Parsley Energy Inc Annual Report 2014

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FY2014 Annual Report · Parsley Energy Inc

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2 014 A N N U A L R E P O R T

COMMITTED

TO THE

CORE

PARSLEY ENERGY

Founded in 2008, Parsley Energy is an independent oil and natural gas company with operations in the Permian

Basin, where we develop unconventional oil and natural gas reserves. As we efficiently and responsibly grow

reserves, production, and cash flow by developing our liquids-rich resource base, we seek to create value for

shareholders, employees, energy consumers, and the communities in which we work.

Over the past several years we have demonstrated a peer-leading growth profile and have expanded from a

two-person start-up to a large scale Permian Basin pure play operator with several hundred wells producing more

than 18,000 barrels of oil equivalent per day (net) at year-end 2014. With a substantial inventory of horizontal and

vertical drilling locations in the prolific core of the Midland Basin, we look forward to continued growth at superior

rates of return.

CORE AND TIER 1
ACREAGE GROW TH

79,635

PROVED RESERVES
(MMBoe)

90.9

50,349

54.8

Year-end
2013

Year-end
2014

58% GROWTH

CORE

TIER 1

Year-end
2013

Year-end
2014

66% GROWTH

PROVED RESERVES ALLOCATION

• Permian Basin pure play with a total of 136,347 net surface
acres and 370,808 net effective acres, which include the
Spraberry, Wolfcamp A, B, and C, Cline and Atoka intervals
• Of Parsley’s 49,000+ net acres in the Core area, approxi-

mately 98% are located in our Focus Area

• Acquisitions completed in 2014 increased Parsley’s Midland

Basin Core and Tier 1 acreage by 58%

• Parsley now has 1,800+ horizontal drilling locations in the

heart of the Midland Basin

QUARTERLY PRODUCTION GROW TH (Boe/d)

230%

COMPOUNDED ANNUAL
GROWTH 2011–2014
The transition in 2014 from vertical to horizontal drilling
accelerated Parsley’s production growth.

196

269

424

596

1,006

1,324

1,751

2,526

3,075

LIQUIDS
77%

GAS
23%

18,228

15,324

13,995

9,163

5,806

6,404

4,786

1Q
2011

1Q
2012

1Q
2013

1Q
2014

PARSLEY RINGS THE CLOSING BELL AT THE NYSE ON DECEMBER 12, 2014 TO CELEBRATE THE COMPANY’S IPO.

TO OUR
STOCKHOLDERS:

In 2014, Parsley Energy executed on our promise to deliver value
from our first-class asset base in the core of the Midland Basin.
We raised approximately $870 million of net proceeds in May
through the second-largest IPO ever by an E&P company, and we
put that capital to work for investors, nearly tripling our production,
more than doubling our proved developed reserves, and adding
meaningfully to our core acreage position and our inventory of
future horizontal drilling locations.

Over the course of 2014, we successfully transitioned from a
vertical drilling company to one focused on horizontal drilling.
The resulting increase in productivity—a function of basin-leading
initial production rates from our horizontal wells—enabled us to
grow net production by 184% year-over-year, averaging 14,200
barrels of oil equivalent per day (Boe/d) in 2014. More than 90% of
that growth was achieved through the drill bit, and 77% of our
2014 production was oil and natural gas liquids.

DAWSON

BORDEN

GAINES

ANDREWS

MARTIN

ECTOR

MIDLAND

TIER 1
ACREAGE

CORE
ACREAGE

HOWARD

GLASSCOCK

CRANE

UPTON

REAGAN

MILES

MIDLAND BASIN ACREAGE

PARSLEY ACREAGE

CENTRAL BASIN PLATFORM

MIDLAND BASIN

FOCUS AREA

2014 ANNUAL REPORTReserve growth was very strong in 2014, with proved reserves
up 66% year-over-year to almost 91 million barrels of oil equiva-
lent despite voluntarily writing off 14 MMBoe of vertical PUDs
and associated recompletions. We replaced 694% of our 2014
oil and gas production volumes, and the PV-10 value of our
proved reserves reached $1.3 billion at the end of the year, up
79% from the end of 2013. Organic growth accounted for the
majority of our reserve additions. We also delivered solid finan-
cial results, increasing Adjusted EBITDA(1) by 168% from $77 mil-
lion in 2013 to $206 million in 2014.

Taking into account political risk, repeatability, infrastructure,
access to markets, and productivity, acreage in the Midland
Basin constitutes one of the premier assets in the world, and we
are fortunate to have accumulated a substantial acreage port-
folio in the core of the play. Moreover, as a pure play E&P com-
pany, Parsley Energy offers greater dollar-for-dollar exposure to
the core of the Midland Basin than essentially any other invest-
ment vehicle.

A series of bolt-on acquisitions executed throughout the year
increased our Core and Tier 1 net acreage position by almost
60% during 2014, and we ended the year with more than 100,000
net acres in the Midland Basin. The majority of our acreage
offers “stacked pay” potential to develop oil and gas from several
prospective zones. We believe our acreage is in the deepest
and thickest portion of the Midland Basin and that these
characteristics, along with favorable thermal maturity, contribute
to higher productivity, number of discrete target horizons, and
resource potential.

5,000+

FEET OF
PROSPECTIVE ZONES

80–90%

OF 2015 PLANNED
WELLS TARGET
THE WOLFCAMP B
FORMATION

Parsley Energy’s exceptional horizontal well results are consistent
with our superior asset quality. Each of the more than 20 horizon-
tal wells we completed by the end of the year in the Wolfcamp A
and B formations exceeded the 690 MBoe type curve we con-
structed from publicly available well data. In fact, after six months
of production, cumulative production from our Wolfcamp wells has
exceeded that associated with the type curve by 65%. The initial
production rates associated with the Wolfcamp wells we have
drilled and completed in our Core acreage are among the very
best in the basin, averaging more than 200 Boe/d per 1,000 feet of
stimulated lateral. Such prolific initial production rates translate
into robust returns even in a depressed commodity price environ-
ment, with our Wolfcamp wells on track to pay out in less than two
years on average. Our returns were also enhanced during 2014 by
significant progress on the cost front, with both lease operating
expense per BOE and general and administrative expense per
BOE down almost 20%.

While 2014 was a year of accelerated growth, significant changes
in the macroeconomic environment, including substantially lower
commodity prices, have prompted a conservative capital program
in 2015. We are pleased to be among the more nimble E&P
companies, able to adapt quickly to changing conditions. As such,
we intend to reduce our capital spending by half compared with

(1) EBITDA—earnings before interest, taxes, depreciation and amortization—is a non-GAAP

measure. Please see a reconciliation to GAAP results in the accompanying 10-K.

PARSLEY ENERGY30%

EXPECTED
YEAR-OVER-YEAR
PRODUCTION GROWTH
Efficient spending plan on sharply

reduced capital budget.

2014 to a range of $225 million to $250 million. Despite the
reduced capital program, we still expect to deliver annual
production growth of approximately 30%—averaging 18,000-
19,000 Boe/d—and to achieve attractive economics from each
well we drill.

The shape of drilling activity in 2015 is intended to reflect an antic-
ipated uplift in returns associated with declining costs for services
and equipment, with two horizontal rigs running on average during
the first half of the year and four horizontal rigs running on
average during the second half of the year. Substantially all of
Parsley’s horizontal drilling activity will target zones from which
the company has already generated strong well productivity, with
80-90% of horizontal wells targeting the Wolfcamp B zone. In
order to hold acreage, the company intends to operate one verti-
cal rig on an as-needed basis, representing approximately 10% of
drilling and completion spending in 2015.

Looking ahead, we are confident that Parsley’s asset base
includes abundant value yet to be unlocked. We see substantial
opportunity to de-risk additional formations, to reduce between-
well spacing, and to develop our Southern Delaware acreage.
Based on a six-rig run rate and using conservative 870-foot
between-well spacing—or six wells per zone per section—we now
have approximately 25 years of horizontal drilling inventory.
Approximately one-third of this inventory consists of Wolfcamp A
and B drilling locations, and having drilled highly productive
Wolfcamp wells across the portion of our acreage in which
our drilling locations are concentrated, we are confident in the
repeatability of strong results across the entire location count.

WOLFCAMP WELLS
OUTPERFORMING
TYPE CURVE
At strip pricing(3), currently producing

Wolfcamp wells on track to pay out

in 2 years on average.

PE Average Horizontal Well Production(1)

20% EUR Increase: 830 MBoe

10% EUR Increase: 760 MBoe

690 MBoe EUR Type Curve(2)

(1) Normalized to 7,000 stimulated lateral and for
downtime of 24 hours or more; includes all
producing Wolfcamp A and B wells.
(2) Derived from public well data as of 10/14.
(3) Based on NYMEX strip pricing as of 3/18/2015.

)
e
o
B
M

(

N
O

T
C
U
D
O
R
P

E
V

T
A
L
U
M
U
C

16 0

14 0

12 0

10 0

8 0

6 0

4 0

2 0

65%

OUTPERFORMANCE
THROUGH 6 MONTHS

M O N T H S

2014 ANNUAL REPORT

Parsley’s Southern Delaware acreage shows

stacked pay potential, with particular promise

in the Wolfcamp formation.

PARSLEY ACREAGE

CENTRAL BASIN PLATFORM

DELAWARE BASIN

SOUTHERN DELAWARE BASIN ACREAGE

LOVING

WINKLER

ECTOR

WARD

CRANE

REEVES

PECOS

Miles

We are very encouraged by the data we’ve gathered to date in the
Southern Delaware Basin, where we hold approximately 30,000
net acres. Based on results from our vertical exploratory wells and
offsetting well data from other producers in the area, we are
excited about the potential for the horizontal development of the
Wolfcamp formation on our Southern Delaware acreage.

Following a well-received private placement of common equity in
February 2015 that raised $231 million of gross proceeds, we
have a strong balance sheet and liquidity profile. With more than
$500 million of liquidity, including a fully undrawn revolver, we are
well-positioned to fund our growth plans. Our net debt to total
capitalization at year end was less than 2.0, and we have no near-
term maturities. In addition, almost all of our anticipated 2015 oil
production is hedged, and we have more oil volumes hedged in
2016 than in 2015.

We are grateful for the confidence our investors have shown in our
company as we’ve delivered on our promise to build a first-class
asset base from which we’re driving value in an efficient,
disciplined manner. With our substantial drilling inventory in the
“core of the core” of the Midland Basin and an enviable track
record of highly productive horizontal wells, Parsley Energy is
poised to deliver high-return growth across market cycles.

Bryan Sheffield
Chairman, President, and CEO
April 28, 2015

PARSLEY ENERGY2 014

FORM 10-K

PA R S L E Y E N E R G Y

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(Mark One)
 ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF

1934

 TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE

ACT OF 1934

For the fiscal year ended December 31, 2014
or

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)

(737) 704-2300
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:

221 West 6th Street, Suite 750
Austin, Texas 78701
(Former address of principal executive offices)

Title of each class

Class A Common Stock, $0.01 par value

46-4314192
(I.R.S. Employer
Identification No.)

78701
(Zip Code)

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  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 
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  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  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. 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer




 (Do not check if a smaller reporting company)

Non-accelerated filer
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  No 
Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 30, 2014 was approximately
$1,795,805,293.
As of March 11, 2015, the registrant had 108,780,734 shares of Class A common stock and 32,145,296 shares of Class B common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive proxy statement for the 2015 Annual Meeting of Stockholders, to be filed no later than 120 days after the end of
this fiscal year, are incorporated by reference into Part III of this Annual Report on Form 10-K.

Smaller reporting company



Accelerated filer





PARSLEY ENERGY, INC.
FORM 10-K
ANNUAL PERIOD ENDED DECEMBER 31, 2014

TABLE OF CONTENTS

Page

PART I.

Business ..........................................................................................................................................................................

5
Item 1.
Item 1A. Risk Factors ................................................................................................................................................................... 20
Item 1B. Unresolved Staff Comments ......................................................................................................................................... 37
Properties ....................................................................................................................................................................... 38
Item 2.
Legal Proceedings .......................................................................................................................................................... 46
Item 3.
Mine Safety Disclosures ................................................................................................................................................ 46
Item 4.

PART II.

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity

Securities .................................................................................................................................................................... 47
Selected Financial Data ................................................................................................................................................. 48
Item 6.
Management’s Discussion and Analysis of Financial Condition and Results of Operations .................................. 51
Item 7.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk .................................................................................. 69
Financial Statements and Supplementary Data.......................................................................................................... 70
Item 8.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosures ................................ 70
Item 9.
Item 9A. Controls and Procedures ............................................................................................................................................... 70
Item 9B. Other Information ......................................................................................................................................................... 70

PART III.

Item 10. Directors, Executive Officers, and Corporate Governance ....................................................................................... 71
Item 11. Executive Compensation ............................................................................................................................................... 71
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters............. 71
Item 13. Certain Relationships and Related Transactions and Director Independence ........................................................ 72
Item 14. Principal Accounting Fees and Services ...................................................................................................................... 72

PART IV.

Item 15. Exhibits, Financial Statement Schedules ..................................................................................................................... 72

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in or incorporated by reference into this 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 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). These forward-looking
statements include statements, projections and estimates concerning our 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 report, or if 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
“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.

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 statement. This cautionary statement 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 section, to reflect events or circumstances after the date of this Annual Report on
Form 10-K.

GLOSSARY OF CERTAIN TERMS AND CONVENTIONS USED HEREIN

The terms defined in this section are used throughout this Annual Report on Form 10-K:

“Bbl.” One stock tank barrel, of 42 U.S. gallons liquid volume, used in reference to crude oil, condensate or natural gas liquids.

“Boe.” One barrel of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.

“Boe/d.” One barrel of oil equivalent per day.

“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.

“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.

“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.

“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.

“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.

“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).

“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.

“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.

“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. The field name refers to the surface area, although it may refer to both the surface and the
underground productive formations. For a complete definition of field, refer to the SEC’s Regulation S-X, Rule 4-10(a)(15).

“formation.” A layer of rock which has distinct characteristics that differ from nearby rock.

“GAAP.” Accounting principles generally accepted in the United States.

“gross acres” or “gross wells.” The total acres or wells, as the case may be, in which an entity owns a working interest.

“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.

“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.

“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.

“LIBOR.” London Interbank Offered Rate.

“MBbl.” One thousand barrels of crude oil, condensate or NGLs.

“MBoe.” One thousand barrels of oil equivalent.

“Mcf.” One thousand cubic feet of natural gas.

“MMBtu.” One million British thermal units.

“MMcf.” One million cubic feet of natural gas.

“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.

“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.

“NYMEX.” The New York Mercantile Exchange.

“operator.” The entity responsible for the exploration, development and production of a well or lease.

“PE Units.” The single class of units, in which all of the membership interests (including outstanding incentive units) in Parsley LLC

were converted to in connection with the initial public offering.

“proved developed reserves.” Proved reserves that can be expected to be recovered:

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.

“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, the project 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).

“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.

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.

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.

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.

“reasonable certainty.” A high degree of confidence. For a complete definition, refer to the SEC’s Regulation S-X, Rule 4-10(a)(24).

“recompletion.” The process of re-entering an existing wellbore that is either producing or not producing and completing new

reservoirs in an attempt to establish or increase existing production.

“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.

“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.

“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.

“SEC.” The United States Securities and Exchange Commission.

“spacing.” The distance between wells producing from the same reservoir. Spacing is often established by regulatory agencies.

“undeveloped acreage.” Lease 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.

“wellbore.” The hole drilled by the bit that is equipped for oil or gas production on a completed well. Also called well or borehole.

“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.

“workover” Operations on a producing well to restore or increase production.

“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.

ITEM 1:

BUSINESS

Overview

PART I

We are an independent oil and natural gas company focused on the acquisition, development and exploitation 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 primarily located in the Midland and
Delaware Basins and our activities have historically been focused on the vertical development of the Spraberry, Wolfberry and
Wolftoka Trends of the Midland Basin. Our vertical wells in the Permian Basin are drilled into stacked pay zones that include the
Spraberry, Wolfcamp, Upper Pennsylvanian (Cline), Strawn, Atoka and Mississippian formations. During the course of 2014 we
transitioned from primarily vertical development drilling to predominantly horizontal development drilling activity.

On May 29, 2014, we completed our initial public offering (the “Offering”) of 57.5 million shares of Parsley Energy, Inc.’s

Class A Common Stock, par value $0.01 per share (“Class A Common Stock”) at a price of $18.50 per share. Approximately
7.5 million of the shares were sold by selling stockholders and we did not receive any proceeds from the sale of those shares. The
remaining approximately 50 million shares of Class A Common Stock that were sold resulted in gross proceeds of approximately
$924.3 million to us and net proceeds, after deducting underwriting discounts and commissions and offering expenses, of
approximately $867.8 million. A portion of the proceeds from the Offering was used to repay all outstanding borrowings under the
revolving credit agreement entered into on September 10, 2014 (the “Revolving Credit Agreement”), to make a cash payment in
settlement of the Preferred Return (as defined herein), to fund the acquisition of certain oil and gas properties and to pay fees and
expenses related to the Offering. The remaining proceeds were used to fund a portion of our exploration and development program
and for general corporate purposes.

We began operations in August 2008 when we 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 (“Parker and Parsley”). As of December 31,
2014, we continue to operate 87 gross (1.5 net) of these wells. Excluding those legacy 87 gross wells, as of December 31, 2014, we
had an average working interest of 65% in 637 gross (414.9 net) producing wells. As of December 31, 2014, we have interests in 724
gross (416.4 net) producing wells, of which 722 gross (414.4 net) are in the Midland Basin and two gross (two net) are in the
Delaware Basin. We operate 99% of the wells in which we have an interest. Since our inception, we have leased or acquired 133,274
net acres in the Permian Basin, approximately 103,036 of which is in the Midland Basin. Since we commenced our drilling program in
November 2009, we have operated up to 12 rigs simultaneously and averaged 10 operated rigs for the year ended December 31, 2014.
We are currently operating four horizontal rigs and one vertical drilling rig. We expect to average operating three horizontal rigs and
one vertical rig for 2015.

We intend to grow our reserves and production through the development, exploitation and drilling of our multi-year inventory of

identified drilling locations. As of December 31, 2014, we have identified 1,893 80- and 40-acre potential vertical drilling locations,
2,403 20-acre potential vertical drilling locations and 2,125 potential horizontal drilling locations on our existing acreage, which does
not include any locations in Gaines County (Midland Basin) or in our Southern Delaware Basin acreage. We commenced our vertical
appraisal drilling program in the Delaware Basin during the first quarter of 2014 and as of the date of this annual report, we have
drilled and completed two vertical appraisal wells in that area. We believe our acreage in the Delaware Basin may also benefit from
the application of horizontal drilling and completion techniques. We expect to supplement organic growth from our drilling program
by proactively leasing additional acreage and selectively pursuing acquisitions that meet our strategic and financial objectives, with an
emphasis on oil-weighted reserves in the Midland Basin.

Our 2015 capital budget for drilling and completion is approximately $225 million to $250 million. Our capital budget excludes

any amounts that may be paid for acquisitions. For the year ended December 31, 2014, our capital expenditures for drilling and
completions were $491.3 million, as compared to $268.4 million for all of fiscal year 2013, excluding in each period amounts paid for
acquisitions. We expect the average working interest in wells we drill during 2015 will be approximately 90%.

The amount and timing of these capital expenditures is largely discretionary and within our control. We could choose to defer a
portion of these 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 interest owners.

The following table summarizes our acreage and technically identified drilling locations in the Permian Basin as of

December 31, 2014:

Horizontal (3)

Identified Drilling Locations(1)
Vertical(4)

Area (2)
Midland Basin-Core ...........
Midland Basin-Tier I ..........
Midland Basin-Other ..........
Southern Delaware Basin ...
Total Permian Basin ...........

Net Acreage

80-and 40-acre

20-acre

42,564
36,289
24,183
30,238
133,274

1,301
824
—
—
2,125

1,201
583
109
—
1,893

1,676
636
91
—
2,403

Horizontal
Drilling
Inventory
(Years (5))

Vertical
Drilling
Inventory
(Years (6))

22
14
—
—
36

118
50
8
—
176

(1) 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. Also see
‘‘Item 1A. Risk Factors.”
(2) Please see “Item 2. Properties.”
(3) Our target horizontal location count implies 660’ to 870’ between well spacing which is equivalent to five to eight wells per

640-acre section per prospective 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.

(4) Our total identified vertical drilling locations include 196 vertical locations on 80- and 40- acre spacing and no vertical locations

on 20-acre spacing associated with proved undeveloped reserves as of December 31, 2014. Of these 196 vertical locations, 177
are in our Midland Basin-Core area, and 19 are in our Midland Basin-Tier I area.

(5) Based on a continuous five-rig program and an estimated spud to release time of 31.2 days.
(6) Based on a continuous one-rig vertical drilling program and spud to release time of 15 days.

As of December 31, 2014, our estimated proved oil and natural gas reserves at December 31, 2014, were 90.9 MMBoe based on

a reserve report prepared by NSAI, our independent reserve engineers. Our proved reserves are approximately 52% oil, 25% NGLs,
23% natural gas and 51% proved developed.

Our Business Strategy

Our business strategy is to increase stockholder value through the following:

 Grow reserves, production and cash flow by exploiting 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 that
offer competitive returns that we consider to be low risk based on 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
99% of the 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 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. We have reduced the average
time from spud to rig release for our vertical Spraberry and Wolfberry wells from approximately 18 days during 2011 to
approximately 13 days in the fourth quarter of 2014. Our average total depth of wells drilled in 2014 was 11,411 feet. We
have also reduced our total drilling, completion and facilities costs from a peak average of $2.4 million per well in the first
quarter of 2012 to an average of $2.1 million per well in the fourth quarter of 2014. This decrease was driven primarily by
a reduction in hydraulic fracturing costs and efficiencies gained through economies of scale over this time period.
Additionally, we initiated cost reduction discussions with our suppliers beginning in November 2014. During the quarter
ended December 31, 2014, we realized approximately 5-10% cost reductions on drilling and completion expenditures and
further negotiations are ongoing.

 Pursue additional leasing and strategic acquisitions. 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,
with a focus primarily on our Midland Basin-Core area, while selectively pursuing other acquisition opportunities that
meet our strategic and financial objectives. Our acreage position extends through what we believe are multiple oil and
natural gas producing stratigraphic horizons in the Midland 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 provides us with a competitive advantage in identifying leasing opportunities
and acquisition targets and evaluating resource potential.

 Maintain financial flexibility. We intend to maintain a conservative financial position to allow us to develop our drilling,
exploitation and exploration 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 and access to capital
markets over time. As of December 31, 2014 pro forma for the Private Placement (as defined herein), we had
approximately $519.2 million of liquidity, with $154.5 million of cash and cash equivalents and $364.7 million of
available borrowing capacity under our Revolving Credit Agreement. Our borrowing base under the Revolving Credit
Agreement currently stands at $560.8 million, although we have chosen to limit the aggregate commitment to $365.0
million. Consistent with our disciplined approach to financial management, we have an active commodity hedging
program that seeks to hedge approximately 40% to 60% of our expected oil production on a rolling 24 to 36 month basis,
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. In addition, we have hedged 3,300 MMBtu of our
expected 2015 natural gas production. In periods of decreased drilling activity, our percentage of production hedged may
increase above our stated goal. As a result of a reduction in our planned drilling activity, we have greater than 90% of
expected oil production hedged in 2015, with more barrels hedged in 2016 than 2015.

Our Strengths

We believe that the following strengths will help us achieve our business goals:

 Extensive horizontal development potential. We believe there are a significant number of horizontal locations on our

acreage that will allow us to target the Spraberry, Wolfcamp, Upper Pennsylvanian (Cline) and Atoka shales. In addition,
based on our analysis of data acquired through our drilling program and the activities of offset operators, we believe that
multiple benches contained within our acreage may have significant resource potential, which could substantially increase
the ultimate hydrocarbon recovery of each surface acre we have under leasehold. Excluding our Gaines County (Midland
Basin) and Southern Delaware Basin acreage, we had 2,125 identified horizontal drilling locations as of December 31,
2014. We initiated our horizontal development program with one rig during the fourth quarter of 2013 and have increased
to five operated horizontal rigs as of December 31, 2014. Through December 31, 2014, we have drilled and placed on
production 18 horizontal wells in the Midland Basin. As we continue to expand our vertical drilling program to our
undeveloped acreage in Gaines County (Midland Basin) and the Southern Delaware Basin, we expect to identify
additional horizontal drilling locations. The relatively low decline rate of our current production – a function of 694
vertical wells – enables us to grow production with lower capital investment.



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 extensive experience in the Spraberry,
Wolfberry and Wolftoka Trends of the Permian Basin. Our chief executive officer, Bryan Sheffield, is a third generation
oil and gas executive, and our management team has previous experience at Parker and Parsley, Concho Resources,
Chesapeake Energy Corporation, Pioneer Natural Resources, and Whiting Petroleum Corporation. We have also
assembled a technical team that includes twelve petroleum engineers and six geologists with an average of eleven years of
experience, which we believe will be of strategic importance as we continue to expand our future exploration and
development plans. Our management team holds approximately 34.0% of our ownership interest and is our largest
stockholder group. We believe our management team’s significant ownership interest provides meaningful incentive to
increase the value of our business for the benefit of all stockholders.

 Operating control over approximately 99% of our production. As of December 31, 2014, we operated approximately

99% of the wells in which we have an interest. 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, exploitation and development
activities. Our leasehold position is comprised primarily of properties that we operate and, excluding our Gaines County
(Midland Basin) and Southern Delaware Basin acreage, includes an estimated 1,893 80- and 40-acre potential vertical
drilling locations, 2,403 20-acre potential vertical drilling locations and 2,125 potential horizontal drilling locations.

 Conservative balance sheet. We expect to maintain financial flexibility that will allow us to develop our drilling activities
and selectively pursue acquisitions. As of December 31, 2014 pro forma for the Private Placement (as defined herein), we
do not have any debt outstanding under our Revolving Credit Agreement and $364.7 million of available borrowing
capacity. We believe this borrowing capacity, along with our cash flow from operations, will provide us with sufficient
liquidity to execute on our current capital program.

Recent Events

Recent Horizontal Well Results

The following table provides a summary of all wells completed during the fourth quarter of 2014 that have sufficient production

data:

Area

30-Day
Average
IP Rate
(Boe/d)

Well
Count

90-Day
Average
Cumulative
Production
(Boe)

Average
Total
Depth
(feet)

Midland Basin – Core....................................
Midland Basin – Tier I ..................................

396 (1)
544 (2)

26,212
33,743

15,431
13,281

(1) Consisting of 333 Bbls/d of oil and 380 Mcf/d of natural gas. NGLs production and sales are included in our natural gas

production and sales.

(2) Consisting of 443 Bbls/d of oil and 604 Mcf/d of natural gas. NGLs production and sales are included in our natural gas

production and sales.

Recent Acquisition Activity

During the fourth quarter of 2014, we acquired a total of 8,450 net acres in the Permian Basin for approximately $139 million.

The acreage, primarily in northwest Reagan County, Texas, is undeveloped, 100% operated, and adjacent to our horizontal
development operations. The acquisitions add 199 net horizontal drilling locations and 410 net vertical drilling locations.

Private Placement of Common Stock

On February 5, 2014, we entered into an agreement to sell 14,885,797 shares of our Class A Common Stock in a private
placement at a price of $15.50 per share (the “Private Placement”) to selected institutional investors. The Private Placement closed on
February 11, 2015 and resulted in approximately $231 million of gross proceeds and approximately $224 million of net proceeds
(after deducting placement agent commissions and our expenses). We used the net proceeds of the Private Placement to repay a
portion of outstanding borrowings under our Revolving Credit Agreement and for general corporate purposes.

Organizational Structure

We are a holding company that was incorporated as a Delaware corporation on December 11, 2013 for the purpose of
facilitating an initial public offering (“IPO”) of common equity and to become the sole managing member of Parsley Energy, LLC,
which we refer to as “Parsley LLC”. Our principal asset is a controlling equity interest in Parsley LLC. On May 22, 2014, a
registration statement filed on Form S-1 with the SEC related to shares of Class A Common Stock was declared effective. The IPO
closed on May 29, 2014. Prior to the IPO, we had not engaged in any business or other activities except in connection with its
formation and the IPO.

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 PE Unit holder received
one share of our Class B Common Stock (“Class B Common Stock”). Pursuant to such amended and restated limited liability
company agreement (the “Parsley Energy LLC Agreement”), each PE Unit holder has the right to exchange their PE Units together
with an equal number of shares of our Class B Common Stock, for shares of our Class A Common Stock (or cash at our or Parsley
LLC’s election (the “Cash Option”)) on a one-for-one basis, subject to customary conversion rate adjustments for stock splits, stock
dividends and reclassifications (the “Exchange Right”). In addition, in connection with the IPO, we entered into a Tax Receivable
Agreement (the “TRA”) with Parsley LLC, the PE Unit holders and certain of our other equity owners (each such person, a “TRA
Holder”). This agreement generally provides for the payment by Parsley Energy, Inc. to a TRA Holder of 85% of the net cash savings,
if any, in U.S. federal, state or local income tax that Parsley Energy, Inc. 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 Parsley Energy, Inc. 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 Tax Receivable
Agreement. We will retain the benefit of the remaining 15% of these cash savings. See “Certain Relationships and Related
Transactions, and Director Independence” and “Management’s Discussion and Analysis of Financial Conditions and Results of
Operations—Factors Affecting the Comparability of Our Financial Condition and Results of Operations—Corporate Reorganization.”
These transactions are collectively referred to as the “Reorganization Transactions.”

As a result of the IPO and the related Reorganization Transactions, we became the sole managing member of, and has 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 results of
Parsley LLC and its subsidiaries and record noncontrolling interests for the economic interest in Parsley LLC held by the Parsley LLC
Unit holders.

The following diagram indicates our organizational structure as of March 11, 2015. This chart is provided for illustrative

purposes only and does not represent all legal entities affiliated with us.

(1)

(2)

Includes shares of our Class A Common Stock held by Natural Gas Partners, through NGP X US Holdings, L.P. (collectively,
“NGP”) and shares of our Class A Common Stock held by legacy owners.
Includes Parsley Finance Corp.

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:

Year Ended December 31,

2014

2013

2012

Revenues (in thousands, except percentages):
Oil sales ............................................................................................................................ $
Natural gas and natural gas liquid sales ............................................................................
Total revenues ............................................................................................................. $

232,554 $
69,203
301,757 $

97,839 $
23,179
121,018 $

30,443
7,236
37,679

Average realized prices(1):
Oil sales, without realized derivatives (per Bbls) ............................................................. $
Oil sales, with realized derivatives (per Bbls) .................................................................. $
Natural gas and NGLs, without realized derivatives
(per Mcf) ....................................................................................................................... $
Natural gas and NGLs, with realized derivatives
(per Mcf) ....................................................................................................................... $
Average price per BOE, without realized derivatives ...................................................... $
Average price per BOE, with realized derivatives ............................................................ $

Production:
Oil (MBbls) ......................................................................................................................
Natural gas and natural gas liquid (MMcf) .......................................................................
Total (MBoe)(2) ...............................................................................................................

81.91 $
81.33 $

4.92 $

4.96 $
58.19 $
58.00 $

2,839
14,074
5,186

$
$

$
$
$

93.28
87.91

4.95

4.95
66.17
63.09

1,049
4,680
1,829

Average daily production volume:
Oil (Bbls/d) .......................................................................................................................
Natural gas and natural gas liquids (Mcf/d)......................................................................
Total (Boe/d) ....................................................................................................................

7,778
38,559
14,207

2,874
12,823
5,011

85.60
83.08

4.85

4.85
62.33
60.85

356
1,493
604

972
4,079
1,652

(1) One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is an

energy content correlation and does not reflect a value or price relationship between the commodities.

(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.

Productive Wells

As of December 31, 2014 we owned an average 65% working interest in 724 gross (416.4 net) productive 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.

General

As of December 31, 2014, we operated approximately 99% of the 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, 2014, five purchasers each accounted for more than 10% of our revenue during
the period: Atlas Pipeline Mid – Continent WestTex, LLC (“Atlas”), Plains Marketing, LP (“Plains”), BML, Inc., Permian
Transport & Trading (“PTT”) and Enterprise Crude Oil, LLC (“Enterprise”). For the year ended December 31, 2013, four purchasers,
PTT, Plains, Enterprise and Atlas, each accounted for more than 10% of our revenue. For the year ended December 31, 2012, five
purchasers each accounted for more than 10% of our revenues: Enterprise, Plains, Shell Trading (US) Company, Atlas and PTT. 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, 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 materially 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.

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 system.

In addition, we move the majority of our produced water by pipeline connected to commercial 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. We believe that the completion of gathering systems, the connection to salt water disposal wells and other
actions will help us to reduce our lease operating expense in future periods.

In the third quarter of 2014, we entered into an agreement with a private midstream services company for firm pipeline capacity

from our North Upton County and South Midland County acreage to Colorado City, Texas, which will enable us to bypass the
Midland pricing market for a substantial portion of our crude oil production when pipeline deliveries commence.

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 Areas

We operate in one industry segment, which is the exploration, development and production of oil and natural gas, and all of our

operations are conducted in one geographic area of the United States.

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 fourth and first 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.

Oil and Natural Gas Leases

The typical oil and natural gas lease agreement covering our properties provides 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%.

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 factors 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. 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 serves the role of transporter primarily, and gas producers are free to sell their product to marketers, local
distribution companies, end users or a combination thereof.

Recently, natural gas prices have been under considerable pressure due to supply excesses. Specifically, increased efficiencies in

horizontal drilling combined with exploration of newly developed shale fields in North America have dramatically increased annual
domestic natural gas production, which has led to significantly lower market prices for natural gas. However, some produced natural
gas contains within its stream NGLs, which can be processed and stripped from the produced gas and marketed separately. These
NGLs, such as propane, butane and ethane, generally bring a price premium over dry natural gas. As a result, the drilling program will
be favorably affected if the production includes a significant amount of NGLs. There is no guarantee that we, through our drilling
program, will be successful at drilling wells that produce NGLs. It is particularly difficult to estimate accurately future prices of gas,
and any assumptions concerning future prices may prove incorrect.

The United States average daily production of crude oil declined from 9.6 million barrels in 1970 to approximately 4.95 million
barrels in 2008 as a result of decreased drilling activity in the United States, the plugging and abandoning of wells and restrictions on
access to potential drilling sites by governmental agencies. Over the last seven years, however, as a result of new technology, such as
hydraulic fracturing, and rising oil prices, the United States average daily production of crude oil has risen, and the U.S. Energy
Department projects that daily output will continue to increase.

The United States import levels for oil have decreased since reaching a peak, when imports averaged approximately 60% in

2005.

In view of the many uncertainties affecting the supply and demand for oil, gas and refined petroleum products, we are unable to
predict future oil and natural gas prices or the overall effect, if any, that the decline in demand for and the oversupply of such products
will have on the partnership

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 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 gas we can drill. Moreover, each state generally imposes a production or severance tax
with respect to the production and sale of oil, NGLs and gas 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 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 gas, oil, condensate and NGLs are not currently regulated and are made at market prices. Although prices of

these energy commodities are currently unregulated, the United States Congress historically has been active in their regulation. We
cannot predict whether new legislation to regulate oil and gas, or the prices charged for these commodities might be proposed, what
proposals, if any, might actually be enacted by the United States 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 by the
partnership, 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.

In addition to the regulation of natural gas pipeline transportation, FERC has jurisdiction over the purchase or sale of gas or the
purchase or sale of transportation services subject to FERC’s jurisdiction pursuant to the Energy Policy Act of 2005 (“EPAct 2005”).
Under the EPAct 2005, it is unlawful for “any entity,” including producers such as us, that are otherwise not subject to FERC’s
jurisdiction under the Natural Gas Act of 1938 (“NGA”) 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 FERC, in contravention of
rules prescribed by FERC. FERC’s rules implementing this provision make it unlawful, in connection with the purchase or sale of gas
subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of 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. EPAct 2005 also gives FERC authority to impose civil penalties for violations of the
NGA and the Natural Gas Policy Act of 1978 up to $1.0 million per day per violation. 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, 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 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, 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 FERC in monitoring those markets and in detecting market manipulation.

The FERC also regulates rates and service conditions for interstate transportation of oil, including NGLs, under the Interstate

Commerce Act (“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 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 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 FERC.

Rates of interstate liquids pipelines are currently regulated by FERC primarily through an annual indexing methodology, under

which pipelines increase or decrease their rates in accordance with an index adjustment specified by FERC. For the five-year period
beginning in 2010, FERC established an annual index adjustment equal to the change in the producer price index for finished goods
plus 2.65%. This adjustment is subject to review every five years. Under FERC’s regulations, a liquids pipeline 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 for the partnership.

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 or for new shippers. Therefore, 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 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 (“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 million per violation per day. In July 2010, Congress passed the Dodd-Frank Act, which
incorporated an expansion of the authority of the Commodity Futures Trading Commission (“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 their new anti-manipulation authority. The 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.

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. 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 is 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 transport, disposal, or remediation requirements could 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 we believe that we are in substantial compliance with existing environmental laws and regulations and
that continued compliance with existing requirements will not materially affect us, there is no assurance that this current level of
regulation will continue in the future.

The following is a summary of the more significant existing and proposed environmental, 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. Any such change could result in an increase in our costs to manage and dispose
of wastes, which could have a material adverse effect on our results of operations and financial position.

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 response or corrective measures, which could include removal of
previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure
operations to prevent future contamination, the costs of which could be substantial.

Water Discharges

The Federal Water Pollution Control Act, or the Clean Water Act (“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 is prohibited, except in accordance with the terms of a permit issued
by the EPA or an analogous state agency. 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 maintain
all required discharge permits necessary to conduct our operations, and we believe we are in substantial compliance with their terms.

The Oil Pollution Act of 1990 (“OPA”), amends the Clean Water Act and establishes strict liability for owners and operators of

facilities that cause a release of oil into waters of the United States. In addition, OPA requires owners and operators of facilities that
store oil above specified threshold amounts to develop and implement spill prevention, control and countermeasures (“SPCC”) plans.
We continue to review our properties to determine the need for new or updated SPCC plans and, where necessary, we will be
developing or upgrading such plans implementing the physical and operation controls imposed by these plans, the costs of which are
not expected to be substantial.

Safe Drinking Water Act

In the course of our operations, we produce water in addition to oil and 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 (“SDWA”) 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
gas-related wastewaters, 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 recently adopted
new permit rules for injection wells to address these seismic activity concerns within the state. 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 injections 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 our reduce profitability; however, these
costs are commonly incurred by all oil and 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, for
example, 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, the EPA has promulgated rules under the Clean Air Act that subject oil and natural gas production, processing,
transmission and storage operations to regulation under the New Source Performance Standards (“NSPS”) and National Standards for
Emission of Hazardous Air Pollutants (“NESHAPS”) programs. With regards to production activities, these final rules require, among
other things, the reduction of volatile organic compound (“VOC”) emissions from three subcategories of fractured and refractured gas
wells for which well completion operations are conducted: wildcat (exploratory) and delineation gas wells; low reservoir pressure
non-wildcat and non-delineation gas wells; and all “other” fractured and refractured gas wells. All three subcategories of wells must
route flow back emissions to a gathering line or be captured and combusted using a combustion device such as a flare. However, the
“other” wells must 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. The rule is designed to limit emissions of VOC, sulfur dioxide, and hazardous air pollutants from a
variety of sources within natural gas processing plants, oil and natural gas production facilities, and natural gas transmission
compressor stations. This rule could require a number of modifications to our operations including the installation of new equipment.
Compliance with these and other air pollution control and permitting requirements has 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 PSD, construction and Title V operating permit reviews for certain large stationary sources.
Facilities required to obtain Prevention of Significant Deterioration (“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 gas production sources in the United States on an annual basis, which include certain of our operations. More recently, in January
2015, the Obama Administration announced that the EPA is expected to propose in the summer of 2015 and finalize in 2016 new
regulations that will set methane emission standards for new and modified oil and gas production and natural gas processing and
transmission facilities as part of the Administration’s efforts to reduce methane emissions from the oil and gas sector by up to 45%
from 2012 levels by 2025.

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. In the absence of such federal
climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by
means of cap and trade programs 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. 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 and other 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 SDWA 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. To date, no other action has been taken. Further,
the EPA has announced its intention to propose regulations under the CWA by sometime in 2015 governing wastewater discharges
from hydraulic fracturing and certain other natural gas operations. In addition, the EPA is conducting a study of the potential impacts
of hydraulic fracturing activities on water resources and a draft final report is anticipated sometime in 2015 for peer review and public
comment. The results of this study or similar governmental reviews could spur initiatives to regulate hydraulic fracturing under the
SDWA or otherwise. Also, the U.S. Department of the Interior issued proposed rules in May 2013 that would update existing
regulation of hydraulic fracturing activities on federal lands, including requirements for chemical disclosure, well bore integrity and
handling of flowback water. A final version of these rules may be adopted in 2015.

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 government 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 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 may designate critical
habitat and suitable habitat areas that it believes are necessary for 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. For example, in March 2013, the U.S Fish and Wildlife Service (“FWS”) listed the lesser
prairie chicken as a threatened species under the ESA. Although the lesser prairie chicken’s habitat includes areas of the Permian
Basin, where we operate, we do not believe that this listing will have a significant impact on our operations. Moreover, as a result of a
2011 settlement agreement, the FWS is 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. Similar protections are offered to migratory
birds under the Migratory Bird Treaty Act. The federal government recently issued indictments under the Migratory Bird Treaty Act
to several oil and gas companies after dead migratory birds were found near reserve pits associated with drilling activities. 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 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. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker
health and safety.

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 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 can in certain
cases 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 materially adverse
effect on our financial condition and operations. Further, we have no coverage for gradual, long-term pollution events.

In summary, we believe we are in substantial compliance with currently applicable environmental, occupational health and
safety laws and regulations. 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 2014, nor do we anticipate that such
expenditures will be material in 2015.

Employees

As of December 31, 2014, we employed 174 people. 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 consider our relations with our employees to be satisfactory. From time to time we 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
internet website at ww.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 under the symbol “PE.” Our reports, proxy

statements and other information filed with the SEC can also be inspected and copied at the New York Stock Exchange, 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 on Form 10-K. 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 and natural gas prices are volatile. A substantial or extended decline in commodity prices may adversely affect our business,
financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

Prices for oil and natural gas can fluctuate widely. For example, during 2014, NYMEX West Texas Intermediate crude oil prices

ranged from a high of $107.26 per barrel to a low of $53.61 per barrel at the end of 2014. Average daily prices for NYMEX Henry
Hub gas ranged from a high of $6.15 MMBtu to a low of $3.01 per MMBtu during 2014. The duration and magnitude of the recent
decline in crude oil prices cannot be predicted. The prices we receive for our oil and natural gas production heavily influence our
revenue, profitability, access to capital and future rate of growth. Natural gas, NGLs and oil are commodities and, therefore, their
prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the commodities
market has been volatile. This market will likely continue to be volatile in the future. The prices we receive for our production, and the
levels of our production, depend on numerous factors beyond our control. These factors include the following:

 worldwide and regional economic conditions impacting the global supply and demand for natural gas, NGLs and oil;



the price and quantity of foreign imports;

 political conditions in or affecting other producing countries, including conflicts in the Middle East, Africa, South

America and Russia;



the level of global exploration and production;

the level of global inventories;

 prevailing prices on local price indices in the areas in which we operate;



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 price and availability of alternative fuels; and

 domestic, local and foreign governmental regulation and taxes.

In recent months, prices for U.S. crude oil have weakened in response to a buildup in inventories and lower global demand. An

announcement by the Organization of the Petroleum Exporting Countries in November 2014, in which the organization indicated it
would not cut its oil production, further depressed crude prices.

Lower commodity prices will reduce our cash flows and borrowing ability. 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 natural gas, NGLs and oil that we can produce economically.

If commodity prices further decrease, a significant portion of our exploitation, development and exploration 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.

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 increase 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 the 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 exploitation, development and exploration 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 exploitation, development and acquisition of oil and natural gas reserves. We expect to fund 2015 capital expenditures with
cash generated by operations, borrowings under our Revolving Credit Agreement and possibly through additional capital market
transactions. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of,
among other things, oil and natural gas prices, actual drilling results, the availability of drilling rigs and other services and equipment,
and regulatory, technological and competitive developments. A reduction in commodity prices from current levels may result in a
decrease in our actual capital expenditures, which would negatively impact our ability to grow production. We intend to finance our
future capital expenditures primarily through cash flow from operations and through borrowings under our Revolving Credit
Agreement. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Requirements
and Sources of Liquidity.”

Our cash flow from operations and access to capital are subject to a number of variables, including:

 our proved reserves;



the level of hydrocarbons we are able to produce from existing wells;

the prices at which our production is sold;

 our ability to acquire, locate and produce new reserves; and

 our ability to borrow under our Revolving Credit Agreement.

If our revenues or the borrowing base under our Revolving Credit Agreement decreases as a result of lower oil and natural gas

prices, operating difficulties, declines in reserves or for any other reason, 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 a
curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and
production, and would adversely affect our business, financial condition and results of operations.

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 exploitation, development and
acquisition 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 purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of

data obtained through geophysical and geological analyses, 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, our cost of drilling,
completing and operating wells is often uncertain before drilling commences.

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 resulting from

wastewater disposal, discharge of greenhouse gases, and limitations on hydraulic fracturing;

 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 or accidents;

lack of available gathering facilities or delays in construction of gathering facilities;

lack of available capacity on interconnecting transmission pipelines;

adverse weather conditions, such as blizzards, tornados and ice storms;

issues related to compliance with environmental regulations;

environmental hazards, such as oil and natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally
occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases
or other pollutants into the surface and subsurface environment;

 declines in oil and natural gas prices;



limited availability of financing at acceptable terms;

title problems or legal disputes regarding leasehold rights; and

limitations in the market for oil and natural gas.

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 and natural gas prices, the availability and cost of
capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering
system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory
approvals and other factors. Because of these uncertain factors, we do not know if the numerous potential well locations we have
identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other potential locations. In addition,
unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are
obtained, the leases for such acreage will 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 applicable debt instruments, which may not be successful.

Our ability to make scheduled payments on or to refinance our indebtedness obligations, including our $750 million Revolving
Credit Agreement and our senior unsecured notes, depends 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. If oil and natural
gas prices remain at their current level for an extended period of time or continue to decline, 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 debt service obligations, we may be forced to reduce or delay

investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to
restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any
refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could

further restrict 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 outstanding indebtedness on a timely basis could
harm our ability to incur additional indebtedness. 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 debt service and other
obligations. Our Revolving Credit Agreement and the indenture governing our senior unsecured notes currently restrict our ability to
dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the
proceeds of any such disposition 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 scheduled debt service obligations.

In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these
locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on
these potential locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves
or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future
business and results of operations.

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 indenture governing our senior unsecured notes contain a number of significant

covenants, including restrictive covenants that may limit our ability to, among other things:



incur additional indebtedness;

sell assets;

 make loans to others;

 make investments;



enter into mergers;

 make certain payments;

 hedge future production or interest rates;



incur liens; and

engage in certain other transactions without the prior consent of the lenders.

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 impose on us.

Our Revolving Credit Agreement limits the amount we can borrow up to the lower of our aggregate lender commitments and a
borrowing base amount, which the lenders, in their sole discretion, determine 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.

A breach of any covenant in our Revolving Credit Agreement would result in a default under the applicable agreement after any

applicable grace periods. A default, if not waived, could result in acceleration of the indebtedness outstanding under the relevant
facility and in a default with respect to, and an acceleration of, the indebtedness outstanding under other debt agreements. The
accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required
payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be
on terms that are acceptable to us.

If we are unable to comply with the restrictions and covenants in our Revolving Credit Agreement, there could be an event of
default under the terms of our Revolving Credit Agreement, which could results in an acceleration of repayment.

If we are unable to comply with the restrictions and covenants in our Revolving Credit Agreement, there could be an event of
default under the terms of this facility. Our ability to comply with these restrictions and covenants, including meeting the financial
ratios and tests under our Revolving Credit Agreement, may be affected by events beyond our control. If market or other economic
conditions deteriorate or if oil and natural gas prices remain at their current level for an extended period of time or continue to 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 our Revolving Credit Agreement, the lenders
could terminate their commitments to lend or accelerate the loans and declare all amounts borrowed due and payable. 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 our Revolving Credit Agreement 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 oil and natural gas, we

enter into commodity derivative contracts for a significant portion of our production, primarily consisting of put spreads and three way
collars. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview—Our
Properties—Sources of Our Revenues” and “Management’s Discussion and Analysis of Financial Condition and Results of
Operations—Overview—Our Properties—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, highly volatile oil and natural gas prices and interest rates. In addition, derivative
arrangements could limit the benefit we would receive from increases in the prices for oil and natural gas, 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 and natural gas prices, drilling and operating expenses,
capital expenditures, taxes and availability of funds.

Actual future production, oil and natural gas 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.

You should not assume that the present value of future net revenues from our reserves is 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 78% 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, 2014, approximately 78% 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.

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, 2014, 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. As
an example, since all of our production originates in Midland, Texas, our realizations on sales of our oil production may be affected by
the Midland-Cushing price differential, which reflects the difference between the price of crude at Midland, Texas, versus the price of
crude at Cushing, Oklahoma, a major hub where production from Midland is often transported via pipeline. The price we currently
realize on barrels of oil we sell is reduced by the value of the Midland-Cushing differential, which reached as high as $21 per barrel in
August 2014. If the Midland-Cushing differential, or other price differentials pursuant to which our production is subject were to
widen due to oversupply or other factors, our revenue could be negatively impacted.

The marketability of our production is dependent upon transportation and other facilities, certain of which we do not control. If
these facilities are unavailable, our operations could be interrupted and our revenues reduced.

The marketing of oil, NGLs and natural gas production depends in large part on the availability, proximity and capacity of

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, 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 our own facility. 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, NGLs and gas production. Our plans to develop and sell our oil and 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.

Our drilling and production programs may not be able to obtain access on commercially reasonable terms or otherwise to truck
transportation, pipelines, gas gathering, transmission, storage and processing facilities to market our oil and gas production.

The marketing of oil and gas production depends in large part on the capacity and availability of trucks, pipelines and storage facilities,

gas gathering systems and other transportation, processing and refining facilities. Access to such facilities is, in many respects, beyond our
control. If these facilities were unavailable to us on commercially reasonable terms or otherwise, we could be forced to shut in some
production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons. We rely (and expect to
rely in the future) on facilities developed and owned by third parties in order to store, process, transmit and sell our oil and gas
production. Our plans to develop and sell our oil and gas reserves could be materially and adversely affected by the inability or unwillingness
of third parties to provide sufficient facilities and services to us on commercially reasonable terms or otherwise. The amount of oil and gas
that can be produced 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, notice as to when these circumstances will arise and their duration.

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. For example, severe winter weather and the resulting extensive power outages caused our production in the
fourth quarter of 2014 to decline significantly. 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.

We may incur losses as a result of title defects in the properties in which we invest.

It is 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 mineral interest at the time of acquisition. Rather, we rely upon the judgment of lease brokers or land men 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 do 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, 2014, 49% of our total estimated proved reserves were classified as proved undeveloped. Our approximately
44.9 MMBoe of estimated proved undeveloped reserves will require an estimated $627 million 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 capital markets, our
Revolving Credit Agreement and derivative contracts. 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 and reserves auditing guidelines could limit our ability to book additional proved undeveloped reserves (PUDs) in the
future.

SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they 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.

In addition, the methodology used by our independent reserves engineers, NSAI, may limit our ability to book additional
horizontal proved undeveloped reserves. NSAI currently permits operators to book proved undeveloped reserves only for the slots
immediately adjacent to the East and West of producing horizontal wells, but not North and South of such producing wells. This
methodology has limited and may continue to limit our ability to book additional proved undeveloped reserves relating to horizontal
production as we pursue our drilling program.

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 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. If market or other economic conditions deteriorate or if oil and
natural gas prices remain at their current level for an extended period of time or continue to decline, we may incur impairment charges
in 2015, which may have a material adverse effect on our results of operations.

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 exploitation, development and exploration 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 and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We
may not be able to develop, exploit, find or acquire 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. The type curve was prepared by our internal reserve engineers and is based on publicly-available
third party production data rather than our own production data, due to our limited horizontal production history. Such public data is
not extensive and the production results from the wells comprising the data set may differ from our own wells due to geographic
location, completion techniques, and a variety of other well characteristics. As a result, our projected production results and EURs
may differ substantially from our actual production results and ultimate recoveries.

Conservation measures and technological advances could reduce demand for oil and natural gas.

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. The impact of the
changing demand for oil and gas services and products may have a material adverse effect on our business, financial condition, results
of operations and cash flows.

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 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 “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 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 analogies 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
cancelled 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

increase in the cost of, shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs,
equipment and services.

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 and natural gas 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 indenture governing our senior unsecured notes impose certain limitations

on our ability to enter into mergers or combination transactions. Our Revolving Credit Agreement and the indenture governing our
senior unsecured notes 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, 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 the acquisition of a
permit before conducting regulated drilling activities; the restriction of types, quantities and concentration of materials that can be
released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and
other protected areas; the application of specific health and safety criteria addressing worker protection; and 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 is to place more restrictions and limitations on activities that

may affect the environment and thus, our costs of compliance may increase if existing laws and regulations are revised or
reinterpreted, or if new laws and regulations become applicable to our operations. 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. The trend of more expansive and
stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in
increased costs of doing business and consequently affecting profitability. 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 “Business—Regulation of
the Oil and Natural Gas Industry” for a further description of the laws and regulations that affect us.

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 and natural
gas 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. We cannot predict whether these
conditions will exist in the future and, if so, what their timing and duration will be. Such shortages 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 Domenici-Barton Energy Policy Act of 2005, the FERC has civil penalty authority under the NGA 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 FERC as a natural gas company under the NGA, 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 FERC. Additional rules and legislation pertaining to those and other matters may
be considered or adopted by FERC from time to time. Additionally, the Federal Trade Commission 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 “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 while 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 gas production sources in the United States on an annual basis, which include
certain of our operations. More recently, in January 2015, the Obama Administration announced that the EPA is expected to propose
in the summer of 2015 and finalize in 2016 new regulations that will set methane emission standards for new and modified oil and gas
production and natural gas processing and transmission facilities as part of the Administration’s efforts to reduce methane emissions
from the oil and gas sector by up to 45% from 2012 levels by 2025.

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.

At the federal level, the EPA has asserted federal regulatory authority pursuant to the SDWA 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. To date, no other action has been taken. Further,
the EPA has announced its intention to propose regulations under the CWA by sometime in 2015 governing wastewater discharges
from hydraulic fracturing and certain other natural gas operations. In addition, the EPA is conducting a study of the potential impacts
of hydraulic fracturing activities on water resources and a draft final report is anticipated sometime in 2015 for peer review and public
comment. The results of this study or similar governmental reviews could spur initiatives to regulate hydraulic fracturing under the
SDWA or otherwise Also, the U.S. Department of the Interior published a revised proposed rule on May 16, 2013, that would update
existing regulation of hydraulic fracturing activities on federal lands, including requirements for chemical disclosure, well bore
integrity and handling of flowback water.

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting,

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 “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.

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 of West Texas, an area in which industry activity has

increased rapidly. As a result, demand for qualified personnel in this area, and the cost to attract and retain such personnel, has
increased over the past few years due to competition and may increase substantially in the future. 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 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.

Declining general economic, business or industry conditions may have a material adverse effect on our results of operations,
liquidity and financial condition.

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit and the

United States financial market have contributed to increased economic uncertainty and diminished expectations for the global
economy. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or
other countries could adversely affect the global economy. These factors, combined with volatile commodity prices, declining
business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. Concerns
about global economic growth have had a significant adverse impact on 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.

The loss of senior management or technical personnel could adversely affect operations.

We depend on the services of our senior management and technical personnel. With the exception of Bryan Sheffield, our

President and Chief Executive Officer, 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. For example, in the event that Mr. Sheffield no longer controls the entity that is
the sub-operator of the 98 legacy wells we assumed from Parker and Parsley, the sub-operating agreement governing the terms of our
arrangement could terminate and we would no longer be the operator of record on these wells. If the sub-operating agreement were to
terminate, we would be unable to dictate the pace of development and manage the cost, type, and timing of the drilling program on
these identified drilling locations, which could impact our ability to recognize the proved undeveloped reserves associated with these
properties.

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 burden;

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, 2014, we had spud 24 gross (19 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. In addition, to the extent we engage in horizontal drilling, those activities may adversely affect our ability to successfully drill in
one or more of our identified vertical drilling locations. 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 less than anticipated or we are unable to execute our drilling program because of capital constraints, lease
expirations, access to gathering systems and/or commodity prices decline, 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.

Increases in interest rates 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 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. A significant reduction in cash flows from operations or the availability of credit
could materially and adversely affect our ability to achieve our planned growth and operating results.

Certain federal income tax deductions currently available with respect to oil and natural gas exploration and development may be
eliminated, and additional state taxes on oil and natural gas extraction may be imposed, as a result of future legislation.

The Fiscal Year 2016 Budget proposed by the President recommends the elimination of certain key U.S. federal income tax

incentives currently available to oil and gas exploration and production companies, and legislation has been introduced in Congress
that would implement many of these proposals. Such changes include, but are not limited to, (i) the repeal of the percentage depletion
allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the
elimination of the deduction for certain U.S. production activities for oil and gas production; and (iv) an extension of the amortization
period for certain geological and geophysical expenditures. It is unclear, however, whether any such changes will be enacted or how
soon such changes could be effective.

The passage of this legislation or any other similar change in U.S. federal income tax law could eliminate or postpone certain

tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could
negatively affect our financial condition and results of operations.

Our use of 2-D and 3-D 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 predrilling 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.

Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an
adverse effect on our financial condition, results of operations and cash flows.

Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing
processes. Historically, we have been able to purchase water from local land owners for use in our operations. However, Texas has
endured severe drought conditions over the past several years. These drought conditions have led governmental authorities to restrict
the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supplies. If we are unable to obtain water to
use in our operations from local sources, we may be unable to produce oil and natural gas economically, which could have an adverse
effect on our financial condition, results of operations and cash flows.

Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling
activities areas where we operate.

Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling
activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify
competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when
drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations or materially increase our

operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or
require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we
operate as threatened or endangered 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 a material adverse impact on our ability to develop and
produce our reserves.

The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the
effect of commodity price, interest rate and other risks associated with our business.

The Dodd-Frank Act, enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives
market and of entities, such as us, that participate in that market. The Dodd-Frank Act requires the CFTC and the SEC to promulgate
rules and regulations implementing the Dodd-Frank Act. In its rulemaking under the Dodd-Frank Act, the CFTC has issued final
regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their
economic equivalents. Certain bona fide derivative transactions would be exempt from these position limits. The position limits rule
was vacated by the United States District Court for the District of Columbia in September of 2012 although the CFTC has stated that it
will appeal the District Court’s decision. The CFTC also has finalized other regulations, including critical rulemakings on the
definition of “swap,” “security-based swap,” “swap dealer” and “major swap participant.” The Dodd-Frank Act and CFTC rules also
will require us, in connection with certain derivatives activities, to comply with clearing and trade-execution requirements (or to take
steps to qualify for an exemption to such requirements). In addition, new regulations may require us to comply with margin
requirements although these regulations are not finalized and their application to us is uncertain at this time. Other regulations also
remain to be finalized, and the CFTC recently has delayed the compliance dates for various regulations already finalized. As a result,
it is not possible at this time to predict with certainty the full effects of the Dodd-Frank Act and CFTC rules on us or the timing of
such effects. The Dodd-Frank Act also may require the counterparties to our derivative instruments to spin off some of their
derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The Dodd-Frank Act and any
new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral, which
could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives
to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our
exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and CFTC rules,
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. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and
natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and
natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and CFTC rules is to lower
commodity prices. Any of these consequences could have a material and adverse effect on us, our financial condition or our results of
operations.

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 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 increase security for our information,
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

The requirements of being a public company, including compliance with the reporting requirements of the Securities Exchange
Act of 1934, as amended, or the Exchange Act, and the requirements of the Sarbanes-Oxley Act, may strain our resources,
increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective
manner.

As a public company, we are required to comply with new laws, regulations and requirements, certain corporate governance

provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the NYSE, with which we were
not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant
amount of time of our board of directors and management and will significantly increase our costs and expenses. We are required to:



institute a more comprehensive compliance function;

comply with rules promulgated by the NYSE;

continue to prepare and distribute periodic public reports in compliance with our obligations under the federal securities
laws;

establish new internal policies, such as those relating to insider trading; and

involve and retain to a greater degree outside counsel and accountants in the above activities.

Furthermore, while we generally must comply with Section 404 of the Sarbanes Oxley Act of 2002 for our fiscal year ended
December 31, 2014, we are not required to have our independent registered public accounting firm attest to the effectiveness of our
internal controls until our first annual report subsequent to our ceasing to be an “emerging growth company” within the meaning of
Section 2(a)(19) of the Securities Act. Accordingly, while we anticipate that we will cease to be an “emerging growth company” at the
end of 2015, we may not be required to have our independent registered public accounting firm attest to the effectiveness of our
internal controls until as late as our annual report for the fiscal year ending December 31, 2019. Once it is required to do so, our
independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which
our controls are documented, designed, operated or reviewed. Compliance with these requirements may strain our resources, increase
our costs and distract management; and we may be unable to comply with these requirements in a timely or cost-effective manner.

In addition, we expect that being a public company subject to these rules and regulations may make it more difficult and more

expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage
or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and
retain qualified individuals to serve on our board of directors or as executive officers. We are currently evaluating these rules, and we
cannot predict or estimate the amount of additional costs we may incur or the timing of such costs.

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 unitholders, 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 credit facilities. 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 principal stockholders will collectively hold a substantial majority of the voting power of our common stock.

Holders of Class A common stock and Class B common stock will 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. Our
management team holds approximately 34.0% of our ownership interest and is our largest stockholder group. The existence of
significant stockholders may also 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 our management team continues to control a significant amount 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. In addition, NGP and its affiliates may, from time to time, acquire interests in businesses that
directly or indirectly compete with our business, as well as businesses that are significant existing or potential customers. NGP and its
affiliates may acquire or seek to acquire assets that we seek to acquire and, as a result, those acquisition opportunities may not be
available to us or may be more expensive for us to pursue. Moreover, this concentration of stock ownership may also adversely affect
the trading price of our Class A common stock to the extent investors perceive a disadvantage in owning stock of a company with a
controlling stockholder.

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 “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 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;

establishing advance notice provisions for stockholder proposals and nominations for elections to the board of directors to
be acted upon at meetings of stockholders;

 providing that the board of directors is expressly authorized to adopt, or to alter or repeal our bylaws; and



establishing advance notice and certain information requirements for nominations for election to our board of directors or
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 the payment due under our TRA, 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 (the “DGCL”), our amended and restated certificate of incorporation or our 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, and our credit facilities 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 do not plan to declare dividends on shares of our Class A common stock in the foreseeable future. Additionally, our credit

facilities 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.

We will be required to make payments under the TRA for certain tax benefits we may claim, and the amounts of such payments
could be significant.

The TRA 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 to realize in certain circumstances 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 Parsley Inc. 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. In addition, 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 payment obligations under the TRA are our obligations and not obligations of Parsley LLC. 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 term of the TRA will continue until all such tax benefits have
been utilized or expired, unless we exercise our right to terminate the TRA by making the termination payment specified in the
agreement.

The actual increase in tax basis, as well as the amount and timing of any payments under the TRA, will vary depending upon a

number of factors, 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 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 depletable, depreciable or amortizable
basis. We expect that the payments that we will be required to make under the TRA could be substantial.

The payments under the TRA will not be conditioned upon a holder of rights under the TRA having a continued ownership

interest in us. See “Certain Relationships and Related Transactions, and Director Independence.”

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 elect to terminate the TRA early or it is terminated early due to certain mergers or other changes of control we would be

required to make an immediate payment equal to the present value of the anticipated future tax benefits subject to the TRA, which
calculation of anticipated future tax benefits will be based upon certain assumptions and deemed events set forth in the TRA,
including the assumption that we have sufficient taxable income to fully utilize such benefits and that any PE Units that the PE Unit
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 the actual realization, if any, of such future benefits.

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 cost a potential acquirer may attribute to satisfying such obligations.

Payments under the TRA will be based on the tax reporting positions that we will determine. The holders of rights under the
TRA will not reimburse us for any payments previously made under the TRA if such basis increases or other benefits are subsequently
disallowed, except that excess payments made to any such holder will be netted against payments otherwise to 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.

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.

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial
results or prevent fraud. As a result, current and potential stockholders could lose confidence in our financial reporting, which
would harm our business and the trading price of our Class A common stock.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a

public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed.
We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain
adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under
Section 404 of the Sarbanes Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties
encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our
reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information,
which would likely have a negative effect on the trading price of our Class A common stock.

For as long as we are an emerging growth company, we will not be required to comply with certain disclosure requirements that
apply to other public companies.

In April 2012, President Obama signed into law the Jumpstart Our Business Startups Act (the "JOBS Act"). For as long as we

remain an "emerging growth company" as defined in the JOBS Act, we may take advantage of certain exemptions from various
reporting requirements that are applicable to other public companies that are not emerging growth companies, including not being
required to provide an auditor's attestation report on management's assessment of the effectiveness of our system of internal control
over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act and reduced disclosure obligations regarding executive
compensation in our periodic reports. We will remain an emerging growth company for up to five years, although we will lose that
status sooner if we have more than $1.0 billion of revenues in a fiscal year, the date on which we become a “large accelerated filer”
(the fiscal year-end on which the total market value of our common equity securities held by non-affiliates is $700 million or more as
of the last business day of our most recently completed second fiscal quarter), or issue more than $1.0 billion of non-convertible debt
over a three-year period.

To the extent that we rely on any of the exemptions available to emerging growth companies, you will receive less information
about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies.

The corporate opportunity provisions in our amended and restated certificate of incorporation could enable NGP to benefit from
corporate opportunities that might otherwise be available to us.

Subject to the limitations of applicable law, our amended and restated certificate of incorporation, among other things:

 permits us to enter into transactions with entities in which one or more of our officers or directors are financially or

otherwise interested;

 permits any of our stockholders, officers or directors to conduct business that competes with us and to make investments

in any kind of property in which we may make investments; and

 provides that if any director or officer of one of our affiliates who is also one of our officers or directors becomes aware of

a potential business opportunity, transaction or other matter (other than one expressly offered to that director or officer in
writing solely in his or her capacity as our director or officer), that director or officer will have no duty to communicate or
offer that opportunity to us, and will be permitted to communicate or offer that opportunity to such affiliates and that
director or officer will not be deemed to have (1) acted in a manner inconsistent with his or her fiduciary or other duties to
us regarding the opportunity or (2) acted in bad faith or in a manner inconsistent with our best interests.

As a result, NGP or their affiliates may become aware, from time to time, of certain business opportunities, such as acquisition
opportunities, and may direct such opportunities to other businesses in which they have invested, in which case we may not become
aware of or otherwise have the ability to pursue such opportunity. Further, such businesses may choose to compete with us for these
opportunities. As a result, our renouncing our interest and expectancy in any business opportunity that may be from time to time
presented to NGP and their affiliates could adversely impact our business or prospects if attractive business opportunities are procured
by such parties for their own benefit rather than for ours.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2.

PROPERTIES

Our properties are located in the West Texas portion of the Permian Basin. As of December 31, 2014, our acreage position

consisted of 133,274 net acres, 103,036 of which are in the Midland Basin and 30,238 of which are in the Delaware Basin,
approximately 34% of which is held by production. As of December 31, 2014, we have interests in 724 gross (416.4 net) producing
wells, of which we operate 99%. Of these wells, 542 were drilled by us since initiating our drilling program in November 2009. The
table below sets forth our identified drilling locations in the Midland Basin as of December 31, 2014.

Target Horizontal Zone
Spraberry ......................................................................
Wolfcamp A .................................................................
Wolfcamp B .................................................................
Wolfcamp C .................................................................
Upper Pennsylvanian (Cline) .......................................
Atoka ............................................................................
Total Target Horizontal Location .................................

Target Horizontal Locations

Short Laterals(1)

Long Laterals(1)

Total

Gross

Net

Gross

Net

Gross

Net

164
258
247
265
285
356
1,575

131
219
212
224
246
308
1,340

27
88
100
110
112
113
550

22
77
88
97
100
101
485

191
346
347
375
397
469
2,125

153
296
300
321
346
409
1,825

Target Vertical Locations .............................................
Total Target Horizontal and Vertical Locations ...........

1,893

1,351

2,403

1,743

4,296
6,421

Target Vertical Locations(2)

80-and 40-Acre

20-Acre

Total

Gross

Net

Gross

Net

Gross

Net
3,094
4,919

(1) Our target horizontal location count implies 660’ to 870’ between well spacing which is equivalent to five to eight wells per

(2) Ascribes no vertical locations to our Gaines County (Midland Basin) acreage.

The Permian Basin is an area that 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. The Permian Basin is characterized by oil and liquids rich gas production. According to the RRC, over 29
billion barrels of oil and 75 trillion cubic feet of gas have been produced in the Permian Basin since the first producing well was
drilled in 1921 in Mitchell County. 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 formations. With the advent of horizontal drilling and the application of multi-stage
fracture treatments within one horizontal well bore, activity has increased drastically targeting one unconventional formation at a time
for production.

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 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 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 formation throughout the Permian Basin. In the later Permian time 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 in 1949. The
field stretches over 150 miles North to South and over 75 miles East to West. According to RRC, over 1.2 billion barrels of oil have
been produced in this field alone as of April 2013. Additionally, activity targeting the deeper Wolfcamp formation increased
dramatically after Henry Petroleum started drilling fully through the Wolfcamp formation 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 formations. Concurrently, operators started testing zones singularly with horizontal wells and multi-stage

treatments. To date, the majority of these wells in the Midland Basin target the Upper Pennsylvanian and Wolfcamp formations. There
have also been successful horizontal tests in the Clearfork, Spraberry, and Atoka formations.

Core Area Descriptions

We group our assets by area based on similar geologic, economic and technical requirements. We split our assets into four areas,

the Midland Basin-Core, Midland Basin-Tier 1, Midland Basin-Other and Southern Delaware Basin.

Midland Basin-Core

Our Midland Basin-Core assets are characterized by being in the modern day sedimentary deep portion of the Midland Basin

resulting in multiple stacked pay benches ranging from the Clearfork to the Atoka formations. Generally, well drilling and completion
costs are slightly higher in the Midland Basin-Core area due to design for deeper depths and higher pressures. Our Midland Basin-
Core contains the areas of Andrews, Glasscock, Howard, Martin, Midland, Reagan and Upton Counties.

As of December 31, 2014, we have 65,716 gross (42,564 net) acres in our Midland Basin-Core area. Approximately 73% of our
acreage in this area is held by production. We have interests in 503 gross (288.8 net) producing wells in our Midland Basin-Core area
as of December 31, 2014 and we operate 99% of the wells in which we have an interest. Since initiating our drilling program, we have
drilled 362 wells in this area. The table below sets forth our identified drilling locations in the Midland Basin-Core as of December 31,
2014.

Target Horizontal Locations

Short Laterals(1)

Long Laterals(1)

Total

Gross

Net

Gross

Net

Gross

Net

68
142
133
145
176
260
924

52
125
120
129
157
229
812

14
56
70
77
80
80
377

11
49
63
68
71
71
333

82
198
203
222
256
340
1,301

63
174
183
197
228
300
1,145

Target Vertical Locations .............................................
Total Target Horizontal and Vertical Locations ...........

1,201

914

1,676

1,266

2,877
4,178

80-and 40-Acre

20-Acre

Total

Gross

Net

Gross

Net

Gross

Target Vertical Locations

Net
2,180
3,325

(1) Our target horizontal location count implies 660’ to 870’ between well spacing which is equivalent to five to eight wells per

Midland Basin-Tier I

Our Midland Basin-Tier 1 assets are characterized by being in a shallower modern day sedimentary portion of the Midland
Basin than our Midland Basin-Core. The southern boundary is the Big Lake Fault, the western boundary is the Central Basin Platform,
the northern boundary is the Horseshoe Atoll and the Eastern boundary is the transition to the Eastern Shelf. Due to lower pressures
and shallower depths, well drilling and completion costs tend to be slightly lower than the Midland Basin-Core. Our Midland Basin-
Tier 1 includes areas of Andrews, Borden, Crane, Dawson, Ector, Glasscock, Howard, Irion, Martin, Midland, Reagan and Upton
Counties.

As of December 31, 2014, we have 47,154 gross (36,289 net) acres in our Midland Basin-Tier I area. Approximately 68% of our
acreage in this area is held by production. We have interests in 215 gross (125.4 net) producing wells in our Midland Basin-Tier I area
as of December 31, 2014 and operate 99%, of the wells in which we have an interest. Since initiating our drilling program, we have
drilled 160 wells in this area. The table below sets forth our identified drilling locations in the Midland Basin-Tier I as of
December 31, 2014.

Midland Basin-Tier I (continued)

Target Horizontal Locations

Short Laterals(1)

Long Laterals(1)

Total

Gross

Net

Gross

Net

Gross

Net

96
116
114
120
109
96
651

79
94
92
95
89
78
527

13
32
30
33
32
33
173

11
28
26
28
29
30
152

109
148
144
153
141
129
824

90
122
118
123
118
108
679

Target Vertical Locations .............................................
Total Target Horizontal and Vertical Locations ...........

583

437

636

477

1,219
2,043

80-and 40-Acre

20-Acre

Total

Gross

Net

Gross

Net

Gross

Target Vertical Locations

Net

914
1,593

(1) Our target horizontal location count implies 660’ to 870’ between well spacing which is equivalent to five to eight wells per

Midland Basin-Other

Our Midland Basin-Other assets are characterized as assets that we have limited operating activity in which still fall within the
Midland Basin. Over time, as our operating results dictate, we may reclassify these areas based on geologic, economic and technical
results. Our Midland Basin-Other includes portions of Andrews, Dawson and Gaines Counties.

As of December 31, 2014, we have 31,832 gross (24,183 net) acres in our Midland Basin-Other area. None of our acreage in

this area is held by production. We have interest in four gross (0.3 net) producing wells in our Midland Basin-Other area as of
December 31, 2014. As of December 31, 2014, we have identified 109 gross 80- and 40- acre potential vertical locations and 91 gross
20- acre potential vertical drilling location on our properties in the Midland Basin-Other area. We have attributed no horizontal
drilling locations at this time and no vertical locations to our leasehold position in Gaines County due to our limited operating history
in the area. As our operating history and industry activity increases in the area, we expect to identify additional locations.

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, 2014, our Delaware Basin acreage includes 83,109 Boe of proved developed reserves and two gross (two
net) producing wells. We hold a leasehold position in 38,525 gross (30,238 net) acres in the Delaware Basin which we call our Trees
Ranch Prospect. We believe our leasehold is prospective for Pennsylvanian aged production, based on historical shows and well tests
in the Pennsylvanian and Permian (Wolfcamp) aged rocks on our leasehold. We commenced a three-well vertical appraisal program
and completed two wells as of December 31, 2014. Upon further evaluating results, we will make a determination as to future
development plans. Our Southern Delaware Basin assets are an area bounded on the East and Northeast by the Central Basin
Platform, on the West by the Waha field and to the south by the Gomez field. This area is locally known as the Coyanosa Basin. Our
Southern Delaware Basin includes portions of Pecos and Reeves Counties.

Production Status

For the year ended December 31, 2014, our average daily net production from our Midland Basin acreage, was 14,144 Boe/d, of

which 49% was from oil and 51% was from natural gas and NGLs. Our average daily net production from our Delaware Basin
acreage, was 63 Boe/d, of which 93% was from oil and 7% was from natural gas and NGLs. We had no production from the Central
Basin Platform.

Facilities

Our land-based oil and 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/gas/water separation equipment and pumping units.

Recent and Future Activity

During the year ended December 31, 2014, 149 gross (126 net) vertical wells were spud on our Midland Basin acreage for an

aggregate estimated net cost of $284 million and 24 gross (19 net) horizontal wells were spud for aggregate estimated net cost of $140
million. Our capital budget for 2015 is approximately $225 million to $250 million. Our capital budget excludes any amounts that
may be paid for acquisitions.

As of December 31, 2014, we have identified 1,893 80- and 40-acre potential vertical drilling locations, 2,403 20-acre potential
vertical drilling locations and 2,125 potential horizontal drilling locations on our existing acreage, which does not include any vertical
locations in our Gaines County (Midland Basin). Our target horizontal location count implies 660’ to 870’ between well spacing
which is equivalent to five to eight wells per 640-acre section per prospective interval. The availability of local infrastructure, drilling
support assets and other factors as management may deem relevant, such as easement restrictions and state and local regulations, are
considered in determining such locations. The drilling locations on which we actually drill wells will ultimately depend upon the
availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results and other
factors.

Production and Price History

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 and natural gas liquids (Mcf/d) .................................................
Total (Boe/d) ...............................................................................................

7,778
38,559
14,207

2,874
12,823
5,011

2014

Year ended December 31,
2013

2012

(in thousands, except per share unit data)

Average realized prices(1):

Oil sales, without realized derivatives (per Bbls) ........................................ $
Oil sales, with realized derivatives (per Bbls) ............................................. $
Natural gas and NGLs, without realized derivatives (per Mcf) ................... $
Natural gas and NGLs, with realized derivatives (per Mcf) ........................ $
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 costs ................................................................................... $
Acquisition costs ................................................................................... $
Incentive unit compensation .................................................................. $
Stock based compensation ..................................................................... $
Accretion of asset retirement obligations .............................................. $
Total operating expenses per Boe ....................................................... $

Proved Reserves

81.91 $
81.33 $
4.92 $
4.96 $
58.19 $
58.00 $

7.34 $
3.65 $
18.18 $
6.75 $
0.60 $
0.49 $
9.85 $
0.43 $
0.10 $
47.39 $

93.28 $
87.91 $
4.95 $
4.95 $
66.17 $
63.09 $

9.06 $
3.87 $
15.39 $
8.34 $
— $
— $
0.67 $
— $
0.10 $
37.43 $

972
4,079
1,652

85.60
83.08
4.85
4.85
62.33
60.85

7.69
3.99
10.60
6.00
—
—
—
—
0.11
28.39

Evaluation and Review of Proved Reserves. Our historical proved reserve estimates as of December 31, 2014 and 2013 were

prepared based on reports by NSAI, our independent petroleum engineers. NSAI does not own an interest in any of our properties, nor
is it employed by us on a contingent basis.

We maintain an internal staff of petroleum engineers and geoscience professionals who worked closely with our independent

reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our
assets in the Permian Basin. Our internal technical team members meet with our independent reserve engineers periodically during the
period covered by the proved reserve report to discuss the assumptions and methods used in the proved reserve estimation process. We
provide historical information to the independent reserve engineers for our properties, such as ownership interest, oil and natural gas
production, well test data, commodity prices and operating and development costs. Matthew Gallagher, our Vice President—Chief
Operating Officer, is primarily responsible for overseeing the preparation of all of our reserve estimates. Mr. Gallagher is a petroleum
engineer with approximately ten years of reservoir and operations experience, and our engineering and geoscience staff have an
average of approximately 11 years of industry experience per person.

The preparation of our historical proved reserve estimates are completed in accordance with our internal control procedures.

These procedures, which are intended to ensure reliability of reserve estimations, include the following:



review and verification of historical production data, which data is based on actual production as reported by us;

 preparation of reserve estimates by Mr. Gallagher or under his direct supervision;

 verification of property ownership by our land department.

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, 2014 and December 31, 2013 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.

To estimate 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 formation being
evaluated or in an analogous formation. 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.

Summary of Oil, NGLs, and Natural Gas Reserves. The following table presents our estimated net proved oil, NGLs, and

natural gas reserves as of the periods indicated:

Proved developed reserves:
Oil (MBbls) .....................................................................................
NGLs (MBbls) .................................................................................
Natural gas (MMcf) .........................................................................
Combined (MBoe)(1) ......................................................................
Proved undeveloped reserves:
Oil (MBbls) .....................................................................................
NGLs (MBbls) .................................................................................
Natural gas (MMcf) .........................................................................
Combined (MBoe)(1) ......................................................................
Proved reserves:
Oil (MBbls) .....................................................................................
NGLs (MBbls) .................................................................................
Natural gas (MMcf) .........................................................................
Combined (MBoe)(1) ......................................................................

December 31,

2014

2013

23,547
11,491
65,484
45,952

24,070
11,175
58,161
44,939

47,617
22,667
123,645
90,891

13,560
4,762
31,301
23,539

15,947
7,595
46,517
31,295

29,507
12,357
77,818
54,834

(1) One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is an

energy content correlation and does not reflect a value or price relationship between the commodities.

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.”

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 proved reserve report as of December 31, 2014, which is included in this annual
report.

Proved Undeveloped Reserves (PUDs)

As of December 31, 2014, our proved undeveloped reserves were composed of 24,070 MBbls of oil, 11,175 MBbls of NGLs,

and 58,161 MMcf of natural gas for a total of 44,939 MBoe. PUDs will be converted from undeveloped to developed as the applicable
wells begin production.

The following table summarizes our changes in PUDs during the year ended December 31, 2014 (in MBoe):

Balance, December 31, 2013 ...................................
Purchases of reserves ..............................................
Extensions and discoveries .....................................
Revisions of previous estimates ..............................
Transfers to proved developed ................................
Balance, December 31, 2014 ...................................

31,295
10,677
19,256
(9,439 )
(6,850 )
44,939

Extensions and discoveries of 19,256 MBoe during the year ended December 31, 2014, resulted primarily from the drilling of

new wells during the year and from new proved undeveloped locations added during the year.

Costs incurred relating to the development of locations that were classified as PUDs at December 31, 2013 were $292.8 million
during the year ended December 31, 2014. Additionally, during 2014 we spent approximately $189.0 million drilling and completing
other in-field wells which were not classified as PUDs as of December 31, 2013. Estimated future development costs relating to the
development of PUDs at December 31, 2014 were projected to be approximately $34.0 million in the year ended December 31, 2015,
$325.9 million in 2016, $100.5 million in 2017, $90.7 million in 2018 and $76.3 million in 2019. As we continue to develop our
properties and have more well production and completion data, we 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. All of our PUD
drilling locations are scheduled to be drilled within five years of their initial booking.

As of December 31, 2014, less than 1% of our total proved reserves were classified as proved developed non-producing.

Developed and Undeveloped Acreage

The following tables set forth information as of December 31, 2014 relating to our leasehold acreage. Developed acreage is

acres spaced or assigned to productive wells and does not include undrilled acreage held by production under the terms of the lease.
Undeveloped acreage is acres 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.

As of December 31, 2014

Area
Midland Basin ...............................
Delaware Basin .............................
Total ..............................................

Developed Acreage (1)

Gross(3)

Net(4)

Undeveloped Acreage (2)
Net(4)

Gross(3)

Total Acreage

Gross(3)

Net(4)

61,964
240
62,204

36,817
240
37,057

82,738
38,285
121,023

66,219
29,998
96,217

144,702
38,525
183,227

103,036
30,238
133,274

(1) Developed acreage is acres spaced or assigned to productive wells and does not include undrilled acreage held by production

under the terms of the lease.

(2) Undeveloped acreage are acres 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.

(3) 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.

(4) 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.

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. All 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, the lease
is held with additional development every 60 to 180 days until the entire lease is held by production. None of our vertical drilling
locations associated with proved undeveloped reserves are scheduled for drilling outside of a lease term that is not accounted for with
a continuous development schedule. The following table sets forth the gross and net undeveloped acreage, as of December 31, 2014,
that will expire over the next five 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.

2018

Net

Gross
13,413 13,413
—
13,413 13,413

—

2019

Gross

Net
1,944 963
— —
1,944 963

2015

2016

Gross

Net
Gross
Midland Basin ........... 12,922
9,230 26,612
4,613
Delaware Basin ......... 33,672 27,819
Total .......................... 46,594 37,049 31,225

Net
19,859
2,179
22,038

2017

Gross

9,698
—
9,698

Net
8,588
—
8,588

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 necessarily 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.

Horizontal:
Development Wells:
Productive(1) .......................
Dry holes .............................

Vertical:
Development Wells:
Productive(1) .......................
Dry holes .............................

Exploratory Wells:
Productive(1) .......................
Dry holes .............................

Total:
Productive(1) .......................
Dry holes .............................

2014

2013

2012

Gross

Net

Gross

Net

Gross

Net

Year ended December 31,

18
—

13
—

—
—

— —
— —

168
—

2
—

188
—
188

137
—

2
—

152
—
152

170
1

—
—

170
1
171

100
1

—
—

100
1
101

89
1

34
1

— —
— —

89
1
90

34
1
35

(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 where there is no production
history.

As of December 31, 2014 we had one gross (0.8 net) vertical wells in the process of drilling, one gross (0.8 net) vertical wells

awaiting hydraulic fracturing procedures, and two gross (1.8 net) vertical wells in the process of being completed that are not reflected
in the above table. In addition, we had four gross (3.5 net) horizontal wells in the process of drilling, two gross (1.2 net) horizontal
wells awaiting hydraulic fracturing procedures, and two gross (1.6 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, we initially conduct only a cursory review of the title to our properties in

connection with acquisition of leasehold acreage. At such time as 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 commencement of drilling
operations. To the extent title opinions or other investigations 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.

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 the use of or affect our 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

Our corporate headquarters is located in Austin, Texas with field operation facilities in Midland, Texas. We believe that our

facilities are adequate for our current operations.

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.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND

ISSUER PURCHASES OF EQUITY SECURITIES

Our 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 common stock. The following table sets forth high and low sales prices of our common stock for the periods indicated:

2014
Quarter ended December 31 ............................ $
Quarter ended September 30 ........................... $
Quarter ended June 30(a) ................................ $

High

Low

21.03 $
23.95 $
25.16 $

11.26
19.89
22.11

(a) Represents the period from May 29, 2014, the date on which our common stock began trading on the NYSE, through

June 30, 2014.

On March 10, 2015, the closing sales price of our common stock as reported by the NYSE was $14.31 per share and we had
approximately 77 stockholders of record. This number does not include owners for whom shares of common stock may be held in
“street” name.

Dividends

We have never declared or paid any cash dividends to holders of our 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 common stock.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

We did not purchase any shares of our Class A Common Stock or Class B Common Stock during the quarter or fiscal year

ended December 31, 2014.

Sales of Unregistered Equity Securities

We did not have any sales of unregistered equity securities during the quarter or fiscal year ended December 31, 2014.

Subscription Agreement

On February 5, 2015, we entered into a subscription agreement with certain institutional investors pursuant to which the
purchasers agreed to purchase 14,885,797 shares of our Class A Common Stock in a private placement at a price of $15.50 per share.
The issuance of the shares pursuant to the subscription agreement was made in reliance upon an exemption from registration provided
under Section 4(2) of the Securities Act.

The Private Placement closed on February 11, 2015. The Private Placement resulted in approximately $231 million of gross

proceeds and approximately $224 million of net proceeds (after deducting placement agent commissions and the Company’s
expenses). We used the net proceeds of the Private Placement to repay a portion of outstanding borrowings under our Revolving
Credit Agreement and for general corporate purposes.

The foregoing is qualified in its entirety by reference to the Subscription Agreement, a copy of which is herein incorporated by

reference as Exhibit 10.37.

ITEM 6.

SELECTED FINANCIAL DATA

The following tables show selected historical financial data for the periods and as of the periods indicated. The following

selected consolidated and combined 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”:

2014

Year ended December 31,
2013

2012

(in thousands, except per share unit data)

REVENUES (1)

Oil ........................................................................................................ $
Natural gas and natural gas liquids sales ..............................................
Total revenues .................................................................................

232,554 $
69,203
301,757

97,839 $
23,179
121,018

OPERATING EXPENSES

Lease operating expenses .....................................................................
Production and ad valorem taxes ..........................................................
Depreciation, depletion and amortization .............................................
General and administrative expenses ....................................................
Exploration costs ..................................................................................
Acquisition costs...................................................................................
Incentive unit compensation .................................................................
Stock based compensation ....................................................................
Accretion of asset retirement obligations .............................................
Total operating expenses .................................................................
(Loss) gain on sale of property ...................................................................
OPERATING INCOME ..........................................................................
OTHER INCOME (EXPENSE)

Interest expense, net .............................................................................
Rig termination .....................................................................................
Prepayment premium on extinguishment of debt .................................
Income from equity investment ............................................................
Derivative income (loss) .......................................................................
Other income (expense) ........................................................................
Total other income (expense), net ...................................................
INCOME BEFORE INCOME TAXES .................................................
INCOME TAX EXPENSE (2) ................................................................
NET INCOME .........................................................................................
LESS: NET INCOME ATTRIBUTABLE TO
NONCONTROLLING INTERESTS .....................................................
NET INCOME ATTRIBUTABLE TO PARSLEY ENERGY INC.
STOCKHOLDERS ...............................................................................$
Net income per common share:

Basic ........................................................................................................$
Diluted .....................................................................................................$

Weighted average common shares outstanding:

Basic ........................................................................................................
Diluted .....................................................................................................

Total Production Volumes

Oil (MBbls) .............................................................................................
Natural Gas and NGLs (MMcf) ..............................................................
Combined (MBoe) ..................................................................................

30,443
7,236
37,679

4,646
2,412
6,406
3,629
—
—
—
—
66
17,159
7,819
28,339

(6,285)
—
(6,597)
267
(2,190)
(81)
(14,886)
13,453
(554)
12,899

38,071
18,941
94,297
34,997
3,136
2,527
51,088
2,209
512
245,778
(2,097)
53,882

(38,607)
(765)
(5,107)
348
83,858
(419)
39,308
93,190
(36,468)
56,722

(33,293)

16,572
7,081
28,152
15,248
—
—
1,233
—
181
68,467
36
52,587

(13,714 )
—
—
184
(9,800 )
159
(23,171 )
29,416
(1,906 )
27,510

—

23,429 $

27,510 $

12,899

0.42
0.42

55,136
55,239

2,839
14,074
5,186

1,049
4,680
1,829

356
1,493
604

(1) There were multiple significant acquisitions during 2014 and 2013 which affect the comparability of the oil and natural gas

revenues.

(2) 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, Parsley LLC was not subject to U.S. federal income taxes.
As a result, the consolidated and combined 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.

2014

Year ended December 31,
2013

2012

(in thousands, except per share unit data)

Average daily production volume:

Oil (Bbls/d) ............................................................................................
Natural gas and natural gas liquids (Mcf/d) ..........................................
Total (Boe/d) .........................................................................................

7,778
38,559
14,207

2,874
12,823
5,011

Average realized prices:

Oil sales, without realized derivatives (per Bbls) .................................. $
Oil sales, with realized derivatives (per Bbls) ....................................... $
Natural gas and NGLs, without realized derivatives (per Mcf) ............. $
Natural gas and NGLs, with realized derivatives (per Mcf) .................. $
Average price per BOE, without realized derivatives ........................... $
Average price per BOE, with realized derivatives ................................ $

Expense per Boe:

Consolidated Statements of Cash Flows Data:
Net cash provided by (used in):

81.91 $
81.33 $
4.92 $
4.96 $
58.19 $
58.00 $

7.34 $
3.65 $
18.18 $
6.75 $
0.60 $
0.49 $
9.85 $
0.43 $
0.10 $
47.39 $

Operating activities ............................................................................... $
Investing activities .................................................................................
Financing activities ...............................................................................

184,983 $
(1,247,677)
1,093,851

Proved reserves:

Oil (MBbls) ...........................................................................................
Natural gas (MMcf) ...............................................................................
NGLs (MBbls) .......................................................................................
Combined (MBoe) .................................................................................

Consolidated Balance Sheet Data:

Cash and cash equivalents ..................................................................... $
Total assets ............................................................................................
Long-term debt ......................................................................................
Total equity ...........................................................................................

Other Financial Data:

47,617
22,667
123,645
90,891

50,550 $
2,051,079
676,845
992,489

93.28 $
87.91 $
4.95 $
4.95 $
66.17 $
63.09 $

9.06 $
3.87 $
15.39 $
8.34 $
— $
— $
0.67 $
— $
0.10 $
37.43 $

53,235 $
(425,611 )
378,096

29,507
12,357
77,818
54,834

19,393 $
742,556
429,970
108,032

972
4,079
1,652

85.60
83.08
4.85
4.85
62.33
60.85

7.69
3.99
10.60
6.00
—
—
—
—
0.11
28.39

5,025
(89,539)
74,245

12,987
4,732
30,214
22,755

13,673
181,239
112,913
6,017

Adjusted EBITDA (1) ...........................................................................

206,060

76,828

26,281

(1) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation to our most
directly comparable financial measures calculated and presented in accordance with GAAP, please read “— Non-GAAP
Financial Measures.”

Non-GAAP Financial Measures

Adjusted EBITDA

Adjusted EBITDA is not a measure of net income as determined by GAAP. Adjusted EBITDA is a supplemental non-GAAP

financial measure that is used by management and external users of our consolidated and combined financial statements, such as
industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDA as net income before depreciation, depletion
and amortization, exploration costs, acquisition costs, gain (loss) on sales of oil and natural gas properties, asset retirement obligation
accretion expense, non-cash stock based compensation, incentive unit expense, interest expense, income tax, rig termination,
prepayment premium on extinguishment of debt, gain (loss) on derivative instruments, net cash receipts (payments) on settled
derivative instruments and premiums (paid) received on options that settled during the period.

Management believes Adjusted EBITDA is useful because it allows it 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 EBITDA 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 EBITDA 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 or liquidity. Certain items
excluded from Adjusted EBITDA 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 EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measure of other
companies. We believe that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by
investors to measure our ability to meet debt service requirements.

The following table presents a reconciliation of Adjusted EBITDA to the GAAP financial measure of net income for each of the

periods indicated.

Adjusted EBITDA reconciliation to net income:
Net income attributable to Parsley Energy, Inc. stockholders' .................. $
Net income attributable to noncontrolling interests ...................................
Depreciation, depletion and amortization ..................................................
Exploration costs .......................................................................................
Acquisition costs .......................................................................................
Loss (gain) on sales of oil and natural gas properties ................................
Asset retirement obligation accretion expense ..........................................
Non-cash stock based compensation .........................................................
Incentive unit compensation ......................................................................
Interest expense, net ..................................................................................
Income tax .................................................................................................
Rig termination ..........................................................................................
Prepayment premium on extinguishment of debt ......................................
Derivative (income) loss ............................................................................
Net cash receipts (payments) on settled derivative instruments ................
Premiums (paid) received on options that settled during the period ..........
Adjusted EBITDA ..................................................................................... $

2014

Year Ended December 31,
2013
(in thousands)

2012

23,429
33,293
94,297
3,136
2,527
2,097
512
2,209
51,088
38,607
36,468
765
5,107
(83,858)
3,311
(6,928)
206,060

27,510 $
—
28,152
—
—
(36 )
181
—
1,233
13,714
1,906
—
—
9,800
(198 )
(5,434 )
76,828 $

12,899
—
6,406
—
—
(7,819)
66
—
—
6,285
554
—
6,597
2,190
179
(1,076)
26,281

PV-10

The following table provides a reconciliation of PV-10 to the GAAP financial measure of Standardized Measure as of December

31, 2014:

PV-10 of proved reserves ................................................................................................................................ $
Present value of future income tax discounted at 10% ....................................................................................
Standardized Measure ..................................................................................................................................... $

1,314.0
(359.0)
955.0

As of December 31, 2014
(in millions)

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.

Our Predecessor and Parsley Energy, Inc.

We were formed in December 2013 and do not have historical financial operating results. For purposes of this annual report, our

accounting predecessors are Parsley LLC and its predecessors. Parsley LLC was formed in June 2013 to engage in the acquisition,
development, exploration and exploitation of oil and natural gas reserves in the Permian Basin. Concurrent with the formation of
Parsley LLC, all of the interest holders in Parsley Energy, L.P., Parsley Energy Management, LLC, and Parsley Energy Operations,
LLC exchanged their interests in each such entity for interests in Parsley LLC (the “Exchange”). The Exchange was treated as a
reorganization of entities under common control.

We are a holding company whose sole material asset consists of 32,145,296 units in Parsley LLC. We are the managing member

of Parsley LLC and are responsible for all operational, management and administrative decisions of Parsley LLC, and we consolidate
the financial results of Parsley LLC and its subsidiaries.

Basis of Presentation

We consider and report all of our operations as one segment.

Overview

We are an independent oil and natural gas company focused on the acquisition, development and exploitation of unconventional

oil and natural gas reserves in the Permian Basin. Our properties are located in the Midland and Delaware Basins and our activities
have historically been focused on the vertical development of the Spraberry, Wolfberry and Wolftoka Trends of the Midland Basin.
Our vertical wells in the area are drilled into stacked pay zones that include the Spraberry, Wolfcamp, Upper Pennsylvanian (Cline),
Strawn, Atoka and Mississippian formations. During the course of 2014 we transitioned from primarily vertical development drilling
to predominantly horizontal drilling development activity.

Our Properties

At December 31, 2014, our acreage position was 133,274 net acres. The vast majority of our acreage is located in the Midland

Basin, and the majority of our identified vertical and horizontal drilling locations are located in our Midland Basin-Core area. Our
Midland Basin-Core area contains areas of Andrews, Glasscock, Howard, Martin, Midland, Reagan, and Upton Counties. From the
time we began drilling operations in November 2009 through December 31, 2014, we have drilled and placed on production
approximately 524 vertical wells across our acreage in the Midland Basin. In addition to our vertical drilling program in the Midland
Basin, we initiated our horizontal development program with one rig during the fourth quarter of 2013 and have increased to five
operated horizontal rigs as of December 31, 2014. Through December 31, 2014, we have drilled and placed on production 18
horizontal wells in the Midland Basin. Additionally, we commenced our vertical appraisal drilling program in the Delaware Basin
during the first quarter of 2014. At December 31, 2014, we had drilled and completed two vertical appraisal wells. As of December
31, 2014, we have identified 2,125 potential horizontal drilling locations, 1,893 80- and 40-acre potential vertical drilling locations
and 2,403 20-acre potential vertical drilling locations on our existing acreage, which does not include any locations in Gaines County
(Midland Basin) or in our Southern Delaware Basin acreage. As of December 31, 2014, we had interests in 724 gross (416.4 net)
producing wells across our properties and operated 99% of the wells in which we had an interest.

How We Evaluate Our Operations

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; and

 Adjusted EBITDA.

Sources of Our Revenues

Our 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. Our oil and natural gas revenues do not include the effects of derivatives. For the year ended
December 31, 2014 and 2013, our revenues were derived 77% and 81%, respectively, from oil sales and 23% and 19%, respectively,
from natural gas and NGLs sales. Our revenues may vary significantly from period to period as a result of changes in volumes of
production sold or changes in commodity prices. NGLs production and sales are included in our natural gas production and sales.

Production Volumes

The following table presents historical production volumes for our properties for the years ended December 31, 2014, 2013, and

2012.

Oil (MBbls) ...............................................................................................
Natural gas and natural gas liquid (MMcf) ...............................................
Total (MBoe) ............................................................................................
Average net production (Boe/d) ................................................................

2,839
14,074
5,186
14,207

1,049
4,680
1,829
5,011

356
1,493
604
1,652

2014

Year Ended December 31,
2013

2012

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 organic drill-bit growth as well as 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

The NYMEX WTI futures price is a widely used benchmark in the pricing of domestic and imported oil in the United States.

The actual prices realized from the sale of oil differ from the quoted NYMEX WTI price as a result of quality and location
differentials. For example, the prices we realize on the oil we produce are affected by the ability to transport crude oil to the Cushing,
Oklahoma transport hub and the Gulf Coast refineries. Periodically, logistical and infrastructure constraints at the Cushing, Oklahoma
transport hub have resulted in an oversupply of crude oil at Midland, Texas and thus lower prices for Midland WTI. These lower
prices have adversely affected the prices we realize on oil sales and increased our differential to NYMEX WTI.

The NYMEX Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States.
Similar to oil, the actual prices realized from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of
quality and location differentials. For example, wet natural gas with a high Btu content sells at a premium to low Btu content dry
natural gas because it yields a greater quantity of NGLs. Location differentials to NYMEX Henry Hub prices result from variances in
transportation costs based on the natural gas’ proximity to the major consuming markets to which it is ultimately delivered. Also
affecting the differential is the processing fee deduction retained by the natural gas processing plant generally in the form of
percentage of proceeds.

The following table provides the high and low prices for NYMEX WTI and NYMEX Henry Hub prompt month contract prices
and our differential to the average of those benchmark prices for the periods indicated. The differential varies, but our oil and natural
gas normally sells at a discount to the NYMEX WTI and NYMEX Henry Hub price, respectively.

Year Ended December 31,

2014

2013

2012

Oil
NYMEX WTI High ...................................................... $
NYMEX WTI Low ....................................................... $
Differential to Average NYMEX WTI ......................... $

107.26 $
53.61 $
1.47 $

110.53 $
86.68 $
(5.33 ) $

Natural Gas
NYMEX Henry Hub High ............................................ $
NYMEX Henry Hub Low ............................................ $
Differential to Average NYMEX Henry Hub ............... $

6.15 $
3.01 $
0.34 $

4.46 $
3.11 $
1.16 $

109.77
77.69
(8.13)

3.90
1.91
(2.81)

Because our NGLs are reported in our natural gas revenue, our differential to NYMEX Henry Hub is positive.

In the past, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue. For example,
during the year ended December 31, 2014, the NYMEX-WTI oil price ranged from a high of $107.26 per Bbl to a low of $53.61 per
Bbl, while the NYMEX-Henry Hub natural gas price ranged from a high of $6.15 per MMBtu to a low of $3.01 per MMBtu. Further,
during the three years ended December 31, 2014, 2013, and 2012, the NYMEX-WTI oil price ranged from a high of $110.53 per Bbl
to a low of $53.61 per Bbl, while the NYMEX-Henry Hub natural gas price ranged from a high of $6.15 per MMBtu to a low of $1.91
per MMBtu.

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in commodity prices, from time to

time we enter into derivative arrangements for 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 those periods. However, in a portion of our current positions, our hedging activity may also reduce our ability
to benefit from increases in oil prices. We will sustain losses to the extent our derivatives contract prices are lower than market prices
and, conversely, we will sustain gains to the extent our derivatives contract prices are higher than market prices. 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.

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 including
hedging our natural gas production. We are not under an obligation to hedge a specific portion of our oil or natural gas production.

Our positions hedging production as of December 31, 2014 were as follows:

Description and Production Period
Crude Oil Put Spreads:

January 2015 - June 2015 ...............
January 2015 - September 2015 ......
February 2015 - June 2015 .............
July 2015 - September 2015 ...........
July 2015 - September 2015 ...........
July 2015 - February 2016 ..............
October 2015 - June 2016 ...............
October 2015 - December 2016 ......
March 2016 - December 2016 ........
July 2016 - December 2016 ............
July 2016 - December 2016 ............

Crude Oil Three Way Collars:

January 2015 ...................................
January 2015 - September 2015 ......
January 2015 - February 2016 ........
March 2015 - June 2016 .................
July 2016 - December 2016 ............
January 2017 - June 2017 ...............

Description and Production Period
Natural Gas Three Way Collars:

VOLUME
(Bbls)

SHORT PUT
PRICE ($/Bbl)

LONG PUT
PRICE ($/Bbl)

SHORT CALL
PRICE ($/Bbl)

120,000 $
630,000 $
500,000 $
75,000 $
75,000 $
960,000 $
540,000 $
2,325,000 $
1,150,000 $
450,000 $
450,000 $

100,000 $
360,000 $
490,000 $
600,000 $
255,000 $
600,000 $

60.00 $
55.00 $
60.00 $
70.00 $
65.00 $
40.00 $
60.00 $
40.00 $
40.00 $
40.00 $
70.00 $

55.00 $
65.00 $
65.00 $
65.00 $
60.00 $
60.00 $

85.00
72.50
80.00
85.00
85.00
55.00
80.00
55.00
55.00
55.00
85.00

87.50 $
80.00 $
85.00 $
85.00 $
80.00 $
80.00 $

120.00
110.00
110.00
120.00
115.00
115.00

VOLUME
(MBtu)

SHORT PUT
PRICE ($/MMBtu)

LONG PUT
PRICE ($/MMBtu)

SHORT CALL
PRICE
($/MMBtu)

February 2015 - December 2015 ....

3,300,000 $

3.75 $

4.50 $

5.25

During the fourth quarter 2014, Parsley elected to lower certain strike prices for both long and short put positions. The

Company primarily focused on positions in late 2015 and 2016. In lowering the strike prices for the put spreads, the Company
collected approximately $45.5 million of cash which is reflected in our year-end cash balance.

The Company excluded from the table above 6,700 notional MBbls with a fair value of $144.9 million relating to amounts

recognized under the master netting agreement with the derivative counterparty.

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.

We monitor our operations to ensure that we are incurring lease operating expenses at an acceptable level. For example, we
monitor our lease operating expenses per Boe to determine if any wells or properties should be shut in, recompleted or sold. This unit
rate also allows us to monitor these costs in certain fields and geographic areas to identify trends and to assess our lease operating
expenses in comparison to other producers. Although we strive to reduce our lease operating expenses, these expenses can increase or
decrease on a per unit basis as a result of various factors as we operate our properties or make acquisitions and dispositions of
properties. For example, we may increase field level expenditures to optimize our operations, incurring higher expenses in one quarter
relative to another or we may acquire or dispose of properties that have different lease operating expenses per Boe. These initiatives
would influence our overall operating cost and could cause fluctuations when comparing lease operating expenses on a period to

period basis. In addition, since most of our wells were completed relatively recently, they are currently producing at high rates. As
with all wells, however, over time production will decrease, which will result in an increase in our lease operating expenses on a per
barrel basis. We also expect an increase in our lease operating expenses as we increase the number of wells drilled and operated.

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 correlate to the changes in oil and natural gas 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. Depreciation, depletion 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 Costs. Exploration 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 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 twelve-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 headquarters, costs of managing our production and development operations including numerous
software applications, audit and other fees for professional services and legal compliance. Also included as compensation expense are
amounts required to be recognized attributable to issued and outstanding incentive units. See “—Factors Affecting the Comparability
of Our Financial Condition and Results of Operations.”

Derivative Gain (Loss). 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 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 with borrowings under our
Revolving Credit Agreement and second lien credit facility. As a result, we incur interest expense that is affected by both fluctuations
in interest rates and our financing decisions. We reflect interest paid to the lenders under our Revolving Credit Agreement and second
lien credit facility in interest expense. Interest expense also includes the PIK interest on the second lien credit facility and our prior
mezzanine debt facility.

Adjusted EBITDA

We define Adjusted EBITDA as net income before depreciation, depletion and amortization, exploration costs, acquisition

costs, gain (loss) on sales of oil and natural gas properties, asset retirement obligation accretion expense, non-cash stock based
compensation, incentive unit expense, interest expense, income tax, rig termination, prepayment premium on extinguishment of debt,
gain (loss) on derivative instruments, net cash receipts (payments) on settled derivative instruments and premiums (paid) received on
options that settled during the period.

Management believes Adjusted EBITDA is useful because it allows it 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 EBITDA 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 EBITDA 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 or liquidity. Certain items excluded from Adjusted
EBITDA 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 EBITDA. Our
computations of Adjusted EBITDA may not be comparable to other similarly titled measure of other companies. We believe that
Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our ability to
meet debt service requirements. For further discussion, please read “Selected Financial Data—Non-GAAP Financial Measures.”

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:

Incentive Unit Compensation. For the year ended December 31, 2014 and the year ended December 31, 2013, within Incentive
unit compensation, are amounts attributable to incentive units that, pursuant to the terms of the Parsley LLC limited liability company
agreement at that date, were only entitled to a payout after a specified level of cumulative cash distributions had been received by
Natural Gas Partners, through NGP and other investors, including all of our executive officers. At December 31, 2013 and December
31, 2014, the incentive units were being accounted for as liability-classified awards pursuant to ASC Topic 718, “Compensation—
Stock Compensation”, as achievement of the payout conditions required settlement of such awards by transferring cash to the
incentive unit holder.

As part of the transactions described below under “—Corporate Reorganization,” the Parsley LLC limited liability company
agreement was amended. Such amendments, among other things, converted all outstanding incentive units in Parsley LLC into PE
Units. A portion of such PE Units were exchanged on a one for one basis for shares of Class A Common Stock, instead of in cash. As
a result, on May 29, 2014, we accounted for the incentive unit awards as equity-classified awards pursuant to ASC Topic 718. This
resulted in the recognition of $50.6 million of stock based compensation equal to the excess of the modified awards’ fair value (based
on the initial offering price of $18.50) over the amount of cumulative compensation cost recognized prior to that date.

Stock Based Compensation. Restricted stock awards are awards of Class A Common Stock that 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. Restricted stock unit awards are awards of restricted stock units that 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 restriction. Each restricted stock unit represents the right to receive one share of Class A Common Stock. The fair value of such
awards was determined using the weighted average closing price on the grant date and compensation expense is recorded over the
applicable vesting periods. During the year ended December 31, 2014, 769,694 shares of restricted stock and 23,649 restricted stock
units were granted to our directors, management, and employees. During the year ended December 31, 2014, 36,739 shares were
forfeited. Stock based compensation expense related to restricted stock and restricted stock units was $2.2 million for year ended
December 31, 2014. There was approximately $11.8 million of unamortized stock compensation expense relating to outstanding
restricted stock and restricted stock units at December 31, 2014.

Public Company Expenses. We expect to incur direct, incremental general and administrative expenses as a result of being a

publicly traded company, including, but not limited to, increased scope of our operations as a result of recent activities and costs
associated with hiring new personnel, implementation of compensation programs that are competitive with our public company peer
group, annual and quarterly reports to stockholders, tax return preparation, independent auditor fees, legal fees, investor relations
activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director
compensation. These direct, incremental general and administrative expenses are not included in our historical results of operations.

Corporate Reorganization. The historical consolidated and combined financial statements included in this annual report are
based on the financial statements of our accounting predecessors, Parsley LLC and its predecessors, prior to the reorganization that
occurred in connection with our IPO as described in Note 1—Organization and Nature of Operations – Corporate Reorganization of
our consolidated and combined financial statements for the year ended December 31, 2014 included elsewhere in this annual report.
As a result, the historical consolidated and combined financial data may not give you an accurate indication of what our actual results
would have been if the transactions described in Note 1—Organization and Nature of Operations – Corporate Reorganization of our
consolidated and combined financial statements for the year ended December 31, 2014 included elsewhere in this annual report had
been completed at the beginning of the periods presented or of what our future results of operations are likely to be. In addition, we
have entered into the TRA with the TRA Holders in connection with our IPO. 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 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 (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 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 pursuant to the Exchange Right (or resulting from an exchange of PE Units for cash at our or
Parsley LLC’s election) 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.

Income Taxes. Our accounting predecessors are limited liability companies or limited partnerships and therefore not subject to

U.S. federal income taxes. Accordingly, no provision for U.S. federal income tax has been provided for in our historical results of
operations. We are taxed as a corporation under the Internal Revenue Code and subject to U.S. federal income tax at a statutory rate of
35% of pretax earnings, and, as such, the amount of our future U.S. 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 1.0% of

Texas income.

Increased Drilling Activity. We began drilling operations in November 2009. As of December 31, 2014, we operated five
horizontal drilling rigs and one vertical drilling rig on our properties. For the year ended December 31, 2014, our capital expenditures
for drilling and completions were $491.3 million, as compared to $268.4 million for all of fiscal year 2013.

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 interest owners.

Results of Operations

Year ended December 31, 2014 Compared to Year ended December 31, 2013

Oil and Natural Gas Sales Revenues. The following table provides the components of our revenues for the periods indicated, as

well as each period’s respective average prices and production volumes:

Year Ended December 31,

2014

2013

$ Change

% Change

Revenues (in thousands, except percentages):
Oil sales ...................................................................................... $
Natural gas and natural gas liquid sales ......................................
Total revenues ....................................................................... $

232,554 $
69,203
301,757 $

97,839 $
23,179
121,018 $

134,715
46,024
180,739

Average realized prices(1):
Oil sales, without realized derivatives (per Bbls) ....................... $
Oil sales, with realized derivatives (per Bbls) ............................ $
Natural gas and NGLs, without realized derivatives (per Mcf) ........ $
Natural gas and NGLs, with realized derivatives (per Mcf) ....... $
Average price per BOE, without realized derivatives ................ $
Average price per BOE, with realized derivatives ...................... $

Production:
Oil (MBbls) ................................................................................
Natural gas and natural gas liquid (MMcf) .................................
Total (MBoe)(2) .........................................................................

Average daily production volume:
Oil (Bbls/d) .................................................................................
Natural gas and natural gas liquids (Mcf/d)................................
Total (Boe/d) ..............................................................................

81.91 $
81.33 $
4.92 $
4.96 $
58.19 $
58.00 $

93.28 $
87.91 $
4.95 $
4.95 $
66.17 $
63.09 $

2,839
14,074
5,186

7,778
38,559
14,207

1,049
4,680
1,829

2,874
12,823
5,011

(11.37 )
(6.58 )
(0.03 )
0.01
(7.98 )
(5.09 )

1,790
9,394
3,357

4,904
25,736
9,196

138%
199%
149%

(12)%
(7)%
(1)%
0%
(12)%
(8)%

171%
201%
184%

(1) Average prices shown in the table reflect prices both before and after the effects of our realized commodity hedging

(2) One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is an

energy content correlation and does not reflect a value or price relationship between the commodities.

The following table shows the relationship between our average realized oil price as a percentage of the average NYMEX price

and the relationship between our average realized natural gas price as a percentage of the average NYMEX price for the years
indicated. Management uses the realized price to NYMEX margin analysis to analyze trends in our oil and natural gas revenues.

Average realized oil price ($/Bbl) ..................................................................... $
Average NYMEX ($/Bbl) ............................................................................ $
Differential to NYMEX .......................................................................... $
Average realized oil price to NYMEX percentage ......................................
Average realized natural gas price ($/Mcf) ....................................................... $
Average NYMEX ($/Mcf) ........................................................................... $
Differential to NYMEX .......................................................................... $
Average realized natural gas to NYMEX percentage ..................................

Year Ended December 31,

2014

2013

81.91 $
80.44 $
1.47 $
102 %
4.92 $
4.58 $
0.34 $
107 %

93.28
98.61
(5.33)
95%
4.95
3.79
1.16
131%

Oil revenues increased 138% to $232.6 million during the year ended December 31, 2014 from $97.8 million during the year

ended December 31, 2013. The increase is attributable to an increase in oil production volumes of 1,790 MBbls offset by a decrease in
average oil prices to $81.91 per barrel from $93.28 per barrel. Of the overall changes in oil sales, increases in oil production volumes
accounted for a positive change of $167.0 million, offset by the decrease in oil prices, which accounted for a negative change of $32.3
million.

Natural gas and NGLs revenues increased 199% to $69.2 million during the year ended December 31, 2014 from $23.2 million

during the year ended December 31, 2013. The increase is attributable to an increase in volumes sold of 9,394 MMcf offset by a
decrease in average natural gas prices to $4.92 per Mcf from $4.95 per Mcf. Of the overall changes in natural gas and NGLs, increases
in natural gas and NGLs production volumes accounted for a positive change of $46.5 million while decreases in prices accounted for
a negative change of $0.5 million. Natural gas revenue includes revenue from the sale of NGLs volumes.

Operating Expenses. The following table summarizes our expenses for the periods indicated:

Operating expenses (in thousands,
except percentages):
Lease operating expenses ....................................................... $
Production and ad valorem taxes ...........................................
Depreciation, depletion and amortization ..............................
General and administrative expenses .....................................
Exploration costs ....................................................................
Acquisition costs ....................................................................
Incentive unit compensation ..................................................
Stock based compensation .....................................................
Accretion of asset retirement obligations ...............................
Total operating expenses .................................................. $

Expense per Boe:
Lease operating expenses ....................................................... $
Production and ad valorem taxes ...........................................
Depreciation, depletion and amortization ..............................
General and administrative expenses .....................................
Exploration costs ....................................................................
Acquisition costs ....................................................................
Incentive unit compensation ..................................................
Stock based compensation .....................................................
Accretion of asset retirement obligations ...............................
Total operating expenses per Boe ..................................... $

Year ended December 31,

2014

2013

$ Change

% Change

38,071 $
18,941
94,297
34,997
3,136
2,527
51,088
2,209
512
245,778 $

7.34 $
3.65
18.18
6.75
0.60
0.49
9.85
0.43
0.10
47.39 $

16,572 $
7,081
28,152
15,248
—
—
1,233
—
181
68,467 $

9.06 $
3.87
15.39
8.34
—
—
0.67
—
0.10
37.43 $

21,499
11,860
66,145
19,749
3,136
2,527
49,855
2,209
331
177,311

(1.72 )
(0.22 )
2.79
(1.59 )
0.60
0.49
9.18
0.43
—
9.96

130%
167%
235%
130%
100%
100%
4,043%
100%
183%
259%

(19)%
(6)%
18%
(19)%
100%
100%
1,370%
100%
—%
27%

Lease Operating Expenses. Lease operating expenses increased 130% to $38.1 million during the year ended December 31,

2014 from $16.6 million during the year ended December 31, 2013. The increase is primarily due to the higher operated well count

during the year ended December 31, 2014 as compared to the prior year period. On a per Boe basis, lease operating expenses
decreased to $7.34 per Boe from $9.06 per Boe. This decrease was attributable to higher initial production from new wells which
lower our average price, partially offset by an increase in costs for workovers, repairs and maintenance, and additional lease operators.

Production and Ad Valorem Taxes. Production and ad valorem taxes increased 167% to $18.9 million during the year ended
December 31, 2014 from $7.1 million during the year ended December 31, 2013 due to increased wellhead revenue resulting from
higher production. Our increased drilling activity led to a higher number of wells brought on production during the year ended
December 31, 2014 compared to the year ended December 31, 2013.

Depreciation, Depletion and Amortization. DD&A expense increased by 235% to $94.3 million for the year ended

December 31, 2014 from $28.2 million during the year ended December 31, 2013 due to an increase in capitalized costs and
production volumes. DD&A expense per BOE for the year ended December 31, 2014 increased by $2.79 from the year ended
December 31, 2013 primarily due to the multiple oil and gas acquisitions and the increase in developmental costs.

General and Administrative Expenses. General and administrative expenses increased 130% to $35.0 million during the year
ended December 31, 2014 from $15.2 million during the year ended December 31, 2013 primarily due to higher payroll and payroll-
related costs as we added additional employees to manage our growing asset base, higher rig count, and increased production.

Exploration Costs. Exploration costs incurred during the year ended December 31, 2014 are comprised of $2.4 million of
geological and geophysical expenses, which primarily consist of the costs of acquiring and processing seismic data, geophysical data
and core analysis, primarily relating to our Delaware Basin area. Exploration costs also include $0.7 million of non-cash leasehold
impairment expense, of which $0.3 million is related to the amortization of unproved properties and $0.4 million is related to future
leasehold expirations. No exploration costs were incurred during the year ended December 31, 2013.

Acquisition Costs. Acquisition costs during the year ended December 31, 2014 are due to a one time advisory and valuation fee
related to the Cimarex Acquisition, as described in Note 6—Acquisitions of Oil and Gas Properties of our consolidated and combined
financial statements for the year ended December 31, 2014 included elsewhere in this annual report. No acquisition costs were
incurred during the year ended December 31, 2013.

Incentive Unit Compensation. Incentive unit compensation increased $49.9 million to $51.1 million during the year ended
December 31, 2014 from $1.2 million during the year ended December 31, 2013 due to the one time incentive unit compensation
expense recognized upon the corporate reorganization. No incentive unit compensation expenses were incurred during the year ended
December 31, 2013.

Stock Based Compensation. Stock based compensation increased $2.2 million for the year ended December 31, 2014 due to the
issuance and amortization of the restricted stock and restricted stock units issued during the year ended December 31, 2014. No stock
based compensation expenses were incurred during the year ended December 31, 2013.

Other Income and Expenses. The following table summarizes our other income and expenses for the periods indicated:

Other income (expense) (in thousands, except
percentages):
Interest expense, net .............................................................. $
Rig termination .....................................................................
Prepayment premium paid on extinguishment of debt ..........
Income from equity investment ............................................
Derivative income (loss) .......................................................
Other income (expense) ........................................................
Total other expense, net ........................................................ $

Year ended December 31,

2014

2013

$ Change

% Change

(38,607) $
(765)
(5,107)
348
83,858
(419)
39,308 $

(13,714) $
—
—
184
(9,800)
159
(23,171) $

(24,893 )
(765 )
(5,107 )
164
93,658
(578 )
62,479

182%
(100)%
(100)%
89%
956%
(364)%
(270)%

Interest Expense. Interest expense increased 182% to $38.6 million in the year ended December 31, 2014 from $13.7 million

during the year ended December 31, 2013 primarily due to higher weighted-average outstanding borrowings under our credit facilities
and accrued interest under our Senior Notes due 2022 (the “Notes”).

Rig Termination. During the fourth quarter of 2014, we paid a total of $0.4 million in rig termination expenses in connection
with the early termination of one drilling rig contract entered into in 2014 and $0.4 million in rig termination expenses for stacking
fees associated with three drilling rig contracts. No rig termination expenses were incurred during the year ended December 31, 2013.

Prepayment Premium on Extinguishment of Debt. During the first quarter of 2014, we incurred a $5.1 million charge related to a

prepayment penalty on our then outstanding second lien term loan. No similar expenses were incurred during the year ended
December 31, 2013.

Derivative Income (Loss). Income from derivative instruments increased $93.7 million during the year ended December 31,
2014 to $83.9 million during the year ended December 31, 2014 from a loss of $9.8 million during the year ended December 31, 2013,
primarily as a result of the impact of unfavorable commodity price changes on increased hedging activities.

Gain on Sales of Oil and Natural Gas Properties

In August of 2014, we sold our interest in one operated well and 38 net acres for total proceeds of $0.2 million and realized a

$2.1 million loss on the sale.

In August 2013, we sold our interest in seven non-operated wells and 190 net acres for total proceeds of $0.8 million and

realized a $36,000 gain on the sale.

Income Tax Expense

From the date of the corporate reorganization, our operations have been taxed at a combined U.S. federal and state effective tax
rate of 35.7%. As a pass-through entity, our predecessor was subject only to the Texas margin tax at a statutory rate of 1.0% and was
not subject to U.S. federal income tax. During the year ended December 31, 2014, we recognized $36.5 million of expense, an
increase of $34.6 million, or 1821%, as compared to the $1.9 million we recognized during the year ended December 31, 2013. This
increase was attributable to our status as a corporation subject to U.S. federal income tax as well as a net increase in operating income,
the components of which are discussed above.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Oil and Natural Gas Sales Revenues. The following table provides the components of our revenues for the periods indicated, as

well as each period’s respective average prices and production volumes:

Year Ended December 31,

2013

2012

$ Change

% Change

Revenues (in thousands, except percentages):
Oil sales ................................................................................. $
Natural gas and natural gas liquid sales ................................
Total revenues ................................................................. $

97,839 $
23,179
121,018 $

30,443 $
7,236
37,679 $

67,396
15,943
83,339

Average realized prices(1):
Oil sales, without realized derivatives (per Bbls) .................. $
Oil sales, with realized derivatives (per Bbls) ....................... $
Natural gas and NGLs, without realized derivatives
(per Mcf) ............................................................................
Natural gas and NGLs, with realized derivatives
(per Mcf) ............................................................................
Average price per BOE, without realized derivatives ........... $
Average price per BOE, with realized derivatives ................ $

Production:
Oil (MBbls) ...........................................................................
Natural gas and natural gas liquid (MMcf) ...........................
Total (MBoe)(2) ....................................................................

$
$

$
$
$

93.28
87.91

4.95

4.95
66.17
63.09

1,049
4,680
1,829

Average daily production volume:
Oil (Bbls/d) ...........................................................................
Natural gas and natural gas liquids (Mcf/d) ..........................
Total (Boe/d) .........................................................................

2,874
12,823
5,011

$
$

$
$
$

85.60
83.08

4.85

4.85
62.33
60.85

356
1,493
604

972
4,079
1,652

7.68
4.83

0.10

0.10
3.84
2.24

693
3,187
1,225

1,902
8,744
3,359

221%
220%
221%

9%
6%

2%
6%
4%

195%
213%
203%

196%
214%
203%

(1) Average prices shown in the table reflect prices both before and after the effects of our realized commodity hedging

(2) One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is an

energy content correlation and does not reflect a value or price relationship between the commodities.

The following table shows the relationship between our average realized oil price as a percentage of the average NYMEX price

Year Ended December 31,
2012
2013

Average realized oil price ($/Bbl) ................................... $
Average NYMEX ($/Bbl) ......................................... $
Differential to NYMEX ....................................... $
Average realized oil price to NYMEX percentage ....
Average realized natural gas price ($/Mcf) ..................... $
Average NYMEX ($/Mcf) ........................................ $
Differential to NYMEX ....................................... $
Average realized natural gas to NYMEX percentage ...

93.28 $
98.61 $
(5.33) $
95%
4.95 $
3.79 $
1.16 $
131%

85.60
93.73
(8.13 )
91 %
0.10
2.91
(2.81 )
3 %

Oil revenues increased 221% to $97.8 million during year ended December 31, 2013 from $30.4 million during the year ended

December 31, 2012. The increase is attributable to higher oil production volumes of 693 MBbls in conjunction with an increase in
average oil prices of $7.68 per barrel. Of the overall changes in oil sales, increases in oil production volumes accounted for a positive
change of $59.3 million while increases in oil prices accounted for a positive change of $8.1 million.

Natural gas and natural gas liquid revenues increased 220% to $23.2 million during the year ended December 31, 2013 from
$7.2 million during the year ended December 31, 2012. The revenue increase is primarily a result of an increase in volumes sold of
3,187 MMcf. Natural gas revenue includes revenue from the sale of NGLs volumes.

Operating Expenses. The following table summarizes our expenses for the periods indicated:

Operating expenses (in thousands,
except percentages):
Lease operating expenses ...................................................... $
Production and ad valorem taxes ..........................................
Depreciation, depletion and amortization .............................
General and administrative expenses ....................................
Incentive unit compensation .................................................
Accretion of asset retirement obligations ..............................
Total operating expenses ................................................. $

Expense per Boe:
Lease operating expenses ...................................................... $
Production and ad valorem taxes ..........................................
Depreciation, depletion and amortization .............................
General and administrative expenses ....................................
Incentive unit compensation .................................................
Accretion of asset retirement obligations ..............................
Total operating expenses per Boe .................................... $

Year ended December 31,

2013

2012

$ Change

% Change

16,572 $
7,081
28,152
15,248
1,233
181
68,467 $

9.06 $
3.87
15.39
8.34
0.67
0.10
37.43 $

4,646 $
2,412
6,406
3,629
—
66
17,159 $

7.69 $
3.99
10.60
6.00
—
0.11
28.39 $

11,926
4,669
21,746
11,619
1,233
115
51,308

1.37
(0.12 )
4.79
2.34
0.67
(0.01 )
9.04

257%
194%
339%
320%
100%
174%
299%

18%
(3)%
45%
39%
100%
(9)%
32%

Lease Operating Expenses. Lease operating expenses increased 257% to $16.6 million during the year ended December 31,

2013 from $4.6 million during the year ended December 31, 2012. The increase is primarily due to the higher operated well count in
the year ended December 31, 2013 as compared to the prior year period. On a per Boe basis, lease operating expenses increased to
$9.06 per Boe from $7.69 per Boe. This increase was attributable to increases in costs for repair and maintenance for 170 new wells
added, additional lease operators and increased water disposal activity.

Production and Ad Valorem Taxes. Production and ad valorem taxes increased $4.7 million to $7.1 million during the year

ended December 31, 2013 from $2.4 million during the year ended December 31, 2012 due to increased wellhead revenue resulting
from higher production. Our increased drilling activity led to a higher number of wells brought on production during the year ended
December 31, 2013 compared to the year ended December 31, 2012.

Depreciation, Depletion and Amortization. DD&A expense increased by $21.8 million to $28.2 million for the year ended
December 31, 2013 from $6.4 million during the year ended December 31, 2012 due to an increase in capitalized costs and production
volumes.

General and Administrative Expenses. General and administrative expenses increased $11.6 million to $15.2 million during the

year ended December 31, 2013 from $3.6 million during the year ended December 31, 2012 primarily due to higher payroll and
payroll-related costs as we added additional employees to manage our growing asset base, higher rig count and increased production.

Incentive Unit Compensation. Incentive unit compensation was incurred during the year ended December 31, 2013 due to the

incentive unit compensation expense recognized in conjunction with the LLC interest issuance as described in Note 10—Equity in the
notes to the consolidated and combined financial statements. No incentive unit compensation expenses were incurred during the year
ended December 31, 2012.

Other Income and Expenses. The following table summarizes our other income and expenses for the periods indicated:

Other income (expense) (in thousands,
except percentages):
Interest expense, net .............................................................. $
Prepayment premium paid on extinguishment of debt ..........
Income from equity investment ............................................
Derivative loss ......................................................................
Other income (expense) ........................................................
Total other expense, net ........................................................ $

Year ended December 31,

2013

2012

$ Change

% Change

(13,714) $
—
184
(9,800)
159
(23,171) $

(6,285) $
(6,597)
267
(2,190)
(81)
(14,886) $

(7,429 )
6,597
(83 )
(7,610 )
240
(8,285 )

118%
(100)%
(31)%
347%
(296)%
56%

Interest Expense. Interest expense increased $7.4 million to $13.7 million in the year ended December 31, 2013 from $6.3
million during the year ended December 31, 2012 primarily due to higher weighted-average outstanding borrowings under our credit
facilities.

Prepayment Premium on Extinguishment of Debt. In 2012, we incurred a $6.6 million cash charge related to a call premium on

our then outstanding debt facility. In 2013, there were no such prepayment charges related to debt extinguishment.

Derivative Loss. Loss on derivative instruments grew $7.6 million to $9.8 million during the year ended December 31, 2013

from $2.2 million during the year ended December 31, 2012 primarily as a result of the impact of changing commodity prices on
increased hedging activities.

Gain on Sales of Oil and Natural Gas Properties

In August 2013, we sold our interest in seven non-operated wells and 190 net acres for total proceeds of $0.8 million and

realized a $36,000 gain on the sale.

In April 2012, we sold 2,652 net unevaluated acres for $8.6 million and realized a $7.5 million gain on the sale.

Income Tax Expense

Although Parsley LLC’s operations have not been subject to federal income tax in the past, our operations located in Texas are

subject to an entity-level tax, the Texas margin tax, at a statutory rate of up to 1.0% of our Texas sourced operating income. During
the year ended December 31, 2013, we recognized $1.9 million of expense associated with our Texas margin tax obligation, an
increase of $1.3 million, or 217%, as compared to the $0.6 million we recognized during the year ended December 31, 2012. This
increase was attributable to our net increase in operating income, the components of which are discussed above.

Capital Requirements and Sources of Liquidity

For the year ended December 31, 2014, our aggregate drilling and completion capital expenditures were $491.3 million. During

the year ended December 31, 2013, our aggregate drilling and completion capital expenditures were $268.4 million. These capital
expenditure totals exclude acquisitions.

Our 2015 capital budget for drilling and completion is approximately $225 million to $250 million. The amount and timing of

2015 capital expenditures is largely discretionary and within our control. We could choose to defer a portion of these planned 2015
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.

Based upon current oil and natural gas price expectations for the fiscal year 2015, 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 2015.
However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and
significant additional capital expenditures will be 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, 2014 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 2015 does not allocate any amounts for acquisitions of leasehold interests and proved 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 base borrowings, joint venture partnerships, production payment
financings, asset sales, offerings of debt and 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.

Cash Flows

The following table summarizes our cash flows for the periods indicated:

Net cash provided by operating activities .................... $
Net cash used in investing activities ............................
Net cash provided by financing activities ....................

184,983 $
(1,247,677)
1,093,851

53,235 $
(425,611 )
378,096

5,025
(89,539)
74,245

2014

Year Ended December 31,
2013

2012

Cash Flow Provided by Operating Activities. Net cash provided by operating activities was approximately $185.0 million, $53.2

million, and $5.0 million for the years ended December 31, 2014, 2013, and 2012, respectively. The $131.8 million increase in
operating cash flows was due to a $134.7 million increase in oil revenues for the year ended December 31, 2014 as compared to the
year ended December 31, 2013, which is attributable to a 171% increase in crude oil production volumes, and a larger positive
variance in working capital changes, which adjusts for the timing of receipts and payments of actual cash. The increase in cash flow
was offset by increased capital spending resulting from an increase in drilling activity. Revenues, net of operating expenses, increased
for the year ended December 31, 2013 as compared to the year ended December 31, 2012, and therefore our net cash provided by
operating activities were consistent with the increase during that same period.

Cash Flow Used in Investing Activities. Net cash used in investing activities was approximately $1.2 billion, $425.6 million, and

$89.5 million for the years ended December 31, 2014, 2013, and 2012, respectively. The increased amount of cash used in investing
activities in the year ended December 31, 2014 as compared to the year ended December 31, 2013 and the year ended December 31,
2013 as compared to the year ended December 31, 2012 was due primarily to the $553.9 million and 176.4 million, respective,
increase in acquisition activity as discussed in Note 6—Acquisition of Oil and Gas Properties. The increases during 2014 over 2013
and 2013 over 2012 are also due to additional rigs operating, our horizontal drilling plan, and drilling higher working interest wells.

Cash Flow Provided by Financing Activities. Net cash provided by financing activities was approximately $1.1 billion, $378.1

million, and $74.2 million for the years ended December 31, 2014, 2013, and 2012, respectively. Net cash provided by financing
activities increased during the year ended December 31, 2014 primarily due to the issuance of Class A Common Stock in conjunction
with our IPO and corporate reorganization and the increase in long-term borrowings. For 2013, the cash provided by financing
activities was primarily related to new borrowings under our credit facilities in addition to the $73.5 million equity investment that
was closed in June 2013.

Capital Sources

Revolving Credit Agreement. The borrowing base will be redetermined by the lenders at least semi-annually on each April 1 and

October 1, with the most recent redetermination on October 1, 2014. As of December 31, 2014, the borrowing base was $562.0
million, with a commitment level of $365.0 million. In February 2015, the borrowing base was decreased to $560.8, with a
commitment level of $365.0 also resulting from restructuring of commodity price hedges. As of December 31, 2014, pro forma for the
Private Placement, there were no outstanding borrowings under our Revolving Credit Agreement and $0.3 million in letters of credit
outstanding as of December 31, 2014, resulting in availability of $364.7 million.

Our Revolving Credit Agreement is secured by liens on substantially all of our properties and guarantees from our subsidiaries.

The Revolving Credit Agreement contains restrictive covenants that may limit our ability to, among other things:



incur additional indebtedness;

sell assets;

 make loans to others;

 make investments;



enter into mergers;

 make or declare dividends;

 hedge future production or interest rates;



incur liens; and

engage in certain other transactions without the prior consent of the lenders.

The Revolving Credit Agreement requires us to maintain the following two financial ratios:



a current ratio, which is the ratio of consolidated current assets (including unused availability under our Revolving Credit
Agreement) to consolidated current liabilities of not less than 1.0 to 1.0 as of the last day of any fiscal quarter; and

a minimum interest coverage ratio, which is the ratio of EBITDAX to interest expense, of not less than 2.5 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 also places restrictions on the Company and certain of its subsidiaries with respect to
additional indebtedness, liens, dividends and other payments, investments, acquisitions, mergers, asset dispositions, transactions with
affiliates, hedging transactions and other matters.

From time to time, the agents, arrangers, book runners and lenders under the Revolving Credit Agreement and their affiliates

have provided, and may provide in the future, investment banking, commercial lending, hedging and financial advisory services to us
and our affiliates in the ordinary course of business, for which they have received, or may in the future receive, customary fees and
commissions for these transactions.

At December 31, 2014, we were in compliance with all required covenants.

7.500 % Senior Unsecured Notes due 2022. See Note 9—Debt to our consolidated and combined financial statements for the

year ended December 31, 2014 included elsewhere in this annual report for a description of the 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 over a two-to-three year period at a given point in time.

Working Capital

Our working capital totaled ($16.7) million, ($54.2) million, and ($10.0) at December 31, 2014, 2013 and 2012, respectively.
Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not
been significant. Our cash balances totaled $50.6 million, $19.4 million, and $13.7 million at December 31, 2014, 2013, and 2012,
respectively. The $31.2 million increase in cash is primarily attributable to the receipt of proceeds for the sale of Class A Common
Stock in conjunction with our IPO and proceeds from additional borrowing on our Revolving Credit Agreement and Senior Unsecured
Notes offset by acquisitions of oil and gas properties, as described in Note 6—Acquisitions of Oil and Gas Properties and debt
repayments. Due to the amounts that we accrue related to our drilling program, we may incur working capital deficits in the future.
We expect that our cash flows from operating activities and availability under our 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.

We had the following contractual obligations at December 31, 2014:

Revolving Credit Agreement(1) .......... $
7.50% Senior Unsecured Notes

due 2022 (1)(2) ..........................
Capital lease obligations (3) ................
Operating lease obligations (4) ...........
Drilling commitments (5) ....................
Asset retirement obligations(6) ...........
Total ............................................... $

Payments Due by Period
For the Year Ended December 31,

2015

2016

2017

2018

2019

Thereafter

Total

— $

120,000 $

— $

— $120,000

(in thousands)

—
650
3,029
39,466
1,069
44,214 $

—
688
3,025
27,911
1,094
32,718 $

—
705
4,481
10,039
646
15,871 $

—
26
4,866
—
973
125,865 $

—

— 550,000 550,000
2,069
—
4,977 21,005 41,383
— 77,416
—
43 12,380 16,205
5,020 $ 583,385 $807,073

(1) This table does not include future commitment fees, amortization of deferred financing costs, interest expense or other fees on
Parsley’s second lien credit facility 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.

(2) On February 5, 2014, Parsley LLC and Parsley Finance Corp. issued $400 million of the Notes. We repaid all outstanding
borrowings under our second lien credit facility and $174.8 million of principal amounts outstanding under our Revolving
Credit Agreement with the net proceeds from this offering. On April 14, 2014, Parsley LLC and Parsley Finance Corp. issued an
additional $150 million of the Notes. We used approximately $145 million of the net proceeds to repay outstanding borrowings
under our Revolving Credit Agreement.

(3) During 2014, we entered into capital lease agreements payable in connection with the lease of vehicles for operations and field

personnel.

(4) We lease vehicles, equipment and office facilities under non-cancellable operating leases.
(5) 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.

(6) Amounts represent estimates of our predecessor’s 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.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated and combined
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 preparation of our consolidated and combined 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.

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

depreciation, depletion, and amortization 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, 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 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 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 twelve-month period after drilling is complete.

Oil and natural gas exploration and development activities are accounted for using the successful efforts method. Under this

method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending
determination of whether the well has found proved reserves. 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 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 as
exploration costs in our Consolidated and Combined 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 report presents estimates of our proved reserves as of December 31, 2014, 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, 2014 was based on an
unweighted average twelve month WTI posted price of $85.99 per Bbl for oil and $35.27 per Bbl for NGLs, and a Henry Hub spot
natural gas price of $4.28 per MMBtu for natural gas.

Our independent engineers and technical staff prepare the estimates of our oil and natural gas reserves and associated future net

cash flows. Even though our independent engineers and technical staff are knowledgeable and follow authoritative guidelines for
estimating reserves, they must make a number of subjective assumptions based on professional judgments in developing the reserve
estimates. Reserve estimates are updated at least annually and consider recent production 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 report as of December 31, 2014 is the current market

value of our estimated proved reserves. In accordance with SEC requirements, we based the 2014 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 for 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.

Future Development Costs

Future development costs include costs incurred to obtain access to proved reserves such as drilling costs and the installation of

production equipment. We develop estimates of these costs for each of our properties based upon their geographic location, type of
production structure, well depth, currently available procedures and ongoing consultations with construction and engineering
consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires
management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and
the political and regulatory environment. We review our assumptions and estimates of future development costs on an annual basis.

Asset Retirement Obligations

We have significant obligations to remove tangible equipment and facilities associated with our oil and natural gas wells and our

gathering systems, and to restore land at the end of oil and gas production operations. Our removal and restoration obligations are
associated with plugging and abandoning wells and our gathering systems. Estimating the future restoration and removal costs is
difficult and requires us to make estimates and judgments because most of the removal obligations are many years in the future and
contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are
constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Inherent in the present
value calculations are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit
adjusted discount rates, timing of settlements and changes in the legal, regulatory, environmental and political environments.

Allocation of Purchase Price in Business Combinations

As part of our business strategy, we periodically 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.

Equity Investments

Equity investments in which we exercise significant influence but do not control are accounted for using the equity method.

Under the equity method, generally our share of investees’ earnings or loss, after elimination of intra-company profit or loss, is
recognized in the consolidated and combined statement of operations. We reviews its investments to determine if a loss in value which
is other than a temporary decline has occurred. If such loss has occurred, we would recognize an impairment provision. There was no
impairment for our equity investments for the years ended December 31, 2014, 2013, or 2012.

Derivatives

We use various financial instruments for non-trading purposes to manage and reduce price volatility and other market risks
associated with our oil production. These arrangements are structured to reduce our exposure to commodity price decreases, but they
can also limit the benefit we might otherwise receive from commodity price increases. Our risk management activity is generally
accomplished through over-the-counter commodity derivative contracts with large financial institutions.

We apply the provisions of the “Derivatives and Hedging” topic of the ASC, which requires each derivative instrument to be
recorded at fair value. If a derivative has not been designated as a hedge or does not otherwise qualify for hedge accounting, it must be
adjusted to fair value through earnings. We elected not to designate our current portfolio of commodity derivative contracts as hedges.
Therefore, changes in fair value of these derivative instruments are recognized in earnings.

We enter into commodity derivative contracts for the purpose of economically hedging the price of our anticipated oil
production even though we do not designate the derivatives as hedges for accounting purposes. We classify cash flows related to
derivative contracts based on the nature and purpose of the derivative. As the derivative cash flows are considered an integral part of
our oil and natural gas operations, they are classified as cash flows from operating activities in the consolidated statements of cash
flows. All commodity derivative contracts we have entered into are for the purpose of economically hedging our anticipated oil
production.

As required by GAAP, we utilize the most observable inputs available for the valuation technique used. The financial assets and

liabilities are classified in their entirety based on the lowest level of input that is of significance to the fair value measurement. Our
assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of
the financial assets and liabilities. Fair values of swaps are estimated using a combined income-based and market-based valuation
methodology based upon forward commodity price curves obtained from independent pricing services. Settlement is determined by
the average underlying price over a predetermined period of time. We use observable inputs in an option pricing valuation model to
determine fair value such as: (i) current market and contractual prices for the underlying instruments; (ii) quoted forward prices for oil;
(iii) interest rates, such as a LIBOR curve for a term similar to the commodity derivative contract; and (iv) appropriate volatilities.

Please read “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for additional information regarding our

commodity derivative contracts.

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 carryforwards. Deferred tax assets and liabilities are measured using
enacted tax laws and 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.

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 our outlook for future years. We believe it is more likely
than not that certain net operating losses can be carried forward and utilized.

Our federal and state income tax returns are generally not prepared or filed before the consolidated financial statements are

prepared; therefore, we estimate the tax basis of our assets and liabilities, which are based on numerous judgments and assumptions
inherent in the determination of future taxable income, at the end of each period as well as the effects of tax rate changes and tax
credits. Adjustments related to these estimates are recorded in our tax provision in the period in which we finalize our income tax
returns. Material changes to our tax accruals may occur in the future based on audits, changes in legislation or resolution of pending
matters.

Off-Balance Sheet Arrangements

As of December 31, 2014, we had no material off-balance sheet arrangements.

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 oil and natural gas prices.
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, natural gas and NGLs production. Pricing for oil,
natural gas and NGLs has been volatile and unpredictable for several years, and this volatility is expected to continue in the future.
The prices we receive for our oil, natural gas and NGLs 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 fluctuations in oil prices on our revenues, we periodically enter into commodity derivative contracts

with respect to certain 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.

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 enter into an International Swap Dealers Association Master Agreement (“ISDA
Agreement”) with each of 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, 2014, the fair market value of our oil derivative contracts was a net asset of $88.9 million. Based on our

open oil derivative positions at December 31, 2014, a 10% increase in the NYMEX WTI price would decrease our net oil derivative
asset by approximately $14.5 million, while a 10% decrease in the NYMEX WTI price would increase our net oil derivative asset by
approximately $13.7 million. As of December 31, 2014, the fair market value of our natural gas derivative contracts was a net asset of
$2.3 million. Based upon our open commodity derivative positions at December 31, 2014, a 10% increase in the NYMEX Henry Hub
price would decrease our net natural gas derivative asset by approximately $0.2 million, while a 10% decrease in the NYMEX Henry
Hub price would increase our net natural gas derivate asset by approximately $0.2 million. Please read “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 it deems
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. A portion of our derivative contracts currently in place are with
lenders under our Revolving Credit Agreement, who have investment grade ratings.

Interest Rate Risk

Our market risk exposure related to changes in interest rates relates primarily to debt obligations. We are exposed to changes in

interest rates as a result of our Revolving Credit Agreement, and the terms of our Revolving Credit Agreement require us to pay
higher interest rate margins as we utilize a larger percentage of our available commitments.

At December 31, 2014, we had $120 million of variable-rate debt outstanding, with an interest rate of LIBOR plus 1.50%, or
1.67%. Assuming no change in the amount outstanding, the impact on interest expense of a 1% increase or decrease in the average
interest rate would be approximately $1.2 million per year.

PARSLEY ENERGY, INC. AND SUBSIDIARIES

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Our consolidated and combined financial statements and supplementary financial 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, 2014. 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 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, 2014 at the reasonable assurance level.

Management’s Annual Report on Internal Control over Financial Reporting and Attestation Report of the Registered Public
Accounting Firm

This annual report does not include a report of management’s assessment regarding internal control over financial reporting or
an attestation report of our registered public accounting firm due to a transition period established by the rules of the SEC for newly
public companies.

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 fourth quarter of 2014 that have materially affected, or are reasonably likely to materially
affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required in response to this item will be set forth in our definitive proxy statement for the 2015 annual meeting

of stockholders and is incorporated herein by reference.

Section 16(a) Beneficial Ownership Reporting Compliance

See the material appearing under the heading “Section 16(a) Beneficial Ownership Reporting Compliance” in our definitive

proxy statement for the 2015 Annual Meeting of Stockholders which is incorporated herein by reference. Section 16(a) of the
Exchange Act requires our directors, officers (including a person performing a principal policy-making function) and persons who
own more than 10% of a registered class of our equity securities to file with the Commission initial reports of ownership and reports
of changes in ownership of our common stock and other equity securities. Directors, officers and 10% holders are required by
Commission regulations to send us copies of all of the Section 16(a) reports they file.

Based solely on a review of the copies of the forms sent to us and the representations made by the reporting persons to us, we
believe that, other than as described below, during the fiscal year ended December 31, 2014, our directors, officers and 10% holders
complied with all filing requirements under Section 16(a) of the Exchange Act, with the following exceptions. Mssrs. Alameddine,
Carter, Newcomer and Smith each had a delinquent Form 4 filing on June 2, 2014 for a transaction occurring on May 29, 2014.

ITEM 11. EXECUTIVE COMPENSATION

The information required in response to this item will be set forth in our definitive proxy statement for the 2015 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 following table sets forth information about our common stock that may be issued under equity compensation plans as of

December 31, 2014:

(a)

(b)

Number of Securities to be
Issued upon Exercise of
Outstanding Options,
Warrants and Rights (1)

Weighted-Average
Exercise Price of

Outstanding Options,
Plans (Excluding Securities
Warrants and Rights (2) Reflected in Column(a))(3)

Remaining Available for
Future Issuance Under
Equity Compensation

Equity compensation
plans approved by
security holders(a) .............................................................
Equity compensation
plans not approved by
security holders .................................................................
Total .....................................................................................

— $

23,649 $
23,649 $

—

—
—

—

11,957,579
11,957,579

(1) This column reflects all restricted stock units granted under the Parsley Energy, Inc. 2014 Long Term Incentive Plan (the

“LTIP”) outstanding and unvested as of December 31, 2014. No stock options or warrants have been granted under the
LTIP.

(2) No stock options have been granted under the LTIP and restricted stock units reflected in column (a) are not reflected in

this column as they do not have an exercise price.

(3) This column reflects the total number of shares remaining available for issuance under the LTIP.

Our only equity compensation plan is the LTIP. The LTIP was approved by our stockholders prior to our initial public offering
but has not been approved by our public stockholders. Please read Note 10 of Notes to Consolidated Financial Statements included in
“Item 8. Financial Statements and Supplementary Data” for a description of our equity compensation plans. In addition, a detailed
description of the terms of the LTIP is available in our registration statement on Form S-1, last filed on May 22, 2014 under the
heading “Executive Compensation—2014 Long Term Incentive Plan.”

Additional information required in response to this item will be set forth in our definitive proxy statement for the 2015 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 2015 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 2015 annual meeting

of stockholders and is incorporated herein by reference.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

The following documents are filed as part of this report or incorporated by reference:

Financial Statements:

Our consolidated and combined 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 and Combined Financial Statements" on
page F-1 of this annual report.

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

Exhibits

The exhibits required to be filed by Item 15 are set forth in the Exhibit Index accompanying this Annual Report on Form 10-K.

EXHIBIT INDEX

Exhibit No.
2.1

Description
Agreement and Plan of Merger, dated as of May 29, 2014, by and between Parsley Energy Employee Holdings, LLC
and Parsley Energy, Inc. (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 June 4, 2014).

2.2

2.3

2.4

2.5

3.1

3.2

4.1

4.2

4.3

10.1

10.2

10.3

Purchase and Sale Agreement, dated as of June 4, 2014, by and among OGX Production, LP, OGX Operating, LLC
and Parsley Energy, L.P. (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 June 4, 2014).

Purchase and Sale Agreement, dated as of March 27, 2014, by and between Pacer Energy, Ltd and Parsley Energy,
L.P. (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 August 14, 2014).

First Amendment to Purchase and Sale Agreement and Waiver of Conditions Precedent, dated as of May 1, 2014, by
and between Pacer Energy, Ltd. and Parsley Energy, L.P. (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 August 14, 2014).

Purchase and Sale Agreement, dated as of August 19, 2014, by and between Cimarex Energy Co. and Parsley Energy,
L.P. (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 August 25, 2014).

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. (incorporated by reference to Exhibit 3.2 to the Company’s
Current Report on Form 8-K, File No. 001-36463, filed with the SEC on June 4, 2014).

Indenture, dated as of February 5, 2014, by and among Parsley Energy, LLC, Parsley Finance Corp., each of the
guarantors party thereto and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to
the Company’s Registration Statement on Form S-1, File No. 333-195230, filed with the SEC on April 11, 2014).

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).

Amended and Restated Registration Rights Agreement, dated as of May 29, 2014, 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 4.1 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 Credit Agreement, dated as of October 21, 2013, by and among Parsley Energy, L.P., as
borrower, and 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 Amendment No. 1 to the Company’s Registration Statement on Form S-1, File No. 333-
195230, filed with the SEC on May 5, 2014).

First Amendment to Amended and Restated Credit Agreement, dated as of December 20, 2013, by and among Parsley
Energy, L.P., as borrower, and 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 10.14 to the Company’s Registration Statement on Form S-1, File No. 333-
195230, filed with the SEC on April 11, 2014).

Second Amendment to Amended and Restated Credit Agreement, dated as of February 5, 2014, by and among Parsley
Energy, L.P., as borrower, and 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 10.15 to the Company’s Registration Statement on Form S-1, File No. 333-
195230, filed with the SEC on April 11, 2014).

Exhibit No.

10.4

10.5*

10.6

10.7

10.8†

10.9†

10.10†

10.11†

Description

Fifth Amendment to Amended and Restated Credit Agreement, dated as of May 9, 2014, by and among Parsley
Energy, L.P., as borrower, and 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 10.19 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).

Sixth Amendment to Amended and Restated Credit Agreement, dated as of September 5, 2014, by and among Parsley
Energy, L.P., as borrower, and 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.

Seventh Amendment to Amended and Restated Credit Agreement, dated as of November 10, 2014, by and among
Parsley Energy, L.P., as borrower, and 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 November 14, 2014).

Amended and Restated Credit Agreement, dated October 21, 2013, by and among Parsley Energy, L.P., as borrower,
Chambers Energy Management, LP, as agent and the several lenders party thereto (incorporated by reference to
Exhibit 10.2 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).

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).

Employment Agreement, dated as of January 24, 2014, by and between Parsley Energy Operations, LLC and Colin
Roberts (incorporated by reference to Exhibit 10.9 to the Company’s Registration Statement on Form S-1, File No.
333-195230, filed with the SEC on April 11, 2014).

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).

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).

10.12†*

Employment Agreement, dated as of December 8, 2014, by and between Parsley Energy Operations, LLC and
Thomas Layman.

10.13

10.14

10.15

10.16

Amended and Restated Limited Liability Company Agreement of Parsley Energy Employee Holdings, LLC
(incorporated by reference to Exhibit 10.13 to the Company’s Registration Statement on Form S-1, File No. 333-
195230, filed with the SEC on April 11, 2014).

Master Reorganization Agreement, dated as of May 2, 2014, by and among Parsley Energy, Inc., NGP X US
Holdings, L.P., Parsley Energy, LLC, the persons identified on the signature page thereto as Existing Members and
Parsley Energy Employee Holdings, LLC (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 28, 2014).

First Amended and Restated Limited Liability Company Agreement of Parsley Energy, LLC (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
June 4, 2014).

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).

10.17†

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).

Exhibit No.

10.18†

10.19†

10.20†

10.21†

10.22†

10.23†

10.24†

10.25†

10.26†

10.27†

10.28†

10.29†

Description

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).

10.30†*

Amended and Restated Parsley Energy, Inc. 2014 Long Term Incentive Plan.

10.31†

10.32†

10.33†

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).

Form of Notice of Grant of Restricted Stock (Time-Based) (incorporated by reference to Exhibit 10.17 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 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).

10.34†*

Form of Restricted Stock Unit Agreement.

Exhibit No.

Description

10.35†*

Form of Notice of Grant of Restricted Stock Units (Time-Based).

10.36†*

Form of Notice of Grant of Restricted Stock Units (Performance-Based).

10.37

10.38

Common Stock Subscription Agreement, dated as of February 5, 2015, by and among Parsley Energy, Inc. and the
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 11, 2015).

Registration Rights Agreement, dated as of February 11, 2015, by and among Parsley Energy, Inc. and the purchasers
named therein (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 February 11, 2015).

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. Reserve Report.

101.INS*

XBRL Instance Document.

101.SCH*

XBRL Taxonomy Extension Schema Document.

101.CAL*

XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF*

XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB*

XBRL Taxonomy Extension Labels Linkbase Document.

101.PRE*

XBRL Taxonomy Extension Presentation Linkbase Document.

† Management contract or compensatory plan or agreement
*

Filed herewith. Schedules and similar attachments to the Purchase and Sale Agreement 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.
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.

SIGNATURES

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.

March 11, 2015

By: /s/ Bryan Sheffield

Bryan Sheffield
Chairman, President 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.

March 11, 2015

By: /s/ Bryan Sheffield

Bryan Sheffield

Chairman, President and Chief Executive Officer
(Principal Executive Officer)

By: /s/ Ryan Dalton

Ryan Dalton

Vice President—Chief Financial Officer
(Principal Accounting and Financial Officer)

By: /s/ A.R. Alameddine

A.R. Alameddine
Director

By: /s/ William Browning
William Browning
Director

By: /s/ Chris Carter

Chris Carter
Director

By: /s/ Hemang Desai

Hemang Desai
Director

By: /s/ Randolph Newcomer, Jr.

Randolph Newcomer, Jr.
Director

By: /s/ David H. Smith

David H. Smith
Director

Index to Consolidated and Combined Financial Statements

Report of Independent Registered Public Accounting Firm ....................................................................................................... F-2

Consolidated and Combined Balance Sheets as of December 31, 2014 and 2013 ...................................................................... F-3

Consolidated and Combined Statements of Operations for the Years Ended December 31, 2014, 2013, and 2012................... F-4

Consolidated and Combined Statements of Changes in Equity for the Years Ended December 31, 2014, 2013, and 2012 ....... F-5

Consolidated and Combined Statements of Cash Flows for the Years Ended December 31, 2014, 2013, and 2012 ................. F-7

Notes to Consolidated and Combined Financial Statements ....................................................................................................... F-8

Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited) ................................................................................. F-35

Page

F-1

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders
Parsley Energy, Inc.:

We have audited the accompanying consolidated and combined balance sheets of Parsley Energy, Inc. and subsidiaries (the
Company) as of December 31, 2014 and 2013, and the related consolidated and combined statements of operations, changes in
equity, and cash flows for each of the years in the three-year period ended December 31, 2014. These consolidated and combined
financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these
consolidated and combined financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made
by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

In our opinion, the consolidated and combined financial statements referred to above present fairly, in all material respects, the
financial position of Parsley Energy, Inc. and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and
their cash flows for each of the years in the three-year period ended December 31, 2014, in conformity with U.S. generally accepted
accounting principles.

(signed) KPMG LLP

Dallas, Texas
March 11, 2015

F-2

PARSLEY ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED AND COMBINED BALANCE SHEETS

ASSETS
CURRENT ASSETS

Cash and cash equivalents .......................................................................................................................................................................... $
Accounts receivable:

50,550 $

19,393

December 31, 2014 December 31, 2013
(In thousands)

Joint interest owners and other ....................................................................................................................................................
Oil and gas ...................................................................................................................................................................................
Related parties .............................................................................................................................................................................
Short-term derivative instruments ......................................................................................................................................................
Materials and supplies .........................................................................................................................................................................
Other current assets .............................................................................................................................................................................
Total current assets ...............................................................................................................................................................

PROPERTY, PLANT AND EQUIPMENT, AT COST

Oil and natural gas properties, successful efforts method ..................................................................................................................
Accumulated depreciation, depletion and amortization .....................................................................................................................
Total oil and natural gas properties, net ...............................................................................................................................
Other property, plant and equipment, net ...........................................................................................................................................
Total property, plant and equipment, net .............................................................................................................................

NONCURRENT ASSETS

Long-term derivative instruments .......................................................................................................................................................
Equity investment ...............................................................................................................................................................................
Deferred loan costs, net .......................................................................................................................................................................
Other noncurrent assets .......................................................................................................................................................................
Total noncurrent assets .........................................................................................................................................................
TOTAL ASSETS ............................................................................................................................................................................................. $

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 deferred tax liability ...............................................................................................................................................................
Amounts due related parties ...............................................................................................................................................................
Total current liabilities .........................................................................................................................................................

NONCURRENT LIABILITIES

Long-term debt ....................................................................................................................................................................................
Asset retirement obligations ...............................................................................................................................................................
Deferred tax liability ...........................................................................................................................................................................
Payable pursuant to tax receivable agreement ....................................................................................................................................
Long-term derivative instruments .......................................................................................................................................................
Other noncurrent liabilities .................................................................................................................................................................
Total noncurrent liabilities ...................................................................................................................................................

COMMITMENTS AND CONTINGENCIES
MEMBERS' EQUITY .....................................................................................................................................................................................
MEZZANINE EQUITY ..................................................................................................................................................................................
STOCKHOLDERS' EQUITY

Preferred Stock, $.01 par value, 50,000,000 shares authorized, none issued and outstanding ..........................................................
Common Stock

Class A, $.01 par value, 600,000,000 shares authorized, 93,937,947 issued and 93,901,208
outstanding at December 31, 2014 and 1,000 issued and outstanding at December 31, 2013 ...............................................
Class B, $.01 par value, 125,000,000 shares authorized, 32,145,296 issued and
outstanding at December 31, 2014 and none issued and outstanding at December 31, 2013 .................................................
Additional paid in capital ....................................................................................................................................................................
Retained earnings ................................................................................................................................................................................
Treasury Stock, at cost, 36,739 shares and none at December 31, 2014 and December 31, 2013 ....................................................
Total stockholders' equity ....................................................................................................................................................
Noncontrolling interest .......................................................................................................................................................................
Total equity ...........................................................................................................................................................................
TOTAL LIABILITIES AND EQUITY .......................................................................................................................................................... $

The accompanying notes are an integral part of these consolidated and combined financial statements.

37,620
22,700
4,065
80,911
3,767
4,548
204,161

1,872,616
(128,044)
1,744,572
16,290
1,760,862

70,805
2,121
12,943
187
86,056
2,051,079 $

139,922 $
38,366
650
29,326
12,601
—
220,865

676,845
16,207
62,334
50,689
31,275
375
837,725

—
—

—

932

321
644,636
61,352
—
707,241
285,248
992,489
2,051,079 $

90,490
15,202
1,041
6,999
3,078
1,123
137,326

614,315
(34,957)
579,358
7,525
586,883

13,850
1,774
2,723
—
18,347
742,556

158,385
28,419
227
4,435
—
31
191,497

429,970
8,277
2,572
—
2,208
—
443,027

30,874
77,158

—

—
—
—
—
—
—
108,032
742,556

F-3

PARSLEY ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS

2014

Year ended December 31,
2013

2012

(in thousands, except per share data)

REVENUES

Oil sales ............................................................................................... $
Natural gas and natural gas liquids sales .............................................
Total revenues ................................................................................

232,554 $
69,203
301,757

97,839 $
23,179
121,018

OPERATING EXPENSES

Lease operating expenses ....................................................................
Production and ad valorem taxes .........................................................
Depreciation, depletion and amortization ............................................
General and administrative expenses ...................................................
Exploration costs .................................................................................
Acquisition costs..................................................................................
Incentive unit compensation ................................................................
Stock based compensation ...................................................................
Accretion of asset retirement obligations ............................................
Total operating expenses ................................................................
(Loss) gain on sale of property ..................................................................
OPERATING INCOME .........................................................................
OTHER INCOME (EXPENSE)

Interest expense, net ............................................................................
Rig termination costs ...........................................................................
Prepayment premium on extinguishment of debt ................................
Income from equity investment ...........................................................
Derivative income (loss) ......................................................................
Other income (expense) .......................................................................
Total other income (expense), net ..................................................
INCOME BEFORE INCOME TAXES ................................................
INCOME TAX EXPENSE .....................................................................
NET INCOME ........................................................................................
LESS: NET INCOME ATTRIBUTABLE TO
NONCONTROLLING INTERESTS ....................................................
NET INCOME ATTRIBUTABLE TO PARSLEY ENERGY INC.
STOCKHOLDERS .............................................................................. $

38,071
18,941
94,297
34,997
3,136
2,527
51,088
2,209
512
245,778
(2,097)
53,882

(38,607)
(765)
(5,107)
348
83,858
(419)
39,308
93,190
(36,468)
56,722

(33,293)

16,572
7,081
28,152
15,248
—
—
1,233
—
181
68,467
36
52,587

(13,714 )
—
—
184
(9,800 )
159
(23,171 )
29,416
(1,906 )
27,510

30,443
7,236
37,679

4,646
2,412
6,406
3,629
—
—
—
—
66
17,159
7,819
28,339

(6,285)
—
(6,597)
267
(2,190)
(81)
(14,886)
13,453
(554)
12,899

—

23,429 $

27,510 $

12,899

Net income per common share:

Basic ....................................................................................................... $
Diluted .................................................................................................... $

Weighted average common shares outstanding:

Basic .......................................................................................................
Diluted ....................................................................................................

0.42
0.42

55,136
55,239

The accompanying notes are an integral part of these consolidated and combined financial statements.

F-4

PARSLEY ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED AND COMBINED STATEMENT OF CHANGES IN EQUITY

Issued Shares

Members'
Equity

Mezzanine
equity

Class A
common
stock

Class B
common
Stock

Class A
common
stock

Class B
common
Stock

Additional
paid in
capital
(In thousands)

Retained
Earnings

Treasury
stock

Total
Stockholders'
equity

Noncontrolling
interest

Total
Equity

— $ — $
—
—
—
—

— $
—
—

—

— $
—
—

—

—
—
—

—

— $
—
—

—

— $
—
—

—

— $
9,053
— (15,935)
— 12,899

—

6,017

77,158

—

6,017

1,723

(3,886 )

(1,723 )

—
—

— 77,158

—
—
—

(8,772 ) 78,881

Balance at
12/31/2011 ............ $ 9,053 $
Distributions ............ (15,935 )
Net income .............. 12,899
Balance at
12/31/2012 ............
LLC interest
issuance ................
Preferred return
on redeemable
LLC interests ........
Deemed
contribution -
incentive unit
compensation .........
1,233
Net income .............. 27,510
Balance at
12/31/2013 ............ 30,874 77,158
Preferred return
on redeemable
LLC interests ........
Net loss prior to
corporate
reorganization ........ (37,923 )
Balance prior to
Corporate
Reorganization
and Offering .........
Reorganization
Transactions:
Payment of
Preferred Return .......
Conversion of PE
Units for Class
A Common
Stock and Class
B Common
Stock ...................... (42,316 ) (72,155 ) 43,204 32,145
Net deferred tax
liability due to
corporate
reorganization ........
Deemed
contribution -
incentive unit
compensation ......... 51,088
Offering
Transactions:
Issuance of Class
A Common
Stock, net of
underwriters
discount
and expenses ..........
Initial allocation
of noncontrolling
interest of
Parsley LLC
effective on the
date of the
Offering .................
Tax benefit from
tax receivable
agreement ..............
Liability due to
tax receivable
agreement ..............

— 49,963

(6,726 )

—

(3,886)

—
—

—

—
—

—

—
—

—

—
—

—

—
—

—

—
—

—

—
—

—

—
1,233
— 27,510

— 108,032

—

— (37,923)

—

— 70,109

—

(6,726)

432

321 113,718

—

114,471

—

(95,530)

—

(95,530 )

— (95,530)

—

— 51,088

500

— 867,250

—

867,750

— 867,750

—

— (251,955)

—

(251,955 )

251,955

—

59,633

—

59,633

— 59,633

—

(50,689)

—

(50,689 )

— (50,689)

F-5

PARSLEY ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED AND COMBINED STATEMENT OF CHANGES IN EQUITY
(continued)

Issued Shares

Members'
Equity

Mezzanine
equity

Class A
common
stock

Class B
common
Stock

Class A
common
stock

Class B
common
Stock

Additional
paid in
capital
(In thousands)

Retained
Earnings

Treasury
stock

Total
Stockholders'
equity

Noncontrolling
interest

Total
Equity

Issuance of
restricted stock
and restricted
stock units ..............
Restricted stock
forfeited .................
Stock based
compensation .........
Consolidated net
income
subsequent to
the Corporate
Reorganization
and the Offering .......
Balance at
12/31/2014 ............. $

—

770

—

(41 )

—

2,250

—

(41 )

—

(41 )

2,250

—

2,250

—

— 61,352

—

61,352

33,293 94,645

— $

— 93,937 32,145 $

932 $

321 $ 644,636 $ 61,352

37 $

— $

707,241 $

285,248 $992,489

The accompanying notes are an integral part of these consolidated and combined financial statements.

F-6

PARSLEY ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS

2014

Year Ended December 31,
2013
(In thousands)

2012

56,722 $

27,510 $

12,899

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ............................................................................................................................................... $
Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation, depletion and amortization ..........................................................................................
Unproved leasehold impairment ........................................................................................................
Accretion of asset retirement obligations ...........................................................................................
Loss (gain) on sale of oil and natural gas properties ..........................................................................
Amortization of debt issue costs ........................................................................................................
Amortization of bond premium .........................................................................................................
Interest not paid in cash .....................................................................................................................
Income from equity investment .........................................................................................................
Provision for deferred income taxes ..................................................................................................
Deemed contribution - incentive unit compensation ..........................................................................
Stock based compensation .................................................................................................................
Derivative (income) loss ....................................................................................................................
Net cash received (paid) for derivative settlements ...........................................................................
Net cash received (paid) for option premiums ...................................................................................
Net cash paid to margin account ........................................................................................................

Changes in operating assets and liabilities, net of acquisitions:

Accounts receivable ...........................................................................................................................
Other current assets ...........................................................................................................................
Materials and supplies .......................................................................................................................
Other noncurrent assets ......................................................................................................................
Accounts payable and accrued expenses ............................................................................................
Revenue and severance taxes payable ...............................................................................................
Amounts due to/from related parties ..................................................................................................
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 ....................................................................................
Additions to other property and equipment .......................................................................................
Proceeds from sales of oil and natural gas properties ........................................................................
Investment in equity investment ........................................................................................................
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 ..................................................................................
Payment of Preferred Return .............................................................................................................
Proceeds from issuance of LLC interests ...........................................................................................
Equity issue costs...............................................................................................................................
Distributions ......................................................................................................................................
Net cash provided by financing activities ..........................................................................................
Net increase in cash and cash equivalents ................................................................................................
Cash and cash equivalents at beginning of period ....................................................................................
Cash and cash equivalents at end of period .............................................................................................. $
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:

94,297
742
512
2,097
2,327
(574 )
234
(348 )
36,468
51,088
2,209
(83,858 )
3,311
193
(320 )

45,372
241
(689 )
(187 )
(32,121 )
9,947
(3,055 )
375
184,983

(477,681 )
(762,244 )
(7,924 )
172
—
(1,247,677 )

946,140
(700,766 )
(12,547 )
867,750
(6,726 )
—
—
—
1,093,851
31,157
19,393
50,550 $

28,152
—
181
(36)
1,225
—
2,597
(184)
1,906
1,233
—
9,800
(198)
(16,342)
(462)

(77,086)
(348)
(867)
—
57,532
19,243
(621)
—
53,235

(209,859)
(208,381)
(8,121)
750
—
(425,611)

561,218
(254,100)
(2,294)
—
—
73,540
(268)
—
378,096
5,720
13,673
19,393 $

Cash paid for interest ......................................................................................................................... $
Cash paid for income taxes ................................................................................................................ $

26,235 $
— $

13,536 $
— $

SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES:
Asset retirement obligations incurred, including changes in estimate ................................................ $
Additions to oil and natural gas properties - change in capital accruals ............................................. $
Additions to other property and equipment funded by capital lease borrowings ............................... $

7,498 $
13,658 $
2,263 $

6,238 $
58,540 $
— $

The accompanying notes are an integral part of these consolidated and combined financial statements.

F-7

6,406
—
66
(7,819)
853
—
1,845
(267)
548
—
—
2,190
179
(9,318)
(35)
—
(18,040)
212
(1,866)
—
14,726
3,653
(1,207)
—
5,025

(66,352)
(31,954)
(328)
9,295
(200)
(89,539)

128,298
(37,012)
(871)
—
—
—
(235)
(15,935)
74,245
(10,269)
23,942
13,673

4,661
6

1,040
5,593
—

PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
December 31, 2014

NOTE 1. ORGANIZATION AND NATURE OF OPERATIONS

Parsley Energy, Inc. (together with its subsidiaries, the “Company”) was formed on December 11, 2013, pursuant to the laws of
the State of Delaware, as a wholly-owned subsidiary of Parsley Energy, LLC (“Parsley LLC”), a Delaware limited liability company
formed on June 11, 2013 and is engaged in the acquisition, development, production, exploration, and sale of crude oil and natural gas
properties located primarily in the Permian Basin, which is located in West Texas and Southeastern New Mexico. Concurrent with the
formation of Parsley Energy, LLC, all of the interest holders of Parsley Energy, L.P. (“Parsley LP”), Parsley Energy Management,
LLC (“PEM”) and Parsley Energy Operations, LLC (“PEO”) exchanged their interest in each entity in return for interest in Parsley
Energy, LLC (the “Exchange”). Prior to the formation of Parsley Energy, LLC, 67.8% of Parsley LP, 100% of PEM and 100% of PEO
were held by Mr. Bryan Sheffield, Parsley Energy, LLC’s President and Chief Executive Officer (“Sheffield”). Subsequent to Parsley
Energy, LLC’s formation, Sheffield controlled 53.7% of Parsley Energy, LLC. As such, as all power and authority to control the core
functions of Parsley LP, PEM and PEO were, and continue to be, controlled by Sheffield, the Exchange has been treated as a
reorganization of entities under common control and the results of Parsley LP, PEM and PEO have been consolidated and combined
for all periods.

Parsley LP was formed on February 29, 2008, as a Texas limited partnership and is primarily engaged in the acquisition,
development, production, exploration, and sale of crude oil and natural gas properties located in the Permian Basin in West Texas. On
September 9, 2011, Parsley LP formed, and held all of the interest in, Spraberry Energy, LLC (“Spraberry”), a Texas limited liability
company. On November 20, 2012, Spraberry merged with and into Parsley LP, thereby terminating Spraberry’s corporate existence.

PEM was formed on February 19, 2008, as a Texas limited liability company and was formed to be the general partner of

Parsley LP.

PEO was formed on February 19, 2008, as a Texas limited liability company and is primarily engaged in the operation of crude

oil and natural gas properties located in the Permian Basin in West Texas.

Parsley LP also owns a noncontrolling 42.5% investment in Spraberry Production Services LLC (“SPS”). SPS was formed on
August 27, 2010, as a Texas limited liability company and is primarily engaged in the oilfield services business servicing properties
located in the Permian Basin in West Texas.

Initial Public Offering

On May 29, 2014, the Company completed its initial public offering (the “Offering”) of 57.5 million shares of the Company’s

Class A common stock, par value $0.01 per share (“Class A Common Stock”) at a price of $18.50 per share. Approximately
7.5 million of the shares were sold by selling stockholders and the Company did not receive any proceeds from the sale of those
shares. The remaining approximately 50 million shares of the Company’s Class A Common Stock that were sold resulted in gross
proceeds of approximately $924.3 million to the Company and net proceeds, after deducting underwriting discounts and commissions
and offering expenses, of approximately $867.8 million. The material terms of the Offering are described in the Company’s final
prospectus, dated May 22, 2014 and filed with the Securities and Exchange Commission (“SEC”) pursuant to Rule 424(b)(4) of the
Securities Act of 1933, as amended, on May 27, 2014.

A portion of the proceeds from the Offering were used to repay all outstanding borrowings under the Revolving Credit
Agreement (as defined herein), to make a cash payment in settlement of the Preferred Return (as defined herein), to fund the OGX
Acquisition (as defined herein), and to pay fees and expenses related to the Offering. The remaining proceeds will be used to fund a
portion of the Company’s exploration and development program and for general corporate purposes.

Corporate Reorganization

On May 29, 2014, in connection with the Offering, Parsley LLC underwent a corporate reorganization (“Corporate

Reorganization”) whereby (a) all of the membership interests (including outstanding incentive units) in Parsley LLC held by its then
existing owners (the “Existing Owners”) were converted into a single class of units in Parsley LLC (“PE Units”), (b) certain of the
Existing Owners contributed all of their PE Units to the Company in exchange for an equal number of shares of the Company’s
Class A Common Stock, (c) certain of the Existing Owners contributed only a portion of their PE Units to the Company in exchange
for an equal number of shares of the Company’s Class A Common Stock and continue to own a portion of the PE Units and
(d) Parsley Energy Employee Holdings, LLC (“PEEH”), an entity owned by certain of Parsley LLC’s officers and employees that was
formed to hold a portion of the incentive units in Parsley LLC, was merged with and into the Company, with the Company surviving
the merger and the members of PEEH receiving shares of the Company’s Class A Common Stock. As a result of the above
transactions, the Company issued a total of 43.2 million shares of its Class A Common Stock.

F-8

PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
December 31, 2014

Upon completion of the Offering, the Company issued and contributed 32.1 million shares of its Class B common stock, par

value $0.01 per share (“Class B Common Stock”) and all of the net proceeds of the Offering to Parsley LLC in exchange for
93.2 million PE Units. Parsley LLC distributed to each of the Existing Owners that continued to own PE Units following the
Corporate Reorganization and the Offering (collectively, the “PE Unit Holders”), one share of Class B Common Stock for each PE
Unit such PE Unit Holder held. After giving effect to these transactions the Company owns an approximate 74.3% interest in Parsley
LLC and Parsley LLC became a majority-owned subsidiary of the Company. The PE Unit Holders own an approximate 25.7% interest
in Parsley LLC.

NOTE 2.

BASIS OF PRESENTATION

These consolidated and combined financial statements include the accounts of Parsley Energy, Inc. and its majority-owned
subsidiary, Parsley LLC, and its wholly-owned subsidiaries: (i) Parsley LP, (ii) PEM, (iii) PEO, and its wholly-owned subsidiary,
Parsley Energy Aviation, LLC, and (iv) Parsley Finance Corp. Parsley LP owns a 42.5% noncontrolling interest in 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.

Transfers of a business between entities under common control are accounted for as if the transfer occurred at the beginning of

the period, and prior years are retrospectively adjusted to furnish comparative information. As discussed above, the Corporate
Reorganization has been accounted for as transactions between entities under common control thus the accompanying consolidated
and combined financial statements and related notes of the Company have been retrospectively re-cast to include the historical results
of the entities involved at historical carrying values and their operations as if they were consolidated and combined for all periods
presented.

NOTE 3.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

These consolidated and combined financial statements and related notes are presented in accordance with GAAP. Preparation in
accordance with GAAP requires us to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards
Board (“FASB”) and by the SEC and (2) 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. Our management believes the major estimates and assumptions impacting our consolidated and
combined 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 of oil and natural gas properties we own, particularly properties that we have not yet explored,
or fully explored, by drilling and completing wells;

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 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-9

PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
December 31, 2014

Cash and Cash Equivalents

Cash and cash equivalents include demand deposits and funds invested in highly liquid instruments with original maturities of

three months or less and typically exceed federally insured limits.

Accounts Receivable

Accounts receivable consist of receivables from joint interest owners on properties the Company operates and crude oil, NGLs,

and natural gas 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, 2014 or December 31, 2013.

For the years ended December 31, 2014, 2013 and 2012, each of the following purchasers accounted for more than 10% of our

revenue:

Atlas Pipeline Mid-Continent WestTex, LLC ......................................................
Plains Marketing, L.P. ..........................................................................................
BML, Inc. .............................................................................................................
Permian Transport & Trading ..............................................................................
Enterprise Crude Oil, LLC ...................................................................................
Shell Trading (US) Company ...............................................................................

2014
20%
15%
14%
11%
10%
4%

Year Ended December 31,
2013
16%
22%
2%
25%
20%
7%

2012
14%
16%
—%
20%
26%
17%

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.

Material and Supplies

Materials and supplies are stated at the lower of cost or market and consists of oil and gas drilling or repair items such as 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 accounts under joint operating agreements to which the Company is a party. As of December 31, 2014, the
Company estimated that all of its tubular goods and equipment will be utilized within one year.

Oil and Natural Gas Properties

As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to
the properties 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. At December 31, 2014, 2013 and
2012, the Company had excluded $624.2 million, $68.2 million and $14.0 million, respectively, of capitalized costs from depletion.
Depreciation and depletion expense on capitalized oil and gas property was $92.8 million, $27.1 million and $6.3 million for the years
ended December 31, 2014, 2013 and 2012, respectively. The Company had no exploratory wells in progress at December 31, 2014,
2013 or 2012.

F-10

PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
December 31, 2014

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. During the years ended December 31, 2014, 2013, and 2012, the Company
capitalized interest of $2.7 million, $3.4 million and $1.0 million, respectively.

On the sale of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated

depreciation, depletion, and amortization 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

Oil and Gas Reserves

The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated and combined 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 12-month average price 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 reservoir 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, future gross revenues, 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 oil and natural gas properties.

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.

The following table summarizes the changes in the Company’s asset retirement obligation for the periods indicated:

Asset retirement obligations, January 1 .......................... $
Additional liabilities incurred .........................................
Liabilities assumed .........................................................
Disposition of wells ........................................................
Accretion expense ...........................................................
Liabilities settled upon plugging and abandoning wells .....
Revision of estimates ......................................................
Asset retirement obligations, December 31 .................... $

December 31,

2014

2013

(in thousands)
8,277 $
6,604
—
(80)
512
(7)
901
16,207 $

1,858
3,915
2,420
(45 )
181
(3 )
(49 )
8,277

F-11

PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
December 31, 2014

Allocation of Purchase Price in Business Combinations

Impairment of Long-Lived Assets

The Company reviews its long-lived assets to be held and used, including proved oil and natural gas properties by reservoir.

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 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 and unproved oil and natural gas
reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production
costs. The Company recognized no impairment expense on proved oil and natural gas properties during the years ended December 31,
2014, 2013, or 2012.

Exploration costs

Exploration 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 twelve-month period after drilling is complete.

The Company recorded $2.4 million of geological and geophysical costs during the year ended December 31, 2014 and no such

expenses for the years ended December 31, 2013 and 2012.

Unproved oil and natural gas properties are each periodically assessed 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. The
Company recorded $0.7 million of impairment charges related to unproved oil and natural gas properties during the year ended
December 31, 2014 and no impairment charges for the years ended December 31, 2013, or 2012. All of these expenses are included
in “exploration costs” on the Consolidated and Combined Statement of Operations.

F-12

PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
December 31, 2014

Other Property and Equipment, net

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 and combined
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 to fifteen years. Construction in
process includes costs related to the construction of the new office space. All construction in process is expected to be completed
during 2015 and will be depreciated using the straight-line-method once construction is complete and the assets are placed in use.
Depreciation expense on other property and equipment was $1.5 million, $1.1 million and $0.1 million for the years ended
December 31, 2014, 2013 and 2012, respectively.

Buildings ................................................................................... $
Computers, software, and equipment ........................................
Airplane .....................................................................................
Vehicles .....................................................................................
Furniture and fixtures ................................................................
Land ...........................................................................................
Leasehold improvements ...........................................................
Machinery and equipment .........................................................
Construction in process .............................................................
Property and equipment ..........................................................
Accumulated depreciation .........................................................
Property and equipment, net ................................................... $

December 31,

2014

2013

(in thousands)
2,660 $
4,011
4,533
2,611
1,734
1,189
439
188
1,812
19,177
(2,887)
16,290 $

2,117
325
3,729
102
676
1,299
545
97
—
8,890
(1,365)
7,525

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 and combined 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,
2014, 2013, or 2012.

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 and Combined 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 and Combined Statements of Operations in the period of
change. Gains and losses from derivatives are included in cash flows from operating activities.

F-13

PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
December 31, 2014

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 measurements are obtained using unadjusted quoted prices in active markets that are accessible at the

measurement date for identical unrestricted assets or liabilities as of the reporting date.

 Level 2 measurements use as inputs market prices which are either directly or indirectly observable as of the reporting

date for similar commodity derivative contracts. The Company valued its level 2 assets and liabilities using industry-
standard models that considered various assumptions including current market and contractual prices for the underlying
instruments, time value, volatility factors, nonperformance risk, as well as other relevant economic measures.
Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be
supported by observable data.

 Level 3 measurements are based on process or valuation models that use inputs that are both significant to the fair value
measurement and less observable from objective sources (i.e., supported by little of no market activity). These inputs
generally reflect management’s own assumptions about the assumptions a market participant would use in pricing the
asset or liability.

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, NGLs, and natural gas 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, 2013 and 2012, 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 substantially all employees at their date of hire.

The plan allow 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 year ended December 31, 2014, 2013, and 2012, the Company made contributions to the plan of $0.8 million, $0.2 million, and
$0.1 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 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.

F-14

PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
December 31, 2014

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. The Company
believes it is more likely than not that certain net operating losses can be carried forward and utilized.

Parsley LLC, the Company’s accounting predecessor, is a limited liability company that is not subject to U.S. federal income

tax.

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

The Company operates in only one industry segment: the oil and natural gas exploration and production industry in the United

States. All revenues are derived from customers located in the United States.

Reclassifications

Certain reclassifications have been made to prior period amounts to conform to the current presentation

Recent Accounting Pronouncements

In June 2014, the FASB issued ASU No. 2014-12, Compensation - Stock Compensation (Topic 718): Accounting for Share-
Based Payments When the Terms of an Award Provide That a Performance Target Could be Achieved after the Requisite Service
Period. This ASU provides more explicit guidance for treating share-based payment awards that require a specific performance target
that affects vesting and that could be achieved after the requisite service period as a performance condition. The new guidance is
effective for annual and interim reporting periods beginning after December 15, 2015. The Company does not expect the adoption of
this guidance to have a material impact on the consolidated and combined financial statements.

On May 28, 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which requires an entity to
recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The
ASU will replace most existing revenue recognition guidance in GAAP when it becomes effective. The new standard will be effective
for the Company on January 1, 2017. Early application is not permitted. The standard permits the use of either the retrospective or
cumulative effect transition method. The Company is evaluating the effect that ASU 2014-09 will have on its consolidated and
combined financial statements and related disclosures. The Company has not yet selected a transition method nor has it determined the
effect of the standard on its ongoing financial reporting.

NOTE 4.

DERIVATIVE FINANCIAL INSTRUMENTS

Commodity Derivative Instruments and Concentration of Risk

Objective and Strategy

The Company uses derivative financial instruments to manage its exposure to cash-flow variability from commodity-price risk

inherent in its exploration and production activities. These include exchange traded and over-the-counter (OTC) crude put spread
options and three way collars with the underlying contract and settlement pricings based on NYMEX West Texas Intermediate (WTI)
and Henry Hub. Options and collars are used to establish a floor price, or floor and ceiling prices, for expected future oil and natural
gas sales.

The Company uses put spread options to manage commodity price risk for 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.

F-15

PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
December 31, 2014

The Company uses three way collars to manage commodity price risk for both oil and natural gas production. A three way collar

is a combination of three options: a sold call, a purchased put and a sold put. The sold call establishes the maximum price that the
Company will receive for the contracted commodity volumes. 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.

As of December 31, 2014, the Company had entered into derivative contracts through June 2017 covering a total of

approximately 9,680 MBbls of our projected oil production through the purchases of put spreads and three way collars. The Company
also entered into three way collars through December 2015 covering approximately 3,300 MMBtu of our projected natural gas
production.

Derivative Activities

The following table summarizes the open positions for the commodity derivative instruments held by the Company at

December 31, 2014:

Crude Options
Purchased

Notional
(MBbl)

Weighted Average

Strike Price

Puts ......................................................................................................................
Calls .....................................................................................................................

Sold

9,680 $
$
—

(9,680 ) $
(2,405 ) $

67.91
—

50.86
114.69

Natural Gas
Purchased

Notional
(MMBtu)

Weighted Average

Strike Price

Sold

3,300 $
$
—

(3,300 ) $
(3,300 ) $

4.50
—

3.75
5.25

During the fourth quarter 2014, Parsley elected to lower certain strike prices for both long and short put positions. The

The Company excluded from the table above 6,700 notional MBbls with a fair value of $144.9 million relating to amounts

recognized under the master netting agreement with the derivative counterparty.

Effect of Derivative Instruments on the Consolidated and Combined Financial Statements

Consolidated and Combined Balance Sheets

The following table summarizes the gross fair values of the Company’s commodity derivative instruments as of the reporting

dates indicated (in thousands):

December 31,

2014

2013

Short-term derivative instruments ....................................... $
Long-term derivative instruments .......................................
Total derivative instruments - asset ...............................
Short-term derivative instruments .......................................
Long-term derivative instruments .......................................
Total derivative instruments - liability ..........................
Net commodity derivative asset ............................... $

80,911 $
70,805
151,716
(29,326)
(31,275)
(60,601)
91,115 $

6,999
13,850
20,849
(4,435 )
(2,208 )
(6,643 )
14,206

F-16

PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
December 31, 2014

Consolidated and Combined Statements of Operation

The Company recognized a gain from its derivative activities of $83.9 million for the year ended December 31, 2014 and losses

of $9.8 million and $2.2 million for the years ended December 31, 2013, and 2012, respectively. These gains and losses are included
in the Consolidated and Combined Statements of Operations line item, Derivative income (loss), as they were not designated as
hedges for accounting purposes for any of the periods presented. The fair value of the derivative instruments is discussed in Note 14—
Disclosures about Fair Value of Financial Instruments.

Offsetting of Derivative Assets and Liabilities

The Company has agreements in place with all 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 2014, the Company did not post margins with any of its counterparties. During 2013, the Company posted margins
with some of its counterparties to collateralize certain derivative positions.

The following table presents the Company’s net exposure from its offsetting derivative asset and liability positions, as well as

cash collateral on deposit with the brokers as of the reporting dates indicated (in thousands):

Gross Amount
Presented on
Balance Sheet

Netting

Adjustments

Cash
Collateral
Posted (Received)

Net
Exposure

December 31, 2014
Derivative assets with right of offset or
master netting agreements ....................................... $
Derivative liabilities with right of offset or
master netting agreements .......................................

December 31, 2013
Derivative assets with right of offset or
master netting agreements ....................................... $
Derivative liabilities with right of offset or
master netting agreements .......................................

Concentration of Credit Risk

151,716 $

(60,601) $

— $

91,115

(60,601)

60,601

—

20,849 $

(6,643) $

524 $

14,730

(6,643)

6,643

—

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 OTC 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 our commodity derivative contracts as of December 31, 2014 and 2013 is summarized in the table
above.

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 has netting
agreements with its counterparties and brokers that permit net settlement of gross commodity derivative assets against gross
commodity derivative liabilities, and 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, 2014, 2013 or 2012.

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 were in a net liability position with respect to any individual
counterparty at December 31, 2014 and 2013. During 2013, the Company received and posted margins with some of its counterparties
to collateralize certain derivative positions.

F-17

PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
December 31, 2014

NOTE 5. OIL AND NATURAL GAS PROPERTIES

Oil and natural gas properties includes the following (in thousands):

December 31, 2014

December 31, 2013

Oil and natural gas properties:

Subject to depletion ................................................... $
Not subject to depletion-acquisition costs

Incurred in 2014 ...................................................
Incurred in 2013 ...................................................
Incurred in 2012 ...................................................
Total not subject to depletion ..........................................
Gross oil and natural gas properties ................................
Less accumulated depreciation and depletion .................
Oil and natural gas properties, net ...................................
Other property and equipment ........................................
Less accumulated depreciation ..................................
Other property and equipment, net ..................................
Property and equipment, net ........................................... $

1,248,376 $

562,046
62,194
—
624,240
1,872,616
(128,044)
1,744,572
19,177
(2,887)
16,290
1,760,862 $

546,072

—
65,666
2,577
68,243
614,315
(34,957)
579,358
8,890
(1,365)
7,525
586,883

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 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. Costs subject to depletion are proved costs and costs not subject to depletion are unproved costs. At December 31, 2014, the
Company had excluded $624.2 million of capitalized costs from depletion. Depletion expense on capitalized oil and gas property was
$92.8 million, $27.1, and $6.3 million for the years ended December 31, 2014, 2013 and 2012, respectively. The Company had no
exploratory wells in progress at December 31, 2014 and December 31, 2013.

The Company capitalizes interest on expenditures made in connection with long term projects that are not subject to current

Depreciation expense on other property and equipment was $1.5 million, $1.1 million, and $0.1 million for the years ended

December 31, 2014, 2013 and 2012, respectively.

NOTE 6.

ACQUISITIONS OF OIL AND GAS PROPERTIES

The following acquisitions were accounted for using the acquisition method under ASC Topic 805, “Business Combinations,”

which requires the assets acquired and liabilities assumed to be recorded at fair values as of the respective acquisition dates.

During 2012, the Company acquired, from unaffiliated individuals and entities, additional working interests in wells it operates

through a number of separate, individually negotiated transactions for an aggregate total cash consideration of $9.7 million. The
Company reflected the total consideration paid as part of its cost subject to depletion within its oil and gas properties.

In October 2012, the Company acquired, from Diamond K Production, LLC, an entity owned by Diamond K Interests, LP, a
member of Parsley LLC, additional working interests in wells it operates for an aggregate cash consideration of $8.2 million. The
Company reflected the total consideration paid as part of its cost subject to depletion within its oil and gas properties.

During 2013, the Company acquired, from certain of its directors and officers, additional working interests in wells it operates

through a number of separate, individually negotiated transactions for an aggregate cash consideration of $19.4 million. The Company
reflected the total consideration paid as part of its cost subject to depletion within its oil and gas properties. The revenues and
operating expenses attributable to the individual acquisitions during the years ended December 31, 2014 and 2013 were not material.

F-18

PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
December 31, 2014

During 2013, the Company acquired, from unaffiliated individuals and entities, additional working interests in wells it operates

through a number of separate, individually negotiated transactions for an aggregate total cash consideration of $25.1 million. The
Company reflected the total consideration paid as part of its cost subject to depletion within its oil and gas properties. The revenues
and operating expenses attributable to the individual acquisitions during the years ended December 31, 2014 and 2013 were not
material.

In October 2013, the Company acquired oil and gas properties including 5,818 gross (5,330 net) acres primarily in Upton and

Reagan Counties, Texas. The Company’s total consideration paid was $18.0 million. The revenues and operating expenses attributable
to the acquisition during the years ended December 31, 2014 and 2013 were not material. The following table summarizes the
purchase price and the value of assets acquired and liabilities assumed (in thousands):

Consideration given

Allocation of purchase price

Proved oil and gas properties .......................................................................................................... $
Unproved oil and gas properties .....................................................................................................
Total fair value of oil and gas properties acquired ....................................................................
Asset retirement obligation .............................................................................................................

Fair value of net assets acquired ................................................................................................ $

14,734
4,729
19,463
(1,462)
18,001

In December 2013, the Company acquired oil and gas properties including 3,250 gross (2,595 net) acres in Upton and Reagan
Counties, Texas. The Company’s total consideration paid was $32.3 million. The revenues and operating expenses attributable to the
acquisition during the years ended December 31, 2014 and 2013 were not material. The following table summarizes the purchase
price and the values of assets acquired and liabilities assumed (in thousands):

Consideration given

Allocation of purchase price

Fair value of net assets acquired ................................................................................................ $

24,365
8,062
32,427
(167)
32,260

On December 30, 2013, the Company acquired non-operated working interests in a number of wells which it currently operates
for $80.0 million (the “Merit Acquisition”). The transaction did not increase The Company’s gross acreage position, but increases its
net acreage by 637 acres in Upton County, Texas. The following table summarizes the purchase price and the values of assets acquired
and liabilities assumed (in thousands):

Consideration given

Allocation of purchase price

Fair value of net assets acquired ................................................................................................ $

54,440
26,358
80,798
(792)
80,006

The following table presents operating revenues and net earnings included in the Company’s Consolidated and Combined
Statements of Operations for the year ended December 31, 2014 as a result of the Merit Acquisition described above. The revenues
and operating expenses attributable to the Merit Acquisition during the year ended December 31, 2013 were not material.

Total operating revenues .................................................. $
Total operating expenses ..................................................
Operating income ............................................................. $

39,324
7,001
32,323

Year Ended
December 31, 2014
(in thousands)

F-19

PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
December 31, 2014

On March 27, 2014, the Company entered into a purchase and sale agreement, effective May 1, 2014, pursuant to which it
agreed to acquire 2,240 gross (2,005 net) acres in its Midland Basin-Core area and seven gross (6.3 net) wells for total consideration
of $165.3 million (the “Pacer Acquisition”), including purchase price adjustments. The following table summarizes the purchase price
and the values of assets acquired and liabilities assumed (in thousands):

Consideration given

Allocation of purchase price

Fair value of net assets acquired ................................................................................................ $

56,870
108,583
165,453
(172)
165,281

The following table presents operating revenues and net earnings included in the Company’s Consolidated and Combined
Statements of Operations for the year ended December 31, 2014 as a result of the Pacer Acquisition described above. There were no
earnings included in the Consolidated and Combined Statements of Operations for the year ended December 31, 2013.

19,401
3,111
16,290

Year Ended
December 31, 2014
(in thousands)

On May 30, 2014, the Company entered into the First Amendment to Option Agreement to which the Company acquired an

option to purchase 4,640 gross (4,640 net) acres in its Midland Basin-Core area for total consideration of $127.6 million (the “OGX
Acquisition”, net of purchase price adjustments. On June 4, 2014, the option was exercised. The revenues and operating expenses
attributable to the OGX Acquisition during the years ended December 31, 2014 and 2013 were not material. The following table
summarizes the purchase price and the values of assets acquired and liabilities assumed (in thousands):

Consideration given

Allocation of purchase price

Proved oil and gas properties ..................................................................................................... $
Unproved oil and gas properties ................................................................................................
Total fair value of oil and gas properties acquired ............................................................
Asset retirement obligation ........................................................................................................
Fair value of net assets acquired ................................................................................................

10,747
116,919
127,666
(38)
127,628

On September 30, 2014, the Company entered into a purchase and sale agreement, effective September 1, 2014, pursuant to
which it agreed to acquire 4,320 gross (4,228 net) acres and 9 gross (9 net) wells in its Midland Basin-Core area for total consideration
of $239.5 million (the “Cimarex Acquisition”), net of purchase price adjustments. The revenues and operating expenses attributable to
the Cimarex Acquisition during the years ended December 31, 2014 and 2013 were not material. The following table summarizes the
purchase price and the values of assets acquired and liabilities assumed (in thousands):

Consideration given

Allocation of purchase price

111,003
128,756
239,759
(219)
239,540

On December 16, 2014, the Company purchased 8,643 gross (7,128 net) unproved acres in our Midland Basin – Core area for

total consideration of $120.0 million from unaffiliated third parties (the “APC Acquisition”).

F-20

PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
December 31, 2014

The Company incurred a total of $54.0 million and $32.7 million of leasehold acquisition costs during 2014 and 2013, which are

included as part of costs not subject to depletion.

During 2014, the Company acquired, from unaffiliated individuals and entities, additional working interests in wells it operates

through a number of separate, individually negotiated transactions for an aggregate total cash consideration of $55.2 million. The
Company reflected the total consideration paid as part of its cost subject to depletion within its oil and gas properties.

Pro forma for information for material acquisitions (unaudited)

The Merit Acquisition and the Pacer acquisition (collectively, the "Material Acquisitions") were deemed material for purposes
of the following pro forma disclosures. The Material Acquisitions were not included in the Company’s consolidated results until their
closing dates. For the periods after the closing date of each Material Acquisition to December 31, 2014, the Material Acquisitions
contributed revenue of $58.7 million and operating income of $48.6 million for the year ended December 31, 2014.

The operating income attributable to the Material Acquisitions does not reflect certain expenses, such as general and

administrative and interest expense; therefore, this information is not intended to report results as if these operations were managed on
a stand-alone basis. The financial information was derived from the Company's audited historical consolidated financial statements for
the years ended December 31, 2014 and 2013, the Material Acquisitions' audited and historical financial statements for the year ended
December 31, 2013 and the Material Acquisitions' unaudited interim financial statements from January 1, 2013 to each closing date.
The following unaudited pro forma consolidated financial information has been prepared as if the Material Acquisitions occurred on
January 1, 2013 for the years ending December 31, (in thousands, except per share data).

Revenue

As reported ...................................................................................... $
Pro forma......................................................................................... $

Net Income

Basic net income per share

Diluted net income per share

Pro Forma

2014

2013

301,757 $
307,999 $

23,429 $
24,894 $

0.42 $
0.45 $

121,018
143,443

27,510
29,452

0.32
0.34

0.23
0.25

These pro-forma adjustments have been calculated after applying the Company's accounting policies and adjusting the results to

reflect additional depreciation and amortization that would have been charged assuming the properties were acquired and fair value
adjustments to property and equipment had been applied. In addition, pro forma adjustments have been made for the interest that
would have been incurred for financing the acquisitions with the Company's credit facility. These pro forma results of operations have
been prepared for comparative purposes only and they do not purport to be indicative of the results of operations that actually would
have resulted had the acquisitions occurred on the date indicated or that may result in the future.

NOTE 7.

SALES OF OIL AND NATURAL GAS PROPERTIES

In April 2012, The Company sold 2,652 net unevaluated acres in Dawson, Glasscock, Howard, Martin and Upton Counties,

Texas for $8.6 million and realized a $7.5 million gain on the sale.

In November 2012, The Company sold 960 net unevaluated acres in Howard County, Texas for total proceeds of $0.7 million

and realized a $0.3 million gain on the sale.

In August 2013, The Company sold its interest in seven non-operated wells and 190 net acres for total proceeds of $0.8 million

and realized a $36,000 gain on the sale.

In August 2014, the Company sold its interest in one operated well and 38 net acres for total proceeds of $0.2 million and

realized a $2.1 million loss on the sale.

F-21

PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
December 31, 2014

NOTE 8.

EQUITY INVESTMENT

The Company uses the equity method of accounting for the investment in SPS, with earnings or losses, after adjustment for

intra-company profits and losses, reported in the income (loss) from equity investment line on the Consolidated and Combined
Statements of Operations.

In November 2014, SPS underwent a corporate reorganization, effective January 1, 2014, in which two nonrelated parties were

admitted as members, each obtaining a 7.5% interest in exchange for a capital contributions. As a result of the reorganization, the
Company’s interest in SPS was decreased to 42.5%

As of December 31, 2014 and December 31, 2013, the balance of the Company’s investment in SPS was $2.2 million and $1.8
million, respectively. The investment balance increased by $1.1 million and $0.7 million for the years ended December 31, 2014 and
2013, for the Company’s share of SPS’ net income, before adjustment for intra-company profits and losses, respectively. During the
years ended December 31, 2014 and 2013, SPS provided services to the Company in its oil and natural gas field development
operations, which the Company capitalized as part of its oil and gas properties. As such, that portion of the Company’s share of SPS’
gross profit from these services totaling $0.7 million and $0.5 million for the years ended December 31, 2014 and 2013, was
subsequently eliminated from its share of SPS’s net income and a corresponding reduction was made to the carrying value of its
investment.

NOTE 9.

DEBT

The Company’s debt consists of the following (in thousands):

Revolving credit agreement .................................... $
Senior unsecured notes ...........................................
Capital leases ..........................................................
Second lien term loan .............................................
Aircraft term loan ....................................................
Total debt .....................................................
Premium on senior unsecured notes ........................
Less: current portion ..........................................
Total long-term debt..................................... $

December 31,

2014

2013

120,000 $
550,000
2,069
—
—
672,069
5,426
(650)
676,845 $

234,750
—
—
192,854
2,593
430,197
—
(227 )
429,970

First Lien Obligations

Western National Bank Facility

On July 26, 2010, the Company entered into a loan agreement with Western National Bank which was subsequently amended
and extended multiple times. On September 10, 2013, the Company repaid all amounts outstanding plus accrued interest associated
the the Western National Bank facility.

Revolving Credit Agreement

On September 10, 2013, the Company entered into the Revolving Credit Agreement with Wells Fargo Bank National

Association as the administrative agent. The Revolving Credit Agreement provides a revolving credit facility with a borrowing
capacity up to the lesser of (i) the borrowing base (as defined in the Revolving Credit Agreement), (ii) aggregate lender commitments,
and (iii) $750.0 million. The Revolving Credit Agreement matures on September 10, 2018. The Revolving Credit Agreement is
secured by substantially all of the Company’s assets.

The Revolving Credit Agreement provided for an initial borrowing base of $175.0 million based on the Company’s proved
producing reserves and a portion of its proved undeveloped reserves. The borrowing base will be redetermined by the lenders at least
semi-annually on each April 1 and October 1, with the next redetermination on April 1, 2015. The amount the Company is able to
borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the Revolving
Credit Agreement.

On October 21, 2013, the Company entered into an amended and restated credit agreement (as amended, the “Revolving Credit
Agreement”), whereby the borrowing base was reduced from $175.0 million to $143.8 million. On December 20, 2013, The Company

F-22

PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
December 31, 2014

entered into the First Amendment to the Amended and Restated Credit Agreement which increased the borrowing base from $143.8
million to $240 million. In addition, the amendment provided that the borrowing base would automatically increase from $240 million
to $280 million upon the closing of the Merit Acquisition, which closed on December 30, 2013.

On April 15, 2014, in connection with the issuance of the Notes (as defined herein) offering, the Company entered into the Third

Amendment to the Amended and Restated Credit Agreement whereby the borrowing base was increased from $227.5 million to
$365.0 million. Immediately following the Notes offering, the borrowing base was reduced to $327.5 million.

On May 2, 2014, the Company entered into the Fourth Amendment to the Revolving Credit Agreement whereby the expiration

date of any letter of credit was increased from fifteen months to eighteen months.

On May 9, 2014, the Company entered into the Fifth Amendment to the Revolving Credit Agreement whereby certain terms

were amended permitting the Corporate Reorganization to occur.

On May 29, 2014, the Company used proceeds from the Offering to repay the outstanding borrowings under the Revolving

Credit Agreement.

On September 4, 2014, the Company entered into the Sixth Amendment to the Revolving Credit Agreement (the “Sixth
Amendment”.) The Sixth Amendment changed the reporting requirements and deliverables in response to the Company becoming a
public company.

In November 2014, the Company entered into the Seventh Amendment to the Amended and Restated Credit Agreement

whereby the borrowing base was increased to $575.0 million, with a commitment level of $365.0 million.

In December 2014, the Company’s borrowing base was decreased to $562.0 million, with a commitment level of $365.0
million, resulting from a restructuring of commodity price hedges. In February 2015, the borrowing base was decreased to $560.8,
with a commitment level of $365.0 also resulting from restructuring of commodity price hedges.

As of December 31, 2014 there were $120.0 million of borrowings outstanding and $0.3 million in letters of credit outstanding,

resulting in availability of $244.7 million.

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 (equal to the product of: (a) the LIBO rate, multiplied by (b) a fraction
(expressed as a decimal), the numerator of which is the number one and the denominator of which is the number one minus the
aggregate of the maximum reserve percentages (expressed as a decimal) on such date at which the Administrative Agent is required to
maintain reserves on ‘Eurocurrency Liabilities’ as defined in and pursuant to Regulation D of the Board of Governors of the Federal
Reserve System) plus an applicable margin ranging from 150 to 250 basis points, depending on the percentage of our borrowing base
utilized. Alternate base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the
federal funds effective rate plus 50 basis points and (iii) the adjusted LIBO rate (as calculated above) plus 100 basis points, plus an
applicable margin ranging from 50 to 150 basis points, depending on the percentage of our 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 our borrowing
base utilized. As of December 31, 2014, letters of credit outstanding under the Revolving Credit Agreement had a weighted average
interest rate of 1.75%. 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 requires the Company to maintain the following two financial ratios:



a current ratio, which is the ratio of consolidated current assets (including unused availability under its revolving credit
facility) to consolidated current liabilities of not less than 1.0 to 1.0 as of the last day of any fiscal quarter; and

At December 31, 2014, the Company was in compliance with all required covenants. 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 Majority Lenders (as defined in the Revolving Credit Agreement) may accelerate any amounts
outstanding.

F-23

PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
December 31, 2014

7.500% Senior Notes due 2022

On February 5, 2014, Parsley LLC and Finance Corp. issued $400 million of 7.500% senior notes due 2022 (the “Notes”).
Interest is payable on the Notes semi-annually in arrears on each February 15 and August 15, and commenced August 15, 2014. These
notes are guaranteed on a senior unsecured basis by all of our subsidiaries, other than Parsley LLC and Finance Corp. The issuance of
the Notes resulted in net proceeds, after discounts and offering expenses, of approximately $391.4 million, $198.5 million of which
was used repay all outstanding term debt, accrued interest and a prepayment penalty under a second lien credit facility (which was
terminated concurrently with such repayment) and $175.1 million of which was used to partially repay amounts outstanding, plus
accrued interest, under the Revolving Credit Agreement.

On April 14, 2014, Parsley LLC and Finance Corp. issued an additional $150 million of the Notes at 104% of par for gross

proceeds of $156 million. The issuance of these notes resulted in net proceeds of approximately $152.8 million, after deducting the
initial purchasers’ discount and estimated offering expenses, $145 million of which was used to repay borrowings under the Revolving
Credit Agreement.

At any time prior to February 15, 2017, the Company may redeem up to 35% of the Notes at a redemption price of 107.5% of

the principal amount, plus accrued and unpaid interest, if any, to the redemption date, with the proceeds of certain equity offerings so
long as the redemption occurs within 120 days of completing such equity offering and at least 65% of the aggregate principal amount
of the Notes remains outstanding after such redemption. Prior to February 15, 2017, the Company may redeem some or all of the
Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued
and unpaid interest to the redemption date. On and after February 15, 2017, the Company may redeem some or all of the Notes at
redemption prices (expressed as percentages of principal amount) equal to 105.625% for the twelve-month period beginning on
February 15, 2017, 103.750% for the twelve-month period beginning February 15, 2018, 101.875% for the twelve-month period
beginning on February 15, 2019 and 100.00% beginning on February 15, 2020, plus accrued and unpaid interest to the redemption
date.

The indenture governing the Notes restricts our ability and the ability of certain of our subsidiaries to, among other things:

(i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem,
repurchase or retire our 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 our restricted subsidiaries to us; (vii) consolidate,
merge or transfer all or substantially all of our assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted
subsidiaries. These covenants are subject to a number of important exceptions and qualifications. At December 31, 2014, the
Company was in compliance with all of these covenants. 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 Indenture) 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 will be reinstated.

Second Lien Agreement

On November 20, 2012, The Company entered into a second lien credit agreement (the “Second Lien Agreement”) providing

for term loans up to an aggregate principal amount of $75.0 million and an original maturity date of December 31, 2016. Obligations
under the Second Lien Agreement were secured by a second lien on substantially all of the Company’s oil and natural gas properties.

The Second Lien Agreement may be prepaid at any time. If prepaid prior to November 20, 2014, The Company will be

obligated to pay a prepayment premium equal to 7.5% of the principal amount being prepaid. As a condition to entering into the
Second Lien Agreement, The Company was required to enter into certain derivative instruments to hedge not less than 80% of the
anticipated projected production from proved, developed, producing oil and natural gas properties.

On June 10, 2013, the Company entered into a First Amendment and Waiver to the Second Lien Agreement (the “First
Amendment”). The First Amendment: (1) reduced the Consolidated Current Ratio, as at June 30, 2013, to be not less than 0.75:1.00,
and as at the last day of any quarter thereafter, to be not less than 1.00:1.00; (2) provided a waiver of the Lenders’ right to assert an
Event of Default with respect to the Consolidated Current Ratio covenant as of March 31, 2013; and (3) extended the deadline of
delivery of required financial statements from 120 days to 180 days after The Company’s year-end (each of the capitalized terms used
in the foregoing clauses (1) through (4) being as defined in the Second Lien Term Agreement).

On September 10, 2013, the Company entered into a Second Amendment and Waiver to the Second Lien Agreement (the
“Second Amendment”). The Second Amendment: (1) amended the definition of the Consolidated Current Ratio to allow for the
inclusion, in the numerator, of unused borrowing capacity under the Syndicated Credit Agreement; and (2) waived the Lenders’ right
to assert an Event of Default with respect to the Consolidated Current Ratio covenant as of June 30, 2013 (each of the capitalized
terms used in the foregoing clauses (1) through (4) being as defined in the Second Lien Agreement agreement).

F-24

PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
December 31, 2014

On October 21, 2013, the Company entered into an amended and restated second lien credit agreement (the “Amended Second

Lien Agreement”). The Amended Second Lien Agreement created two tranches of loan commitments, the Tranche A Commitment
totaling $75.0 million and the Tranche B Commitment, totaling $125.0 million. The maturity date remains December 31, 2016.

Tranche A borrowings bore interest at the combined rate equal to (i) the greater of 1.0%, and the three- month LIBO rate, plus
10.0%, paid in cash, plus (ii) 4.0% paid-in-kind by adding to the principal balance outstanding. Tranche B borrowings bore interest at
the greater of 1.0%, and the three-month LIBO rate, plus 11.0%, paid in cash.

The Second Lien Agreement was repaid in full in February 2014. The Company paid a prepayment penalty equal to 7.5% of the

principal amount being repaid.

Aircraft Term Loan

On April 2, 2013, the Company entered into a $2.8 million term loan (“Aircraft Term Loan”) in connection with the purchase of

a corporate aircraft. The Company repaid the Aircraft Term Loan in full in August 2014.

Capital Lease

During the year ended December 31, 2014, the Company entered into an aggregate of $2.3 million in capital lease agreements

payable (“Capital Leases”) in connection with the lease of vehicles for operations and field personnel. The Capital Leases bear interest
at annual rates ranging from 5.0% to 6.7% with varying maturities between March 2017 and August 2018. The Capital Leases require
monthly payments of $58,426 of principal and interest.

Principal maturities of long-term debt

Principal maturities of long-term debt outstanding, excluding the premium on the Notes, at December 31, 2014 are as follows

(in thousands):

2015 ................................................................................................................... $
2016 ...................................................................................................................
2017 ...................................................................................................................
2018 ...................................................................................................................
2019 ...................................................................................................................
Thereafter ..........................................................................................................
Total ............................................................................................................. $

650
688
705
120,026
—
550,000
672,069

Interest expense

The following amounts have been incurred and charged to interest expense for the year ended December 31, 2014, 2013, and

2012 (in thousands):

Cash payments for interest ................................... $
Change in interest accrual ....................................
Payment-in-kind interest ......................................
Amortization of deferred loan origination costs ..
Amortization of original issue discount ...............
Write-off of deferred loan origination costs .........
Amortization of bond premium ............................
Interest income .....................................................
Interest costs incurred ...............................
Less: capitalized interest ................................
Total interest expense ............................... $

For the Year Ended December 31,

2014

2013

2012

26,235 $
13,390
234
1,941
—
386
(574)
(316)
41,296
(2,689)
38,607 $

13,536 $
—
2,597
405
—
820
—
(235 )
17,123
(3,409 )
13,714 $

4,661
—
1,845
80
158
615
—
(75)
7,284
(999)
6,285

F-25

PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
December 31, 2014

NOTE 10. EQUITY

Preferred Stock

Pursuant to the Company’s 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, 2014.

Class A Common Stock

As a result of the Offering and the Corporate Reorganization, the Company has a total of 93.9 million shares of its Class A
Common Stock outstanding as of December 31, 2014, which includes 0.8 million shares of restricted stock and restricted stock units.
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 our outstanding shares of preferred
stock.

Class B Common Stock

As a result of the Corporate Reorganization, the Company has a total of 32.1 million shares of its Class B Common Stock

outstanding as of December 31, 2014. 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.

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 the Company’s 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 cash at the Company’s or Parsley LLC’s election
(the “Cash Option”). During the year ended December 31, 2014, no PE Unit Holders elected to exchange pursuant to their Exchange
Right.

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 its Class B
Common Stock and the treasury stock method to determine the potential dilutive effect of outstanding restricted stock and restricted
stock units. For the year ended December 31, 2014, Class B Common Stock was not recognized in dilutive earnings per share as the
effect would be antidilutive.

F-26

PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
December 31, 2014

The following table reflects the allocation of net income 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, 2014

Basic EPS (in thousands, except per share data)
Numerator:
Basic net income attributable to Parsley Energy Inc.
Stockholders .......................................................................................................................................... $
Denominator:
Basic weighted average shares outstanding .............................................................................................
Basic EPS attributable to Parsley Energy Inc. Stockholders .................................................................... $
Diluted EPS
Numerator:
Net income 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 attributable to Parsley Energy Inc.
Stockholders .......................................................................................................................................... $
Denominator:
Basic weighted average shares outstanding .............................................................................................
Effect of dilutive securities:

Class B Common Stock ......................................................................................................................
Restricted Stock and Restricted Stock Units ......................................................................................
Diluted weighted average shares outstanding ..........................................................................................
Diluted EPS attributable to Parsley Energy Inc.
Stockholders .......................................................................................................................................... $

23,429

55,136
0.42

23,429

—

23,429

55,136

—
103
55,239

0.42

LLC Interest Issuance

On June 11, 2013, Parsley LLC issued membership interests to NGP X US Holdings, L.P. and other investors for total

consideration of $73.5 million. These interest holders were designated as “Preferred Holders” and granted certain rights in the limited
liability agreement of Parsley LLC (the “Parsley LLC Agreement”). Included with these rights were (1) the right to receive a 9.5%
return on their invested capital prior to any distribution to any other unit holders (the “Preferred Return”) and (2) the right to require
Parsley LLC to redeem all, but not less than all, of each Preferred Holder’s interest in Parsley LLC after the seventh anniversary, but
before the eighth anniversary, of the date of their investment, or if Bryan Sheffield ceased to be Parsley LLC’s Chief Executive
Officer.

As the investment by the Preferred Holders was redeemable at their option, the Company reflected this investment outside of

permanent equity, under the heading “Mezzanine Equity—Redeemable LLC Units” in Parsley LLC’s Consolidated and Combined
Balance Sheet at December 31, 2013, in accordance with ASC Topic 480, “Distinguishing Liabilities from Equity”.

On May 29, 2014, in connection with the Corporate Reorganization, the Preferred Holders’ interests were converted to PE

Units. A portion of such PE Units were redeemed by Parsley LLC in exchange for the Preferred Return payment of approximately
$6.7 million and the remainder of such PE Units were contributed to the Company in exchange for an equal number of shares of
Class A Common Stock.

Incentive Units

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

F-27

PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
December 31, 2014

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 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.

In connection with the Corporate Reorganization, all of the incentive units were immediately vested and converted into PE Units

and, subsequently, a portion of such PE Units were exchanged on a one for one basis for shares of Class A Common Stock. As a
result, Parsley LLC was required to recognize, as a non-cash charge, the unrecognized cumulative incentive unit compensation
expense of approximately $50.6 million on May 29, 2014, in addition to the $0.5 million recognized during the period from January 1,
2014 through May 29, 2014.

Restricted Stock and Restricted Stock Unit Awards

Restricted stock awards are awards of Class A Common Stock that 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. Restricted stock unit awards are awards of restricted stock units that 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
restriction. Each restricted stock unit represents the right to receive one share of Class A Common Stock. The fair value of such
restricted stock and restricted stock units was determined using the weighted average closing price on the grant date and compensation
expense, net of estimated forfeitures, is recorded over the applicable vesting periods.

The following table summarized the Company’s restricted stock and restricted stock unit award activity for the year ended

December 31, 2014:

Number of Shares
(in thousands)

Weighted - Average Grant Date
Fair Value

Outstanding at January 1, 2014 ............
Restricted Stock Granted ................
Restricted Stock Units Granted ......
Vested .............................................
Forfeited .........................................
Outstanding at December 31, 2014 ......

$
—
$
770
$
24
—
$
(37) $
$
757

—
18.54
18.50
—
18.50
18.54

Stock based compensation expense related to restricted stock and restricted stock units was $2.2 million for the year ended

December 31, 2014, respectively. There was approximately $11.8 million of unamortized compensation expense relating to
outstanding restricted stock and restricted stock units at December 31, 2014.

Noncontrolling Interest

As a result of the Corporate Reorganization and the Offering, the Company acquired 74.3% of Parsley LLC, with the Existing

Owners retaining ownership of 25.7% of Parsley LLC. As a result, the Company has consolidated the financial position and results of
operations of Parsley LLC and reflected that portion retained by the Existing Owners as a noncontrolling interest.

Net income attributable to noncontrolling interest for the year ended December 31, 2014 of approximately $33.3 million

represents the net income of Parsley LLC attributable to the Existing Owners’ retained interest since May 29, 2014.

NOTE 11.

INCOME TAXES

The Company accounts for income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized

F-28

PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
December 31, 2014

Parsley LLC, the Company’s accounting predecessor, is a limited liability company that is not subject to U.S. federal income
tax. As part of the Corporate Reorganization, certain of the Existing Owners exchanged all or part of their PE Units for shares of the
Company’s common stock, as discussed in Note 1 – Organization and Nature of Operations. On the date of the Corporate
Reorganization, a corresponding “first day” tax charge of approximately $95.5 million was recorded to establish a net deferred tax
liability for differences between the tax and book basis of Parsley LLC’s assets and liabilities. In addition, the Company recorded a
long term liability of $56.3 million to establish the TRA (as defined herein) and a corresponding deferred tax asset of $66.3 million.
The offset of the deferred tax liability, TRA, and deferred tax asset was recorded to additional paid-in capital. Subsequently, in 2014,
as part of the tax return preparation process, adjustments were made to reduce the TRA liability by $5.6 million and to reduce the
deferred tax asset by $6.7 million with the offset recorded to additional paid in capital. As of December 31, 2014, the liability
associated with the TRA was $50.7 million and the corresponding deferred tax asset was $59.6 million.

The components of the income tax provision were as follows for the periods indicated (in thousands):

Federal:
Current .................................................................................. $
Deferred ................................................................................
Total federal ..........................................................................
State, net of federal benefit:
Deferred ................................................................................
Total state .............................................................................
Income tax provision ............................................................ $

Year Ended December 31,

2014

2013

2012

— $
31,968
31,968

4,500
4,500
36,468 $

— $
—
—

1,906
1,906
1,906 $

—
—
—

554
554
554

The following table reconciles the income tax provision with income tax expense at the federal statutory rate for the periods

indicated (in thousands):

Income (loss) before income taxes ....................................... $
Plus: net loss prior to corporate reorganization ....................
Less: net income attributable to noncontrolling
interest ...............................................................................
Income (loss) before income taxes and noncontrolling
interest subsequent to corporate reorganization .................
Income taxes at the federal statutory rate .............................
State income taxes, net of federal benefit .............................
State income taxes, prior to corporate reorganization...........
Provision to return adjustment ..............................................
Permanent and other .............................................................
Income tax provision ............................................................

Year Ended December 31,

2014

2013

2012

93,190 $
37,378

29,416 $
—

13,453
—

(33,293)

—

97,275
34,046
967
1,246
170
39
36,468

29,416
—
—
1,906
—
—
1,906

13,453
—
—
554
—
—
554

The Company has net operating loss carryforwards (“NOLs”) for United States income tax purposes that have been generated
from our operations. Our NOLs are scheduled to expire if not utilized between 2033 and 2034. NOLs available for utilization as of
December 31, 2014 were approximately $144 million.

F-29

PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
December 31, 2014

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):

Current:
Liabilities:
Derivative fair value gain .......................................................................
Total current deferred tax liability ..........................................................
Net current deferred tax liability ..........................................................

Noncurrent:
Assets:
Asset retirement obligations ...................................................................
Materials and supplies ............................................................................
Deferred stock based compensation .......................................................
Net operating loss carryforward .............................................................
Total noncurrent deferred tax assets .......................................................
Liabilities:
Book basis of oil and natural gas properties
in excess of tax basis ...........................................................................
Derivative fair value gain .......................................................................
Earnings in investment in subsidiary ......................................................
Total noncurrent deferred tax liabilities ..................................................
Net noncurrent deferred tax liability ....................................................

December 31,

2014

2013

(12,601 )
(12,601 )
(12,601 )

4,379
431
644
50,425
55,879

(108,825 )
(8,874 )
(514 )
(118,213 )
(62,334 )

—
—
—

—
—
—
—
—

(2,572)
—
—
(2,572)
(2,572)

NOTE 12. RELATED PARTY TRANSACTIONS

Well Operations

During the years ended December 31, 2014, 2013, and 2012, several of the Company’s directors, officers, 5% stockholders,
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, 2014, 2013, and 2012, totaled $11.3 million, $14.4 million,
and $10.8 million, respectively. The revenues disbursed to the Related Party Working Interest Owners for the year ended December
31, 2014 include $2.1 million of revenues for the five months ended May 29, 2014 for entities no longer considered a related party due
to their direct relationship with Diamond K (defined herein.)

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.

Acquisitions

On October 29, 2012, The Company acquired, from Diamond K Production, LLC, an entity owned by Diamond K (defined

herein), additional working interests in wells it operates for an aggregate cash consideration of $8.2 million. The Company reflected
the total consideration paid as part of its cost subject to depletion within its oil and gas properties.

During the years ended December 31, 2013, The Company acquired, from certain of its directors and officers, additional
working interests in wells it operates through a number of separate, individually negotiated transactions for an aggregate total of and
$19.4 million, respectively.

Tex-Isle Supply, Inc. Purchases

The Company makes purchases of equipment used in its drilling operations from Tex-Isle Supply, Inc. (“Tex-Isle”). Tex-Isle is
controlled by a party who is also the general partner of Diamond K Interests, LP (“Diamond K”), a former member of Parsley LLC. In
connection with the Offering, Diamond K exchanged its membership interest for shares of Class A Common Stock. As of May 29,

F-30

PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
December 31, 2014

2014, Diamond K is no longer considered a related party as their ownership interest fell below 5% due to this transaction, which
results in Tex-Isle no longer being considered a related party. During the five months ended May 29, 2014, the Company made
purchases of equipment used in its drilling operations totaling $29.3 million, from Tex-Isle. During the years ended December 31,
2013 and 2012, the Company made purchases of equipment used in its drilling operations totaling $68.1 million and $31.1 million
from Tex-Isle.

Spraberry Production Services LLC

As defined in Note 8—Equity Investment, as of December 31, 2014, the Company owns a 42.5% interest in SPS. During the

years ended December 31, 2014, 2013 and 2012, the Company incurred charges totaling $5.1 million, $3.3 million, and $2.0 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 year ended December 31, 2014, the Company incurred charges totaling $0.7
million, for services performed by Lone Star for the Company’s well operations and drilling activities. There were no such charges
incurred during 2013 and 2012.

Davis, Gerald, and Cremer

During the years ended December 31, 2014, 2013, and 2012, we incurred charges totaling $0.2 million, $0.3 million, and

$0.1 million, respectively, for legal services from Davis, Gerald & Cremer, PC, of which our director David H. Smith is a shareholder.

Exchange Right

In accordance with the terms of the amended Parsley LLC Agreement, the PE Unit Holders generally have the right to exchange

their PE Units (and a corresponding number of shares of the Company’s Class B Common Stock), for shares of the Company’s
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
cash (pursuant to the Cash Option). As a PE Unit Holder exchanges its PE Units, the Company’s interest in Parsley LLC will be
correspondingly increased.

Tax Receivable Agreement

In connection with the Offering, on May 29, 2014, the Company entered into a Tax Receivable Agreement (the “TRA”) with
Parsley LLC, and certain holders of PE Units prior to the Offering (each such person a “TRA Holder”), including certain executive
officers. This agreement 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 Offering as a result of (i) any tax basis increases resulting from the contribution in connection with the Offering 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 pursuant to the
Exchange Right (or resulting from an exchange of PE Units for cash pursuant to the Cash Option) and (ii) 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 commences 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.

NOTE 13. COMMITMENTS AND CONTINGENCIES

Legal Matters

In the ordinary course of business, the Company may at times be subject to claims and legal actions. Management believes it is
remote that the impact of such matters will have a material adverse effect on The Company’s financial position, results of operations
or cash flows.

F-31

PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
December 31, 2014

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, 2014 and 2013, the Company had no environmental matters requiring specific disclosure or requiring the recognition of
a liability.

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, 2014:

(in thousands)
Drilling commitments ..................

2015

2016

39,466

27,911

2017

10,039

2018

2019

—

Thereafter
—

—

Total

77,416

Payments Due by Period

Operating Leases

The estimated future minimum lease payments under long term operating lease agreements as of December 31, 2014 was as

follows (in thousands):

Office Leases ................................ $
Vehicle Operating Leases .............
Office Equipment ..........................

For the years ended December 31,

2015

2016

2017

2018

2019

Thereafter

Total

2,827 $
116
86
3,029

2,831 $
124
70
3,025

(in thousands)

4,452 $
—
29
4,481

4,865 $
—
1
4,866

4,977 $
—
—
4,977

21,005 $
—
—
21,005

40,957
240
186
41,383

Rent expense for the years ended December 31, 2014, 2013 and 2012 was $1.5 million, $0.7 million and $0.3 million,

respectively.

F-32

PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
December 31, 2014

NOTE 14. 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 into the following fair
value input hierarchy:

Level 1:

Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted
assets or liabilities. The Company considers active markets to be those in which transactions for the assets or
liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2:

Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for
substantially the full term of the asset or liability. This category includes those derivative instruments that the
Company values using observable market data. Substantially all of these inputs are observable in the marketplace
throughout the full term of the derivative instrument, can be derived from observable data, or supported by
observable levels at which transactions are executed in the marketplace. Level 2 instruments primarily include
non-exchange traded derivatives such as over-the-counter commodity price swaps, basis swaps, collars and floors,
investments and interest rate swaps. The Company’s valuation models are primarily industry-standard models that
consider various inputs including: (i) quoted forward prices for commodities, (ii) time value and (iii) current
market and contractual prices for the underlying instruments, as well as other relevant economic measures.

Level 3:

Measured based on prices or valuation models that require inputs that are both significant to the fair value
measurement and less observable from objective sources (supported by little or no market activity). The
Company’s valuation models are primarily industry-standard models that consider various inputs including:
(i) quoted forward prices for commodities, (ii) time value, (iii) volatility factors and (iv) current market and
contractual prices for the underlying instruments, as well as other relevant economic measures.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

The book value of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate their

fair value due to the short-term nature of these instruments. The book value of the Company’s Revolving Credit Agreement
approximates its fair value as the interest rate is variable.

The estimated fair value of the Company’s $550 million of Notes at December 31, 2014, was approximately $521.1 million. The

fair value of the Notes is classified as a level 1 measurement as it is calculated based on market quotes.

Impairments of long-lived assets – The Company 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, for
instance when there are declines in commodity prices or well performance. An impairment loss is indicated if the sum of the expected
undiscounted future net cash flows 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 depletion base or by individual well for those wells not constituting part of a depletion
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 of the properties would be recognized at that time.

The Company calculates the estimated 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
further 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 appropriate risk-adjusted probable and possible 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 accompanying
Consolidated and Combined Balance Sheets and in Note 4—Derivative Financial Instruments. The company adjusts the valuations

F-33

PARSLEY ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
December 31, 2014

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):

Commodity derivative contracts

Assets:

Short-term derivative instruments ................... $
Long-term derivative instruments ...................
Total derivative instrument - asset ............. $

Liabilities:

Short-term derivative instruments ................... $
Long-term derivative instruments ...................
Total derivative instruments - liability .......
Net commodity derivative asset ............ $

Commodity derivative contracts

Assets:

Short-term derivative instruments ................... $
Long-term derivative instruments ...................
Total derivative instrument - asset ............. $

Liabilities:

Level 1

Level 2

Level 3

Total

December 31, 2014

— $
—
— $

— $
—
—
— $

80,911 $
70,805
151,716 $

(29,326) $
(31,275)
(60,601)
91,115 $

— $
—
— $

— $
—
—
— $

80,911
70,805
151,716

(29,326)
(31,275)
(60,601)
91,115

Level 1

Level 2

Level 3

Total

December 31, 2013

— $
—
— $

— $
—
—
— $

6,999 $
13,850
20,849 $

(4,435) $
(2,208)
(6,643)
14,206 $

— $
—
— $

— $
—
—
— $

6,999
13,850
20,849

(4,435)
(2,208)
(6,643)
14,206

There were no transfers in to or out of level 2 during the years ended December 31, 2014 or 2013.

NOTE 15. 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.

Private Placement of Common Stock

On February 5, 2014, the Company entered into an agreement to sell 14,885,797 shares of Class A Common Stock in a private

placement at a price of $15.50 per share to selected institutional investors. The Private Placement closed on February 11, 2015 and
resulted in approximately $231 million of gross proceeds and approximately $224 million of net proceeds (after deducting placement
agent commissions and the Company’s estimated expenses. The Company used the net proceeds from the private placement to repay
borrowings under its Revolving Credit Agreement and for general corporate purposes.

F-34

SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (Unaudited)

The Company’s oil and natural gas reserves are attributable solely to properties within the United States.

Capitalized Costs

Oil and natural gas properties:

December 31,

2014

2013

(in thousands)

Proved properties .............................................................. $
Unproved properties ..........................................................
Total oil and natural gas properties ......................................
Less accumulated depreciation, depletion and amortization .....
Net oil and natural gas properties capitalized ...................... $

1,248,376 $
624,240
1,872,616
(128,044)
1,744,572 $

546,072
68,243
614,315
(34,957 )
579,358

Costs Incurred for Oil and Natural Gas Producing Activities

Acquisition costs:

2014

Year Ended December 31,
2013

2012

(in thousands)

Proved properties ............................................................ $
Unproved properties .......................................................
Development costs .............................................................
Total ................................................................................... $

233,899 $
528,301
488,673
1,250,873 $

142,695 $
65,686
268,400
476,781 $

17,932
14,022
71,945
103,899

Reserve Quantity Information

The following information represents estimates of the Company’s proved reserves as of December 31, 2014, 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, 2014 was based on an unweighted average 12-month
average West Texas Intermediate posted price per Bbl for oil and NGLs, and a Henry Hub spot natural gas price per Mcf for natural
gas, as set forth in the following table:

Oil (per Bbl) ...................................................................... $
Natural gas liquids (per Bbl).............................................. $
Natural gas (per Mcf) ........................................................ $

85.99 $
35.27 $
4.28 $

92.53 $
36.20 $
3.46 $

89.71
35.02
2.48

2014

Year Ended December 31,
2013

2012

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, particularly as it develops its significant acreage in the
Permian Basin of West Texas. 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 all located in the United States, primarily in the Permian Basin of West

Texas. All of the estimates of the proved reserves at December 31, 2012 were estimated by the Company’s in-house petroleum
engineers, taking into consideration the information and assumptions contained in the December 31, 2013 report prepared by
Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers. 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.

F-35

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 provides a roll forward of the total proved reserves for the years ended December 31, 2014, 2013, and 2012,

as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year:

Crude Oil

(Bbls)

Year Ended December 31, 2014
Natural Gas

Liquids

(Bbls)

(Mcf)

Boe

(in thousands)

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 .................................................................

29,507
18,776
(7,832)
10,006
—
(2,840)
47,617

12,357
8,157
(528)
3,906
—
(1,225)
22,667

77,818
41,348
(6,714 )
18,244
—
(7,051 )
123,645

54,834
33,824
(9,480)
16,953
—
(5,240)
90,891

Proved Developed Reserves:
Beginning of the year .......................................................
End of the year .................................................................

Proved Undeveloped Reserves:
Beginning of the year .......................................................
End of the year .................................................................

13,560
23,547

4,762
11,491

31,301
65,484

23,539
45,952

15,947
24,070

7,595
11,175

46,517
58,161

31,295
44,939

Crude Oil

(Bbls)

Year Ended December 31, 2013
Natural Gas

Liquids

(Bbls)

(Mcf)

Boe

(in thousands)

12,987
10,378
(2,029)
9,223
(3)
(1,049)
29,507

4,732
4,840
(796)
3,695
(1)
(113)
12,357

30,214
29,489
(1,813 )
23,937
(7 )
(4,002 )
77,818

22,755
20,132
(3,127)
16,908
(5)
(1,829)
54,834

Proved Developed Reserves:
Beginning of the year .......................................................
End of the year .................................................................

Proved Undeveloped Reserves:
Beginning of the year .......................................................
End of the year .................................................................

5,834
13,560

1,906
4,762

12,186
31,301

9,771
23,539

7,153
15,947

2,826
7,595

18,028
46,517

12,984
31,295

F-36

Proved Developed and Undeveloped Reserves:
Beginning of the year .......................................................
Extensions and discoveries ...............................................
Revisions of previous estimates .......................................
Purchases 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 .................................................................

Crude Oil

(Bbls)

Year Ended December 31, 2012
Natural Gas

Liquids

(Bbls)

(Mcf)

Boe

(in thousands)

8,519
4,047
(39)
816
(356)
12,987

2,070
5,834

3,127
1,369
(56)
294
(2)
4,732

623
1,906

20,689
8,898
274
1,833
(1,480 )
30,214

15,094
6,899
(49)
1,416
(605)
22,755

4,230
12,186

3,398
9,771

6,449
7,153

2,504
2,826

16,459
18,028

11,696
12,984

The tables above include changes in estimated quantities of oil and natural gas reserves shown in Bbl equivalents (“Boe”) at a

rate of six Mcf per one Bbls.

Extensions and discoveries of 33,824 MBoe, 20,132 MBoe and 6,899 MBoe during the years ended December 31, 2014, 2013
and 2012, result primarily from the drilling of new wells during each year and from new proved undeveloped locations added during
each year.

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, 2014, 2013, and 2012 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%.

The standardized measure of discounted future net cash flows relating to proved oil, NGLs, and natural gas 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 ....................
Standardized measure of discounted future net cash flows .... $

2014

5,423,551 $
(642,746)
(1,640,422)
(903,354)
2,237,029
(1,281,400)
955,629 $

December 31,
2013
(in thousands)

3,446,766 $
(515,247 )
(1,097,734 )
(24,127 )
1,809,658
(1,088,878 )
720,780 $

2012

1,405,580
(186,996)
(368,099)
(9,839)
840,646
(544,598)
296,048

(1) Future net cash flows do not include the effects of U.S. federal income taxes on future results because the Company was a

limited liability company not subject to entity-level federal income taxation as of December 31, 2013, and 2012. Accordingly,
no provision for federal corporate income taxes has been provided because taxable income was passed through to the
Company’s equity holders. However, the Company’s operations located in Texas are subject to an entity-level tax, the Texas

F-37

Margin Tax, at a statutory rate of up to 1.0% of income that is apportioned to Texas. Following the Corporate Reorganization,
the Company will be a subchapter C corporation subject to U.S. federal and state income taxes. If the Company had been subject
to entity-level income taxation, the unaudited pro forma future income tax expense at December 31, 2013 and 2012 would have
been $562.5 million and $289.5 million, respectively. The unaudited standardized measure at December 31, 2013, 2012 would
have been $497.7 million and $193.6 million, respectively.

In the foregoing determination of future cash inflows, sales prices used for oil, NGLs, and natural gas for December 31, 2014,

2013, and 2012, 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, NGLs, and natural gas 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 ........................................................................................ $

2014

Year Ended December 31,

2013

(in thousands)

2012

720,780 $
(244,745)
279,725
—
537,241
96,881
(74,080)
(9,517)
(126,395)
73,107
(348,501)
51,133

296,048 $
(97,365 )
227,937
(122 )
204,135
57,158
11,463
2,793
(41,242 )
30,010
(6,240 )
36,205

181,714
(30,621)
20,222
—
82,517
36,423
(21,592)
1,627
(625)
18,443
(1,336)
9,276

955,629 $

720,780 $

296,048

F-38

EXHIBIT INDEX

Exhibit No.
2.1

2.2

2.3

2.4

2.5

3.1

3.2

4.1

4.2

4.3

10.1

10.2

10.3

Amended and Restated Bylaws of Parsley Energy, Inc. (incorporated by reference to Exhibit 3.2 to the Company’s
Current Report on Form 8-K, File No. 001-36463, filed with the SEC on June 4, 2014).

Exhibit No.

10.4

10.5*

10.6

10.7

10.8†

10.9†

10.10†

10.11†

Description

10.12†*

Employment Agreement, dated as of December 8, 2014, by and between Parsley Energy Operations, LLC and
Thomas Layman.

10.13

10.14

10.15

10.16

10.17†

Exhibit No.

10.18†

10.19†

10.20†

10.21†

10.22†

10.23†

10.24†

10.25†

10.26†

10.27†

10.28†

10.29†

Description

10.30†*

Amended and Restated Parsley Energy, Inc. 2014 Long Term Incentive Plan.

10.31†

10.32†

10.33†

10.34†*

Form of Restricted Stock Unit Agreement.

Exhibit No.

Description

10.35†*

Form of Notice of Grant of Restricted Stock Units (Time-Based).

10.36†*

Form of Notice of Grant of Restricted Stock Units (Performance-Based).

10.37

10.38

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. Reserve Report.

101.INS*

XBRL Instance Document.

101.SCH*

XBRL Taxonomy Extension Schema Document.

101.CAL*

XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF*

XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB*

XBRL Taxonomy Extension Labels Linkbase Document.

101.PRE*

XBRL Taxonomy Extension Presentation Linkbase Document.

† Management contract or compensatory plan or agreement
*

CORPORATE INFORMATION

MANAGEMENT

BOARD OF DIRECTORS

CORPORATE OFFICES

BRYAN SHEFFIELD

President, Chief Executive Officer
and Chairman of the Board

RYAN DALTON
Vice President, Chief Financial Officer

MAT T GALL AGHER
Vice President, Chief Operating Officer

COLIN ROBERTS
Vice President, General Counsel and Secretary

PAUL TRE ADWELL
Vice President, Operations

MIKE HINSON
Vice President, Land

THOMA S L AYMAN
Vice President, Geoscience

BRYAN SHEFFIELD
Chairman of the Board

A.R. AL AMEDDINE (2)
Director

WILLIAM BROWNING (1)
Director

CHRIS CARTER (2)(3)
Director

DR. HEMANG DESAI (1)(2)
Director

R ANDOLPH NE WCOMER, Jr. (1)(3)
Director

DAVID SMITH (3)
Director

1) Member of the Audit Committee
2) Member of the Compensation Committee
3) Member of the Nominating and Governance Committee

COMMON STOCK
The company’s Class A common stock is
traded on the New York Stock Exchange
under the symbol PE.

INDEPENDENT AUDITOR
KPMG LLP
717 N. Harwood Street, Suite 3100
Dallas, TX 7520

INDEPENDENT PE TROLEUM
ENGINEERS
Netherland, Sewell & Associates, Inc.
2100 Ross Avenue, Suite 2200
Dallas, TX 75201

INVESTOR AND MEDIA REL ATIONS
Shareholders, brokers, securities analysts,
portfolio managers or financial news
media seeking information about the
Company may email us at:
ir@parsleyenergy.com
or call
Brad Smith, CFA
Director, Investor Relations
Parsley Energy, Inc.
512-505-5199
or
Lisa Elliot or Jack Lascar
Dennard-Lascar Associates
713-529-6600

AUSTIN OFFICE
303 Colorado Street
Suite 3000
Austin, TX 78701
737-704-2300

MIDL AND OFFICE
500 W. Texas Avenue
Suite 200
Midland, TX 79701
432-818-2100

TR ANSFER AGENT
For shareholder questions regarding
transfer of shares, lost stock certificates,
duplicate mailings, change of address or
other similar matters, please contact our
Transfer Agent:
American Stock Transfer & Trust Company
6201 15th Avenue
Brooklyn, NY 11219
800-937-5449

ANNUAL MEETING
The Annual Meeting of Stockholders will be
held Friday, June 19, 2015, at 8:00 a.m. CT
JW Marriott Austin
110 E. 2nd Street
Austin, TX 78701

VISIT OUR WEBSITE
www.parsleyenergy.com

PA R S L E Y E N E R G Y. C O M