basis as a result of the
decrease in the future statutory tax rate.
NOTE 11. RELATED PARTY TRANSACTIONS
Well Operations
During the years ended December 31, 2017 , 2016 and 2015 , several of the Company’s directors, officers, their immediate family and entities affiliated or
controlled by such parties (“Related Party Working Interest Owners”) owned non-operated working interests in certain of the oil and natural gas properties that the
Company operates. The revenues disbursed to such Related Party Working Interest Owners for the years ended December 31, 2017 , 2016 and 2015 totaled $1.5
million , $2.5 million and $5.2 million , respectively.
As a result of this ownership, from time to time, the Company will be in a net receivable or net payable position with these individuals and entities. The
Company does not consider any net receivables from these parties to be uncollectible.
Spraberry Production Services, LLC
At December 31, 2017 , the Company owned a 42.5% interest in SPS and accounts for this investment using the equity method. Using the equity method of
accounting results in transactions between the Company and SPS and its subsidiaries being accounted for as related party transactions. During the years ended
December 31, 2017 , 2016 and 2015 , the Company incurred charges totaling $10.2 million , $4.4 million and $4.8 million , respectively, for services performed by
SPS for the Company’s well operations and drilling activities.
Lone Star Well Service, LLC
The Company makes purchases of equipment used in its drilling operations from Lone Star Well Service, LLC (“Lone Star”). Lone Star is controlled by
SPS. During the years ended December 31, 2017 , 2016 and 2015 , the Company incurred charges totaling $6.5 million , $6.3 million and $5.0 million ,
respectively, for services performed by Lone Star for the Company’s well operations and drilling activities.
Davis, Gerald & Cremer, P.C.
During the years ended 2016 and 2015 , the Company incurred charges totaling $0.5 million and $0.2 million , respectively, for legal services from Davis,
Gerald & Cremer, P.C., of which the Company’s director David H. Smith is a shareholder. There were no material charges incurred during the year ended
December 31, 2017 .
Riverbend Acquisition
During the year ended December 31, 2016, the Company acquired 8,800 gross ( 6,269 net) acres located in Glasscock, Midland and Reagan Counties,
Texas, along with net production of approximately 900 Boe/d from existing wells, from Riverbend Permian L.L.C. (“Riverbend”), for total consideration of $177.1
million , after customary purchase price adjustments (the “Riverbend Acquisition”). Randolph J. Newcomer, Jr., a former member of the Company’s board of
directors, is the President and Chief Executive Officer of Riverbend. As the transaction involved a related party at the time it was entered into, the Riverbend
Acquisition was approved by the disinterested members of the Company’s board of directors. The Company
F-40
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
reflected $37.9 million of the total consideration paid as part of its cost subject to depletion within its oil and natural gas properties and $139.2 million as unproved
leasehold costs within its oil and natural gas properties for the year ended December 31, 2016.
Exchange Right
In accordance with the terms of the Parsley LLC Agreement, the PE Unit Holders generally have the right to exchange (the “Exchange Right”) their PE
Units (and a corresponding number of shares of the Class B Common Stock) for shares of Class A Common Stock at an exchange ratio of one share of Class A
Common Stock for each PE Unit (and a corresponding share of Class B Common Stock) exchanged (subject to conversion rate adjustments for stock splits, stock
dividends and reclassifications) or, if the Company or Parsley LLC so elects, cash. As a PE Unit Holder exchanges its PE Units, the Company’s interest in Parsley
LLC will be correspondingly increased.
NOTE 12. COMMITMENTS AND CONTINGENCIES
Legal Matters
From time to time, the Company is a party to ongoing legal proceedings in the ordinary course of business, including workers’ compensation claims and
employment-related disputes. The Company does not believe the results of these proceedings, individually or in the aggregate, will have a material adverse effect
on its business, financial condition, results of operations, or liquidity.
Environmental Matters
The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. These laws, which are often
changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or
release of petroleum or chemical substances at various sites. The Company has established procedures for the ongoing evaluation of its operations, to identify
potential environmental exposures and to comply with regulatory policies and procedures.
The Company accounts for environmental contingencies in accordance with the accounting guidance related to accounting for contingencies. Environmental
expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations,
which do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are
probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed or readily determinable.
At December 31, 2017 and 2016 , the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability.
Asset Retirement Obligations
The following table summarizes the Company’s asset retirement obligations as of December 31, 2017 (in thousands):
Payments Due by Period
Asset retirement obligations
$
6,297 $
774 $
824 $
834 $
929 $
17,512 $
27,170
2018
2019
2020
2021
2022
Thereafter
Total
Drilling Commitments
The Company periodically enters into contractual arrangements under which the Company is committed to expend funds to drill wells in the future,
including agreements to secure drilling rig services, which require the Company to make future minimum payments to the rig operators. The Company records
drilling commitments in the periods in which well capital is incurred or rig services are provided. The following table summarizes the Company’s drilling
commitments as of December 31, 2017 (in thousands):
F-41
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
Drilling commitments
$
30,752 $
46,150 $
— $
— $
— $
— $
76,902
2018
2019
2020
2021
2022
Thereafter
Total
Payments Due by Period
Derivative Obligations
The future deferred premium payments related to derivative agreements as of December 31, 2017 was as follows (in thousands):
Payments Due by Period
Derivative obligations
$
49,601 $
14,730 $
— $
— $
— $
— $
64,331
2018
2019
2020
2021
2022
Thereafter
Total
Operating Leases
The estimated future minimum lease payments under long-term operating lease agreements as of December 31, 2017 was as follows (in thousands):
For the years ended December 31,
Office Leases
Office Equipment
Total
2018
2019
2020
2021
2022
Thereafter
Total
$
8,810 $
9,626 $
9,640 $
9,219 $
9,102 $
20,219 $
155
76
4
1
—
—
$
8,965 $
9,702 $
9,644 $
9,220 $
9,102 $
20,219 $
66,616
236
66,852
Rent expense for the years ended December 31, 2017 , 2016 and 2015 was $9.5 million , $7.1 million and $4.7 million , respectively.
Firm Transportation and Processing Agreements
During the year ended December 31, 2016, the Company entered into a contract with a private midstream company that provides for firm pipeline
transportation from its acreage in Reagan, Upton and Midland Counties, Texas to Crane, Colorado City and Midland, Texas, which enables the Company to choose
from multiple destinations for a substantial portion of its crude oil production.
During the year ended December 31, 2017, the Company entered into a contract that provides firm transportation off one of the pipeline systems through
which the Company transports or sells crude oil. Satisfaction of the volume requirements includes volumes produced by the Company, and other third-party
working, royalty, and overriding royalty interest owners whose volumes the Company markets on their behalf. The Company’s consolidated statements of
operations reflects its share of firm transportation costs. This contract requires the Company to pay a deficiency fee if it fails to deliver the required volumes.
As of December 31, 2017, approximately 69% of the Company’s gross oil production was being transported by these pipelines systems and sold under these
agreements. The Company does not believe, however, that the termination of either of these agreements would materially impact its operating results, as crude oil
and natural gas are fungible products with well-established markets and numerous purchasers.
NOTE 13. DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company uses a valuation framework based upon inputs that market participants use in pricing an asset or liability, which are classified into two
categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs
reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of
inputs are further prioritized
F-42
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
into the following fair value input hierarchy:
Level
1:
Level
2:
Level
3:
Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.
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.
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.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing
basis, but are subject to fair value adjustments whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. These
assets and liabilities can include inventory, proved and unproved oil and natural gas properties and other long-lived assets that are written down to fair value when
they are impaired.
The Company periodically reviews its long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or
circumstances indicate that the carrying value of those assets may not be recoverable ( e.g. , if there was a sustained decline in commodity prices or the productivity
of the Company’s wells). The Company reviews its oil and natural gas properties by field. An impairment loss is recognized if the sum of the expected
undiscounted future net cash flows is less than the carrying amount of the assets. If the estimated undiscounted future net cash flows are less than the carrying
amount of a particular asset, the Company recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value
of such asset.
Materials and Supplies. During the year ended December 31, 2017 , the Company recognized impairment of $1.1 million primarily to reduce the carrying
value of oil and gas drilling and repair items. No impairment charge was recorded during the year ended December 31, 2016 . The Company estimates fair value of
the inventory using significant Level 2 assumptions based on third-party price quotes for the asset in an active market. The impairment charges are included in
Other income (expense) in the Company’s consolidated statements of operations.
Proved Oil and Natural Gas Properties. During the years ended December 31, 2017 and 2016, the Company did no t recognize impairment charges, as the
carrying amount of the assets exceeds the undiscounted future cash flows of the assets.
The Company estimates fair values using a discounted future cash flow model. Management’s assumptions associated with the calculation of discounted
future cash flows include commodity prices based on NYMEX futures price strips (Level 1), as well as Level 3 assumptions including (i) pricing adjustments for
differentials, (ii) production costs, (iii) capital expenditures, (iv) production volumes and (v) estimated reserves.
It is reasonably possible that the estimate of undiscounted future net cash flows may change in the future resulting in the need to impair carrying values. The
primary factors that may affect estimates of future cash flows are (i) commodity futures prices, (ii) increases or decreases in production and capital costs, (iii)
future reserve adjustments, both positive and negative, to proved reserves and (iv) results of future drilling activities.
Financial Assets and Liabilities Measured at Fair Value
Commodity derivative contracts are marked-to-market each quarter and are thus stated at fair value in the Company’s consolidated balance sheets and in
Note 3—Derivative Financial Instruments . The company adjusts the valuations from the valuation model for nonperformance risk and for counterparty risk. The
fair values of the Company’s commodity derivative instruments are classified as Level 2 measurements as they are calculated using industry standard models using
assumptions and inputs which are substantially observable in active markets throughout the full term of the instruments. These include market price curves,
contract terms and prices, credit risk adjustments, implied market volatility and discount factors. The following summarizes the fair value of the Company’s
derivative assets and liabilities according to their fair value hierarchy as of the reporting dates indicated (in thousands):
F-43
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
Level 1
Level 2
Level 3
Total
December 31, 2017
$
$
$
$
$
476,619 $
—
476,619 $
— $
57,689
57,689 $
— $
— $
(105,543) $
(105,543) $
476,619 $
(47,854) $
—
—
— $
— $
— $
— $
476,619
57,689
534,308
(105,543)
(105,543)
428,765
Level 1
Level 2
Level 3
Total
December 31, 2016
$
94,280 $
— $
—
94,280
56,124
56,124
—
—
(56,968)
(56,968)
$
94,280 $
(844) $
—
—
—
—
—
— $
94,280
56,124
150,404
(56,968)
(56,968)
93,436
Assets:
Money market funds
Commodity derivative contracts
Total assets
Liabilities:
Commodity derivative contracts
Total liabilities
Net asset (liability)
Assets:
Money market funds
Commodity derivative contracts
Total assets
Liabilities:
Commodity derivative contracts
Total liabilities
Net asset (liability)
Money market funds in the preceding tables consist of money market funds included in cash and cash equivalents on the Company’s consolidated balance
sheets at December 31, 2017 and 2016. The Company’s money market funds represent cash equivalents backed by the assets of high-quality major banks and
financial institutions. The Company identifies the money market funds as Level 1 instruments because the money market funds have daily liquidity, quoted prices
for the underlying investments can be obtained and there are active markets for the underlying investments. During the years ended December 31, 2017 and 2016,
income related to these investments was $7.6 million and $0.9 million , respectively, and is recorded on the Company’s consolidated statements of operations as
Interest income.
There were no transfers in to or out of Level 2 during the years ended December 31, 2017 or 2016 .
F-44
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
Financial Instruments Not Carried at Fair Value
The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated balance sheets (in thousands):
Cash and cash equivalents:
Commercial paper
Short-term investments:
Commercial paper
Current portion of long-term debt:
7.500% senior unsecured notes due 2022
Long-term debt:
6.250% senior unsecured notes due 2024
5.375% senior unsecured notes due 2025
5.250% senior unsecured notes due 2025
5.625% senior unsecured notes due 2027
Revolving Credit Agreement
December 31, 2017
December 31, 2016
Carrying
Amount
Fair Value
Carrying
Amount
Fair Value
$
24,939 $
24,918 $
—
$
149,283
149,151
—
—
—
—
—
61,846
65,737
400,000
423,824
650,000
658,483
450,000
454,010
700,000
715,169
—
—
400,000
650,000
422,548
654,531
— —
—
—
—
—
—
The fair values of the 2024 Notes, the 2025 Notes, the New 2025 Notes and the 2027 Notes included in long-term debt were determined using the
December 31, 2017 quoted market price, a Level 1 classification in the fair value hierarchy. The fair value of the 2022 Notes included in Current portion of long-
term debt at December 31, 2016 is equal to the principal amount of the cash payment made on January 5, 2017. The book value of the Revolving Credit Agreement
approximates its fair value as the interest rate is variable. As of December 31, 2017 , there were no indicators for change in the Company’s market spread.
Periodically, the Company invests in commercial paper with investment grade rated entities. The investments are carried at amortized cost and classified as
held-to-maturity because the Company has the intent and ability to hold them until they mature. The net carrying value of held-to-maturity investments is adjusted
for amortization of premiums and accretion of discounts to maturity over the life of the investments. Income related to these investments is recorded on the
Company’s consolidated statements of operations as Interest income.
The following table provides the components of the Company’s cash and cash equivalents and short-term investments as of the dates indicated (in
thousands):
Consolidated Balance Sheet Location
Cash and cash equivalents
Short-term investments
Consolidated Balance Sheet Location
Cash and cash equivalents
December 31, 2017
Cash
Commercial Paper
Money Market
Funds
$
52,631 $
24,939 $
476,619 $
—
149,283
—
Total
554,189
149,283
December 31, 2016
Cash
Commercial Paper
Money Market
Funds
Total
$
39,099 $
— $
94,280 $
133,379
The Company has other financial instruments consisting primarily of accounts receivable, prepaid expenses, other current assets, accounts payable and
accrued liabilities and capital leases that approximate their fair value due to the short-term nature of these instruments.
F-45
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
NOTE 14. SUBSEQUENT EVENTS
The Company has evaluated subsequent events through the date these financial statements were issued. The Company determined there were no events,
other than as described below, that required disclosure or recognition in these financial statements.
Divestiture of Non-Operated Properties
As part of an ongoing initiative to high-grade its acreage portfolio, the Company recently closed the divestiture of a portion of its non-operated properties,
which were classified as held for sale as of December 31, 2017. In aggregate, the Company divested 42,852 gross ( 3,710 net) acres in Martin, Howard, Reagan,
Irion, Dawson, and Pecos Counties for approximately $39.4 million with no gain or loss recognized.
NOTE 15. SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (Unaudited)
The Company has only one reportable operating segment, which is oil and gas development, exploration and production in the United States. See the
Company’s consolidated statements of operations for information about results of operations for oil and gas producing activities.
Capitalized Costs
Oil and natural gas properties:
Proved properties
Unproved properties
Total oil and natural gas properties
Less accumulated depreciation, depletion and amortization
Net oil and natural gas properties capitalized
Costs Incurred for Oil and Natural Gas Producing Activities
Acquisition costs:
Proved properties
Unproved properties
Development costs
Total
Reserve Quantity Information
December 31,
2017
2016
(in thousands)
$
4,492,802 $
4,058,512
8,551,314
(822,459)
$
7,728,855 $
2,376,712
1,686,705
4,063,417
(506,175)
3,557,242
Year Ended December 31,
2017
2016
2015
(in thousands)
$
482,160 $
273,940 $
2,893,434
1,207,401
1,072,250
495,971
$
4,582,995 $
1,842,161 $
16,422
57,385
404,291
478,098
The following information represents estimates of the Company’s proved reserves as of December 31, 2017 , which have been prepared and presented under
SEC rules. These rules require SEC reporting companies to prepare their reserve estimates using specified reserve definitions and pricing based on a 12 -month
unweighted average of the first-day-of-the-month pricing. The pricing that was used for estimates of the Company’s reserves as of December 31, 2017 was based
on an unweighted average 12-month average WTI posted price per Bbl for oil and NGLs and a Waha spot natural gas price per Mcf for natural gas, adjusted for
transportation, quality and basis differentials, as set forth in the following table:
F-46
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
Oil (per Bbl)
Natural gas (per Mcf)
Natural gas liquids (per Bbl)
Year Ended December 31,
2017
2016
2015
$
$
$
49.17 $
2.53 $
22.20 $
39.36 $
2.23 $
15.04 $
46.54
2.53
16.42
Subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of
booking. This requirement has limited and may continue to limit, the Company’s potential to record additional proved undeveloped reserves as it pursues its
drilling program. Moreover, the Company may be required to write down its proved undeveloped reserves if it does not drill on those reserves with the required
five-year timeframe. The Company does not have any proved undeveloped reserves which have remained undeveloped for five years or more.
The Company’s proved oil and natural gas reserves are located in the U.S. in the Permian Basin of West Texas. Proved reserves were estimated in
accordance with the guidelines established by the SEC and the FASB.
Oil and natural gas reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the
projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data
and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward
revision of previous estimates.
Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that reserve
estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties.
Accordingly, these estimates are expected to change as additional information becomes available in the future.
The following table and subsequent narrative disclosure provides a roll forward of the total proved reserves for the years ended December 31, 2017 , 2016
and 2015 , as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year:
Proved Developed and Undeveloped Reserves:
Beginning of the year
Extensions and discoveries
Revisions of previous estimates
Purchases of reserves in place
Divestures of reserves in place
Production
End of the year
Proved Developed Reserves:
Beginning of the year
End of the year
Proved Undeveloped Reserves:
Beginning of the year
End of the year
Year Ended December 31, 2017
Crude Oil
(MBbls)
Natural Gas
(MMcf)
Liquids
(MBbls)
MBoe
136,536
99,916
(709)
33,017
(3,839)
(16,390)
248,531
223,605
161,989
32,342
64,055
(6,962)
(23,326)
451,703
48,543
33,426
4,522
12,121
(1,468)
(4,512)
92,632
222,347
160,340
9,205
55,814
(6,467)
(24,792)
416,447
61,133
119,591
123,946
240,337
24,306
49,751
106,097
209,399
75,403
128,940
99,659
211,366
24,237
42,880
116,250
207,048
F-47
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
Proved Developed and Undeveloped Reserves:
Beginning of the year
Extensions and discoveries
Revisions of previous estimates
Purchases of reserves in place
Divestures of reserves in place
Production
End of the year
Proved Developed Reserves:
Beginning of the year
End of the year
Proved Undeveloped Reserves:
Beginning of the year
End of the year
Proved Developed and Undeveloped Reserves:
Beginning of the year
Extensions and discoveries
Revisions of previous estimates
Purchases of reserves in place
Divestures of reserves in place
Production
End of the year
Proved Developed Reserves:
Beginning of the year
End of the year
Proved Undeveloped Reserves:
Beginning of the year
End of the year
Year Ended December 31, 2016
Crude Oil
(MBbls)
Natural Gas
(MMcf)
Liquids
(MBbls)
MBoe
73,877
64,005
(4,476)
16,041
(3,543)
(9,368)
136,536
157,175
83,815
(19,032)
25,024
(9,914)
(13,463)
223,605
23,738
20,698
3,898
4,023
(1,424)
(2,390)
48,543
123,811
98,672
(3,750)
24,235
(6,619)
(14,002)
222,347
27,628
61,133
77,612
123,946
10,890
24,306
51,453
106,097
46,249
75,403
79,563
99,659
12,848
24,237
72,358
116,250
Year Ended December 31, 2015
Crude Oil
(MBbls)
Natural Gas
(MMcf)
Liquids
(MBbls)
MBoe
47,617
38,282
(7,493)
1,897
(1,619)
(4,807)
73,877
123,645
52,629
(14,572)
6,946
(1,134)
(10,339)
157,175
22,667
9,163
(7,278)
921
(235)
(1,500)
23,738
23,547
27,628
65,484
77,612
11,491
10,890
24,070
46,249
58,161
79,563
11,176
12,848
90,891
56,217
(17,201)
3,976
(2,042)
(8,030)
123,811
45,952
51,453
44,939
72,358
Extensions and Discoveries. For the years ended December 31, 2017 , 2016 and 2015 , extensions and discoveries contributed to the increase of 160,340
MBoe, 98,672 MBoe and 56,217 MBoe in the Company’s proved reserves, respectively, and for each such year the increase is attributable to the Company’s
successful horizontal drilling program in the Midland Basin and Delaware Basin.
Revisions of Previous Estimates. The Company made total revisions in proved reserves of 9,205 MBoe, 3,750 MBoe and 17,201 MBoe for the years ended
December 31, 2017 , 2016 and 2015 , respectively.
Positive revisions of previous estimates for 2017 were 9,205 MBoe. The main driver of this adjustment was related to positive revisions due to better than
expected performance for a total of 8,134 MBoe. Additionally, positive revisions of 2,752
F-48
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
MBoe and 3,044 MBoe were recorded due to the increase in oil prices and production, respectively, when compared to 2016. This was offset by the reclassification
of PUD reserves to unproved reserves, which accounted for a 4,725 MBoe downward revision to previous estimates related to the removal of reserves for locations
determined to be outside of the Company’s five-year capital expenditure plan.
Negative revisions of previous estimates for 2016 were 3,750 MBOE. The revisions include the reclassification of proved undeveloped reserves to unproved
reserves, which accounted for a 26,597 MBoe downward revision to previous estimates (of which 18,532 MBoe related to the removal of reserves for all of the
Company’s vertical proved undeveloped reserve locations). Additionally, downward revisions of 2,873 MBoe were recorded due to the decline of oil prices when
compared to 2015. This was offset by positive revisions due to better than expected performance and cost reduction initiatives for a total of 25,720 MBoe.
Negative revisions of previous estimates for 2015 were 17,201 MBoe. This figure includes downward revisions of 13,087 MBoe due to the decline of oil
prices as compared to 2014. Additionally, this includes the reclassification of proved undeveloped reserves to unproved reserves, which accounted for 11,688
MBoe of downward revisions to previous estimates due to the removal of vertical proved undeveloped reserve locations. These amounts were offset by positive
revisions of 7,574 MBoe due to better than expected performance during 2015 and cost reduction initiatives.
Purchases of Reserves in Place. For the years ended December 31, 2017 , 2016 and 2015 , the Company added 55,814 MBoe, 24,235 MBoe and 3,976
MBoe of reserves, respectively, primarily as a result of the acquisition of developed and undeveloped acreage in the Midland and Delaware Basins. For the year
ended December 31, 2017 , the Company acquired 53,105 MBoe of proved reserves in the Midland Basin and 2,709 MBoe of proved reserves in the Delaware
Basin. For the year ended December 31, 2016, the Company acquired 19,184 MBoe of proved reserves in the Midland Basin and 5,051 MBoe of proved reserves in
the Delaware Basin. All of the Company’s acquisitions of proved reserves for the years ended December 31, 2015 were in the Midland Basin.
Divestitures of Reserves in Place . As a result of divestitures of developed and undeveloped acreage in the Midland and Delaware Basins, the Company’s
reserves decreased by 6,467 MBoe, 6,619 MBoe and 2,042 MBoe during the years ended December 31, 2017 , 2016 and 2015 , respectively. For the year ended
December 31, 2017, the Company divested 5,936 MBoe of proved reserves in the Midland Basin and 531 MBoe of proved reserves in the Delaware Basin. For the
year ended December 31, 2016, the Company divested 6,588 MBoe of proved reserves in the Midland Basin and 31 MBoe of proved reserves in the Delaware
Basin. All of the Company’s divestitures of proved reserves for the year ended December 31, 2015 were in the Midland Basin.
Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and
natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as
proved, the value of unproved properties and consideration of expected future economic and operating conditions.
The estimates of future cash flows and future production and development costs as of December 31, 2017 , 2016 and 2015 are based on the unweighted
arithmetic average first-day-of-the-month price for the preceding 12-month period. Estimated future production of proved reserves and estimated future production
and development costs of proved reserves are based on current costs and economic conditions. All wellhead prices are held flat over the forecast period for all
reserve categories. The estimated future net cash flows are then discounted at a rate of 10% .
F-49
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
The standardized measure of discounted future net cash flows relating to proved oil, natural gas and NGLs reserves is as follows:
Future cash inflows
Future development costs
Future production costs
Future income tax expenses
Future net cash flows
10% discount to reflect timing of cash flows
2017
December 31,
2016
(in thousands)
$
15,421,590 $
6,603,206 $
(2,181,447)
(4,536,530)
(1,102,385)
7,601,228
(4,585,723)
(1,019,823)
(2,176,081)
(370,337)
3,036,965
(1,852,653)
2015
4,225,912
(829,560)
(1,534,011)
(240,203)
1,622,138
(1,024,290)
Standardized measure of discounted future net cash flows
$
3,015,505 $
1,184,312 $
597,848
In the foregoing determination of future cash inflows, sales prices used for oil, natural gas and NGLs for December 31, 2017 , 2016 and 2015 , were
estimated using the average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-month price for each month.
Prices were adjusted by lease for quality, transportation fees and regional price differentials. Future costs of developing and producing the proved gas and oil
reserves reported at the end of each year shown were based on costs determined at each such year-end, assuming the continuation of existing economic conditions.
It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of its’ predecessor’s proved
reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are
inherently imprecise and subject to revision and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the
determinations and no value may be assigned to probable or possible reserves.
Changes in the standardized measure of discounted future net cash flows relating to proved oil, natural gas and NGLs reserves are as follows:
Standardized measure of discounted future net cash flows
at the beginning of the year
Sales of oil and natural gas, net of production costs
Purchase of minerals in place
Divestiture of minerals in place
Extensions and discoveries, net of future
development costs
Previously estimated development costs incurred
during the period
Net changes in prices and production costs
Changes in estimated future development costs
Revisions of previous quantity estimates
Accretion of discount
Net change in income taxes
Net changes in timing of production and other
Standardized measure of discounted future net cash flows
at the end of the year
Year Ended December 31,
2017
2016
2015
(in thousands)
$
1,184,312 $
597,848 $
(800,553)
489,910
(50,257)
(369,295)
118,795
(14,591)
955,629
(185,344)
4,872
(53,018)
1,864,041
770,947
485,380
58,377
525,693
(150,028)
142,510
148,314
(603,696)
206,882
61,756
(80,492)
118,930
84,309
69,731
(199,368)
25,742
12,560
(821,783)
77,621
(225,485)
131,442
249,065
(33,091)
$
3,015,505 $
1,184,312 $
597,848
F-50
PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2017
NOTE 16. SUMMARY OF QUARTERLY RESULTS OF OPERATIONS (Unaudited)
The Company’s unaudited quarterly financial data for the years ended December 31, 2017 and 2016 is summarized as follows:
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
(in thousands, except per share amounts)
2017
Revenues
Operating income
Income tax (expense) benefit
Net income (loss)
Net income (loss) attributable to noncontrolling interests
$
$
$
$
$
Net income (loss) attributable to Parsley Energy, Inc. stockholders $
Net income (loss) per common share:
Basic
Diluted
2016
Revenues
Operating (loss) income
Income tax benefit (expense)
Net loss
Net income (loss) attributable to noncontrolling interests
Net loss attributable to Parsley Energy, Inc. stockholders
Net loss per common share:
Basic
Diluted
$
$
$
$
$
$
$
$
$
$
213,677 $
45,259 $
(12,216) $
55,794 $
15,048 $
40,746 $
0.17 $
0.17 $
106,872 $
1,636 $
10,918 $
(27,488) $
(6,111) $
(21,377) $
(0.13) $
(0.13) $
241,021 $
63,072 $
5,080 $
(15,161) $
(1,828) $
(13,333) $
(0.05) $
(0.05) $
132,537 $
12,340 $
1,279 $
(1,641) $
1,065 $
(2,706) $
(0.02) $
(0.02) $
311,488
85,939
19,830
44,997
(39,214)
49,919
0.20
0.16
155,876
43,213
(4,341)
(34,097)
(3,352)
(30,745)
(0.17)
(0.17)
200,858 $
72,531 $
(18,402) $
38,290 $
8,848 $
29,442 $
0.13 $
0.13 $
62,488 $
(26,042) $
9,568 $
(25,691) $
(6,337) $
(19,354) $
(0.14) $
(0.14) $
F-51
Exhibit 10.20
PARSLEY ENERGY OPERATIONS, LLC
EMPLOYMENT, CONFIDENTIALITY, AND NON-COMPETITION AGREEMENT
For good and valuable consideration set forth herein, this Employment, Confidentiality, and Non-Competition Agreement (“
Agreement ”) is executed as of the date set forth below and effective upon the closing of the initial public offering of Parsley Energy, Inc., a
corporation organized under the laws of the State of Delaware (“ Parsley Inc. ”) (the “ Effective Date ”), by and between: (i) Parsley Energy
Operations, LLC (“ Parsley ”) and (ii) Michael Hinson , a natural person (“ Employee ”) (Employee and Parsley each a “ Party ” and
collectively “ Parties ” herein). In the event the initial public offering of Parsley Inc. does not close on or before the two-year anniversary of
the date this Agreement is executed by the Parties, this Agreement shall never become effective and shall have no force or effect.
PREAMBLE
WHEREAS, Parsley and Employee entered into an employment, confidentiality, and non-competition agreement on June 21, 2013
(the “ Prior Agreement ”);
WHEREAS, in connection with and as a result of the restructuring of Parsley Energy Operations, LLC and its affiliates, and the
creation and initial public offering of Parsley Inc., the Parties believe it is appropriate to cancel the Prior Agreement and enter into this
Agreement;
WHEREAS , in the course of Employee’s employment, Parsley will provide Employee with internal confidential information,
commercially obtained information, research resources, and other valuable and proprietary materials. Further, Employee’s position will be to
develop and obtain such confidential information for the benefit of Parsley and its affiliates and subsidiaries (the “ Parsley Group ” and each
individual entity, a “ member of the Parsley Group ”). This information will include trade secrets, and other confidential information,
including, without limitation, strategic goals and plans of Parsley or another member of the Parsley Group, employment information,
geophysical data, engineering data and compilations, well logs, well production records, well files and the like.
THEREFORE, the Parties agree as follows:
I.
EMPLOYMENT AGREEMENT
1.01 Initial Term. The Parties agree that this Agreement hereby cancels and supersedes the Prior Agreement. The term of this
Agreement shall begin on the Effective Date and continue for a period of one year (the “ Initial Term ”) unless earlier terminated pursuant to
this Section 1, provided that, on such one-year anniversary of the Effective Date, and each annual anniversary thereafter (such date and each
annual anniversary thereof, a “ Renewal Date ”), the term of this Agreement shall be deemed to be automatically extended, upon the same
terms and conditions, for successive periods of one year, unless either of the Parties provides written notice of its intention not to extend the
term of the Agreement at least 60 days prior to the applicable Renewal Date. The Initial Term and all periods beyond the Initial Term while
this Agreement remains in effect shall collectively be referred to herein as the “ Term .”
1.02 Base Salary. During the Term, Parsley will pay Employee a base salary of at least $232,000 per year, in periodic installments
in accordance with Parsley’s customary payroll practices as may exist from time to time, but no less frequently than monthly. During the
Term, Parsley may not decrease Employee’s salary below the base salary enumerated in this Section 1.02, but may, in Parsley’s sole
discretion, increase Employee’s salary as it sees fit from time to time. Employee’s annual base salary, as in effect from time to time, is
hereinafter referred to as Employee’s “ Base Salary .”
Employment, Confidentiality, and Non-Competition Agreement
Page 1 of 14
1.03 Bonus. Employee shall be eligible to earn an annual bonus (the “ Annual Bonus ”). However, the decision to provide any
Annual Bonus and the amount and terms of any Annual Bonus shall be in the sole and absolute discretion of the Compensation Committee
(the “ Compensation Committee ”) of the Board of Directors of Parsley (the “ Board ”). For the avoidance of doubt, Employee shall not be
entitled to any Annual Bonus if Employee is not employed by Parsley on the date any such Annual Bonus is paid.
1.04 Benefits. At all times during Employee’s employment with Parsley, Employee will be entitled to all other benefits and
conditions of employment generally available to employees of Parsley of the same level and responsibility. Furthermore, Parsley shall pay all
costs (including all reasonable costs associated with travel and lodging) for Employee to obtain a bi-annual physical examination at the
Cooper Clinic in Dallas, Texas.
1.05 Duties. During Employee’s employment, Employee agrees to serve as Vice President of Land, whose job it will be to manage
and lead the strategic direction of the Parsley Group’s land-related activities, and in such other position(s) as the Employee’s supervisor and
Employee shall mutually agree. Employee will have the duties that are normally required of an employee of Employee’s same level and
responsibility in the exploration and production business and agrees to perform diligently and to the best of Employee’s abilities the duties
and services appertaining to such position(s), as well as such additional duties and services which may be designated by Parsley or other
members of the Parsley Group, at Parsley’s discretion, from time to time. Employee will also, at the reasonable discretion and request of
Parsley, advise and assist in other ways to further the business of the Parsley Group, as may be requested. Initially, Employee shall report to
and be subject to the supervision and direction of Parsley’s Chief Executive Officer.
1.06 Place of Work. Employee shall perform Employee’s services at an office, space for which will be furnished by Parsley at
Parsley’s principal office in Midland, Texas, or such other location to which Parsley relocates its principal office. If Employee is required to
travel, Parsley agrees to reimburse Employee in accordance with Parsley’s expense reimbursement policy in effect from time to time.
1.07 No Privacy on Electronic Systems. Employee agrees and understands that the computer and email services provided by the
Parsley Group are for the purpose of conducting work for the Parsley Group alone. Employee agrees and stipulates that Employee shall have
no expectation of privacy with regard to emails or computer files on, or sent to or from, the computers or servers of the Parsley Group or
otherwise made available to Employee through Employee’s employment with Parsley.
1.08 Employee Resources. Parsley agrees to pay for memberships, seminars, professional meetings and/or professional
publications needed for the continuing development of prospects and education of Employee, but only as the same are pre‑approved by
Parsley in Parsley’s sole and absolute discretion.
1.09 Full-Time Employee. While employed by Parsley, Employee agrees to devote Employee’s entire and full-time productive
ability and attention to the business of Parsley, provided that Employee may engage in passive personal investment and charitable activities
that do not Compete (as defined below) with the business and affairs of Parsley or interfere with Employee’s performance of Employee’s
duties hereunder. Employee warrants and agrees to not, directly or indirectly, render any services of a business, commercial, or professional
nature to any other person or organization, including self-employment, without the prior written consent of Parsley. Employee warrants and
agrees that Employee will not render any services as either an employee or independent consultant to any person or entity that is in
competition with Parsley or, while employed, prepare or establish a business that would result in a breach of Employee’s non-compete
restrictions set forth in Section 3.03.
Employment, Confidentiality, and Non-Competition Agreement
Page 2 of 14
1.10 Fiduciary Duties of Employee. At all times while an employee of Parsley, Employee warrants and agrees that Employee will
perform and discharge the duties of Employee’s position fully and faithfully and to the best of Employee’s abilities. Employee agrees
Employee shall owe Parsley, and hereby voluntarily assumes, a duty of loyalty and utmost good faith; a duty of candor; a duty to refrain from
any self-dealing; a duty to act with integrity of the strictest kind; a duty of fair and honest dealing; a duty of full disclosure, that is, a duty not
to conceal matters that might influence Employee’s actions to Parsley’s prejudice; and any other and further duties imposed by law on
employees to their employers, and specifically including under this Agreement a covenant not to solicit fellow Parsley employees for future
employment, as set forth in Section 3.04.
1.11 Reporting Requirement. During the course of Employee’s employment with Parsley, Employee agrees that, if Employee
learns or even suspects that any fellow employee is, or may be, breaching Employee’s fiduciary duties to Parsley, Employee agrees to alert
Parsley promptly. Employee understands that this is a broad and general obligation in light of the difficulty to anticipate all possible
circumstances. If Employee is in doubt, Employee agrees to resolve Employee’s doubts by reporting to Parsley the information that has come
to Employee’s attention.
1.12 Corporate Opportunities. During Employee’s employment with Parsley, in the event that Employee, in Employee’s
individual capacity, shall be presented with, or made aware of, any commercial proposal, prospect, solicitation, deal, transaction or
opportunity relating to the oil and gas business (“ New Business Opportunity ”), Employee shall immediately notify and present the terms and
conditions of such New Business Opportunity to Employee’s superiors at Parsley; whether or not any member of the Parsley Group elects to
take advantage of such New Business Opportunity, Employee shall not present such New Business Opportunity to any person or entity other
than the Parsley Group.
1.13 Termination by Non-Renewal, by Parsley for Cause or by Employee without Good Reason. Employee’s employment
hereunder may be terminated by (x) the provision of notice by either of the Parties that they do not wish to renew the Term on the next
Renewal Date in accordance with Section 1.01 and shall terminate the employment relationship between the Parties on such date, (y) by
Parsley for Cause, or (z) by Employee without Good Reason. If Employee’s employment is terminated for any of the reasons enumerated in
this Section 1.13 then Employee shall be entitled to receive: (i) any accrued but unpaid Base Salary, which shall be paid, unless otherwise
required by law, on the pay date immediately following the date of Employee’s termination of employment in accordance with Parsley’s
customary payroll procedures; (ii) reimbursement for unreimbursed business expenses properly incurred by Employee, which shall be subject
to and paid in accordance with Parsley’s expense reimbursement policy in effect from time to time; and (iii) such employee benefits
(including equity compensation), if any, as to which Employee may be entitled under Parsley’s employee benefit plans as of the date of
Employee’s termination of employment; provided that, in no event shall Employee be entitled to any payments in the nature of severance
payments except as specifically provided herein (items (i) through (iii), the “ Accrued Obligations ”). If Employee’s employment is
terminated for any of the reasons enumerated in this Section 1.13 then Parsley will not be obligated to make any payments other than the
Accrued Obligations under this Agreement and, except as otherwise provided in the award agreement under which the award was granted,
Employee will forfeit all unvested outstanding equity awards held by Employee as of the date of Employee’s termination of employment.
“ Cause ” shall mean: (i) violation of Parsley’s substance abuse policy; (ii) refusal or inability (other than by reason of death or Disability) to
perform the duties assigned to Employee; (iii) acts or omissions evidencing a violation of Employee’s duties of loyalty and good faith;
candor; fair and honest dealing; integrity; or full disclosure to Parsley, as well as any acts or omissions which constitute self-dealing; (iv)
willful disobedience of lawful orders, policies, regulations, or directives issued to Employee by Parsley, including policies related to sexual
harassment, discrimination, computer use or the like; (v) conviction or commission of a felony, a crime of moral turpitude, or a crime that
could reasonably be expected to impair the ability of Employee to
Employment, Confidentiality, and Non-Competition Agreement
Page 3 of 14
perform Employee’s job duties; (vi) breach of any part of this Agreement by Employee; (vii) revocation or suspension of any necessary
license or certification; (viii) generation of materially incorrect financial, geological, seismic or engineering projections, compilations or
reports; or (ix) a false statement by Employee to obtain this position, in each case as determined by the Board in good faith and in its sole and
absolute discretion. For purposes of clarity, “Cause” shall not mean termination of Employee’s employment for death or Disability, which
shall be governed by Section 1.15.
1.14 Termination by Employee for Good Reason or Termination by Parsley without Cause. Employee’s employment
hereunder may be terminated by Employee for Good Reason or by Parsley without Cause. If Employee’s employment is terminated by
Employee for Good Reason or by Parsley without Cause then Employee shall be entitled to receive (i) the Accrued Obligations, (ii) provided
that Employee has fulfilled the Severance Conditions (as defined below), a cash payment equal to 1.25 times the sum of (A) Employee’s Base
Salary and (B) the average of the three most recent Annual Bonuses actually paid in the three-year period preceding the date of Employee’s
termination (or the period of Employee’s employment, if shorter), which amount shall be paid in a lump-sum on the first business day
following the Release Consideration Period (as defined below), (iii) during the portion, if any, of the 18-month period commencing on the
date of such termination of employment that Employee is eligible to elect and elects to continue coverage for himself and his eligible
dependents under any of the Parsley Group’s group health plans, as applicable, under the Consolidated Omnibus Budget Reconciliation Act
of 1985, as amended (“ COBRA ”), Parsley shall promptly reimburse Employee on a monthly basis for the difference between the amount
Employee pays to effect and continue such coverage and the employee contribution amount that vice presidents of the Parsley Group pay for
the same or similar coverage under such group health plans at that time, and (iv) outplacement services provided by a company of Parsley’s
choosing for up to 6 months following the date of Employee’s termination or such time as Employee obtains reasonably comparable
employment, whichever occurs earlier. Except as otherwise provided in the award agreement under which the award was granted, all
unvested outstanding equity awards held by Employee upon a termination of employment without Cause or by Employee for Good Reason
covered by this Section 1.14 shall be forfeited for no consideration.
“ Good Reason ” shall mean (i) a material diminution in Employee’s base compensation, (ii) a material diminution in Employee’s authority,
duties, or responsibilities, or (iii) any other action or inaction that constitutes a material breach by Parsley of the Agreement, in each case,
without Employee’s consent. Employee cannot terminate Employee’s employment for Good Reason unless Employee has provided written
notice to Parsley of the existence of the circumstances providing grounds for termination for Good Reason within sixty (60) days of the initial
existence of such grounds and Parsley has had at least thirty (30) days from the date on which such notice is provided to cure such
circumstances. If Employee does not terminate Employee’s employment for Good Reason within 120 days after the first occurrence of the
applicable grounds, then Employee will be deemed to have waived Employee’s right to terminate for Good Reason with respect to such
grounds.
1.15 Death or Disability. Employee’s employment shall terminate automatically on the date of Employee’s death or immediately
upon Parsley’s sending Employee a notice of termination for “ Disability ,” which shall mean Employee’s inability to perform the essential
functions of Employee’s position, with reasonable accommodation, due to an illness or physical or mental impairment or other incapacity that
continues, or can reasonably be expected to continue, for a period in excess of ninety (90) days (whether or not consecutive) during any
period of three hundred sixty-five (365) consecutive days. Upon termination of Employee’s employment for death or Disability pursuant to
this Section 1.15, Parsley’s sole obligations to Employee shall be to pay (i) the Accrued Obligations and (ii) provided that Employee or
Employee’s estate, as applicable, has fulfilled the Severance Conditions, beginning on the first business day following the Release
Consideration Period (the “ Initial Payment Date ”), Employee’s Base Salary for the remainder of the calendar year in which death or
Disability occurred, which, following the Initial Payment Date, shall be paid as and when such amounts would have been due had Employee’s
employment continued (the “ Death
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or Disability Payment ”). Any installments of the Death or Disability Payment that, in accordance with customary payroll practices, would
have typically been made during the Release Consideration Period shall accumulate and shall then be paid on the Initial Payment Date.
1.16 Termination by Parsley without Cause or by Employee for Good Reason following a Change of Control. If within the
12 months following a Change of Control Employee’s employment is terminated by Employee for Good Reason or by Parsley without Cause
then Employee shall be entitled to receive (i) the Accrued Obligations, (ii) provided that Employee has fulfilled the Severance Conditions, a
cash payment equal to two (2) times the sum of (A) Employee’s Base Salary and (B) the average of the three most recent Annual Bonuses
actually paid in the three-year period preceding the date of Employee’s termination (or the period of Employee’s employment, if shorter),
which amount shall be paid in a lump-sum on the first business day following the Release Consideration Period, (iii) during the portion, if
any, of the 18-month period commencing on the date of such termination of employment that Employee is eligible to elect and elects to
continue coverage for himself and his eligible dependents under any of the Parsley Group’s group health plans, as applicable, under COBRA,
Parsley shall promptly reimburse Employee on a monthly basis for the difference between the amount Employee pays to effect and continue
such coverage and the employee contribution amount that vice presidents of the Parsley Group pay for the same or similar coverage under
such group health plans at that time, and (iv) outplacement services provided by a company of Parsley’s choosing for up to 6 months
following the date of Employee’s termination or such time as Employee obtains reasonably comparable employment, whichever occurs
earlier. Except as otherwise provided in the award agreement under which the award was granted, all unvested outstanding equity awards held
by Employee upon a termination of employment without Cause or by Employee for Good Reason following a Change of Control and covered
under this Section 1.16 shall be accelerated in full upon Employee’s termination of employment.
“ Change of Control ” means the occurrence of any of the following events:
(i) A “change in the ownership of the Company” which shall occur on the date that any one person, or more than one person acting as a
group, acquires ownership of stock in the Company that, together with stock held by such person or group, constitutes more than 50% of the
total fair market value or total voting power of the stock of the Company; however, if any one person or more than one person acting as a
group, is considered to own more than 50% of the total fair market value or total voting power of the stock of the Company, the acquisition of
additional stock by the same person or persons will not be considered a “change in the ownership of the Company” (or to cause a “change in
the effective control of the Company” within the meaning of paragraph (ii) below) and an increase of the effective percentage of stock owned
by any one person, or persons acting as a group, as a result of a transaction in which the Company acquires its stock in exchange for property
will be treated as an acquisition of stock for purposes of this paragraph; provided, further, however, that for purposes of this Section 1.16, any
acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any entity controlled by the Company
will not constitute a Change of Control. This paragraph (i) applies only when there is a transfer of the stock of the Company (or issuance of
stock) and stock in the Company remains outstanding after the transaction.
(ii) A “change in the effective control of the Company” which shall occur on the date that either (A) any one person, or more than one
person acting as a group, acquires (or has acquired during the twelve month period ending on the date of the most recent acquisition by such
person or persons) ownership of stock of the Company possessing 35% or more of the total voting power of the stock of the Company, except
for any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any entity controlled by the
Company; or (B) a majority of the members of the Board are replaced during any twelve-month period by directors whose appointment or
election is not endorsed by a majority of the members of the Board prior to the date of the appointment or election. For purposes of a “change
in the effective control of the Company,” if any one person, or more than one person acting as a group, is considered to effectively control the
Company within the meaning of this Section 1.16, the acquisition of additional control
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of the Company by the same person or persons is not considered a “change in the effective control of the Company,” or to cause a “change in
the ownership of the Company” within the meaning of paragraph (i) above.
(iii) A “change in the ownership of a substantial portion of the Company’s assets” which shall occur on the date that any one person, or
more than one person acting as a group, acquires (or has acquired during the twelve month period ending on the date of the most recent
acquisition by such person or persons) assets of the Company that have a total gross fair market value equal to or more than 40% of the total
gross fair market value of all the assets of the Company immediately prior to such acquisition or acquisitions. For this purpose, gross fair
market value means the value of the assets of the Company, or the value of the assets being disposed of, determined without regard to any
liabilities associated with such assets. Any transfer of assets to an entity that is controlled by the shareholders of the Company immediately
after the transfer, as provided in guidance issued pursuant to Section 409A (as defined below), shall not constitute a Change of Control.
For purposes of the definition of Change of Control, the provisions of section 318(a) of the Internal Revenue Code (the “ Code ”) regarding
the constructive ownership of stock will apply to determine stock ownership; provided, that, stock underlying unvested options (including
options exercisable for stock that is not substantially vested) will not be treated as owned by the individual who holds the option. In addition,
for purposes of this Section 1.16, “Company” includes (x) Parsley, (y) the entity for whom Employee performs services, and (z) an entity that
is a stockholder owning more than 50% of the total fair market value and total voting power (a “ Majority Shareholder ”) of Parsley or the
entity identified in (y) above, or any entity in a chain of entities in which each entity is a Majority Shareholder of another entity in the chain,
ending in Parsley or the entity identified in (y) above.
1.17 Release and Compliance with this Agreement . The obligation of the Parsley Group to pay any portion of the amounts due
pursuant to Sections 1.14, 1.15, and 1.16, with the exception of the Accrued Obligations, shall be expressly conditioned on (i) Employee’s
execution (and, if applicable, non-revocation) of a full general release, releasing all claims, known or unknown, that Employee may have
against the Parsley Group, including those arising out of or in any way related to Employee’s employment or termination of employment with
the Parsley Group no later than the 60 th day following the date of Employee’s termination of employment (such period, the “ Release
Consideration Period ”) and (ii) continued compliance with the requirements of Sections II and III (the “ Severance Conditions ”). If
Employee (x) does not execute the release described above during the Release Consideration Period, or (y) breaches Section II or III of this
Agreement, (i) Parsley shall immediately cease any payments owed pursuant to Sections 1.14, 1.15, or 1.16 (other than the Accrued
Obligations) but not yet paid and shall have no obligation to make any further payments to Employee pursuant to Sections 1.14, 1.15, or 1.16
and (ii) Employee shall promptly pay to Parsley (or its successor) an amount equal to any payments Employee has received pursuant to
Sections 1.14, 1.15, or 1.16 (other than the Accrued Obligations) as of the time of Employee’s breach or refusal to execute the general release
(such repayment outlined in (ii) of this sentence, the “ Recoupment Payment ”).
1.18 Excise Taxes. If the Compensation Committee determines, in its sole discretion, that Section 280G of the Code applies to any
compensation payable to Employee, then the provisions of this Section 1.18 shall apply. If any payments or benefits to which Employee is
entitled from the Parsley Group, any successor to Parsley or another member of the Parsley Group, or any trusts established by any of the
foregoing by reason of, or in connection with, any transaction that occurs after the Effective Date (collectively, the “ Payments ,” which shall
include, without limitation, the vesting of any equity awards or other non-cash benefit or property) are, alone or in the aggregate, more likely
than not, if paid or delivered to Employee, to be subject to the tax imposed by Section 4999 of the Code or any successor provisions to that
section, then the Payments (consistent with the requirements of Section 409A (as defined below) and beginning with any Payment to be paid
in cash hereunder), shall be either (a) reduced (but not below zero) so that the present value of such total Payments received by Employee will
be one dollar ($1.00) less than three times Employee’s
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“base amount” (as defined in Section 280G(b)(3) of the Code) and so that no portion of such Payments received by Employee shall be subject
to the excise tax imposed by Section 4999 of the Code, or (b) paid in full, whichever of (a) or (b) produces the better net after tax position to
Employee (taking into account any applicable excise tax under Section 4999 of the Code and any other applicable taxes). The determination
as to whether any Payments are more likely than not to be subject to taxes under Section 4999 of the Code and as to whether reduction or
payment in full of the amount of the Payments provided hereunder results in the better net after tax position to Employee shall be made by the
Board and Employee in good faith.
1.19 Resignation. Unless otherwise agreed to in writing by Parsley and Employee prior to the termination of Employee’s
employment, any termination of Employee’s employment shall constitute, to the extent applicable: (i) an automatic resignation of Employee
as an officer of each member of the Parsley Group and (ii) an automatic resignation of Employee from the Board and the board of directors or
board of managers of each member of the Parsley Group and from the board of directors or managers or similar governing body of any
corporation, limited liability entity or other entity in which Parsley or another member of the Parsley Group holds an equity interest and with
respect to which board or similar governing body Employee serves as a designee or other representative for a member of the Parsley Group.
II.
CONFIDENTIALITY AND NON-DISCLOSURE AGREEMENT
2.01 Return of Property. Employee hereby acknowledges and agrees that all Personal Property and equipment furnished to
Employee in the course of, or incident to, Employee’s employment by the Parsley Group belongs to the Parsley Group and shall be promptly
returned to Parsley upon termination of employment or upon demand by the Parsley Group. “ Personal Property ” includes, without
limitation, all automobiles, computers, phones, equipment, well reports, engineering data, credit cards, books, manuals, records, reports,
notes, contracts, lists, blueprints, and other documents, or materials, or copies thereof (including computer files and other electronically stored
information), and all other proprietary information relating to the business of any member of the Parsley Group. Following termination,
Employee will not retain any written, computer files, or other tangible or intangible material containing any proprietary information,
Confidential Information (as defined below) or trade secrets of the Parsley Group or any of its agents, employees, and representatives.
2.02 Developed Intellectual Property. Employee also acknowledges and agrees that in connection with the performance of
Employee’s duties, Employee may author, create, or develop Confidential Information, trade secrets, and other intellectual property, both
alone or in conjunction with others. With respect to any and all trade secrets, inventions (whether or not patentable), discoveries, conceptions,
ideas, copyrights (including copyrights in software), know-how, other intellectual property or proprietary rights and/or improvements to any
of the same authored, created, conceived, developed, or reduced to practice by Employee or Parsley (whether alone or in combination with
others) (a) during Employee’s working hours, or (b) at Parsley’s, expense, or (c) using any of Parsley’s, materials or facilities, or (d) that
relates to the business of Parsley or to the research or development of Parsley (collectively, “ Developed Intellectual Property ”), Employee
agrees that the same are, and shall be, the exclusive property of the Parsley Group. Employee further acknowledges that all original works of
authorship made by Employee (solely or jointly with others) that constitute Developed Intellectual Property are “works made for hire,” as that
term is defined in the United States Copyright Act. Without limiting the immediately preceding sentence, Employee agrees to and does
hereby assign to Parsley, or its nominee, Employee’s entire right, title, and interest in and to all Developed Intellectual Property. For clarity,
such assignment includes all registrations or applications for registration of such Developed Intellectual Property, including any U.S. or
international applications for patents or copyright registrations filed during or after the Term of this Agreement. Employee shall promptly
disclose all such works made for hire and other Developed Intellectual Property to Parsley and, both during and after the Term of this
Agreement, agrees to execute, at no cost to Parsley, any and all documents that Parsley reasonably deems necessary to obtain, maintain,
protect and/or enforce its worldwide right to, title interest in, and ownership of such works made for hire and Developed Intellectual Property.
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2.03 Confidential Information. During Employee’s employment, Parsley also agrees to provide, and Employee will develop as
part of Employee’s duties, various trade secrets and other confidential information that are, or will be, owned by Parsley, and that Parsley
expressly agrees to assist Employee in developing. Such trade secrets or confidential information includes (but is not limited to) internal
confidential information previously developed or compiled by Parsley, commercially obtained information at substantial cost, research
resources and other valuable and proprietary materials, and more specifically (but without limitation): financial information and company
planning, strategic goals and plans of Parsley or another member of the Parsley Group, geophysical data, engineering data and compilations,
well logs, well production records, well files, seismic and other geophysical data and interpretation, engineering data and analysis, maps,
samples, cores, cuttings, well logs, well production records, well files, and the like (“ Confidential Information ”). Employee stipulates and
acknowledges: (i) that the Confidential Information is not generally known outside of Parsley’s business or by employees and others involved
in the same business as Parsley; (ii) that Parsley takes significant measures to guard the secrecy of this information; (iii) that the information
is extremely valuable to Parsley and would be valuable to Parsley’s competitors; (iv) that Parsley has expended material amounts of money
and effort in developing this Confidential Information; and (v) that this Confidential Information could not be easily or properly acquired by
others.
2.04 Confidentiality Obligation. Employee agrees to not disclose, directly or indirectly, any of the Confidential Information of
Parsley, nor use it in any way, directly or indirectly, except in furtherance of Employee’s duties as an employee under this Agreement.
Employee specifically agrees that Employee will not use any Confidential Information for Employee’s own benefit, the benefit of any other
person, including competitors of Parsley, or for the disadvantage of Parsley. Employee will take care to guard the security of the Confidential
Information at all times. In this regard, Employee agrees that Employee will not disclose any of this Confidential Information to any person
that does not need to know and have the right to know the information, including other Parsley employees, and that Employee will take care
in guarding electronic data. Notwithstanding the foregoing, to the extent that Employee shall be required, by law or process of law, to disclose
Confidential Information, Employee shall be entitled to do so only to the extent so required, subject to giving prompt, advance notice of such
requirement in writing to the General Counsel of Parsley so that Parsley may pursue a protective order or other remedy, and Employee
acknowledges and agrees to cooperate reasonably with Parsley’s efforts to obtain a confidentiality order or similar protection.
2.05 Duties Upon Termination. Employee agrees that at such time as Employee’s services are terminated or upon demand by the
Parsley Group, for whatever reason, Employee shall promptly return: (i) all Confidential Information (however stored) and (ii) equipment in
Employee’s possession belonging to Parsley.
2.06 These confidentiality duties survive the termination of Employee’s employment into perpetuity.
III. NON-COMPETITION AGREEMENT AND NON-SOLICITATION
3.01 Ancillary. The non-competition obligations of Employee and the non-solicitation provisions in this Section III are ancillary
to, and are supported by (and in support of), Parsley’s and Employee’s respective obligations set forth in this Agreement.
3.02
Definitions. Terms given special meaning in this Section III are:
“ Compete ” means: (i) to lease, purchase, or otherwise obtain a mineral estate (in whole or in part), including purchasing or obtaining
a royalty interest, overriding royalty interest, working interest, or the like or (ii) to work as a landman or provide any land-related services for
any corporate entity operating as an exploration and production business other than members of the Parsley Group.
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“ Restricted Period ” means during such time as Employee is employed with Parsley and the one-year period commencing on the date
Employee ceases employment with Parsley for any reason and ending on the first anniversary thereof; provided, however, that if Parsley
terminates Employee’s employment other than for Cause, the Restricted Period shall end six months after the date of termination of
Employee’s employment with Parsley.
“ Territory ” means all land within a three mile radius from the farthest outside edge of each oil or gas lease that is or was under lease,
letter agreement, or operated by a member of the Parsley Group as of the effective date of this Agreement.
3.03 Non-Compete Obligation. In return for the consideration given in this Agreement and in support of the promises therein,
Employee agrees that Employee will not Compete during the Restricted Period in the Territory.
3.04 Non-Solicitation. In return for the consideration given in this Agreement and in support of the promises therein, Employee
agrees that Employee will not directly or indirectly solicit or hire any employee of the Parsley Group to be an employee or co-venturer in
another matter that Competes or intends to Compete with Parsley during the Restricted Period in the Territory.
3.05 Non‑‑Disparagement. Employee shall not, during the Term or any time thereafter, make any untrue, misleading, or
defamatory statements concerning the Parsley Parties. After termination of Employee’s employment with the Parsley Group for any reason,
Parsley shall make commercially reasonable efforts to ensure that its managers, directors and officers do not make any untrue, misleading, or
defamatory statements concerning Employee. Employee will not, and Parsley shall make commercially reasonable efforts to ensure that its
managers, directors and officers do not, directly or indirectly make, repeat or publish any false, disparaging, negative, unflattering,
accusatory, or derogatory remarks or references, whether oral or in writing, concerning the Parsley Parties or Employee, respectively, or
otherwise take any action which might reasonably be expected to cause damage or harm to the Parsley Parties or Employee, respectively.
However, nothing in this Agreement is intended to restrict actions or communications protected or required by law, such as enforcing rights
under this Agreement or any other agreement, testifying truthfully as a witness, or complying with other legal obligations, including
communicating with or fully cooperating in the investigations of any governmental agency on matters within their jurisdictions.
3.06 Cooperation. Upon the receipt of reasonable notice from Parsley (including outside counsel), Employee agrees that while
employed by any Parsley and thereafter, Employee shall provide reasonable assistance to the Parsley Group and their respective
representatives in defense of any claims that may be made against any member of the Parsley Group and shall assist in the prosecution of any
claims that may be made by any member of the Parsley Group, to the extent that such claims relate to or arise out of Employee’s service to or
employment by Parsley. Employee agrees to inform Parsley promptly if Employee becomes aware of any lawsuits involving such claims that
may be filed or threatened against any member of the Parsley Group. Employee also agrees to inform Parsley promptly (to the extent legally
permitted to do so) if Employee is asked to assist in any investigation of any member of the Parsley Group (or its actions), regardless of
whether a lawsuit or other proceeding has then been filed against any member of the Parsley Group with respect to such investigation. Upon
presentation of appropriate documentation, Parsley shall pay or reimburse Employee for all reasonable out-of-pocket expenses incurred by
Employee in complying with this Section 3.06. If at the time of compliance Employee is no longer an employee, officer or director (or
functional equivalent) of any member of the Parsley Group, Parsley shall provide a reasonable per diem to Employee.
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3.07 Stipulation of Reasonable Scope and Term. Employee warrants, represents, and stipulates that the consideration given in
this Agreement was good and valid consideration and that no bad faith existed in the negotiation of this Agreement. Employee further
warrants, represents, and stipulates the duties imposed and rights granted in this Section III are necessary to protect legitimate interests of
Parsley and the Parsley Group as set forth in this document and, in particular, that the non‑compete obligations set forth in Section 3.03 are
fair, appropriate, and reasonable in their limitations with respect to time, geographic area, and scope of activities and impose no more restraint
than is necessary to protect Parsley’s legitimate business interest, nor are they oppressive, nor will they unreasonably deprive Employee of the
ability to earn a living.
IV.
GENERAL
4.01 Enforcement by Injunction. Employee acknowledges that Employee’s violation or threatened or attempted violation of the
covenants contained in Section III of this Agreement will cause irreparable harm to Parsley and that money damages would not be sufficient
remedy for any breach of those covenants. Employee agrees that Parsley shall be entitled as a matter of right to specific performance of the
covenants in Section III of this Agreement, including entry of an ex parte temporary restraining order in a state or federal court, preliminary
and permanent injunctive relief against activities in violation of this Agreement, or both, or other appropriate judicial remedy, writ, or order,
in any court of competent jurisdiction, restraining any violation or further violation of such agreements by Employee or others acting on
Employee’s behalf, without any showing of irreparable harm and without any showing that Parsley does not have an adequate remedy at law.
In furtherance of the intent to allow for immediate injunctive relief in the event of a breach, or threatened breach, of this Agreement,
Employee agrees that Parsley would be entitled to its attorneys’ fees if successful in seeking injunctive relief and that any temporary
restraining order or temporary/preliminary injunction bond should not be more than $1,000. Injunction is expressly not the exclusive remedy
hereunder.
4.02 Assignment. This Agreement is personal to Employee, and neither this Agreement nor any rights or obligations hereunder
shall be assignable or otherwise transferred by Employee. Parsley may assign this Agreement without Employee’s consent to any successor
(whether by merger, purchase, or otherwise) to all or substantially all of the equity, assets, or businesses of Parsley. The rights and obligations
of Parsley under this Agreement will inure to the benefit of the successors and assigns of Parsley.
4.03 Savings Clause. Should any court of competent jurisdiction hold any term, provision, covenant, or condition of this
Agreement (or portion thereof) to be illegal, void, unenforceable, or otherwise invalid, such term, provision, covenant, or condition (or
portion thereof), will be automatically conformed to the applicable law -to give the provision(s) the greatest effectuation possible of the
original intent allowed by law and equity, and this Agreement will otherwise continue in full force and effect.
4.04 Entire Agreement. This Agreement represents the entire agreement of the Parties regarding the employment of Employee
and cancels and supersedes all prior written or oral agreements, including, without limitation, the Prior Agreement and any other prior non-
disclosure, confidentiality, or employment agreements. The terms are contractual and not mere recitals. In entering into this Agreement, each
Party stipulates, warrants, and represents that it or Employee has relied on the advice of its or Employee’s own attorneys and financial
advisors concerning the legal and tax consequences of the Agreement; that its or Employee’s own attorneys have completely read and
explained to it or Employee the terms of the Agreement; that each is a sophisticated business person with experience negotiating these types
of transactions; that no special relationship of influence or trust existed among the Parties prior to the entry into this Agreement that caused it
or Employee to enter this Agreement; that each fully understands and voluntarily accepts the terms of the Agreement without any duress or
undue persuasion put upon it or Employee by the other or any other person, specifically including, but not limited to, counsel or accountants
for either Party; and that no representations, promises, or statements outside the four corners of this Agreement by the opposite Party,
nor any agent, employee, attorney, accountant, or other representative of the opposite Party
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has influenced it or Employee into entering this Agreement . Each Party has had access to counsel and an opportunity to read, review, and
revise this Agreement. This Agreement is the result of the joint efforts of the Parties and each of the party’s respective counsel. Therefore, the
Parties agree that this Agreement, and any given provision of it, should not be construed against either Party. Each of the Parties hereto
recognize and stipulate that this provision is binding as a matter of law and fact and shall preclude said Party from asserting that Employee
was wrongfully induced to enter into this Agreement by any representation, promise, or agreement, or statement of a past or existing fact,
which is not found within the four corners of this Agreement.
4.05 Key Person Insurance. Parsley and Employee acknowledge that Employee is a “key person” and as such Parsley may take
out life insurance on such Employee for the benefit of Parsley or its affiliates. Employee agrees to cooperate with Parsley and submit to the
necessary medical examinations and tests reasonably required to obtain such insurance, but insurability is not a condition of employment or
continuation of employment.
4.06 No Waiver. A waiver of any breach of any of the terms of this Agreement shall be effective only if in writing and signed by
the Party against whom such waiver or breach is claimed. No waiver of any breach shall be deemed a waiver of any other subsequent breach.
4.07 Further Assurances. Each Party shall each execute such assignments, endorsements and other instruments and documents
and shall give such further assurance as shall be reasonably necessary to perform its obligations under this Agreement.
4.08 Third Party Beneficiaries. Each member of the Parsley Group, together with any additional or future affiliates thereof, are
expressly third party beneficiaries of Employee’s representations herein and can enforce this Agreement as if a party hereto.
4.09 Clawback. Notwithstanding any other provisions in this Agreement to the contrary, any incentive-based compensation, or any
other compensation, paid to Employee pursuant to this Agreement or any other agreement or arrangement with Parsley or another member of
the Parsley Group which is subject to recovery under any law, government regulation or stock exchange listing requirement, will be subject to
such deductions and clawback as may be required to be made pursuant to such law, government regulation or stock exchange listing
requirement (or any policy adopted by Parsley or the Parsley Group pursuant to any such law, government regulation or stock exchange
listing requirement).
4.10 Section 409A.
(i) This Agreement is intended to comply with Section 409A of the Code and the applicable Treasury Regulations issued
thereunder (“ Section 409A ”) or an exemption thereunder and shall be construed and administered in accordance with Section 409A.
Notwithstanding any other provision of this Agreement, payments provided under this Agreement may only be made upon an event and in a
manner that complies with Section 409A or an applicable exemption. Any payments under this Agreement that may be excluded from Section
409A either as separation pay due to an involuntary separation from service or as a short-term deferral shall be excluded from Section 409A
to the maximum extent possible. For purposes of Section 409A, each installment payment provided under this Agreement shall be treated as a
separate payment. Any payments to be made under this Agreement upon a termination of employment shall only be made upon a “separation
from service” under Section 409A. The amount of expenses eligible for reimbursement, or in-kind benefits provided, if any, under this
Agreement during Employee’s taxable year shall not affect the expenses eligible for reimbursement or in in-kind benefits to be provided, in
any other taxable year. Further, the reimbursement of an eligible expense will be made on or before the last day of Employee’s taxable year
following the taxable year in which the expense was incurred and the right to reimbursement or in-kind benefits, if any, is not subject to
liquidation or exchange for another benefit. Notwithstanding the foregoing,
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the Parsley Group makes no representations that the payments and benefits provided under this Agreement comply with Section 409A and in
no event shall the Parsley Group be liable for all or any portion of any taxes, penalties, interest or other expenses that may be incurred by
Employee on account of non-compliance with Section 409A.
(ii) Notwithstanding any other provision of this Agreement, if any payment or benefit provided to Employee in connection with
Employee’s termination of employment is determined to constitute “nonqualified deferred compensation” within the meaning of Section
409A and Employee is determined to be a “specified employee” as defined in Section 409A(a)(2)(b)(i), then such payment or benefit shall not
be paid until the first payroll date to occur following the six-month anniversary of the date of Employee’s termination of employment (the “
Specified Employee Payment Date ”). The aggregate of any payments that would otherwise have been paid before the Specified Employee
Payment Date shall be paid to Employee in a lump sum on the Specified Employee Payment Date and thereafter, any remaining payments
shall be paid without delay in accordance with their original schedule.
4.11 Governing Law; Venue; Waiver of Trial by Jury.
(i) This Agreement and the rights of the Parties hereunder shall be governed by, interpreted, and enforced in accordance with the
internal laws of the State of Texas without giving effect to any choice of law or conflicts of law rules or provisions thereof.
(ii) This Agreement was negotiated, made, executed, and will be performed (in whole or in part) in Midland County, Texas. Each
Party irrevocably agrees that any action or proceeding involving any dispute or matter arising under or relating to this Agreement may only be
brought in the state or federal courts of the State of Texas in Midland County. In accordance with the foregoing, each Party agrees that the
courts of Midland County will be the exclusive venue for any dispute or matter arising under or relating to this Agreement, which such
jurisdiction, forum, and venue each Party expressly acknowledges and agrees has a direct, reasonable relation to this Agreement and any
controversy relating to or arising from this Agreement, and the Parties agree not to raise, and hereby waive, any objection to or defense based
upon the jurisdiction or venue of any such court or forum non conveniens.
(iii) TO THE EXTENT NOT PROHIBITED BY APPLICABLE LAW, EACH PARTY TO THIS AGREEMENT HEREBY WAIVES, AND
COVENANTS THAT IT SHALL NOT ASSERT (WHETHER AS PLAINTIFF, DEFENDANT OR OTHERWISE), ITS RESPECTIVE RIGHT TO A JURY
TRIAL OF ANY PERMITTED CLAIM OR CAUSE OF ACTION ARISING OUT OF THIS AGREEMENT, ANY OF THE TRANSACTIONS
CONTEMPLATED HEREBY, OR ANY DEALINGS BETWEEN ANY OF THE PARTIES HERETO RELATING TO THE SUBJECT MATTER OF THIS
AGREEMENT OR ANY OF THE TRANSACTIONS CONTEMPLATED HEREBY. THE SCOPE OF THIS WAIVER AND COVENANT IS INTENDED TO
BE ALL ENCOMPASSING OF ANY AND ALL DISPUTES THAT MAY BE FILED IN ANY COURT AND THAT RELATE TO THE SUBJECT MATTER
OF THIS AGREEMENT OR ANY OF THE TRANSACTIONS CONTEMPLATED HEREBY, INCLUDING, CONTRACT CLAIMS, TORT CLAIMS AND
ALL OTHER COMMON LAW AND STATUTORY CLAIMS. THIS WAIVER AND COVENANT IS IRREVOCABLE AND SHALL APPLY TO ANY
SUBSEQUENT AMENDMENTS, SUPPLEMENTS OR OTHER MODIFICATIONS TO THIS AGREEMENT .
(iv) In the event of any action or proceeding involving any dispute or matter arising under or relating to this Agreement, the
prevailing party in such action or proceeding shall be entitled to recover from the other party all reasonable and necessary attorneys’ fees
incurred in connection with such action or proceeding.
Employment, Confidentiality, and Non-Competition Agreement
Page 12 of 14
4.12 Multiple Counterparts. This Agreement may be executed in any number of counterparts, or with counterpart signature
pages, each of which shall be deemed an original, but all of which shall constitute one and the same instrument.
[Signatures Follow]
Employment, Confidentiality, and Non-Competition Agreement
Page 13 of 14
Executed as of this 26 th day of February 2014.
EMPLOYEE:
/s/ Michael Hinson
Michael Hinson, an individual
Parsley Energy Operations, LLC
By: /s/ Bryan Sheffield
Bryan Sheffield, President
Employment, Confidentiality, and Non-Competition Agreement
Page 14 of 14
Exhibit 10.21
PARSLEY ENERGY OPERATIONS, LLC
FIRST AMENDMENT TO EMPLOYMENT, CONFIDENTIALITY, AND
NON-COMPETITION AGREEMENT
WHEREAS, Parsley Energy Operations, LLC (“ Parsley ”) and Michael Hinson, a natural person (“ Employee ”) (Employee and
Parsley each referred to as a “ Party ” and, collectively, as the “ Parties ” herein) entered into an Employment, Confidentiality, and Non-
Competition Agreement, effective as of May 29, 2014 (the “ Agreement ”); and
WHEREAS, the Parties desire to amend the Agreement as described below, effective as of the date set forth below.
NOW, THEREFORE, the Agreement shall be amended as follows:
1. The phrases “(including equity compensation)” and “, except as otherwise provided in the award agreement under which the award
was granted,” shall be deleted from Section 1.13 , and the phrase “by the Board” shall be deleted from the definition of “Cause” in
Section 1.13 and replaced with the phrase “by Parsley”.
2. The final sentence of the first paragraph of Section 1.14 of the Agreement shall be deleted and the following shall be substituted
therefor:
Further, if Employee is terminated pursuant to this Section 1.14 prior to the date on which all unvested outstanding equity awards held
by Employee vest and Employee has fulfilled the Severance Conditions, then (i) at the end of the applicable performance period, a
portion of each unvested grant of performance-based equity awards shall vest, such portion to be equal to the product of (A) the total
number of such awards that would have vested based on the actual levels of performance over the applicable performance period had
Employee continued to provide services to the Parsley Group through the end of such performance period and (B) a fraction, the
numerator of which is equal to the number of days in the applicable performance period for such award that elapsed prior to
Employee’s termination of employment and the denominator of which is equal to the total number of days in the applicable
performance period (the “ Performance-Based Pro-Rata Awards ”), and (ii) a portion of each unvested grant of time-based equity
awards shall immediately vest as of the date of Employee’s termination of employment, such portion to be equal to the product of (A)
the total number of awards included in such grant to Employee and (B) a fraction, the numerator of which is equal to the number of
days that elapsed from the date of grant of such award through the date of Employee’s termination of employment and the
denominator of which is equal to the total number of days from the date of grant through the last vesting date applicable to such grant
(the “ Time-Based Pro-Rata Awards ”); provided, however, that the Time-Based Pro-Rata Awards shall be reduced by the number of
awards from the same grant that vested prior to Employee’s termination of employment, if any. The Performance-Based Pro-Rata
Awards will be settled at the time they would have been settled if Employee had continued to provide services to the Parsley Group
through the end of the applicable performance period; provided, however, that such settlement date shall not be earlier than the first
business day following the Release Consideration Period (the “ Initial Payment Date ”) and shall not be later than sixty-five (65) days
following the end of the applicable performance period. The Time-Based Pro-Rata Awards shall be settled on or following the Initial
Payment Date but no later than sixty-five (65) days following Employee’s termination of employment. Notwithstanding the foregoing,
awards of restricted stock granted to Employee on May 29, 2014, if any, shall vest according to the terms of the applicable award
agreement, and this Section 1.14 shall have no bearing on the vesting of such awards.
First Amendment to Employment, Confidentiality, and Non-Competition Agreement
Page 1 of 5
3. Section 1.15 of the Agreement shall be deleted and the following shall be substituted therefor:
1.15 Death or Disability. Employee’s employment shall terminate automatically on the date of Employee’s death or
immediately upon Parsley’s sending Employee a notice of termination of employment for “ Disability ,” which shall mean
Employee’s inability to perform the essential functions of Employee’s position, with reasonable accommodation, due to an illness or
physical or mental impairment or other incapacity that continues, or can reasonably be expected to continue, for a period in excess of
ninety (90) days (whether or not consecutive) during any period of three hundred sixty-five (365) consecutive days. Upon termination
of Employee’s employment by reason of death or Disability pursuant to this Section 1.15, Employee shall be entitled to receive (i) the
Accrued Obligations and (ii) provided that Employee or Employee’s estate, as applicable, has fulfilled the Severance Conditions, (A)
beginning on the Initial Payment Date, Employee’s Base Salary for the remainder of the calendar year in which death or Disability
occurred, which, following the Initial Payment Date, shall be paid as and when such amounts would have been due had Employee’s
employment continued (the “ Death or Disability Payment ”) and (B) following the applicable performance period, if any, a portion of
Employee’s Annual Bonus for the calendar year in which death or Disability occurred, such portion equal to the product of (1) the
Annual Bonus Employee would have been eligible to receive pursuant to Section 1.03 had Employee continued to provide services to
the Parsley Group through the payment date of such Annual Bonus based on the actual achievement of the applicable performance
conditions, if any, as determined by the Compensation Committee in its sole discretion and (2) a fraction, the numerator of which is
equal to the number of days in the calendar year that elapsed prior to Employee’s termination of employment by reason of death or
Disability and the denominator of which is three hundred sixty-five (365) (the “ Death or Disability Bonus ”). Any installments of the
Death or Disability Payment that, in accordance with customary payroll practices, would have typically been made during the Release
Consideration Period shall accumulate and shall then be paid on the Initial Payment Date. The Death or Disability Bonus shall be paid
in a lump-sum on or before the date annual bonuses for the calendar year in which death or Disability occurred are paid to employees
of the same level and responsibility who have continued employment with the Parsley Group; provided, however, in no event shall
the Death or Disability Bonus be paid prior to the Initial Payment Date or later than March 15 of the calendar year following the
calendar year in which death or Disability occurred. Further, if Employee is terminated pursuant to this Section 1.15 prior to the date
on which all unvested outstanding equity awards held by Employee vest and Employee or Employee’s estate, as applicable, has
fulfilled the Severance Conditions, then (A)(i) the target number of each grant of performance-based equity awards outstanding shall
immediately vest as of the date of Employee’s termination of employment, and (ii) all unvested outstanding time-based equity awards
held by Employee shall immediately vest as of the date of Employee’s termination of employment and (B) such awards shall be
settled on or following the Initial Payment Date but no later than sixty-five (65) days following Employee’s termination of
employment.
4. The final sentence of the first paragraph of Section 1.16 of the Agreement shall be deleted and the following shall be substituted
therefor:
Further, if Employee is terminated pursuant to this Section 1.16 prior to the date on which all unvested outstanding time-based equity
awards held by Employee vest and Employee has fulfilled the Severance Conditions, then all unvested outstanding time-based equity
awards held by Employee shall immediately vest as of the date of Employee’s termination of employment, and such time-based
equity awards shall be settled on or following the Initial Payment Date but no later than sixty-five (65) days following Employee’s
termination of employment. For the avoidance of doubt and notwithstanding anything to the contrary in this Agreement, if Employee
is terminated pursuant to this Section 1.16, then the treatment of each unvested grant of performance-based equity awards
First Amendment to Employment, Confidentiality, and Non-Competition Agreement
Page 2 of 5
granted following a Change of Control shall be determined in accordance with the terms of the award agreement applicable to each
such grant.
5. The following shall be added as a new Section 1.20 :
1.20 Vesting of Performance-Based Equity Awards Based on Actual Performance upon Change of Control. Provided
that Employee remains continuously employed by Parsley from the date of grant of the award through the date that is immediately
prior to the occurrence of a Change of Control, then upon the occurrence of a Change of Control, each grant of performance-based
equity awards outstanding shall immediately vest based on the actual achievement of the applicable performance conditions, as
determined by the Compensation Committee in its sole discretion, measured from the first day of the applicable performance period
through the date immediately prior to the Change of Control. Such awards shall be settled no later than thirty (30) days following the
Change of Control. For the avoidance of doubt, no time-based equity awards shall vest as a result of this Section 1.20.
6. The following shall be added as a new Section 1.21 :
1.21 COBRA Expense Reimbursement Obligation Canceled if Sanctions or Taxes Imposed. Notwithstanding anything
in Section 1.14 and Section 1.16 of this Agreement to the contrary, neither Parsley nor any member of the Parsley Group shall have
any obligation to reimburse Employee for any portion of the cost incurred by Employee to obtain continuation of coverage under the
Parsley Group’s health plans following termination of employment if such reimbursement would subject any member of the Parsley
Group to sanctions imposed pursuant to Section 2716 of the Public Health Service Act.
7. Section 2.02 of the Agreement shall be deleted and the following shall be substituted therefor:
2.02 Developed Intellectual Property. Employee also acknowledges and agrees that in connection with the performance of
Employee’s duties, Employee may author, create, conceive, develop or reduce to practice Confidential Information, trade secrets, and
other Intellectual Property (as defined below) in whole or in part, either alone or jointly with others. With respect to any and all such
Intellectual Property and/or improvements to any of the same authored, created, conceived, developed, or reduced to practice by
Employee or Parsley (whether alone or in combination with others) (a) during Employee’s working hours, or (b) at Parsley’s expense,
or (c) using any of Parsley’s materials or facilities, or (d) that relates to the business of Parsley or to the research or development of
Parsley (collectively, “ Developed Intellectual Property ”), Employee agrees that the same are, and shall be, the exclusive property of
the Parsley Group. Employee further acknowledges that all original works of authorship made by Employee (alone or jointly with
others) that constitute Developed Intellectual Property are “works made for hire,” as that term is defined in the United States
Copyright Act and to the extent allowed by law. Without limiting the immediately preceding sentence, to the extent Employee
develops any interest in the Developed Intellectual Property, Employee agrees to and does hereby assign to Parsley, or its nominee,
Employee’s entire right, title, and interest in and to all Developed Intellectual Property. For clarity, such assignment includes all
registrations or applications for registration of such Developed Intellectual Property, including any U.S. or international applications
for patents or copyright registrations filed during or after the Term of this Agreement. Employee shall promptly disclose all such
works made for hire and other Developed Intellectual Property to Parsley and, both during and after the Term of this Agreement,
agrees to execute, at Parsley’s expense, any and all documents that Parsley reasonably deems necessary to assign, obtain, maintain,
protect and/or enforce its worldwide right to, title interest in, and ownership of such works made for hire and Developed Intellectual
Property. Employee agrees
First Amendment to Employment, Confidentiality, and Non-Competition Agreement
Page 3 of 5
to perform, during and after the Term of this Agreement, all acts deemed necessary or desirable by Parsley to permit and assist
Parsley in evidencing, perfecting, obtaining, maintaining, defending, and enforcing rights and/or Employee’s assignment of such
works made for hire and Developed Intellectual Property in any and all countries, at Parsley’s expense. Such acts may include, but are
not limited to, execution of documents and assistance or cooperation in legal proceedings. Employee hereby irrevocably designates
and appoints Parsley and its duly authorized officers and agents, as Employee’s agents and attorneys-in-fact to act for and on behalf
and instead of Employee, to execute and file any documents and to do all other lawfully permitted acts to further the above purposes
with the same legal force and effects as if executed by Employee.
“ Intellectual Property ” means software, technical data, know-how, discoveries, conceptions, ideas, research, reports, patents,
inventions (whether or not patentable), copyrights (including copyrights in software), trademarks, and trade secrets, including all
forms and types of financial, business, scientific, technical, economic, or engineering information, including patterns, plans,
compilations, program devices, formulas, designs, prototypes, methods, techniques, processes, procedures, programs, or codes,
whether tangible or intangible, and whether or how stored, compiled, or memorialized physically, electronically, graphically,
photographically, or in writing.
8. The phrase “Notwithstanding the foregoing,” shall be deleted from Section 2.04 and replaced with the phrase “Notwithstanding the
foregoing and subject to Section 2.07,”.
9. The following shall be added as a new Section 2.07 :
2.07 Whistleblowing. Nothing in this Agreement will prevent Employee from: (i) making a good faith report of possible
violations of applicable law to the Securities and Exchange Commission (“ SEC ”) or any other governmental agency or entity or (ii)
making disclosures to the SEC or any other governmental agency or entity that are protected under the whistleblower provisions of
applicable law, in each case, without notice to Parsley. Nothing in this Agreement limits Employee’s right, if any, to receive an award
for information provided to the SEC. For the avoidance of doubt, nothing herein shall prevent Employee from making a disclosure of
a trade secret that: (A) is made (1) in confidence to a federal, state or local government official, either directly or indirectly, or to an
attorney; and (2) solely for the purpose of reporting or investigating a suspected violation of law; or (B) is made in a complaint or
other document filed in a lawsuit or other proceeding, if such filing is made under seal. Further, an individual who files a lawsuit for
retaliation by an employer of reporting a suspected violation of law may disclose a trade secret to the attorney of the individual and
use the trade secret information in the court proceeding, if the individual (X) files any document containing the trade secret under seal
and (Y) does not disclose the trade secret, except pursuant to court order.
10. The following shall be added as a new Section 2.08 :
2.08 Legally Protected Activities. Nothing in this Agreement precludes Employee from engaging in legally protected
activities, including those protected by the National Labor Relations Act.
11. The following shall be added as a new Section 2.09 .
2.09 Exclusive Knowledge. Employee acknowledges and agrees that Employee will obtain knowledge and skill relevant to
the Parsley Group’s industry, methods of doing business and marketing strategies by virtue of Employee’s employment; and that the
terms and conditions of this Agreement are reasonable under these circumstances. Employee further acknowledges that Confidential
Information has been and will be developed or acquired by the Parsley Group through
First Amendment to Employment, Confidentiality, and Non-Competition Agreement
Page 4 of 5
the expenditure of substantial time, effort and money. Employee understands and acknowledges that this Confidential Information
and the Parsley Group’s ability to reserve it for the exclusive knowledge and use of the Parsley Group is of great competitive
importance and commercial value to the Parsley Group, and that improper use or disclosure of the Confidential Information by
Employee might cause the Parsley Group to incur financial costs, loss of business advantage, liability under confidentiality
agreements with third parties, civil damages and criminal penalties. Employee agrees that the Parsley Group’s substantial investments
in its business interests, goodwill, and Confidential Information are worthy of protection, and that the Parsley Group’s need for the
protection afforded by this Section 2.09 and Section III is greater than any hardship Employee might experience by complying with
its terms.
12. The definition of “Restricted Period” in Section 3.02 shall be deleted and the following shall be substituted therefor:
“ Restricted Period ” means during such time as Employee is employed with Parsley and the one-year period commencing on
the date Employee ceases employment with Parsley for any reason and ending on the first anniversary thereof; provided, however,
that if Employee’s employment is terminated by Employee for Good Reason or by Parsley other than for Cause, the Restricted Period
shall end six months after the date of termination of Employee’s employment with Parsley.
13. As amended hereby, the Parties ratify and reaffirm the Agreement.
[Signatures Follow]
First Amendment to Employment, Confidentiality, and Non-Competition Agreement
Page 5 of 5
Executed as of this 30 th day of September 2016.
EMPLOYEE:
/s/ Michael Hinson
Michael Hinson, an individual
PARSLEY ENERGY OPERATIONS, LLC
By: /s/ Colin Roberts
Colin Roberts, General Counsel
First Amendment to Employment, Confidentiality, and Non-Competition Agreement
Signature Page
Exhibit 10.58
NOTICE OF GRANT OF RESTRICTED STOCK
(Performance-Based)
Pursuant to the terms and conditions of the Parsley Energy, Inc. 2014 Long Term Incentive Plan, attached as Appendix A
(the “Plan”), and the associated Restricted Stock Agreement, attached as Appendix B (the “Agreement”), you are hereby issued
shares of Stock, subject to certain restrictions thereon, and under the terms and conditions set forth below, in the Agreement, and in
the Plan (the “Restricted Shares”). Capitalized terms used but not defined herein shall have the meanings set forth in the Plan.
Grantee:
Date of Grant :
Number of Restricted Shares Granted :
______________________
____________ (“Date of Grant”)
____________ (the “Restricted Shares”)
Fair Market Value of Shares on Date of Grant:
______________________
Vesting Schedule :
Subject to the terms and conditions of the Agreement and the Plan, the restrictions on a proportion
of the Restricted Shares will expire and such proportion of the Restricted Shares will become
transferable and nonforfeitable as calculated in accordance with Appendix C; provided, however,
that such restrictions will expire under the circumstances enumerated in Appendix C only if you
remain in the employ of or a service provider to the Company or its Subsidiaries continuously from
the Date of Grant through the end of the Performance Period (as defined below), except as otherwise
provided in Section 6 of the Agreement. The period over which the Company’s performance will be
measured for purposes of applying the methodology set forth in Appendix C shall be from [______]
to [______] (the “Performance Period”).
You and the Company hereby acknowledge receipt of the Restricted Shares issued on the Date of Grant indicated above,
which have been issued under the terms and conditions contained herein and in the Plan and the Agreement.
You acknowledge and agree that (a) you are not relying upon any determination by the Company, its affiliates, or any of their
respective employees, directors, officers, attorneys or agents (collectively, the “Company Parties”) of the Fair Market Value of the
Stock on the Date of Grant, (b) you are not relying upon any written or oral statement or representation of the Company Parties
regarding the tax effects associated with this Notice of Grant of Restricted Stock or your execution of the Agreement and your
receipt and holding of and the vesting of the Restricted Shares, and (c) in deciding to enter into the Agreement, you are relying on
your own judgment and the judgment of the professionals of your choice with whom you have consulted. You hereby release, acquit
and
forever discharge the Company Parties from all actions, causes of actions, suits, debts, obligations, liabilities, claims, damages,
losses, costs and expenses of any nature whatsoever, known or unknown, on account of, arising out of, or in any way related to the
tax effects associated with your execution of the Agreement and your receipt and holding of and the vesting of the Restricted Shares.
In addition, you are consenting to receive documents from the Company and any plan administrator by means of electronic
delivery, provided that such delivery complies with the rules, regulations, and guidance issued by the Securities and Exchange
Commission and any other applicable government agency. This consent shall be effective for the entire time that you are a
participant in the Plan.
Furthermore, you understand and acknowledge that you should consult with your tax advisor regarding the advisability of
filing with the Internal Revenue Service an election under section 83(b) of the Code with respect to the Restricted Shares for which
the restrictions have not lapsed. This election must be filed no later than 30 days after Date of Grant set forth in this Notice of Grant
of Restricted Stock. This time period cannot be extended. You acknowledge (a) that you have been advised to consult with a tax
advisor regarding the tax consequences of the award of the Restricted Shares and (b) that timely filing of a section 83(b) election is
your sole responsibility, even if you request the Company or its representative to file such election on your behalf.
You further acknowledge receipt of a copy of the Plan and the Agreement and agree to all of the terms and conditions of the
Plan and the Agreement, which are incorporated herein by reference.
Attachments: Appendix A - Parsley Energy, Inc. 2014 Long Term Incentive Plan
Appendix B - Restricted Stock Agreement
Appendix C - Performance Vesting Criteria and Methodology
Appendix D - Section 83(b) Election
2
Appendix A
Parsley Energy, Inc. 2014 Long Term Incentive Plan
Appendix A-1
Appendix B
Restricted Stock Agreement
Appendix B-1
Appendix C
Performance-Based Restricted Stock Vesting Criteria and Methodology
This Appendix C to this Notice of Grant of Restricted Stock (Performance-Based) contains the performance requirements and methodology for the vesting of the
Restricted Shares. Capitalized terms used but not defined herein or in the Notice of Grant of Restricted Stock shall have the same meaning assigned to them in the
Agreement or the Plan.
A. Performance Criteria
[ ]
B. Threshold(s)
[ ]
C. Additional Factors or Information Regarding Performance Vesting Methodology
[ ]
Appendix C-1
1.
2.
3.
Appendix D
INSTRUCTIONS FOR FILING
YOUR SECTION 83(b) ELECTION
Completely fill out and sign three copies of the election form.
Not later than 30 days after the date of grant, mail one executed copy of the election by certified mail, return receipt requested, to the
IRS Service Center where your federal tax returns are filed (see the chart below for the appropriate IRS Service Center). Attached is a
sample cover letter to the Internal Revenue Service to be used in connection with filing the Section 83(b) election
Taxpayer’s State of Residence
Florida, Louisiana, Mississippi, Texas
Alaska, Arizona, Arkansas, California, Colorado, Hawaii, Idaho, Illinois, Indiana, Iowa, Kansas, Michigan,
Minnesota, Montana, Nebraska, Nevada, New Mexico, North Dakota, Ohio, Oklahoma, Oregon, South Dakota,
Utah, Washington, Wisconsin, Wyoming
IRS Service Center
Department of the Treasury
Internal Revenue Service
Austin, TX 73301-0002
Department of the Treasury
Internal Revenue Service
Fresno, CA 93888-0002
Alabama, Connecticut, Delaware, District of Columbia, Georgia, Kentucky, Maine, Maryland, Massachusetts,
Missouri, New Hampshire, New Jersey, New York, North Carolina, Pennsylvania, Rhode Island, South Carolina,
Tennessee, Vermont, Virginia, West Virginia
Department of the Treasury
Internal Revenue Service
Kansas City, MO 64999-0002
A foreign country, U.S. possession or territory*, or use an APO or FPO address, or file Form 2555, 2555-EZ, or
4563, or are a dual-status alien
Department of the Treasury
Internal Revenue Service
Austin, TX 73301-0215
*If you live in American Samoa, Puerto Rico, Guam, the U.S. Virgin Islands, or the Northern Mariana Islands, see IRS Publication 570.
Provide one copy of the executed election to:
Parsley Energy, Inc.
Attn: General Counsel
303 Colorado Street, Suite 3000
Austin, Texas 78701
4.
Retain one copy of the executed election for your records.
Note : It is your sole responsibility, and not the responsibility of Parsley Energy, Inc. (the “ Company ”) or any of its affiliates, to
timely file your Section 83(b) election even if you request the Company or any of its affiliates or any of their respective managers,
directors, officers, employees or authorized representatives (including attorneys, accountants, consultants, bankers, lenders,
prospective lenders and financial representatives) of the Company to assist in making such filing. In addition, the Company and its
affiliates cannot provide you with tax advice. The information provided in these instructions is general in nature and if you have any
specific questions about your individual tax circumstances, you should consult with your tax adviser.
Appendix D-1
SUGGESTED FORM OF SECTION 83(b)
ELECTION TRANSMITTAL LETTER
[DATE]
VIA CERTIFIED MAIL
Return Receipt Requested
Department of the Treasury
Internal Revenue Service Center
[Insert applicable IRS service center address]
Re: Election Under Section 83(b) of the Internal Revenue Code
Ladies and Gentlemen:
Pursuant to Treasury Regulation Section 1.83-2(c) promulgated under Section 83 of the Internal Revenue Code of 1986, as amended
(the “Code”), enclosed please find a copy of an executed election under Section 83(b) of the Code relating to the issuance of Class A common
stock of Parsley Energy, Inc., a Delaware corporation.
Enclosure
Very truly yours,
[______________]
Appendix D-2
SECTION 83(b) ELECTION FORM
The undersigned taxpayer hereby elects, pursuant to Section 83(b) of the Internal Revenue Code of 1986, as amended, to include in
gross income as compensation for services the excess (if any) of the fair market value of the property described below over the amount paid
for such property.
1.
The name, social security number and address of the undersigned (the “ Taxpayer ”), and the taxable year for which this election is
being made are:
Taxpayer’s Name: ______________________ _____
Taxpayer’s Social Security Number: __________ -______- _________
Taxpayer’s Address: ______________________ _____
Taxpayer’s Address: ______________________ _____
Taxable Year: 201___
The property that is the subject of this election (the “ Property ”) is _______ shares of Class A common stock in Parsley Energy, Inc.
The Property was transferred to the Taxpayer on __________, 201___.
The Property is subject to the following restriction: The shares are subject to various transfer restrictions and are subject to forfeiture
in the event certain service and performance conditions are not satisfied.
The fair market value of the Property at the time of transfer (determined without regard to any restriction other than a nonlapse
restriction as defined in Section 1.83-3(h) of the Income Tax Regulations) is $______ per Class A common share x _______ shares =
$___________.
The amount paid by the Taxpayer for the Property is $0.00.
The amount to include in gross income is $______________.
2.
3.
4.
5.
6.
7.
The undersigned taxpayer will file this election with the Internal Revenue Service office with which the taxpayer files his or her annual
income tax return not later than 30 days after the date of transfer of the Property. A copy of the election also will be furnished to the person
for whom the services were performed. The undersigned is the person performing the services in connection with which the Property was
transferred.
Dated:
Taxpayer's Signature
Appendix D-3
PARSLEY ENERGY, INC.
2014 LONG TERM INCENTIVE PLAN
RESTRICTED STOCK AGREEMENT
Exhibit 10.59
This Agreement is made and entered into as of the “Date of Grant” set forth in the Notice of Grant of Restricted Stock (the
“Notice of Grant”) by and between Parsley Energy, Inc., a Delaware corporation (the “Company”), and you;
WHEREAS , the Company adopted the Parsley Energy, Inc. 2014 Long Term Incentive Plan, as it may be amended from
time to time (the “Plan”) under which the Company is authorized to grant restricted stock awards to certain employees and service
providers of the Company;
WHEREAS , in order to induce you to enter into or to continue to provide services to the Company and to materially
contribute to the success of the Company, the Company agrees to grant you this restricted stock award;
WHEREAS , a copy of the Plan has been furnished to you and shall be deemed a part of this restricted stock award
agreement (“Agreement”) as if fully set forth herein and the terms capitalized but not defined herein shall have the meanings set
forth in the Plan; and
WHEREAS , you desire to accept the restricted stock award made pursuant to this Agreement.
NOW, THEREFORE, in consideration of and mutual covenants set forth herein and for other valuable consideration
hereinafter set forth, the parties agree as follows:
1.
The Grant . Subject to the conditions set forth below, the Company hereby grants to you, effective as of the Date of
Grant, as a matter of separate inducement but not in lieu of any salary or other compensation for your services for the Company, an
award (the “Award”) consisting of the aggregate number of Restricted Shares of Stock set forth in the Notice of Grant in accordance
with the terms and conditions set forth herein, in the Notice of Grant and in the Plan.
2.
Escrow of Restricted Shares . The Company shall evidence the Restricted Shares in the manner that it deems
appropriate. The Company may issue in your name a certificate or certificates representing the Restricted Shares and retain that
certificate or those certificates until the restrictions on such Restricted Shares expire as described in the Notice of Grant and Section
5 of this Agreement or the Restricted Shares are forfeited as described in the Notice of Grant and Sections 4 and 6 of this Agreement.
If the Company certificates the Restricted Shares, you shall execute one or more stock powers in blank for those certificates and
deliver those stock powers to the Company. The Company shall hold the Restricted Shares and the related stock powers pursuant to
the terms of this Agreement, if applicable, until such time as (a) a certificate or certificates for the Restricted Shares are delivered to
you, (b) the Restricted Shares are otherwise transferred to you free of restrictions, or (c) the Restricted Shares are canceled and
forfeited pursuant to this Agreement.
3.
Ownership of Restricted Shares . Subject to the terms, conditions and restrictions set forth in this Agreement, from
and after the time the Restricted Shares are issued in your name, you will be entitled to all the rights of absolute ownership of the
Restricted Shares, including the right to vote those shares and the right to receive dividends thereon; provided, however, that any
dividends paid by the Company with respect to the Restricted Shares prior to the expiration of the Forfeiture Restrictions shall be
held in escrow by the Company and paid to you, if at all, at the time the Forfeiture Restrictions expire on the Restricted Share for
which the dividend accrued; provided, further, that in no event shall dividends be settled later than 74 days following the date on
which the Forfeiture Restrictions expire with respect to the Restricted Share for which the dividends were accrued. For purposes of
clarity, if the Restricted Shares are forfeited by you pursuant to the terms of this Agreement then you shall also forfeit the dividends,
if any, accrued with respect to such forfeited Restricted Shares. No interest will accrue on the dividends between the declaration and
settlement of the dividends.
4.
Restrictions; Forfeiture . The Restricted Shares are restricted in that they may not be sold, transferred or otherwise
alienated or hypothecated until these restrictions are removed or expire as described in the Notice of Grant and Section 5 of this
Agreement. The Restricted Shares are also restricted in the sense that they may be forfeited to the Company (the “Forfeiture
Restrictions”). You hereby agree that if the Restricted Shares are forfeited, as provided in the Notice of Grant and Section 6 of this
Agreement, the Company shall have the right to deliver the Restricted Shares to the Company’s transfer agent for, at the Company’s
election, cancellation or transfer to the Company.
5.
Expiration of Restrictions and Risk of Forfeiture . The restrictions on the Restricted Shares granted pursuant to this
Agreement will expire and the Restricted Shares will become transferable and nonforfeitable as set forth in the Notice of Grant and
in Section 6 below, provided that you remain in the employ of, or a service provider to, the Company or its Subsidiaries until the
applicable dates set forth therein.
6.
Termination of Services .
(a)
Termination Generally . Subject to subsection (b) and (c) of this Section 6, if your service relationship with
the Company or any of its Subsidiaries is terminated for any reason, then those Restricted Shares for which the restrictions have not
lapsed as of the date of termination shall become null and void and those Restricted Shares shall be forfeited to the Company. The
Restricted Shares for which the restrictions have lapsed as of the date of such termination, including Restricted Shares for which the
restrictions lapsed in connection with such termination, shall not be forfeited to the Company.
(b)
Termination by Reason of Death or Disability . Notwithstanding subsection (a) of this Section 6 above, if
your service relationship with the Company or any of its Subsidiaries is terminated by reason of death or Disability (as defined
below) prior to the date on which the Restricted Shares vest as provided in the Notice of Grant, then effective as of the date of such
separation from service, the restrictions on [NTD:
For
Performance-Based
Restricted
Shares
Only:]
[50% of the] [NTD:
For
Time-Based
Restricted
Shares
Only:]
[all] Restricted Shares
2
granted pursuant to this Agreement, including the Forfeiture Restrictions, will immediately expire, and such Restricted Shares will
become transferable and nonforfeitable.
“Disability” shall mean (i) your inability to engage in any substantial gainful activity by reason of any medically
determinable physical or mental impairment that can be expected to result in death or last for a continuous period of not less than 12
months, or (ii) that you are receiving income replacement benefits for a period of at least three months under a company-sponsored
accident and health plan by reason of any medically determinable physical or mental impairment that can be expected to result in
death or can be expected to last for a continuous period of not less than 12 months.
(c)
Effect of Employment Agreement . Notwithstanding any provision herein to the contrary, in the event of
any inconsistency between this Section 6 and any employment agreement entered into by and between you and the Company
or its Subsidiaries, the terms of the employment agreement shall control. [NTD:
For
Performance-Based
Restricted
Shares
Only:]
[For purposes any employment agreement entered into by and between you and the Company or its Subsidiaries, the
term “target number” shall be deemed to reference 50% of the aggregate number of Restricted Shares granted pursuant to this
Agreement.]
7.
Leave of Absence . With respect to the Award, the Company may, in its sole discretion, determine that if you are on
leave of absence for any reason you will be considered to still be in the employ of, or providing services for, the Company; provided,
that rights to the Restricted Shares during a leave of absence may be limited to the extent to which those rights were earned or vested
when the leave of absence began; provided, further, that no “separation from service” has occurred, as such term is defined in
Section 409A of the Internal Revenue Code, as amended, and the regulations and guidance promulgated thereunder.
8.
Delivery of Stock . Promptly following the expiration of the restrictions on the Restricted Shares as contemplated in
Section 5 of this Agreement, the Company shall cause to be issued and delivered to you or your designee a certificate or other
evidence of the number of Restricted Shares as to which restrictions have lapsed, free of any restrictive legend relating to the lapsed
restrictions, upon receipt by the Company of any tax withholding as may be requested pursuant to Section 9. The value of such
Restricted Shares shall not bear any interest owing to the passage of time.
9.
Payment of Taxes . The Company may require you to pay to the Company (or the Company’s Subsidiary if you are
an employee of a Subsidiary of the Company), an amount the Company deems necessary to satisfy its (or its Subsidiary’s) current or
future obligation to withhold federal, state or local income or other taxes that you incur as a result of the Award and may condition
settlement of the Award upon such payment. With respect to any required tax withholding, the Committee may, in its sole discretion:
(a) withhold from the shares of Stock to be issued to you under this Agreement the number of shares necessary to satisfy the
Company’s obligation to withhold taxes; which determination will be based on the shares’ Fair Market Value at the time such
determination is made; (b) allow you to deliver to the Company shares of Stock sufficient to satisfy the Company’s tax withholding
obligations, based on the shares’ Fair Market Value at the time such determination is made; (c) allow you to deliver cash to the
Company sufficient to satisfy its tax
3
withholding obligations; (d) satisfy such tax withholding through any combination of (a), (b) and (c); or (e) take such other action as
the Company deems advisable to enable the Company (or its Subsidiaries) to satisfy obligations for the payment of withholding
taxes and other tax obligations related to the Award. In the event the Company determines that the aggregate Fair Market Value of
the shares of Stock withheld as payment of any tax withholding obligation is insufficient to discharge that tax withholding
obligation, then you must pay to the Company, in cash, the amount of that deficiency immediately upon the Company’s request.
10.
Compliance with Securities Law . Notwithstanding any provision of this Agreement to the contrary, the issuance
of Stock (including Restricted Shares) will be subject to compliance with all applicable requirements of federal, state, or foreign law
with respect to such securities and with the requirements of any stock exchange or market system upon which the Stock may then be
listed. No Stock will be issued hereunder if such issuance would constitute a violation of any applicable federal, state, or foreign
securities laws or other law or regulations or the requirements of any stock exchange or market system upon which the Stock may
then be listed. In addition, Stock will not be issued hereunder unless (a) a registration statement under the Securities Act, is at the
time of issuance in effect with respect to the shares issued or (b) in the opinion of legal counsel to the Company, the shares issued
may be issued in accordance with the terms of an applicable exemption from the registration requirements of the Securities Act. The
inability of the Company to obtain from any regulatory body having jurisdiction the authority, if any, deemed by the Company’s
legal counsel to be necessary to the lawful issuance and sale of any shares subject to the Award will relieve the Company of any
liability in respect of the failure to issue such shares as to which such requisite authority has not been obtained. As a condition to any
issuance hereunder, the Company may require you to satisfy any qualifications that may be necessary or appropriate to evidence
compliance with any applicable law or regulation and to make any representation or warranty with respect to such compliance as
may be requested by the Company. From time to time, the Board, the Committee and appropriate officers of the Company are
authorized to take the actions necessary and appropriate to file required documents with governmental authorities, stock exchanges,
and other appropriate Persons to make shares of Stock available for issuance.
11.
Legends . The Company may at any time place legends referencing any restrictions imposed on the shares pursuant
to Section 4 of this Agreement on all certificates representing shares issued with respect to this Award.
12.
Right of the Company and Subsidiaries to Terminate Services . Nothing in this Agreement confers upon you the
right to continue in the employ of or performing services for the Company or any Subsidiary, or interfere in any way with the rights
of the Company or any Subsidiary to terminate your employment or service relationship at any time.
13.
Furnish Information . You agree to furnish to the Company all information requested by the Company to enable it
to comply with any reporting or other requirements imposed upon the Company by or under any applicable statute or regulation.
14.
Remedies . The parties to this Agreement shall be entitled to recover from each other reasonable attorneys’ fees
incurred in connection with the successful enforcement of the terms and
4
provisions of this Agreement whether by an action to enforce specific performance or for damages for its breach or otherwise.
15.
No Liability for Good Faith Determinations . The Company and the members of the Board and the Committee
shall not be liable for any act, omission or determination taken or made in good faith with respect to this Agreement or the Restricted
Shares granted hereunder.
16.
Execution of Receipts and Releases . Any payment of cash or any issuance or transfer of shares of Stock or other
property to you, or to your legal representative, heir, legatee or distributee, in accordance with the provisions hereof, shall, to the
extent thereof, be in full satisfaction of all claims of such Persons hereunder. The Company may require you or your legal
representative, heir, legatee or distributee, as a condition precedent to such payment or issuance, to execute a release and receipt
therefor in such form as it shall determine.
17.
No Guarantee of Interests . The Board, the Committee and the Company do not guarantee the Stock of the
Company from loss or depreciation.
18.
Notice . All notices required or permitted under this Agreement must be in writing and personally delivered or sent
by mail and shall be deemed to be delivered on the date on which it is actually received by the person to whom it is properly
addressed or if earlier the date it is sent via certified United States mail.
19.
Waiver of Notice . Any person entitled to notice hereunder may waive such notice in writing.
20.
Information Confidential . As partial consideration for the granting of the Award hereunder, you hereby agree to
keep confidential all information and knowledge, except that which has been disclosed in any public filings required by law, that you
have relating to the terms and conditions of this Agreement; provided, however, that such information may be disclosed as required
by law and may be given in confidence to your spouse and tax and financial advisors. In the event any breach of this promise comes
to the attention of the Company, it shall take into consideration that breach in determining whether to recommend the grant of any
future similar award to you, as a factor weighing against the advisability of granting any such future award to you.
21.
Successors . This Agreement shall be binding upon you, your legal representatives, heirs, legatees and distributees,
and upon the Company, its successors and assigns.
22.
Severability . If any provision of this Agreement is held to be illegal or invalid for any reason, the illegality or
invalidity shall not affect the remaining provisions hereof, but such provision shall be fully severable and this Agreement shall be
construed and enforced as if the illegal or invalid provision had never been included herein.
23.
Company Action . Any action required of the Company shall be by resolution of the Board or by a person or entity
authorized to act by resolution of the Board.
5
24.
Headings . The titles and headings of Sections are included for convenience of reference only and are not to be
considered in construction of the provisions hereof.
25.
Governing Law . All questions arising with respect to the provisions of this Agreement shall be determined by
application of the laws of Delaware, without giving any effect to any conflict of law provisions thereof, except to the extent
Delaware state law is preempted by federal law. The obligation of the Company to sell and deliver Stock hereunder is subject to
applicable laws and to the approval of any governmental authority required in connection with the authorization, issuance, sale, or
delivery of such Stock.
26.
Consent to Texas Jurisdiction and Venue . You hereby consent and agree that state courts located in Midland
County, Texas and the United States District Court for the Western District of Texas each shall have personal jurisdiction and proper
venue with respect to any dispute between you and the Company arising in connection with the Award or this Agreement. In any
dispute with the Company, you will not raise, and you hereby expressly waive, any objection or defense to any such jurisdiction as
an inconvenient forum.
27.
Amendment . This Agreement may be amended the Board or by the Committee at any time (a) if the Board or the
Committee determines, in its sole discretion, that amendment is necessary or advisable in light of any addition to or change in any
federal or state, tax or securities law or other law or regulation, which change occurs after the Date of Grant and by its terms applies
to the Award; or (b) other than in the circumstances described in clause (a) or provided in the Plan, with your consent.
28.
Clawback . This Agreement is subject to any written clawback policies that the Company, with the approval of the
Board or the Committee, may adopt. Any such policy may subject your Award and amounts paid or realized with respect to Award
under this Agreement to reduction, cancelation, forfeiture or recoupment if certain specified events or wrongful conduct occur,
including but not limited to an accounting restatement due to the Company’s material noncompliance with financial reporting
regulations or other events or wrongful conduct specified in any such clawback policy adopted to conform to the Dodd-Frank Wall
Street Reform and Consumer Protection Act of 2010 and rules promulgated thereunder by the Securities and Exchange Commission
and that the Company determines should apply to this Agreement.
29.
The Plan . This Agreement is subject to all the terms, conditions, limitations and restrictions contained in the Plan.
[Remainder of page intentionally left blank]
6
Parsley Energy, Inc.
Subsidiaries
Exhibit 21.1
Entity
Parsley Energy, LLC
Parsley Energy, L.P.
Parsley Energy Operations, LLC
Parsley Administration, LLC
Parsley GP, LLC
Parsley Finance Corp.
Parsley Minerals, LLC
Parsley Veritas Energy Partners, LLC
Parsley DE Operating LLC
Parsley DE Lone Star LLC
Parsley Novus Land Services LLC
State of Jurisdiction
Delaware
Texas
Texas
Texas
Delaware
Delaware
Texas
Delaware
Delaware
Delaware
Delaware
Exhibit 23.1
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors
Parsley Energy, Inc.:
We consent to the incorporation by reference in the registration statement No. 333‑196295 on Form S-8, in the registration statement No. 333-
204766 on Form S-3 and in the registration statement No. 333-217626 on Form S-3 of Parsley Energy, Inc. and subsidiaries (the “Company”),
including amendments thereto, of our reports dated February 28, 2018, with respect to the consolidated balance sheets of the Company as of
December 31, 2017 and 2016, and the related consolidated statements of operations, changes in equity, and cash flows for each of the years in the
three-year period ended December 31, 2017, and the related notes (collectively, the “consolidated financial statements”), and the effectiveness of
internal control over financial reporting as of December 31, 2017, which reports appear in the December 31, 2017 annual report on Form 10‑K of the
Company.
Dallas, Texas
February 28, 2018
Exhibit 23.2
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
We hereby consent to the references to our firm, in the context in which they appear, and to the references to and the inclusion of our audit letter dated February 13,
2018, in the Annual Report on Form 10-K of Parsley Energy, Inc. (the "Company"). We also hereby consent to the incorporation by reference of the references to
our firm, in the context in which they appear, and of our audit letter dated February 13, 2018, into the Company's registration statements on Form S-8 (File No.
333-196295), Form S-3 (File No. 333-204766) and Form S-3 (File No. 333-217626), including any amendments thereto, in accordance with the requirements of the
Securities Act of 1933, as amended.
NETHERLAND, SEWELL & ASSOCIATES, INC.
By:
/s/ C.H. (Scott) Rees III, P.E.
C.H. (Scott) Rees III, P.E.
Chairman and Chief Executive Officer
Dallas, Texas
February 28, 2018
Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to
be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original
document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.
CERTIFICATION OF CHIEF EXECUTIVE OFFICER
PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)
OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED
Exhibit 31.1
I, Bryan Sheffield, certify that:
1.
2.
3.
4.
I have reviewed this Annual Report on Form 10-K (this “report”) of Parsley Energy, Inc. (the “registrant”);
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;
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;
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:
a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to
ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles;
c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant’s internal control over financial reporting; and
5.
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):
a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably
likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control
over financial reporting.
Date: February 28, 2018
By:
/s/ Bryan Sheffield
Bryan Sheffield
Chairman and Chief Executive Officer
CERTIFICATION OF CHIEF FINANCIAL OFFICER
PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)
OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED
Exhibit 31.2
I, Ryan Dalton, certify that:
1.
2.
3.
4.
I have reviewed this Annual Report on Form 10-K (this “report”) of Parsley Energy, Inc. (the “registrant”);
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;
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;
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:
a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to
ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles;
c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant’s internal control over financial reporting; and
5.
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):
a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably
likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control
over financial reporting.
Date: February 28, 2018
By:
/s/ Ryan Dalton
Ryan Dalton
Executive Vice President—Chief Financial Officer
CERTIFICATION OF CHIEF EXECUTIVE OFFICER
UNDER SECTION 906 OF THE
SARBANES OXLEY ACT OF 2002, 18 U.S.C. § 1350
Exhibit 32.1
In connection with the Annual Report on Form 10-K for the year ended December 31, 2017 of Parsley Energy, Inc. (the “Company”), as filed with the Securities
and Exchange Commission on the date hereof (the “Report”), I, Bryan Sheffield, Chairman of the Board of Directors and Chief Executive Officer of the Company,
hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge:
(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
Date: February 28, 2018
By:
/s/ Bryan Sheffield
Bryan Sheffield
Chairman and Chief Executive Officer
CERTIFICATION OF CHIEF FINANCIAL OFFICER
UNDER SECTION 906 OF THE
SARBANES OXLEY ACT OF 2002, 18 U.S.C. § 1350
Exhibit 32.2
In connection with the Annual Report on Form 10-K for the year ended December 31, 2017 of Parsley Energy, Inc. (the “Company”), as filed with the Securities
and Exchange Commission on the date hereof (the “Report”), I, Ryan Dalton, Executive Vice President—Chief Financial Officer of the Company, hereby certify,
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge:
(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
Date: February 28, 2018
By:
/s/ Ryan Dalton
Ryan Dalton
Executive Vice President—Chief Financial Officer
Exhibit 99.1
February 13, 2018
Ms. Carrie Endorf
Parsley Energy, Inc.
303 Colorado Street, Suite 3000
Austin, Texas 78701
Dear Ms. Endorf:
In accordance with your request, we have audited the estimates prepared by Parsley Energy, Inc. (Parsley), as of December 31, 2017, of the proved
reserves and future revenue to the Parsley interest in certain oil and gas properties located in Texas. It is our understanding that the proved reserves
estimates shown herein constitute all of the proved reserves owned by Parsley. We have examined the estimates with respect to reserves
quantities, reserves categorization, future producing rates, future net revenue, and the present value of such future net revenue, using the definitions
set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Rule 4‑10(a). The estimates of reserves and future revenue have been
prepared in accordance with the definitions and regulations of the SEC and, with the exception of the exclusion of future income taxes, conform to
the FASB Accounting Standards Codification Topic 932, Extractive Activities-Oil and Gas. We completed our audit on or about the date of this letter.
This report has been prepared for Parsley's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the
preparation of this report are appropriate for such purpose.
The following table sets forth Parsley's estimates of the net reserves and future net revenue, as of December 31, 2017, for the audited properties:
Category
Oil
(MBBL)
Net Reserves
NGL
(MBBL)
Gas
(MMCF)
Future Net Revenue (M$)
Total
Present Worth
at 10%
Proved Developed Producing
Proved Developed Non-Producing
Proved Undeveloped
118,534.7
1,056.3
128,940.1
49,153.9
237,190.3
597.4
3,147.0
42,880.9
211,365.6
4,026,467.6
47,628.0
4,629,516.3
2,447,329.5
28,046.5
1,442,655.0
Total Proved
248,531.1
92,632.2
451,702.9
8,703,611.9
3,918,031.6
Totals may not add because of rounding.
The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL);
a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and
pressure bases.
When compared on a lease-by-lease basis, some of the estimates of Parsley are greater and some are less than the estimates of Netherland,
Sewell & Associates, Inc. (NSAI). However, in our opinion the estimates shown herein of Parsley's reserves and future revenue are reasonable
when aggregated at the proved level and have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and
Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). Additionally, these estimates are within the
recommended 10 percent tolerance threshold set forth in the SPE Standards. We are satisfied with the methods and procedures used by Parsley in
preparing the December 31, 2017, estimates of reserves and future revenue, and we saw nothing of an unusual nature that would cause us to take
exception with the estimates, in the aggregate, as prepared by Parsley.
Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The
estimates of reserves and future revenue included herein have not been adjusted for risk. Parsley's estimates do not include probable or possible
reserves that may exist for these properties, nor do they include any value for undeveloped acreage beyond those tracts for which undeveloped
reserves have been estimated.
Prices used by Parsley are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period
January through December 2017. For oil and NGL volumes, the average West Texas Intermediate Phillips 66 posted price of $47.96 per barrel is
adjusted for quality, transportation fees, and market differentials. For gas volumes, the average Waha spot price of $2.665 per MMBTU is adjusted
for energy content, transportation fees, and market differentials. All prices are held constant throughout the lives of the properties. The average
adjusted product prices weighted by production over the remaining lives of the properties are $49.17 per barrel of oil, $22.20 per barrel of NGL, and
$2.530 per MCF of gas.
Operating costs used by Parsley are based on historical operating expense records. For the nonoperated properties, these costs include the per-well
overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels.
Operating costs for the operated properties are limited to direct lease- and field-level costs and Parsley's estimate of the portion of its headquarters
general and administrative overhead (G&A) expenses necessary to operate the properties. Parsley's estimates of G&A expenses are included at the
field area level. Operating costs have been divided into field area-level costs, per-well costs, and per-unit-of-production costs. Capital costs used by
Parsley are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new
development wells, and production equipment. Abandonment costs used are Parsley's estimates of the costs to abandon the wells and production
facilities, net of any salvage value. Operating, capital, and abandonment costs are not escalated for inflation.
The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil
and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable
and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves
may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to
the primary economic assumptions discussed herein, estimates of Parsley and NSAI are based on certain assumptions including, but not limited to,
that the properties will be developed consistent with current development plans as provided to us by Parsley, that the properties will be operated in a
prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the
reserves, and that projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues
therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of
supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions
made while preparing these estimates.
It should be understood that our audit does not constitute a complete reserves study of the audited oil and gas properties. Our audit consisted
primarily of substantive testing, wherein we conducted a detailed review of all properties. In the conduct of our audit, we have not independently
verified the accuracy and completeness of information and data furnished by Parsley with respect to ownership interests, oil and gas production, well
test data,
historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales
of production. However, if in the course of our examination something came to our attention that brought into question the validity or sufficiency of
any such information or data, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or had
independently verified such information or data. Our audit did not include a review of Parsley's overall reserves management processes and
practices.
We used standard engineering and geoscience methods, or a combination of methods, including performance analysis and analogy, that we
considered to be appropriate and necessary to establish the conclusions set forth herein. As in all aspects of oil and gas evaluation, there are
uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed
professional judgment.
Supporting data documenting this audit, along with data provided by Parsley, are on file in our office. The technical person primarily responsible for
conducting this audit meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards.
James E. Ball, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 1998
and has over 17 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do
not own an interest in these properties nor are we employed on a contingent basis.
Sincerely,
NETHERLAND, SEWELL & ASSOCIATES, INC.
Texas Registered Engineering Firm F-2699
By:
By:
/s/ C.H. (Scott) Rees III
C.H. (Scott) Rees III, P.E.
Chairman and Chief Executive Officer
/s/ James E. Ball
James E. Ball, P.E. 57700
Vice President
Date Signed: February 13, 2018
JEB:CVH
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