Parsley Energy Inc
Annual Report 2015

Plain-text annual report

2015 ANNUAL REPORT A STEP AHEAD PURE PERMIAN POTENTIAL FROM SOME OF THE BEST ROCK IN THE COUNTRY  2 0 1 5 A N N UA L R E P O R T // PAG E 0 1 FINANCIAL & OPERATIONAL HIGHLIGHTS PRODUCTION GROWTH (MBOE per day) CRUDE OIL PROVED RESERVES (MMBOE) +55% Y/Y +36% Y/Y 22.0 14.2 91 CRUDE OIL 124 FY 2014 FY 2015 FY 2014 FY 2015 HORIZONTAL INVENTORY GROWTH (gross drilling locations) +36% Y/Y GROSS HORIZONTAL COMPLETIONS 2,479 1,821 +105% Y/Y 41 20 FY 2014 FY 2015 FY 2014 FY 2015 SUBSTANTIAL OIL HEDGE POSITION 20.2 18.8 $38.24 $41.32 23.5 21.8 20.5 20.2 PUT SPREADS (MBBLs per day)(1) PUT PRICE ($ per barrel) $53.25 $53.26 $45.88 $45.88 $55.00 $55.00 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 2.4 3Q17 2.4 4Q17 (1) When NYMEX price is above put price, Parsley receives the NYMEX price. When NYMEX price is between the put price and the short put price, Parsley receives the put price. When NYMEX price is below the short put price, Parsley receives the NYMEX price plus the difference between the short put price and the put price. PAG E 0 2 // PA R S L E Y E N E R GY FELLOW SHAREHOLDERS 2015 was a year of major strides that placed Parsley Energy a step ahead in our quest to deliver compelling value for our shareholders. Despite a challenging commodity price backdrop, it was a year of execution, of growth, of unlocking new sources of value, and of positioning for an exciting future. Industry-leading performance during 2015 reinforced our belief that Parsley’s Permian Basin assets represent some of the best acreage in North America and confirmed that we can deliver consistently strong results across this acreage. Early in 2015 we raised our internal estimate or “type curve” for Wolfcamp A and B wells by 45% to an estimated ultimate recovery of 1 million BOE for a well with a 7,000-foot lateral. Parsley’s Wolfcamp wells with 180 and 360 days of production history are outperforming the revised type curve by 4% and 11%, respectively, representing basin-leading production rates. Compared to other basins in North America, horizontal development in the Permian Basin is still in its infancy, and we believe there is ample opportunity for ongoing productivity enhancement as we optimize completion techniques, fine tune target intervals, and test new strategies for reservoir stimulation. Indeed, we continue to establish new company records each quarter. For example, a recently completed Wolfcamp B well in Reagan County produced more than 43,000 barrels of oil during its peak 30-day period, setting a company record for first-month oil production. With a firmly established record of strong well results in north Upton County, we were very encouraged by the performance of our Wolfcamp wells in adjacent Reagan County as we expanded the aerial scope of our drilling program in 2015. Initial production rates from our wells in northwest Reagan County, where our recent bolt-on activity has been concentrated, approach those generated by our wells in north Upton County, with lower drilling costs. So the economic profile for our Wolfcamp wells is robust across our entire core area. Even as we achieve enhanced productivity, we continue to make significant strides in operational efficiency and cost reduction. From the fourth quarter of 2014 to the fourth quarter of 2015, we reduced drilling and completion costs by 31%, driven in large part by sustainable efficiency gains, including a 35% reduction in average drilling time. Our recent transition to pad drilling has amplified the downtrend in drilling and completion costs. We set company records for drill time and drill cost on our first pad project, and on a recently completed two-well pad in northwest Reagan County, we set a Permian Basin record for the fastest lateral drilled, covering 7,100 feet in 41 hours. HORIZONTAL DRILLING & COMPLETION COST PER WELL* ($ in millions) –31% Y/Y $8.0 $5.5 *Normalized for 7,000-foot lateral 4Q14 4Q15 INDUSTRY-LEADING PERFORMANCE DURING 2015 REINFORCED OUR BELIEF THAT PARSLEY’S PERMIAN BASIN ASSETS REPRESENT SOME OF THE BEST ACREAGE IN NORTH AMERICA AND CONFIRMED THAT WE CAN DELIVER CONSISTENTLY STRONG RESULTS ACROSS THIS ACREAGE. The combination of robust well productivity and compressed cycle times has yielded top-tier production growth. Full-year 2015 production increased 55% over full-year 2014 production, to 22.0 MBOE per day, with growth through drilling accounting for substantially all of the increase. Growth in oil volumes was even more pronounced, up 69% in 2015 relative to 2014. As a company that has transitioned from vertical to horizontal drilling, our oil volumes are poised to grow significantly faster than our overall volumes, positioning us for higher revenue per BOE, lower unit costs, and expanding margins as our horizontal production constitutes a larger percentage of our overall production. So for Parsley, growth and returns go hand-in-hand. Parsley Energy also posted strong reserve growth in 2015 despite substantial macro headwinds, increasing proved reserves by 36% year-over-year with minimal contribution from acquisitions. A 49% decline in the projected commodity prices used by the SEC for reserve estimation limited reserve growth to a considerable extent, making our additions even more impressive. In addition to our enviable growth in production and reserves, we also expanded our resource base in 2015. The history of Parsley Energy is filled with examples of creative transactions through which we have built a premier acreage position, and we pursued a variety of such transactions in 2015. Through acquisitions, divestitures, and trades, we added close to 400 net locations and extended the lateral length of 70 future horizontal wells for $178 million. These transactions increased our horizontal inventory by 36% and increased the percentage of that inventory in our Core area from 67% to 77%. PERMIAN BASIN ACREAGE  2 0 1 5 A N N UA L R E P O R T // PAG E 0 3 35% REDUCTION IN AVERAGE DRILLING TIME VERSUS 2014 FINANCIAL LIQUIDITY ($ in millions) 48% Y/Y $770 $519 FY 2014 FY 2015 Quarter-by-quarter we are strategically filling in our drilling corridor, building a footprint that can support a high level of activity and rapid production growth over an extended period. Counting only our most proven and prolific target formations—the Wolfcamp A and B horizons—we have almost 1,000 horizontal drilling locations in the Midland Basin, providing plenty of running room to develop our world-class asset portfolio at a brisk pace. We believe that maintaining an industry-leading growth rate will enhance full-cycle value creation, and we have deliberately positioned the company to continue moving forward at a time when many companies are slowing down. Our hedging program and capital markets activity have been calibrated to allow us to drill through a downturn of the magnitude and duration we are experiencing without stretching our leverage and liquidity. In other words, we have positioned Parsley Energy to stay a step ahead. In 2015 we were a step ahead when we were among the first to stack rigs after oil prices collapsed, we were a step ahead when we kept layering on hedges, and we were a step ahead when we raised equity in relatively favorable market contexts. Now, we hope to be a step ahead when commodity prices rebound, and our outlook for 2016 reflects this objective. As of the time of writing, the midpoint of our production guidance range implies year-over-year growth of more than 40%. We expect oil growth in the neighborhood of 60%—on top of almost 70% growth in oil volumes in 2015—as oil as a percent of total production increases from 60% in 2015 to 65–70% this year. And we expect to generate production growth of this magnitude while holding capital expenditures roughly flat relative to 2015 spending. We have deliberately managed our leverage and liquidity, and following an increase in our borrowing base from $500 million to $575 million in the Fall, we entered 2016 with a strong balance sheet to support our leading growth profile. As of December 31, 2015, pro forma for an acquisition that closed in January 2016, the company had $195 million of cash on hand, $770 million of liquidity, and a net debt to annualized adjusted EBITDAX1 ratio of 1.5x. In addition, based on the midpoint of Parsley’s 2016 production guidance range, the company’s hedge position covers all anticipated oil volumes to be produced during 2016. A substantial hedge position through the first half of 2017 provides additional visibility and ongoing cash flow support. (1) EBITDAX—earnings before interest, taxes, depreciation and amortization, and exploration expense—is a non-GAAP measure. Please see a reconciliation to GAAP results in the accompanying 10-K. PAG E 0 4 // PA R S L E Y E N E R GY SOUTHERN DELAWARE BASIN Looking ahead, given our strong financial profile, robust growth expectations, and an array of exciting delineation prospects, we have abundant value yet to unlock. For example, even as our Midland Basin Wolfcamp development program continues to shine, years of hard work and investment are starting to pay off in the Southern Delaware Basin. We mapped and acquired our Trees Ranch prospect in 2013, and we spent much of 2014 and 2015 exploring and understanding the asset. So far, the results from our first horizontal well in the Southern Delaware could not be more favorable. In fact, this well tied Parsley’s second-highest scaled 30-day initial production rate at 252 BOE per day per thousand completed feet. We are thrilled with this result and also pleased with robust productivity from the non-operated well we participated in at the edge of our acreage. Given these results and the exploratory work we have done, we think the value of our Southern Delaware acreage is substantial. It is a large, contiguous acreage block that is ideally suited for long-lateral development. We believe that we are just scratching the surface of a new core area for Parsley, and we are sufficiently encouraged by results to date that we plan to allocate additional capital to the Southern Delaware in 2016, with several wells planned for the second half of the year. Ongoing appraisal and development of our Southern Delaware acreage is an exciting prospect, and we eagerly anticipate a compelling set of upcoming delineation activities in the Midland Basin, as well. These projects include testing multiple target intervals within the Wolfcamp B horizon, appraising the Wolfcamp C formation, and refining our Lower Spraberry well design. Together, these projects promise to supplement the tremendous resource potential associated with Parsley’s premier asset base. We expect 2016 financial results to be enhanced by substantial progress on unit costs. From the first quarter of 2015 to the fourth quarter of 2015, we reduced lease operating expense (LOE) by more than $4.00 per BOE, reflecting the benefit of strategic infrastructure investment. Together, the midpoints of our LOE and general and administrative expense guidance ranges are almost $2.50 per BOE lower than our 2015 averages, representing a material boost to operating margins. We are gratified that investors have recognized and rewarded our accomplishments and ongoing value creation potential. Against a 30% decline in oil prices, Parsley Energy outperformed all but three U.S.-listed exploration and production stocks in 2015, registering 16% share price appreciation versus an average share price decline of 51% for all E&P stocks. LOOKING AHEAD, GIVEN OUR STRONG FINANCIAL PROFILE, ROBUST GROWTH EXPECTATIONS, AND AN ARRAY OF EXCITING DELINEATION PROSPECTS, WE HAVE ABUNDANT VALUE YET TO UNLOCK. As commodity price volatility persists, Parsley Energy is fortunate to be situated in the choicest portions of the Permian Basin, one of the premier oil basins in the world. At a constant $50 oil price, our average Wolfcamp well generates a return of nearly 60%, with a net present value of almost $6 million. And given our position on the early end of our corporate lifecycle, the trajectory of our cost and efficiency gains is steep, pushing our returns upward even if commodity prices remain depressed. We have a durable inventory of premier horizontal drilling locations, now supplemented by high-quality drilling inventory in the Southern Delaware Basin. Our substantial hedge position, low leverage, and ample liquidity mean that ongoing growth should not compromise our financial strength. And our consistent drilling program maintains the operational momentum we established in 2015, keeping us a step ahead as we move through 2016. For these reasons and with the resources of a tremendously capable and committed group of employees, we look forward to building on our track record of differentiated shareholder value creation. B RYA N S H E F F I E L D Chairman, President, and CEO April 1, 2016 2015 ANNUAL REPORT FORM 10-K UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) (cid:95) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 (cid:133) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2015 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: Title of each class Class A Common Stock, $0.01 par value Securities registered pursuant to Section 12(g) of the Act: None 46-4314192 (I.R.S. Employer Identification No.) 78701 (Zip Code) Name of each exchange on which registered New York Stock Exchange Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes (cid:95) No (cid:133)(cid:3) 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 (cid:133) No (cid:95) 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 (cid:95) No (cid:133) 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 (cid:95) No (cid:133) 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. (cid:95) 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 (cid:133) Non-accelerated filer (cid:133) Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes (cid:133) No (cid:95) Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 30, 2015 was approximately $1,319,941,307. As of February 29, 2016, the registrant had 136,623,407 shares of Class A Common Stock and 32,145,296 shares of Class B Common Stock outstanding. (cid:95) (cid:133) (Do not check if a smaller reporting company) Accelerated filer Smaller reporting company (cid:3) (cid:3) DOCUMENTS INCORPORATED BY REFERENCE Portions of the registrant’s definitive proxy statement for the 2016 Annual Meeting of Stockholders, to be filed no later than 120 days after the end of the fiscal year to which this Annual Report on Form 10-K relates, are incorporated by reference into Part III of this Annual Report on Form 10-K. PARSLEY ENERGY, INC. FORM 10-K ANNUAL PERIOD ENDED DECEMBER 31, 2015 TABLE OF CONTENTS Page PART I. Business ........................................................................................................................................................................ Item 1. Item 1A. Risk Factors ................................................................................................................................................................. Item 1B. Unresolved Staff Comments ....................................................................................................................................... Properties ..................................................................................................................................................................... Item 2. Legal Proceedings ........................................................................................................................................................ Item 3. Mine Safety Disclosures .............................................................................................................................................. Item 4. 6 22 41 42 50 50 PART II. Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities .................................................................................................................................................................. Selected Financial Data ............................................................................................................................................... Item 6. Management’s Discussion and Analysis of Financial Condition and Results of Operations ................................ Item 7. Item 7A. Quantitative and Qualitative Disclosures About Market Risk ................................................................................ Financial Statements and Supplementary Data........................................................................................................ Item 8. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ................................ Item 9. Item 9A. Controls and Procedures ............................................................................................................................................. Item 9B. Other Information ....................................................................................................................................................... 51 52 56 79 80 80 80 80 PART III. Item 10. Directors, Executive Officers, and Corporate Governance ..................................................................................... Item 11. Executive Compensation ............................................................................................................................................. Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters........... Item 13. Certain Relationships and Related Transactions, and Director Independence ..................................................... Item 14. Principal Accounting Fees and Services .................................................................................................................... 81 81 81 81 81 PART IV. Item 15. Exhibits, Financial Statement Schedules ................................................................................................................... 82 i CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS Various statements contained in or incorporated by reference into this Annual Report on Form 10-K (this “Annual Report”) that express a belief, expectation, or intention, or that are not statements of historical fact, are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These forward-looking statements include statements, projections and estimates concerning 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 Annual 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 under “Item 1A. Risk Factors,” as well as those factors summarized below. Forward-looking statements may include statements about our: (cid:121) business strategy; (cid:121) (cid:121) (cid:121) (cid:121) (cid:121) (cid:121) 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; (cid:121) hedging strategy and results; (cid:121) (cid:121) (cid:121) future drilling plans; competition and government regulations; ability to obtain permits and governmental approvals; (cid:121) pending legal or environmental matters; (cid:121) marketing of oil, natural gas and NGLs; (cid:121) (cid:121) leasehold or business acquisitions; costs of developing our properties; (cid:121) general economic conditions; (cid:121) credit markets; (cid:121) uncertainty regarding our future operating results; and (cid:121) plans, objectives, expectations and intentions contained in this Annual Report that are not historical. Additionally, we caution you that reserve engineering is a process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered. 1 Should one or more of the risks or uncertainties described in this Annual Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this Annual Report are expressly qualified in their entirety by this cautionary note. This cautionary note should also be considered in connection with any subsequent written or oral forward- looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Annual Report. 2 GLOSSARY OF CERTAIN TERMS AND CONVENTIONS USED HEREIN The terms defined in this section are used throughout this Annual Report: “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. Refer to the SEC’s Regulation S-X, Rule 4-10(a)(15) for a complete definition of field. “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 where a well is drilled vertically to a certain depth and then drilled laterally within a specified target zone. “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. 3 “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 our initial public offering. “proved developed reserves.” Proved reserves that can be expected to be recovered: i. ii. Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well; or Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. “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. Refer to the SEC’s Regulation S-X, Rule 4- 10(a)(22) for a complete definition of proved oil and natural gas reserves. “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 new production 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. 4 “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. 5 ITEM 1: BUSINESS Overview PART I Parsley Energy, Inc. (either individually or together with its subsidiaries, as the context requires, the “Company,” “we,” “us” or “our”) is 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. In 2015, we transitioned from primarily vertical development drilling activity to predominantly horizontal development drilling activity. On May 29, 2014, we completed our initial public offering (the “IPO”) 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 50.0 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 IPO was used to repay all outstanding borrowings under the revolving credit agreement entered into on September 10, 2013 (as amended, 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 IPO. 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, 2015, we continue to operate 37 gross wells. Excluding those legacy 37 wells, as of December 31, 2015, we had an average working interest of 82% in 71 gross (58.2 net) horizontal wells, of which 67 gross (56.7 net) are in the Midland Basin. We operate 99.5% of the wells in which we have an interest and have the rights to develop 142,734 gross (110,967 net) acres in the Permian Basin, with approximately 84,441 net acres located in the Midland Basin. Since we commenced our drilling program in November 2009, we have operated up to 12 rigs simultaneously and averaged four operated rigs for the year ended December 31, 2015. We are currently operating four horizontal rigs and two vertical drilling rigs. The vertical rigs are used primarily to drill the vertical portion of horizontal wells. Our 2016 capital budget contemplates operating three to four horizontal rigs and one to two vertical rigs for 2016. 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, 2015, we have identified 147 80- and 40-acre potential vertical drilling locations, no 20-acre potential vertical drilling locations and 2,677 potential horizontal drilling locations on our existing acreage, which does not include any locations 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 three vertical appraisal wells and one horizontal appraisal well. As of December 31, 2015, we had an interest in four gross (1.5 net) wells in this area. 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 2016 capital budget for drilling and completion is approximately $380 million to $430 million. Our capital budget excludes any amounts that may be paid for acquisitions. For the year ended December 31, 2015, our capital expenditures for drilling and completions were $400.9 million, as compared to $491.3 million for the year ended December 31, 2014, excluding, in each period, amounts paid for acquisitions. We expect the average working interest in wells we drill during 2016 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. 6 The following table summarizes our technically identified horizontal drilling locations in the Permian Basin as of December 31, 2015: Area (1) Midland Basin-Core .............................................. Midland Basin-Tier I ............................................. Midland Basin-Other............................................. Southern Delaware Basin (4) ............................... Total Permian Basin .............................................. Net Acreage Identified Drilling Locations(2,3) 59,895 17,227 7,319 26,526 110,967 1,979 698 — — 2,677 (1) Please see “Item 2. Properties.” (2) 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.” (3) Our target horizontal location count implies 660’ to 990’ 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) Please see “Item 2. Properties—Delaware Basin.” Our total identified vertical drilling locations include 147 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, 2015. Of these 147 vertical locations, 135 are in our Midland Basin-Core area, and 12 are in our Midland Basin-Tier I area. An additional 1,300 vertical locations at 80- and 40-acre spacing have been identified throughout our acreage position, but are not included in the proved undeveloped reserves. At December 31, 2015, our estimated proved oil and natural gas reserves at December 31, 2015, were 123.8 MMBoe based on a reserve report prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), our independent reserve engineers. Our proved reserves are approximately 60% oil, 21% natural gas, 19% NGLs and 42% proved developed. Our Business Strategy Our business strategy is to increase stockholder value through the following: (cid:121) 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. (cid:121) Improve operational and cost efficiency by maintaining control of our production. We currently operate approximately 98% 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 horizontal Spraberry and Wolfberry wells from approximately 34 days during the fourth quarter of 2014 to approximately 22 days in the fourth quarter of 2015. Our average total depth of horizontal wells drilled in 2015 was 16,440 feet. We have also reduced our total horizontal drilling, completion and facilities costs from an average of $8.4 million per well in the fourth quarter of 2014 to an average of $6.7 million per well in the fourth quarter of 2015. 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. 7 (cid:121) 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. (cid:121) 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, 2015, we had approximately $918.9 million of liquidity, with $344.2 million of cash and cash equivalents and $574.7 million of available borrowing capacity under our Revolving Credit Agreement. Our borrowing base under the Revolving Credit Agreement currently stands at $575.0 million. Consistent with our disciplined approach to financial management, we have an active commodity hedging program that seeks to hedge a meaningful portion of our expected oil production, reducing our exposure to downside commodity price fluctuations and enabling us to protect cash flows and maintain liquidity to fund our capital program and investment opportunities. At December 31, 2015, a significant portion of our expected 2016 oil production was hedged. Our Strengths We believe that the following strengths will help us achieve our business goals: (cid:121) 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 Southern Delaware Basin acreage, we had 2,677 identified horizontal drilling locations as of December 31, 2015. We initiated our horizontal development program in 2013 and are currently operating four horizontal rigs and two vertical rigs, which are primarily used to drill the vertical portion of horizontal wells. Through December 31, 2015, we have drilled and completed 60 gross (51.0 net) horizontal wells in the Midland Basin and one gross (0.9 net) horizontal wells in the Delaware Basin, and as we continue to develop our Southern Delaware Basin acreage, we expect to identify additional horizontal drilling locations in that area. We believe that our 596 gross (372.9 net) vertical wells provide a stable production base from which to grow our horizontal drilling program. (cid:121) 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 an average of 17 years of experience. We have also assembled a technical team that includes 15 petroleum engineers and seven geologists with an average of 13 years of experience, which we believe will be of strategic importance as we continue to expand our future exploration and development plans. Our executive officers hold approximately 27.1% of our ownership interest and is our largest stockholder group. We believe our executive officers’ significant ownership interest provides meaningful incentive to increase the value of our business for the benefit of all stockholders. (cid:121) Operating control over approximately 98% of our production. As of December 31, 2015, we operated approximately 98% 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 Southern Delaware Basin acreage, includes an estimated 2,677 potential horizontal drilling locations and 147 80- and 40-acre potential vertical drilling locations. (cid:121) 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, 2015, we did not have any debt outstanding under our Revolving Credit Agreement and had $574.7 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 our current capital program. 8 Recent Events Recent Horizontal Well Results The following table provides a summary of all wells completed during the fourth quarter of 2015 that have sufficient production data: Area Well Count 30-Day Average IP Rate (Boe/d) 90-Day Average Cumulative Production (Boe) Average Total Depth (feet) Midland Basin – Core...................................... Midland Basin – Tier I .................................... 5 2 727 (1) 430 (2) 50,143 33,953 16,238 14,822 (1) Consisting of 589 Bbls/d of oil, 352 Mcf/d of natural gas, and 79 Bbls/d of NGLs. (2) Consisting of 365 Bbls/d of oil, 203 Mcf/d of natural gas, and 31 Bbls/d of NGLs. Recent Activity In December 2015, the Company sold its interest in 91 net operated wells and 11,664 gross (7,155 net) acres in north Martin and south Dawson Counties, Texas, for net proceeds of $39.4 million and realized a $36.7 million dollar loss, net of estimated purchase price adjustments. During the first quarter of 2016, we acquired certain undeveloped acreage and producing oil and gas properties located adjacent to our existing operating areas in Upton, Reagan, and Glasscock Counties for an aggregate purchase price of $148.5 million, of which a deposit of $10.0 million was paid in December 2015. The acquisition added 260 gross (227 net) horizontal drilling locations across 6,040 gross (5,274 net) surface acres and production from three producing horizontal wells. The acquisition also included one drilled horizontal well that was completed by the seller prior to the transaction closing in January 2016. Issuance of Class A Common Stock On February 5, 2015, we entered into an agreement to sell 14,885,797 shares of our Class A Common Stock in a private placement (the “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 gross proceeds of approximately $230.7 million to us and net proceeds, after deducting underwriting discounts and commissions and offering expenses, of approximately $224.0 million. The net proceeds were used to repay a portion of our outstanding borrowings under our Revolving Credit Agreement and for general corporate purposes. On September 18, 2015, we entered into an agreement to sell 14,950,000 shares of our Class A Common Stock (including 1,950,000 shares pursuant to the underwriters’ option to purchase additional shares) at a price of $15.00 per share in an underwritten public offering (the “September Offering”). The September Offering resulted in gross proceeds of approximately $224.3 million to us and net proceeds, after deducting underwriting discounts and commissions and offering expenses, of approximately $217.0 million. A portion of the net proceeds were used to repay borrowings outstanding under our Revolving Credit Agreement. The remainder of the net proceeds are expected to be used to fund a portion of our capital program, which may include acquisitions. On December 9, 2015, we and NGP X US Holdings, L.P., one of our stockholders (“NGP”), entered into an agreement to sell an aggregate of 14,202,500 shares of Class A Common Stock, including 12,911,364 shares of Class A Common Stock issued and sold by us and 1,291,136 shares of Class A Common Stock sold by NGP at a price of $18.00 per share in an underwritten public offering (the “December Offering”). On December 10, 2015, the underwriters exercised in full their option to purchase additional shares. The December Offering resulted in gross proceeds of approximately $228.7 million to us and net proceeds, after deducting underwriting discounts and commissions and offering expenses, of approximately $228.4 million. A portion of the net proceeds from the offering were used to fund the acquisition of 6,040 gross (5,274 net) acres located in Upton, Reagan and Glasscock Counties, Texas, and the remaining net proceeds are expected to be used to fund a portion of our capital program and for general corporate purposes. We did not receive any of the proceeds from the sale of shares by NGP. Upon completion of each of the Private Placement, September Offering and the December Offering, we contributed all of the net proceeds to Parsley LLC in exchange for an aggregate of 42,747,161 PE Units. As a result, our ownership of Parsley LLC increased to 81.0%, with the PE Unit Holders’ ownership of Parsley LLC decreasing to 19.0%. 9 Organizational Structure We are a holding company that was incorporated as a Delaware corporation on December 11, 2013 for the purpose of facilitating the IPO 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. 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 us 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 us in exchange for shares of Class A Common Stock, (ii) the tax basis increases resulting from the exchange by such TRA Holder of PE Units for shares of Class A Common Stock pursuant to the Exchange Right (or resulting from an exchange of PE Units for cash pursuant to the Cash Option ) and (iii) imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, any payments we make under the TRA. We will retain the benefit of the remaining 15% of these cash savings. See “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. 10 The following diagram indicates our organizational structure as of February 29, 2016. This chart is provided for illustrative purposes only and does not represent all legal entities affiliated with us. Management 12.2% Class A Common Stock 90.6% Class B Common Stock 27.1% Total Voting Power Public 87.8% Class A Common Stock 9.4% Class B Common Stock 72.9% Total Voting Power 3,013,715 PE Units 1.8% of PE Units 29,131,581 PE Units 17.3% of PE Units Parsley Energy, Inc. (NYSE: PE) (1) Includes Parsley Finance Corp. Sole Managing Member 136,623,407 PE Units 81.0% of PE Units Parsley Energy, LLC (Parsley LLC) 100% Operating Subsidiaries (1) 11 Oil and Natural Gas Production Prices and Production Costs Production and Price History The following table sets forth information regarding net production of oil, natural gas and NGLs, and certain price and cost information for the periods indicated: Revenues (in thousands, except percentages): Oil sales ......................................................................................................... $ Natural gas sales ............................................................................................ Natural gas liquids sales (1) .......................................................................... Total revenues .......................................................................................... $ Average realized prices(2): Oil sales, without realized derivatives (per Bbls) .......................................... $ Oil sales, with realized derivatives (per Bbls) ............................................... Natural gas, without realized derivatives (per Mcf) ...................................... Natural gas, with realized derivatives (per Mcf) ........................................... NGLs sales (per Bbls) ................................................................................... Average price per Boe, without realized derivatives ..................................... Average price per Boe, with realized derivatives .......................................... Production (3): Oil (MBbls) ................................................................................................... Natural gas (MMcf) ....................................................................................... Natural gas liquids (MBoe) (1) ...................................................................... Total (MBoe) ................................................................................................. Average daily production volume: Oil (Bbls/d) .................................................................................................... Natural gas (Mcf/d) ....................................................................................... Natural gas liquids (Boe/d) ............................................................................ Total (Boe/d) ................................................................................................. 2015 Year Ended December 31, 2014 2013 215,795 $ 26,582 23,680 266,057 $ 232,554 $ 30,642 38,561 301,757 $ 97,839 23,179 — 121,018 $ 44.89 56.60 2.57 2.72 15.79 33.13 40.33 4,807 10,339 1,500 8,031 13,170 28,326 4,110 22,003 $ 81.91 81.33 4.23 4.32 33.83 58.19 58.00 2,839 7,245 1,140 5,186 7,778 19,849 3,123 14,207 93.28 87.91 4.95 4.95 — 66.17 63.09 1,049 4,680 — 1,829 2,874 12,822 — 5,011 (1) For the year ended December 31, 2013, NGLs sales and production are included in the natural gas line item. (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. (3) 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. Productive Wells As of December 31, 2015 we owned an average 82% working interest in 71 gross (58.2 net) productive horizontal wells. As of December 31, 2015 we owned an average 68% working interest in 596 gross (372.9 net) productive vertical wells. Productive wells consist of producing wells and wells capable of production, including oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells. 12 General As of December 31, 2015, we operated approximately 99.5% 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, 2015, four purchasers each accounted for more than 10% of our revenue during the period: Shell Trading (US) Company, BML, Inc. (“BML”), Targa Pipeline Mid-Continent, LLC (“Targa”), and Transoil Marketing, LLC. For the year ended December 31, 2014, five purchasers each accounted for more than 10% of our revenue during the period: Targa, Plains Marketing, LP (“Plains”), BML, Permian Transport & Trading (“PTT”) and Enterprise Crude Oil, LLC (“Enterprise”). For the year ended December 31, 2013, four purchasers, PTT, Plains, Enterprise and Targa, each accounted for more than 10% of our revenue. 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 enables us to bypass the Midland pricing market for a substantial portion of our crude oil production when pipeline deliveries commence. As of December 31, 2015, approximately 43% of our gross oil production was being transported by this pipeline. 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 13 such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation. Our larger competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. Segment Information and Geographic Area Operating segments are defined under generally accepted accounting principles as components of an enterprise that (i) engage in activities from which it may earn revenues and incur expenses (ii) for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance. Based on our organization and management, we have only one reportable operating segment, which is oil and natural gas exploration and production. We consider drilling rig services ancillary to our oil and gas exploration and producing activities and manage these services to support such activities. All of our operations are conducted in one geographic area of the United States. For additional information, see our consolidated and combined financial statements in this Annual Report beginning on page F-1. Seasonality of Business Weather conditions affect the demand for, and prices of, oil and natural gas. Demand for oil and natural gas is typically higher in the 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, oil and natural gas prices have been under considerable pressure due to oversupply and other market conditions. Specifically, increased foreign production and increased efficiencies in horizontal drilling combined with exploration of newly developed shale fields in North America have dramatically increased global oil and natural gas production, which has led to significantly lower market prices for these commodities. In view of the many uncertainties affecting the supply and demand for oil, natural gas, and NGLs, 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 our financial condition or results of operations. 14 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. 15 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%. For the five-year period beginning on July 1, 2016, FERC established an annual index adjustment equal to the change in the producer price index for finished goods plus 1.23%. This adjustment is subject to review every five years. Under 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- 16 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 and occupational health and safety. These laws and regulations may, among other things (i) require the acquisition of permits to conduct exploration, drilling and production operations; (ii) restrict the types, quantities and concentration of various substances that can be released into the environment or injected into formations in connection with oil and natural gas drilling and production activities; (iii) limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; (iv) require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; and (v) impose substantial liabilities for pollution resulting from drilling and production operations. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of corrective or remedial obligations, and the issuance of orders enjoining performance of some or all of our operations. These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs. The clear trend in environmental regulation 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 compliance with existing environmental laws and regulations has not had a material adverse effect on our operations, we can provide no assurance that this will continue in the future. The following is a summary of the more significant existing and proposed environmental, occupational health and safety laws and regulations to which our business operations are or may be subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position. The Resource Conservation and Recovery Act The Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Pursuant to rules issued by the U.S. Environmental Protection Agency (the “EPA”), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of crude oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. For example, from time to time various environmental groups have challenged the EPA’s exemption of certain oil and gas wastes from RCRA. 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. Also, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes if such wastes have hazardous characteristics. Comprehensive Environmental Response, Compensation and Liability Act The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and former owners and operators of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health 17 studies. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances. Despite the “petroleum exclusion” of CERCLA, which currently encompasses natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. In addition, we currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration, production and processing for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state and local laws. Under such laws, we could be required to undertake investigatory, response, or corrective measures, which could include soil and groundwater sampling, the removal of previously disposed substances and wastes, the cleanup of contaminated property, or performance of remedial plugging or pit closure operations to prevent future contamination, the costs of which could be substantial. 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, including wetland areas, is prohibited, except in accordance with the terms of a permit issued by the EPA, the U.S. Army Corps of Engineers (the “USACE”) or an analogous state agency. In September 2015, new EPA and USACE rules defining the scope of the EPA’s and the USACE’s jurisdiction became effective. To the extent the rule expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. The rule has been challenged in court on the grounds that it unlawfully expands the reach of CWA programs, and implementation of the rule has been stayed pending resolution of the court challenge. In addition, federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. We do not expect the costs to comply with the requirements of the CWA to be substantial. 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 has 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. 18 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, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. In addition, the EPA has adopted new rules under the Clean Air Act that require the reduction of volatile organic compound emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. More recently, in August 2015, the EPA announced proposed rules that would establish new air emission controls for emissions of methane from certain equipment and processes in the oil and natural gas source category, including production, processing, transmission, and storage activities. The EPA’s proposed rule package includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. In addition, the rule package would extend existing VOC standards under the EPA’s Subpart OOOO of the New Source Performance Standards (“NSPS”) to include previously unregulated equipment within the oil and natural gas source category. Compliance with this rule will require enhanced record-keeping practices, the purchase of new equipment such as optical gas imaging instruments to detect leaks, and the increased frequency of maintenance and repair activities to address emissions leakage. The rules will also likely require hiring additional personnel to support these activities or the engagement of third party contractors to assist with and verify compliance. These and other air pollution control and permitting requirements have the potential to delay the development of oil and natural gas projects and increase our costs of development and production, which costs could be significant. However, we do not believe that compliance with such requirements will have a material adverse effect on our operations. Regulation of “Greenhouse Gas” Emissions In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the Clean Air Act that, among other things, establish 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. Recently, in December 2015, the EPA finalized rules that added new sources to the scope of the greenhouse gases monitoring and reporting rule. These new sources include gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells. The revisions also include the addition of well identification reporting requirements for certain facilities. In addition, as noted above, the EPA has proposed an NSPS related to methane emissions from the oil and natural gas source category 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. Additional federal action with respect to the control of methane emissions is likely. 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 cap and trade programs have emerged that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce. 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. 19 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 proposed regulations under the CWA in April 2015 prohibiting wastewater discharges from hydraulic fracturing and certain other natural gas operations to publicly owned wastewater treatment plants. Also, in June 2015, the EPA released its draft report on the potential impacts of hydraulic fracturing on drinking water resources. The EPA report concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water resources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources. The draft report is expected to be finalized after a public comment period and a formal review by the EPA’s Science Advisory Board. In addition, the U.S. Department of the Interior finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. The U.S. District Court of Wyoming has temporarily stayed implementation of this rule. A final decision has not yet been issued. 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 and represents an area of increased enforcement. 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 20 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. 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 2015, nor do we anticipate that such expenditures will be material in 2016. Employees As of December 31, 2015, we employed 212 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 (“NYSE”) under the symbol “PE.” Our reports, proxy statements and other information filed with the SEC can also be inspected and copied at the offices of the NYSE, at 20 Broad Street, New York, New York 10005. We also make available free of charge through our website, www.parsleyenergy.com, electronic copies of certain documents that we file with the SEC, including our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. 21 ITEM 1A. RISK FACTORS You should carefully consider the following risks and all of the information contained in this Annual Report. Our business, financial condition, and results of operations could be materially and adversely affected by any of these risks. The risks described below are not the only ones facing us. Additional risks not presently known to us or which we consider immaterial also may adversely affect us. Risks Related to the Oil and Natural Gas Industry and Our Business Oil and natural gas prices are volatile and have declined significantly over the past year. An extended continuation of low, or a further 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 and have declined significantly over the past year. For example, from 2013 to 2015, NYMEX WTI crude oil prices ranged from a high of $110.53 per barrel on September 6, 2013 to a low of $26.21 per barrel on February 11, 2016. Average daily prices for NYMEX Henry Hub gas ranged from a high of $6.15 MMBtu during 2014 to a low of $1.76 per MMBtu during 2015. 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: (cid:121) worldwide and regional economic conditions impacting the global supply and demand for natural gas, NGLs and oil; (cid:121) the price and quantity of foreign imports; (cid:121) political conditions in or affecting other producing countries, including conflicts in the Middle East, Africa, South America and Russia; (cid:121) (cid:121) the level of global exploration and production; the level of global inventories; (cid:121) prevailing prices on local price indices in the areas in which we operate; (cid:121) (cid:121) the proximity, capacity, cost and availability of gathering and transportation facilities; localized and global supply and demand fundamentals and transportation availability; (cid:121) weather conditions; (cid:121) (cid:121) technological advances affecting energy consumption; the price and availability of alternative fuels; and (cid:121) 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 December 2015, in which the organization indicated it would not put a production ceiling in place, 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 continuation of low, or 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. 22 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 2016 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: (cid:121) our proved reserves; (cid:121) (cid:121) the level of hydrocarbons we are able to produce from existing wells; the prices at which our production is sold; (cid:121) our ability to acquire, locate and produce new reserves; and (cid:121) 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 a continuation 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. 23 Future price declines could result in a reduction in the carrying value of our proved oil and gas properties, which could adversely affect our results of operations. Commodity prices have declined significantly from 2014. Through February 22, 2016, oil prices have declined from a high of $107.26 per Bbl on June 20, 2014 to a low of $26.21 per Bbl on February 11, 2016, and gas prices have declined from a high of $6.15 per Mcf on February 19, 2014 to a low of $1.76 per Mcf on December 17, 2015. Likewise, NGLs have suffered significant recent declines. NGLs are made up of ethane, propane, isobutene, normal butane and natural gasoline, all of which have different uses and different pricing characteristics. As stated above, price declines, as have occurred recently, could result in downward adjustments to our estimated proved reserves. It is possible that prices could decline further, or our estimates of production or other economic factors could change to such an extent that we may be required to impair, as a noncash charge to earnings, the carrying value of our oil and gas properties. We are required to perform impairment tests on proved oil and gas properties whenever events or changes in circumstances indicate that the carrying value of proved properties may not be recoverable. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our oil and gas properties, the carrying value may not be recoverable and therefore an impairment charge would be required to reduce the carrying value of the proved properties to their fair value. See Impairment of Oil and Gas Properties included in "Part 2. Item 7. Management’s Discussion and Analysis" for specific information regarding our impairments. We may incur impairment charges in the future, which could materially affect our results of operations in the period incurred. 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: (cid:121) 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; (cid:121) pressure or irregularities in geological formations; (cid:121) (cid:121) (cid:121) (cid:121) (cid:121) (cid:121) (cid:121) shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities; equipment failures or accidents, such as fires or blowouts; 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; (cid:121) declines in oil and natural gas prices; (cid:121) (cid:121) (cid:121) 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. 24 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 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: (cid:121) (cid:121) incur additional indebtedness; sell assets; (cid:121) make loans to others; (cid:121) make investments; (cid:121) enter into mergers; (cid:121) make certain payments; (cid:121) hedge future production or interest rates; 25 (cid:121) (cid:121) 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 the Midland- Cushing differential, we enter into commodity derivative contracts for a significant portion of our production, primarily consisting of put spreads and basis swaps. 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: (cid:121) production is less than the volume covered by the derivative instruments; (cid:121) (cid:121) (cid:121) 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 26 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 45% 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, 2015, approximately 45% 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, 2015, 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 27 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. 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, 2015, 59% of our total estimated proved reserves were classified as proved undeveloped. Our approximately 72.4 MMBoe of estimated proved undeveloped reserves will require an estimated $818.4 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 28 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 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. 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. 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: (cid:121) injury or loss of life; (cid:121) damage to and destruction of property, natural resources and equipment; (cid:121) pollution and other environmental damage; 29 (cid:121) (cid:121) (cid:121) 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 analogues we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further, our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including: (cid:121) unexpected drilling conditions; (cid:121) title problems; (cid:121) pressure or lost circulation in formations; (cid:121) (cid:121) (cid:121) (cid:121) 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: (cid:121) (cid:121) recoverable reserves; future oil and natural gas prices and their applicable differentials; (cid:121) operating costs; and (cid:121) 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 30 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. Concerns over 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, the European, Asian and the United States financial markets 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 volatility in commodity prices, business and consumer confidence and unemployment rates, have precipitated an economic slowdown. 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 further, 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. 31 A downgrade in our credit ratings could negatively impact our cost of and ability to access capital. As of December 31, 2015, our long-term debt was rated B3 with a positive outlook by Moody’s Investors Service, Inc. (“Moody’s”), and B with a stable outlook by Standard & Poor’s Ratings Services. On December 16, 2015, Moody’s announced that it had placed the ratings of 29 U.S. exploration and production companies and their related subsidiaries on review for downgrade. Since that action, Moody’s lowered its oil price estimates and placed additional exploration and production companies and their related subsidiaries, including Parsley LLC, on review for downgrade. With Moody’s reduced expectations for the likely range of prices and deteriorating industry conditions, there is an increased possibility for multi-notch downgrades as an outcome of the review process. The ultimate outcome of the ratings review process for any particular exploration and production company will depend on the issuer’s particular credit attributes. As of the date of this Annual Report, no changes in our credit ratings have occurred; however, we cannot be assured that our credit ratings will not be downgraded in the future. A downgrade in our credit ratings could negatively impact our costs of capital or our ability to effectively execute aspects of our strategy. Further, a downgrade in our credit ratings could affect our ability to raise debt in the public debt markets and the cost of any new debt could be much higher than our outstanding debt. These and other impacts of a downgrade in our credit ratings could have a material adverse effect on our business, financial condition and results of operations. The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis. The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil 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. Recently, in December 2015, the EPA finalized rules that added new sources to the scope of the greenhouse gases monitoring and reporting rule. These new sources include gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells. The revisions also include the addition of well identification reporting requirements for certain facilities. In addition, as noted above, the EPA has proposed an NSPS related to methane emissions from the oil and natural 32 gas source category 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. Additional federal action with respect to the control of methane emissions is likely. 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 cap and trade programs have emerged that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce. 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. 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 cap and trade programs have emerged that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce. 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. Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production. Hydraulic fracturing is a common industry practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into target geological formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Recently, there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies, 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 proposed regulations under the CWA in April 2015 prohibiting wastewater discharges from hydraulic fracturing and certain other natural gas operations to publicly owned wastewater treatment plants. Also, in June 2015, the EPA released its draft report on the potential impacts of hydraulic fracturing on drinking water resources. The EPA report concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water resources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources. The draft report is expected to be finalized after a public comment period and a formal review by the EPA’s Science Advisory Board. In addition, the U.S. Department of the Interior finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. The U.S. District Court of Wyoming has temporarily stayed implementation of this rule. A final decision has not yet been issued. 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 33 restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells. Further regulation of hydraulic fracturing at the federal, state, and local level could subject our operations to additional permitting requirements and result in permitting delays as well as potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves. Please read “Item 1. Business—Regulation of the Oil and Natural Gas Industry” for a further description of the laws and regulations that affect us. Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties and market oil or natural gas. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, and raising additional capital, which could have a material adverse effect on our business. We operate in areas of high industry activity, which may affect our ability to hire, train or retain qualified personnel needed to manage and operate our assets. Our operations and drilling activity are concentrated in the Permian Basin in West Texas, an area in which industry activity has remained relatively steady despite the recent downturn in commodity prices. As a result, demand for qualified personnel in this area, and the cost to attract and retain such personnel, has continued to be competitive, and would be expected to increase substantially in the future if commodity prices rebound. Moreover, our competitors may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development activities could result in oil and 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. 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 37 legacy wells that we operate and that 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. 34 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: (cid:121) (cid:121) (cid:121) (cid:121) 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, 2015, we had completed 61 gross (51.9 net) horizontal wells and therefore are subject to increased risks associated with horizontal drilling as compared to companies that have greater experience in horizontal drilling activities. Risks that we face while drilling include, but are not limited to, failing to land our wellbore in the desired drilling zone, not staying in the desired drilling zone while drilling horizontally through the formation, not running our casing the entire length of the wellbore and not being able to run tools and other equipment consistently through the horizontal wellbore. Risks that we face while completing our wells include, but are not limited to, not being able to fracture stimulate the planned number of stages, not being able to run tools the entire length of the wellbore during completion operations and not successfully cleaning out the wellbore after completion of the final fracture stimulation stage. Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are 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. Future legislation may result in the elimination of certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and production. Additionally, future federal or state legislation may impose new or increased taxes or fees on oil and natural gas extraction. Potential legislation, if enacted into law, could make significant changes to U.S. federal and state income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural 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; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any other similar changes in U.S. federal and state income tax laws 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. Additionally, legislation could be enacted that increases the taxes states impose on oil and natural gas extraction. Moreover, President Obama has proposed, as part of the Budget of the United States Government for Fiscal Year 2017, to impose an “oil fee” of $10.25 on a per barrel equivalent of crude oil. This fee would be collected 35 on domestically produced and imported petroleum products. The fee would be phased in evenly over five years, beginning October 1, 2016. The adoption of this, or similar proposals, could result in increased operating costs and/or reduced consumer demand for petroleum products, which in turn could affect the prices we receive for our oil. Our ability to use our net operating loss carryforwards may be limited. As of December 31, 2015, we had approximately $50.4 million of U.S. federal net operating loss carryforwards (“NOLs”). Utilization of these NOLs depends on many factors, including our future income, which cannot be assured. Our NOLs begin to expire in 2033. In addition, Section 382 of the Internal Revenue Code of 1986, as amended (“Section 382”), generally imposes an annual limitation on the amount of NOLs that may be used to offset taxable income when a corporation has undergone an “ownership change” (as determined under Section 382). An ownership change generally occurs if one or more shareholders (or groups of shareholders) who are each deemed to own at least 5% of our stock change their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three-year period. In the event that an ownership change has occurred, or were to occur, utilization of our NOLs would be subject to an annual limitation under Section 382, determined by multiplying the value of our stock at the time of the ownership change by the applicable long-term tax-exempt rate as defined in Section 382. Any unused annual limitation may be carried over to later years. We may be found to have had an ownership change in 2015, which would result in an annual limitation under Section 382. However, even if we did have an ownership change in 2015, we do not believe that such limitation would prevent our utilization of our NOLs prior to their expiration. Future ownership changes or future regulatory changes could limit our ability to utilize our NOLs. To the extent we are not able to offset our future income with our NOLs, this would adversely affect our operating results and cash flows if we attain profitability. 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. 36 In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the United States District Court for the District of Columbia in September 2012. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time. 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). To date, the CFTC has only designated certain interest rate swaps and credit default swaps for application of such mandatory clearing and trade-execution requirements. Although we expect to qualify for the end-user exception from such requirements for swaps entered to hedge our commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. If our swaps do not qualify for the commercial end-user exception, or if the cost of entering into swaps outside of mandatory clearing becomes prohibitive, we may be required to clear such transactions. The ultimate effect of the rules and any additional regulations on our business is uncertain at this time. In addition, certain banking regulators and the CFTC have adopted final rules establishing minimum margin requirements for swaps outside of mandatory clearing. Although we expect to qualify for the end-user exception from such margin requirements for swaps entered into to hedge our commercial risks, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. If any of our swaps do not qualify for the commercial end-user exception, the posting of collateral could reduce our liquidity and cash available for capital expenditures and our ability to manage commodity price volatility and the volatility in cash flows. 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 and any new regulations could significantly increase the cost of derivatives, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter and reduce our ability to monetize or restructure our existing derivative contracts. 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. Any of these consequences could have a material and adverse effect on us, our financial condition or our results of operations. In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations. At this time, the impact of such regulations is not clear. 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 37 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: (cid:121) (cid:121) (cid:121) (cid:121) (cid:121) 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. In addition, as a public company subject to these rules and regulations, it can be 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 executive officers hold approximately 27.1% 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 38 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 “Item 13. Certain Relationships and Related Transactions, and Director Independence.” Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A Common Stock. Our amended and restated certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and 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: (cid:121) (cid:121) (cid:121) 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; (cid:121) providing that the board of directors is expressly authorized to adopt, or to alter or repeal our bylaws; and (cid:121) 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 39 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 “Item 13. 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 or due to a material breach of the TRA, we would be required to make an immediate payment equal to the present value of the anticipated future tax benefits subject to the TRA. The calculation of anticipated future tax benefits will be based upon certain assumptions as 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. For example, if the TRA were terminated at December 31, 2015, the estimated termination payment would be approximately $193.8 million (calculated using a discount rate equal to the LIBOR, plus 300 basis points, applied against an undiscounted liability of $409.0 million). The foregoing number is merely an estimate and the actual payment could differ materially. There can be no assurance that we will be able to finance our obligations under the TRA. 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 40 over our Class A Common Stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our Class A Common Stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the Class A Common Stock. We are subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we fail to comply with the requirements of Section 404 or if we or our auditors identify and report material weaknesses in internal control over financial reporting, our investors may lose confidence in our reported information and our stock price may be negatively affected. As of December 31, 2015, we are required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act of 2002, or Sarbanes-Oxley Act. Section 404 requires that we document and test our internal control over financial reporting and issue our management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm issue an attestation report on such internal control. If we fail to comply with the requirements of Section 404 of the Sarbanes-Oxley Act, or if we or our auditors identify and report material weaknesses in our internal control over financial reporting, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our Class A Common Stock. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, results of operations and financial condition. ITEM 1B. UNRESOLVED STAFF COMMENTS None. 41 ITEM 2. PROPERTIES Our properties are located in the West Texas portion of the Permian Basin. As of December 31, 2015, our acreage position consisted of 110,967 net acres, 84,441 of which are in the Midland Basin and 26,526 of which are in the Delaware Basin, approximately 55% of which is held by production. As of December 31, 2015, we have interests in 667 gross (431 net) producing wells, of which we operate 99.5%. The table below sets forth our identified drilling locations in the Midland Basin as of December 31, 2015. Core (1) Target Horizontal Locations Tier I (1) Total Gross Net Gross Net Gross Net Target Horizontal Zone Spraberry (2) ................................................................ Wolfcamp A ................................................................. Wolfcamp B ................................................................. Wolfcamp C ................................................................. Upper Pennsylvanian (Cline) ....................................... Lower Pennsylvanian (Atoka ) ..................................... Total Target Horizontal Location ................................. 254 323 314 366 402 320 1,979 197 268 269 306 332 271 1,643 77 118 146 133 133 91 698 57 93 118 105 105 72 550 331 441 460 499 535 411 2,677 254 361 387 411 437 343 2,193 (1) Our target horizontal location count implies 660’ to 990’ 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. (2) Spraberry locations are based on Middle and Upper Spraberry. For the Middle Spraberry, only those locations located in Upton County are included at 990’ spacing. 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 the RRC, over 1.3 billion barrels of oil and 3.9 trillion cubic feet of gas have been produced in this field through December 2014. 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. 42 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 I, 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, 2015, we have 86,886 gross (59,895 net) acres in our Midland Basin-Core area. Approximately 78% of our acreage in this area is held by production. We have interests in 57 gross (47.3 net) producing horizontal wells and 472 gross (295.4 net) producing vertical wells in our Midland Basin-Core area as of December 31, 2015 and we operate 100% of the wells in which we have an interest. The table below sets forth our identified drilling locations in the Midland Basin-Core as of December 31, 2015. Target Horizontal Zone Spraberry (3) ........................................................................... Wolfcamp A ............................................................................. Wolfcamp B ............................................................................. Wolfcamp C ............................................................................. Upper Pennsylvanian (Cline) ................................................... Lower Pennsylvanian (Atoka ) ................................................. Total Target Horizontal Location ............................................. Total (1,2) Gross Net 254 323 314 366 402 320 1,979 197 268 269 306 332 271 1,643 (1) Our target horizontal location count implies 660’ to 990’ 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. (2) Average Core Stimulated Length is estimated at 6,215 ft. (3) Spraberry locations are based on Middle and Upper Spraberry. For the Middle Spraberry, only those locations located in Upton County are included at 990’ spacing. Midland Basin-Tier I Our Midland Basin-Tier I 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 I includes areas of Andrews, Borden, Crane, Dawson, Ector, Glasscock, Howard, Irion, Martin, Midland, Reagan and Upton Counties. As of December 31, 2015, we have 22,061 gross (17,227 net) acres in our Midland Basin-Tier I area. Approximately 57% of our acreage in this area is held by production. We have interests in 10 gross (9.4 net) producing horizontal wells and 111 gross (73.6 net) producing vertical wells in our Midland Basin-Tier I area as of December 31, 2015 and operate 98%, of the wells in which we have an interest. 43 The table below sets forth our identified drilling locations in the Midland Basin-Tier I as of December 31, 2015. Target Horizontal Zone Spraberry .................................................................................. Wolfcamp A ............................................................................. Wolfcamp B ............................................................................. Wolfcamp C ............................................................................. Upper Pennsylvanian (Cline) ................................................... Lower Pennsylvanian (Atoka ) ................................................. Total Target Horizontal Location ............................................. Total (1,2) Gross Net 77 118 146 133 133 91 698 57 93 118 105 105 72 550 (1) 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. (2) Average Tier 1 Stimulated Length is estimated at 5,235 ft. 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 certain portions of Andrews, Gaines, Reagan, Upton, Irion, Martin, Glasscock, and Howard Counties. As of December 31, 2015, we have 9,875 gross (7,318 net) undeveloped acres in our Midland Basin-Other area. None of our acreage in this area is held by production. We have interests in nine gross (0.9 net) producing non-operated wells in our Midland Basin-Other area as of December 31, 2015. 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, 2015, our Delaware Basin acreage includes 747 MBoe of proved developed reserves and 3.2 MMBoe of proved undeveloped reserves. Our Delaware Basin acreage also includes four gross (1.5 net) producing horizontal wells and four gross (three net) producing vertical wells. We hold a leasehold position in 28,912 gross (26,526 net) acres in the Delaware Basin which we call our Trees Ranch Prospect. Production Status For the year ended December 31, 2015, our average daily net sales from production from our horizontal wells on our Midland Basin acreage, was 11,052 Boe/d, of which 76% was from oil, 11% was from natural gas, and 13% was from NGLs. 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. 44 Recent Activity During the year ended December 31, 2015, we completed 41 gross (37.4 net) horizontal wells for an aggregate net cost of $261.6 million and 16 gross (14.7 net) vertical wells were completed on our Midland Basin acreage for an aggregate estimated net cost of $33.7 million. As of December 31, 2015, we have identified 2,677 potential horizontal drilling locations and 147 80- and 40-acre potential vertical drilling locations on our existing acreage, which does not include any locations in our Southern Delaware acreage. Our target horizontal location count implies 660’ to 990’ 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: 2015 Year ended December 31, 2014 (in thousands, except per share unit data) 2013 Average daily production volume (1): Oil (Bbls/d) ................................................................................................... Natural gas (Mcf/d) ...................................................................................... Natural gas liquids (Boe/d) ........................................................................... Total (Boe/d) ................................................................................................ 13,170 28,326 4,110 22,003 7,778 19,849 3,123 14,207 Average realized prices: Oil sales, without realized derivatives (per Bbls) ......................................... $ Oil sales, with realized derivatives (per Bbls) .............................................. Natural gas, without realized derivatives (per Mcf) ..................................... Natural gas, with realized derivatives (per Mcf)........................................... NGLs sales (per Bbls)................................................................................... 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 ..................................................................................... Impairment .............................................................................................. Acquisition costs ..................................................................................... Accretion of asset retirement obligations ................................................ Rig termination costs ............................................................................... Other operating expenses ........................................................................ Total operating expenses ...................................................................... $ $ $ 44.89 56.60 2.57 2.72 15.79 33.13 40.33 7.83 2.22 22.20 6.89 1.73 0.12 — 0.10 1.12 0.21 42.42 $ $ 81.91 81.33 4.23 4.32 33.83 58.19 58.00 $ 7.34 3.65 18.18 16.96 0.39 — 0.49 0.10 0.15 — 47.26 $ (1) For the year ended December 31, 2013, NGLs sales and production are included in the natural gas line item. 2,874 12,822 — 5,011 93.28 87.91 4.95 4.95 — 66.17 63.09 9.06 3.87 15.39 9.05 — — — 0.10 — — 37.47 45 Proved Reserves Evaluation and Review of Proved Reserves. Our historical proved reserve estimates as of December 31, 2015 and 2014 were prepared based on reports by NSAI. NSAI does not own an interest in any of our properties, nor is it employed by us on a contingent basis. Within NSAI, the technical person primarily responsible for preparing the estimates set forth in the NSAI letter dated January 19, 2016, filed as an exhibit to this Annual Report, was Mr. James Ball. Mr. Ball, Vice President at NSAI and a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 1998 and has over 18 years of prior industry experience. 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. 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 11 years of reservoir and operations experience, and our engineering and geoscience staff have an average of approximately 13 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: (cid:121) review and verification of historical production data, which data is based on actual production as reported by us; (cid:121) preparation of reserve estimates by Mr. Gallagher or under his direct supervision; (cid:121) 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, 2015 and December 31, 2014 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 46 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, 2015 2014 27,628 10,890 77,612 51,454 46,249 12,848 79,563 72,358 73,877 23,738 157,175 123,811 23,547 11,491 65,484 45,952 24,070 11,175 58,161 44,939 47,617 22,667 123,645 90,891 (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 and combined financial statements included elsewhere in this Annual Report and the proved reserve report as of December 31, 2015, which is included as an exhibit to this Annual Report. Proved Undeveloped Reserves (PUDs) As of December 31, 2015, our proved undeveloped reserves were composed of 46,249 MBbls of oil, 79,563 MMcf of natural gas, and 12,848 MBbls of NGLs, for a total of 72,358 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, 2015 (in MBoe): Balance, December 31, 2014 ..................................................................... Purchases of reserves ................................................................................. Extensions and discoveries ........................................................................ Revisions of previous estimates ................................................................. Transfers to proved developed ................................................................... Balance, December 31, 2015 ..................................................................... 44,939 3,375 38,330 (13,577) (709) 72,358 Extensions and discoveries of 38,330 MBoe during the year ended December 31, 2015, resulted primarily from the drilling of new wells during the year and from new proved undeveloped locations added during the year. 47 Costs incurred relating to the development of locations that were classified as PUDs at December 31, 2014 were $40.2 million during the year ended December 31, 2015. Additionally, during 2015 we spent approximately $345.1 million drilling and completing other in-field wells which were not classified as PUDs as of December 31, 2014. Estimated future development costs relating to the development of PUDs at December 31, 2015 were projected to be approximately $105.1 million in the year ended December 31, 2016, $245.8 million in 2017, $268.4 million in 2018, $150.0 million in 2019, and $43.1 million in future periods. 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, 2015, none 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, 2015 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 applicable leases. 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, 2015 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) 76,585 1,972 78,557 53,670 1,778 55,448 37,237 26,940 64,177 30,771 24,748 55,519 113,822 28,912 142,734 84,441 26,526 110,967 (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, 2015, 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. There are currently no expirations for the year ended December 31, 2020. 2016 Gross Midland Basin ................... Delaware Basin ................. Total .................................. 22,764 1,760 24,524 Net 18,346 693 19,039 2017 2018 2019 Gross Net Gross Net Gross Net 5,624 — 5,624 4,931 — 4,931 7,404 16,329 23,733 6,570 16,089 22,659 1,446 8,852 10,298 923 7,966 8,889 48 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 .............................. Exploratory Wells: Productive(1) ........................ Dry holes .............................. Vertical: Development Wells: Productive(1) ........................ Dry holes .............................. Exploratory Wells: Productive(1) ........................ Dry holes .............................. Total: Productive(1) ........................ Dry holes .............................. 2015 Year ended December 31, 2014 2013 Gross Net Gross Net Gross Net 41 — 1 — 15 — 1 — 58 — 58 36 — 1 — 14 — 1 — 52 — 52 20 — — — 15 — — — — — — — 168 — 137 — 170 1 2 — 190 — 190 2 — 154 — 154 — — 170 1 171 — — — — 100 1 — — 100 1 101 (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, 2015 we had five gross (five net) horizontal wells in the process of drilling, one gross (one net) horizontal well awaiting hydraulic fracturing procedures, and seven gross (6.6 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, when we acquire leasehold acreage, we conduct title due diligence on the subject properties but may not have title opinions covering the properties prior to entering into a purchase and sale agreement. At 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 completed after the closing of an acquisition reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry. 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 49 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 As of December 31, 2015, we leased corporate office space in Austin, Texas at 303 Colorado St., where our corporate headquarters is located. We also lease corporate office space and own 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. 50 PART II ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Our Class A Common Stock began trading on the NYSE under the symbol “PE” on May 29, 2014. Prior to that, there was no public market for our Class A Common Stock. The following table sets forth high and low sales prices of our Class A Common Stock for the periods indicated: 2014 Quarter ended December 31 ............................. $ Quarter ended September 30 ............................ $ Quarter ended June 30 (a) ................................ $ 2015 Quarter ended December 31 ............................. $ Quarter ended September 30 ............................ $ Quarter ended June 30 ...................................... $ Quarter ended March 31 ................................... $ High Low 21.03 $ 23.95 $ 25.16 $ 19.82 $ 17.42 $ 18.87 $ 18.29 $ 11.26 19.89 22.11 15.29 13.72 15.92 13.50 (a) Represents the period from May 29, 2014, the date on which our Class A Common Stock began trading on the NYSE, through June 30, 2014. On February 26, 2016, the closing sales price of our Class A Common Stock as reported by the NYSE was $18.00 per share and we had approximately 30 holders of record of our Class A Common Stock. This number does not include owners for whom shares of our Class A Common Stock may be held in “street” name. There is no public market for our Class B Common Stock. On February 26, 2016, we had approximately 11 holders of record of our Class B Common Stock. Dividends We have never declared or paid any cash dividends to holders of our Class A Common Stock or Class B Common Stock. We currently intend to retain all available funds, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our Board of Directors and will depend upon various factors, including our results of operations, financial condition, capital requirements, and investment opportunities. In addition, our debt agreements restrict our ability to pay cash dividends to holders of our Class A Common Stock or Class B Common Stock. Purchases of Equity Securities by the Issuer and Affiliated Purchasers We did not purchase any shares of our Class A Common Stock during the quarter ended December 31, 2015. Sales of Unregistered Equity Securities We did not have any sales of unregistered equity securities during the fiscal year ended December 31, 2015, except as set forth in our Quarterly Reports on Form 10-Q or Current Reports on Form 8-K filed during such fiscal year. 51 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”: 2015 Year ended December 31, 2014 2012 2013 (in thousands, except per share unit data) 2011 REVENUES Oil sales ............................................................................. $ Natural gas sales ................................................................ Natural gas liquids sales .................................................... Total revenues.............................................................. 215,795 $ 26,582 23,680 266,057 232,554 $ 30,642 38,561 301,757 97,839 $ 23,179 — 121,018 30,443 $ 7,236 — 37,679 8,702 2,132 — 10,834 OPERATING EXPENSES Lease operating expenses ................................................... Production and ad valorem taxes ....................................... Depreciation, depletion and amortization .......................... General and administrative expenses ................................. Exploration costs ............................................................... Impairment ........................................................................ Acquisition costs ................................................................ Accretion of asset retirement obligations ........................... Rig termination costs ......................................................... Other operating expenses ................................................... Total operating expenses ............................................. OPERATING (LOSS) INCOME .......................................... OTHER INCOME (EXPENSE) Interest expense, net ........................................................... (Loss) gain on sale of property .......................................... Prepayment premium on extinguishment of debt .............. Derivative income (loss) .................................................... Other income (expense) ..................................................... Total other income (expense), net ...................................... (LOSS) INCOME BEFORE INCOME TAXES.................. INCOME TAX BENEFIT (EXPENSE) (2) ......................... NET (LOSS) INCOME ......................................................... LESS: NET LOSS (INCOME) ATTRIBUTABLE TO NONCONTROLLING INTERESTS ............................... NET (LOSS) INCOME ATTRIBUTABLE TO PARSLEY ENERGY INC. STOCKHOLDERS ..............$ Net (loss) income per common share: (1) Basic ..................................................................................... $ Diluted ..................................................................................$ Weighted average common shares outstanding: (1) 62,913 17,800 178,281 55,294 13,865 950 — 826 8,970 1,696 340,595 (74,538) (45,581) (34,374) — 60,818 (3,111) (22,248) (96,786) 23,755 (73,031) 38,071 18,941 94,297 87,949 3,136 — 2,527 512 765 — 246,198 55,559 (39,624) (2,097) (5,107) 83,858 601 37,631 93,190 (36,468) 56,722 16,572 7,081 28,152 16,553 — — — 181 — — 68,539 52,479 (13,733 ) 36 — (9,800 ) 434 (23,063 ) 29,416 (1,906 ) 27,510 4,646 2,412 6,406 3,658 — — — 66 — — 17,188 20,491 (6,295) 7,819 (6,597) (2,190) 225 (7,038) 13,453 (554) 12,899 1,446 610 1,247 1,369 — — — 32 — — 4,704 6,130 (461) 6,638 — (255) (116) 5,806 11,936 (116) 11,820 22,547 (33,293) — — — (50,484) $ 23,429 $ 27,510 $ 12,899 $ 11,820 (0.45) $ (0.45) $ 0.65 0.65 Basic ..................................................................................... Diluted .................................................................................. 111,271 111,271 93,168 93,271 (1) Please see the section entitled Revision of 2014 Financial Statements in Note 2—Summary of Significant Accounting Policies and Note 8—Equity in our consolidated and combined financial statements, included herein, for additional discussion. (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. 52 2015 Year ended December 31, 2014 2012 2013 (in thousands, except per share unit data) 2011 Total Production Volumes Oil (MBbls) ................................................................. Natural gas (MMcf) ..................................................... Natural gas liquids (MBoe) ......................................... Combined (MBoe) ....................................................... 4,807 10,339 1,500 8,031 2,839 7,245 1,140 5,186 1,049 4,680 — 1,829 356 1,493 — 604 Average daily production volume: Oil (Bbls/d) .................................................................. Natural gas (Mcf/d) ..................................................... Natural gas liquids (Boe/d) .......................................... Total (Boe/d) ............................................................... 13,170 28,326 4,110 22,003 7,778 19,849 3,123 14,207 2,874 12,822 — 5,011 Average realized prices: Oil sales, without realized derivatives (per Bbls) ........ $ Oil sales, with realized derivatives (per Bbls) ............. Natural gas, without realized derivatives (per Mcf) ...... Natural gas, with realized derivatives (per Mcf) ......... NGLs sales (per Boe) .................................................. 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 ......................................................... Impairment .................................................................. Acquisition costs ......................................................... Accretion of asset retirement obligations .................... Rig termination costs ................................................... Other operating expenses ............................................ Total operating expenses per Boe ............................. $ Consolidated and Combined Statements of Cash Flows Data: Net cash provided by (used in): $ $ 44.89 56.60 2.57 2.72 15.79 33.13 40.33 7.83 2.22 22.20 6.89 1.73 0.12 — 0.10 1.12 0.21 42.42 $ $ 81.91 81.33 4.23 4.32 33.83 58.19 58.00 $ 7.34 3.65 18.18 16.96 0.39 — 0.49 0.10 0.15 — 47.26 $ $ 93.28 87.91 4.95 4.95 — 66.17 63.09 $ 9.06 3.87 15.39 9.05 — — — 0.10 — — 37.47 $ 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 $ 94 304 — 145 258 832 — 397 92.43 92.17 7.02 7.02 — 74.84 74.67 9.99 4.21 8.61 9.37 — — — 0.22 — — 32.40 Operating activities ..................................................... $ Investing activities ....................................................... Financing activities ..................................................... 172,290 $ 184,983 $ (427,165) (1,247,677) 547,409 1,093,851 53,235 $ (425,611 ) 378,096 5,025 $ (89,539) 74,245 16,031 (15,654) 19,729 Proved reserves: Oil (MBbls) ................................................................. Natural gas (MMcf) ..................................................... NGLs (MBbls)............................................................. Combined (MBoe) ....................................................... 73,877 23,738 157,175 123,811 47,617 22,667 123,645 90,891 29,507 77,818 12,357 54,834 12,987 30,214 4,732 22,755 Consolidated and Combined Balance Sheet Data: Cash and cash equivalents ........................................... $ 50,550 $ Total assets .................................................................. 2,514,192 2,051,079 676,845 Long-term debt ............................................................ 555,924 992,489 Total equity ................................................................. 1,586,641 343,084 $ 19,393 $ 742,556 429,970 108,032 13,673 $ 181,239 119,663 6,017 8,519 20,689 3,127 15,094 23,942 64,478 26,118 9,053 Other Financial Data: Adjusted EBITDAX (1) .............................................. 195,386 207,077 76,828 26,281 7,265 (1) Adjusted EBITDAX is a non-GAAP financial measure. For a definition of Adjusted EBITDAX and a reconciliation to our most directly comparable financial measures calculated and presented in accordance with GAAP, please read “— Non-GAAP Financial Measures.” 53 Non-GAAP Financial Measures Adjusted EBITDAX Adjusted EBITDAX is not a measure of net income as determined by GAAP. Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated and combined financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as net (loss) income before depreciation, depletion, and amortization (“DD&A”), exploration costs, impairment, acquisition costs, loss (gain) on sales of oil and natural gas properties, asset retirement obligation accretion expense, stock based compensation, net interest expense, income tax (benefit) expense, rig termination, prepayment premium on extinguishment of debt, inventory write down, (income) loss on derivative instruments, net settlements on derivative instruments, and premium realization on options that settled during the period. Management believes Adjusted EBITDAX is useful because it allows 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 EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measure of other companies. We believe that Adjusted EBITDAX is 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 EBITDAX to the GAAP financial measure of net income for each of the periods indicated. 2015 Year Ended December 31, 2013 2014 (in thousands) 2012 2011 Adjusted EBITDAX reconciliation to net income: Net (loss) income attributable to Parsley Energy, Inc. stockholders' ............................................................................. $ (50,484 ) $ 23,429 33,293 (22,547) Net (loss) income attributable to noncontrolling interests ........... 94,297 Depreciation, depletion and amortization .................................... 178,281 3,136 13,865 Exploration costs ......................................................................... — 950 Impairment .................................................................................. 2,527 — Acquisition costs ......................................................................... 2,097 34,374 Loss (gain) on sales of oil and natural gas properties .................. 512 826 Asset retirement obligation accretion expense ............................ 53,297 8,133 Non-cash stock based compensation ........................................... 39,624 45,581 Interest expense, net .................................................................... 36,468 (23,755) Income tax (benefit) expense ...................................................... 765 8,970 Rig termination ............................................................................ 5,107 — Prepayment premium on extinguishment of debt ........................ — 4,147 Inventory write down .................................................................. (83,858) (60,818) Derivative (income) loss ............................................................. 3,311 46,457 Net settlements on derivative instruments ................................... (6,928) Premium realization on options that settled during the period ....... 11,406 $ 207,077 Adjusted EBITDAX .................................................................... $ 195,386 $ 27,510 — 28,152 — — — (36 ) 181 1,233 13,733 1,906 — — — 9,800 (198 ) (5,434 ) $ 76,847 $ 12,899 — 6,406 — — — (7,819) 66 — 6,295 554 — 6,597 — 2,190 179 (1,076) $ 26,291 $ 11,820 — 1,247 — — — (6,638) 32 — 461 116 — — — 255 78 (103) 7,268 $ 54 PV-10 The following table provides a reconciliation of PV-10 to the GAAP financial measure of Standardized Measure as of December 31, 2015: PV-10 of proved reserves ......................................................................................................... $ Present value of future income tax discounted at 10%............................................................. Standardized Measure .............................................................................................................. $ As of December 31, 2015 (in millions) 697.3 (99.5) 597.8 55 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 and combined 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. Parsley Energy, Inc. was formed in December 2013. For purposes of this discussion, our accounting predecessors are Parsley Energy, LLC (“Parsley LLC”) and its predecessors, Parsley Energy Operations, LLC (“Operations”) and Parsley Energy, L.P. (“Parsley LP”). Both Operations and Parsley LP began operations in 2008 in conjunction with the acquisition of operator rights to wells producing from the Spraberry Trend in the Midland Basin. Parsley LLC was formed in June 2013 to engage in the acquisition, development and exploitation of unconventional oil and natural gas reserves located in the Permian Basin. Concurrent with the formation of Parsley LLC, all of the interest holders in Parsley LP, Parsley Energy Management, LLC, and Operations 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 PE Units. 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. We now focus predominately on horizontal development drilling and expect to target various stacked pay intervals in the Spraberry, Wolfcamp, Upper Pennsylvanian (Cline) and Atoka shales. Our Properties At December 31, 2015, our acreage position was 142,734 gross (110,967 net) acres. The majority of our acreage is located in the Midland Basin, and the majority of our identified horizontal drilling locations are located in our horizontal focus area, which is comprised of specific portions of Upton, Reagan, Midland, and Glasscock Counties in Texas. As of December 31, 2015, we operated 651 vertical wells across our acreage in the Midland Basin. Since commencing our horizontal drilling program in 2013 through December 31, 2015, we have drilled and completed 60 gross (51.0 net) horizontal wells in the Midland Basin, of which 41 gross (36.0 net) were completed during 2015. We have also drilled and completed one gross (0.9 net) horizontal wells in the Delaware Basin. As of December 31, 2015, we operated 68 gross (57.6 net) horizontal wells. Additionally, we commenced our vertical appraisal drilling program in the Delaware Basin during the first quarter of 2014. As of December 31, 2015, we had drilled and completed three vertical appraisal wells and one horizontal appraisal well in the Delaware Basin. As of December 31, 2015, we have identified 2,677 potential horizontal drilling locations and 147 80- and 40-acre potential vertical drilling locations on our existing acreage, which does not include any locations in our Southern Delaware Basin acreage. As of December 31, 2015, we had interests in 667 gross (431 net) producing wells across our properties and operated 99.5% of the wells in which we had an interest. 56 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: (cid:121) production volumes; (cid:121) (cid:121) (cid:121) 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 (cid:121) Adjusted EBITDAX. 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, natural gas, and NGLs revenues do not include the effects of derivatives. For the years ended December 31, 2015, 2014 and 2013, our revenues were derived 81%, 77% and 81%, respectively, from oil sales; 10%, 10% and 19%, respectively, from natural gas sales; and 9% and 13% , respectively for 2015 and 2014, from NGLs sales. For the year ended December 31, 2013, NGLs sales were included in the natural gas line item. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. Production Volumes The following table presents historical production volumes for our properties for the years ended December 31, 2015, 2014 and 2013. Oil (MBbls) ................................................................................................. Natural gas (MMcf) .................................................................................... Natural gas liquids (MBoe) (1) ................................................................... Total (MBoe) .............................................................................................. Average net production (Boe/d) .................................................................. 4,807 10,339 1,500 8,031 22,003 2,839 7,245 1,140 5,186 14,207 1,049 4,680 — 1,829 5,011 2015 Year Ended December 31, 2014 2013 (1) For the year ended December 31, 2013, NGLs production was not separately reported. 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 57 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, natural gas, and NGLs normally sell at a discount to the NYMEX WTI and NYMEX Henry Hub price. 2015 Year Ended December 31, 2014 2013 Oil NYMEX WTI High .................................................................................... $ NYMEX WTI Low ..................................................................................... $ Differential to Average NYMEX WTI ....................................................... $ 61.43 $ 34.73 $ (3.19) $ 107.26 $ 53.27 $ 1.65 $ Natural Gas NYMEX Henry Hub High .......................................................................... $ NYMEX Henry Hub Low ........................................................................... $ Differential to Average NYMEX Henry Hub ............................................. $ 3.23 $ 1.76 $ 0.07 $ 6.15 $ 2.89 $ (0.29 ) $ NGLs NYMEX WTI High .................................................................................... $ NYMEX WTI Low ..................................................................................... $ Differential to Average NYMEX WTI ....................................................... $ 61.43 $ 34.73 $ (32.29) $ 107.26 $ 53.27 $ (46.44 ) $ 110.53 86.68 (5.33) 4.46 3.11 1.16 110.53 86.68 (98.61) Historically, oil, natural gas, and NGLs prices have been extremely volatile as illustrated above; we expect the volatility to continue given current economic conditions. To achieve a 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. We are not under an obligation to hedge a specific portion of our oil or natural gas production. 58 Our positions hedging production as of December 31, 2015 were as follows: Description and Production Period Crude Oil Put Spreads: Jan 2016 - Feb 2016................................... Jan 2016 - Feb 2016................................... Jan 2016 - Feb 2016................................... Jan 2016 - Feb 2016................................... Jan 2016 - Mar 2016 .................................. Jan 2016 - Jun 2016 ................................... Jan 2016 - Dec 2016 .................................. Mar 2016 - Jun 2016 .................................. Apr 2016 - Jun 2016 .................................. Jun 2016 - Dec 2016 .................................. Jul 2016 - Sept 2016 .................................. Jul 2016 - Dec 2016 ................................... Aug 2016 - Dec 2016 ................................. Oct 2016 - Dec 2016 .................................. Jan 2017 - Jun 2017 ................................... Jan 2017 - Jun 2017 ................................... Crude Oil Basis Swaps: Jul 2016 - Dec 2016 ................................... Jul 2016 - Dec 2016 ................................... Jan 2017 - Dec 2017 .................................. Jan 2017 - Dec 2017 .................................. Jul 2017 - Dec 2017 ................................... Jul 2016 - Dec 2016 ................................... Jul 2016 - Dec 2016 ................................... Jan 2017 - Dec 2017 .................................. Jan 2017 - Dec 2017 .................................. Jul 2016 - Dec 2016 ................................... Jan 2017 - Dec 2017 .................................. VOLUME (Bbls) SHORT PUT PRICE ($/Bbl) LONG PUT PRICE ($/Bbl) DIFFERENTIAL PRICE 35.00 $ 30.00 $ 30.00 $ 55.00 $ 30.00 $ 35.00 $ 35.00 $ 30.00 $ 30.00 $ 35.00 $ 40.00 $ 40.00 $ 35.00 $ 40.00 $ 40.00 $ 37.50 $ 70,000 $ 240,000 $ 240,000 $ 240,000 $ 585,000 $ 300,000 $ 1,500,000 $ 700,000 $ 585,000 $ 525,000 $ 75,000 $ 2,460,000 $ 250,000 $ 180,000 $ 900,000 $ 1,434,000 $ 210,000 180,000 600,000 360,000 180,000 368,000 390,000 960,000 1,095,000 368,000 1,095,000 60.00 45.00 50.00 40.00 45.00 60.00 50.00 40.00 40.00 50.00 55.00 55.00 50.00 55.00 55.00 52.50 $ $ $ $ $ $ $ $ $ $ $ (1.40) (1.35) (1.70) (1.60) (1.65) (0.35) (1.40) (1.65) (0.40) (0.30) (0.45) We will recognize the following income (expense) in the line item Derivative income (loss) on our consolidated and combined statements of operations from net cash premiums (paid) received on options that settled during the following periods: Q1 2016 ...................................................................................... $ Q2 2016 ...................................................................................... $ Q3 2016 ...................................................................................... $ Q4 2016 ...................................................................................... $ Q1 2017 ...................................................................................... $ Q2 2017 ...................................................................................... $ Q3 2017 ...................................................................................... $ Q4 2017 ...................................................................................... $ 7,828 7,768 (2,754 ) (2,982 ) (505 ) (505 ) (1,238 ) (1,238 ) 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 59 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. 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. 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 12-month period after drilling is complete. General and Administrative Expenses. These are costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our 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 in general and administrative expenses is compensation expense incurred as a result of our corporate reorganization and IPO and stock based compensation. 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 previously our 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. Adjusted EBITDAX Adjusted EBITDAX is not a measure of net income as determined by GAAP. Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated and combined financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as net (loss) income before DD&A, exploration costs, impairment, acquisition costs, loss (gain) on sales of oil and natural gas properties, asset retirement obligation accretion expense, stock based compensation, net interest expense, income tax (benefit) expense, rig termination, prepayment premium on extinguishment of debt, inventory write down, (income) loss on derivative instruments, net settlements on derivative instruments, and premium realization on options that settled during the period. Management believes Adjusted EBITDAX is useful because it allows 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 EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components 60 of Adjusted EBITDAX. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measure of other companies. We believe that Adjusted EBITDAX is 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 and a reconciliation of Adjusted EBITDAX to the GAAP financial measure of net income, please read “Item 6. 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: Recent Transactions The historical results of operations through May 29, 2014 are based on the financial statements of our accounting predecessor, which reflects the combined results of Parsley LLC, prior to the IPO and the concurrent corporate reorganization (“Corporate Reorganization”), which increased the scope of our operations. On February 5, 2015, we entered into an agreement to sell 14,885,797 shares of our Class A Common Stock in the 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 gross proceeds of approximately $230.7 million to us and net proceeds, after deducting underwriting discounts and commissions and offering expenses, of approximately $224.0 million. The net proceeds were used to repay a portion of outstanding borrowings under our Revolving Credit Agreement and for general corporate purposes. On September 18, 2015, we entered into an agreement to sell 14,950,000 shares of our Class A Common Stock at a price of $15.00 per share in an underwritten public offering. The September Offering resulted in gross proceeds of approximately $224.3 million to us and net proceeds, after deducting underwriting discounts and commissions and offering expenses, of approximately $217.0 million. A portion of the net proceeds was used to repay borrowings outstanding under our Revolving Credit Agreement, and the remainder of the net proceeds were used to fund a portion of our capital program, including acquisitions. On December 9, 2015, the Company and NGP entered into an agreement to sell 14,202,500 shares of Class A Common Stock, including 12,911,364 shares of Class A Common Stock issued and sold by the Company and 1,291,136 shares of Class A Common Stock sold by NGP, at a price of $18.00 per share in an underwritten public offering (the “December Offering”). On December 10, 2015, the Underwriters exercised in full their option to purchase additional shares. The December Offering resulted in gross proceeds of approximately $228.7 million to the Company and net proceeds, after deducting underwriting discounts and commissions and offering expenses, of approximately $228.4 million. A portion of the net proceeds from the offering was used to fund the acquisition described below, and the remaining net proceeds were used to fund a portion of our capital program and for general corporate purposes. We did not receive any of the proceeds from the sale of shares by NGP. During January 2016, we used a portion of the proceeds from the December Offering to acquire certain undeveloped acreage and producing oil and gas properties located adjacent to our existing operating areas in Upton, Reagan, and Glasscock Counties for an aggregate purchase price of $148.5 million, of which a deposit of $10.0 million was paid in December 2015. The acquisition added 260 gross (227 net) horizontal drilling locations across 6,040 gross (5,274 net) surface acres and production from three producing horizontal wells. The acquisition also included one drilled horizontal well that was completed by the seller prior to the transaction closing. Incentive Unit Compensation For the years ended December 31, 2014 and 2013, within general and administrative expenses, 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 NGP, through NGP and other preferred investors, including all of our executive officers. At December 31, 2014 and 2013, 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. There were no such costs incurred during the year ended December 31, 2015. 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 61 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 Stock based compensation includes amortization expense related to grants from our 2014 Long Term Incentive Plan. Refer to Note 9—Stock Based Compensation to our consolidated and combined financial statements included elsewhere in this Annual Report for additional discussion. Public Company Expenses We 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 prior to the Corporate Reorganization. Impairment of Oil and Gas Properties Proved oil and gas properties are reviewed for impairment quarterly or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. We estimate the expected future cash flows of our oil and gas properties and compare the undiscounted cash flows to the carrying amount of the oil and gas properties, on a field-by-field basis, to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the oil and gas properties to estimated fair value. As a result of lower commodity prices and their impact on our estimated future cash flows, we have continued to review our proved oil and natural gas properties for impairment. During the period ended December 31, 2015 we recognized an impairment of our proved oil and gas properties of $1.0 million and did not recognize an impairment during the period ended December 31, 2014. At December 31, 2015, in our significant fields that comprise 99% of our carrying value, our expected undiscounted future cash flows exceeded the carrying value of our proved oil and gas properties by an average of 119% and individually a minimum of 6%. At December 31, 2014, in our significant fields that comprise 99% of our carrying value, our expected undiscounted future cash flows exceeded the carrying value of our proved oil and gas properties by an average of 66% and individually a minimum of 59%. The key assumptions used to determine the undiscounted future cash flows include, but are not limited to, future commodity prices, based on 5-year WTI futures price index for oil and NGLs and 5-year Henry Hub futures price index for natural gas, price differentials, future production estimates, estimated future capital expenditures and estimated future operating expenses. All inputs remained relatively consistent in the undiscounted future cash flow estimate from December 31, 2015 to December 31, 2014 except commodity price estimates. Future commodity pricing for oil and NGLs is based on five-year WTI futures prices, which decreased 25% from December 31, 2014 to December 31, 2015, and on five-year Henry Hub futures prices, which decreased 21% from December 31, 2014 to December 31, 2015. In terms of the reduction in value of undiscounted cash flows from December 31, 2014 to December 31, 2015, the effect of the decrease in pricing has been mitigated to a certain extent by the addition of both proved developed and proved undeveloped reserves through our continued drilling and completion of previously unproved oil and natural gas properties. As part of our year-end reserves estimation process for future periods, we expect changes in the key assumptions used, which could be significant, including updates to future pricing estimates and differentials, future production estimates to align with our anticipated five-year drilling plan and changes in our capital costs and operating expense assumptions, which we expect to decrease further as a result of sustained lower commodity prices. There is a significant degree of uncertainty with the assumptions used to estimate future undiscounted cash flows due to, but not limited to the risk factors referred to in Item 1A. Risk Factors included elsewhere in this Annual Report. Any decrease in pricing, negative change in price differentials, increase in capital or operating costs could negatively impact the estimated undiscounted cash flows related to our proved oil and natural gas properties. A decrease of 10% in estimated future pricing of oil and natural gas commodities as of December 31, 2015 would have resulted in an estimated additional impairment of proved oil and gas properties of $46.9 million. 62 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 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 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 of 1986, as amended, 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 revenues less operating expenses attributable to operations in Texas. Drilling Activity. We began drilling operations in November 2009. As of December 31, 2015, we operated four horizontal drilling rigs and two vertical drilling rig on our properties. For the year ended December 31, 2015, our capital expenditures for drilling and completions were $400.9 million, as compared to $491.3 million for all of fiscal year 2014. 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. 63 Results of Operations Year ended December 31, 2015 Compared to Year ended December 31, 2014 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 2015 $ Change % Change Revenues (in thousands, except percentages): Oil sales ........................................................................................ $ Natural gas sales ........................................................................... Natural gas liquids sales ............................................................... Total revenues ......................................................................... $ 215,795 $ 26,582 23,680 266,057 $ 232,554 $ 30,642 38,561 301,757 $ (16,759 ) (4,060 ) (14,881 ) (35,700 ) Average realized prices(1): Oil sales, without realized derivatives (per Bbls) ......................... $ Oil sales, with realized derivatives (per Bbls) .............................. Natural gas, without realized derivatives (per Mcf) ..................... Natural gas, with realized derivatives (per Mcf) .......................... NGLs sales (per Boe) ................................................................... Average price per Boe, without realized derivatives .................... Average price per Boe, with realized derivatives ......................... Production: Oil (MBbls) .................................................................................. Natural gas (MMcf) ...................................................................... Natural gas liquids (MBoe) .......................................................... Total (MBoe)(2) ........................................................................... Average daily production volume: Oil (Bbls) ...................................................................................... Natural gas (Mcf) ......................................................................... Natural gas liquids (Boe) .............................................................. Total (Boe/d) ................................................................................ $ 44.89 56.60 2.57 2.72 15.79 33.13 40.33 4,807 10,339 1,500 8,031 13,170 28,326 4,110 22,003 $ 81.91 81.33 4.23 4.32 33.83 58.19 58.00 2,839 7,245 1,140 5,186 7,778 19,849 3,123 14,207 (37.02 ) (24.73 ) (1.66 ) (1.60 ) (18.04 ) (25.06 ) (17.66 ) 1,968 3,094 360 2,845 5,392 8,477 987 7,796 (7)% (13)% (39)% (12)% (45)% (30)% (39)% (37)% (53)% (43)% (30)% 69% 43% 32% 55% 69% 43% 32% 55% (1) Average prices shown in the table reflect prices both before and after the effects of our realized commodity hedging transactions. Our calculation of such effects includes both realized gains and losses on cash settlements for commodity derivative transactions and premiums paid or received on options that settled during the period. (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. 64 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 ................................... Average realized NGLs price ($/Boe) ................................................................ $ Average NYMEX ($/Boe) ............................................................................ $ Differential to NYMEX ................................................................................ $ Average realized NGLs price to NYMEX oil percentage ............................. Year Ended December 31, 2015 2014 44.89 $ 48.08 $ (3.19 ) $ 93 % 2.57 $ 2.50 $ 0.07 $ 103 % 15.79 $ 48.08 $ (32.29 ) $ 33 % 81.91 80.27 1.65 102% 4.23 4.52 (0.29) 94% 33.83 80.27 (46.44) 42% Oil revenues decreased 7% to $215.8 million during the year ended December 31, 2015 from $232.6 million during the year ended December 31, 2014. The decrease is attributable to a $37.02 per barrel decrease in average oil prices offset by an increase in oil production volumes of 1,968 MBbls. Of the overall changes in oil revenues, the decrease in oil prices accounted for a negative change of $178.0 million, offset by the increase in oil production volumes, which accounted for a positive change of $161.2 million. Natural gas revenues decreased 13% to $26.6 million during the year ended December 31, 2015 from $30.6 million during the year ended December 31, 2014. The decrease is attributable to a $1.66 per Mcf decrease in average natural gas prices, offset by an increase in volumes sold of 3,094 Mcf. Of the overall changes in natural gas revenues, the decrease in price accounted for a negative change of $17.2 million, offset by increases in natural gas production volumes, which accounted for a positive change of $13.1 million. NGLs revenues decreased by 39% to $23.7 million during the year ended December 31, 2015 from $38.6 million during the year ended December 31, 2014. The decrease is attributable to an $18.04 per Boe decrease in average NGLs price in addition to a 360 Boe increase in NGLs production. Of the overall changes in NGLs revenues, the decrease in NGLs average price accounted for a negative change of $27.1 million and the increase in production volumes accounted for a positive change of $12.2 million. 65 Operating Expenses. The following table summarizes our expenses for the periods indicated: Operating expenses (in thousands,(cid:3) except percentages): Lease operating expenses ........................................................ $ Production and ad valorem taxes ............................................ Depreciation, depletion and amortization ............................... General and administrative expenses (1) ................................ Exploration costs ..................................................................... Impairment .............................................................................. Acquisition costs ..................................................................... Accretion of asset retirement obligations ................................ Rig termination costs .............................................................. Other operating expenses ........................................................ Total operating expenses ................................................... $ Expense per Boe: Lease operating expenses ........................................................ $ Production and ad valorem taxes ............................................ Depreciation, depletion and amortization ............................... General and administrative expenses ...................................... Exploration costs ..................................................................... Impairment .............................................................................. Acquisition costs ..................................................................... Accretion of asset retirement obligations ................................ Rig termination costs .............................................................. Other operating expenses ........................................................ Total operating expenses per Boe ...................................... $ Year ended December 31, 2015 2014 $ Change % Change 62,913 $ 17,800 178,281 55,294 13,865 950 — 826 8,970 1,696 340,595 $ $ 7.83 2.22 22.20 6.89 1.73 0.12 — 0.10 1.12 0.21 42.42 $ 38,071 $ 18,941 94,297 87,949 3,136 — 2,527 512 765 — 246,198 $ $ 7.34 3.65 18.18 16.96 0.39 — 0.49 0.10 0.15 — 47.26 $ 24,842 (1,141 ) 83,984 (32,655 ) 10,729 950 (2,527 ) 314 8,205 1,696 94,397 0.49 (1.43 ) 4.02 (10.07 ) 1.34 0.12 (0.49 ) — 0.97 0.21 (4.84 ) 65% (6)% 89% (37)% * 100% (100)% 61% * 100% 38% 7% (39)% 22% (59)% * 100% (100)% —% * 100% (10)% (1) General and administrative expenses include stock based compensation expense of $8.1 million and $53.3 million for the years ended December 31, 2015 and 2014, respectively. The percentage change is not considered meaningful. * Lease Operating Expenses. Lease operating expenses increased 65% to $62.9 million during the year ended December 31, 2015 from $38.1 million during the year ended December 31, 2014. The increase is primarily due to the higher operated well count during the year ended December 31, 2015 as compared to the prior year period. On a per Boe basis, lease operating expenses increased $0.49 per Boe, or 7%, to $7.83 per Boe for the year ended December 31, 2015 from $7.34 per Boe for the year ended December 31, 2014. This increase was attributable an increase in costs for workovers offset by a decrease in disposal costs. Production and Ad Valorem Taxes. Production and ad valorem taxes decreased 6% to $17.8 million during the year ended December 31, 2015 from $18.9 million during the year ended December 31, 2014. On a per Boe basis, production and ad valorem taxes decreased $1.43 per Boe, or 39%, to $2.22 per Boe for the year ended December 31, 2015 from $3.65 per Boe for the year ended December 31, 2014. The decreases are directly related to the decrease in oil, natural gas, and NGLs revenues for the same period. Depreciation, Depletion and Amortization. DD&A expense increased by 89% to $178.3 million for the year ended December 31, 2015 from $94.3 million for the year ended December 31, 2014. On a per Boe basis, DD&A increased $4.02 per Boe, or 22% to $22.20 for the year ended December 31, 2015 from $18.18 per Boe during the year ended December 31, 2014. The increases are due to an increase in proved capitalized costs primarily related to development costs incurred during the year ended December 31, 2015 and multiple oil and gas acquisitions. General and Administrative Expenses. General and administrative expenses decreased 37% to $55.3 million during the year ended December 31, 2015 from $87.9 million during the year ended December 31, 2014 primarily due to the $51.1 million expense recognized in conjunction with our Corporate Reorganization and IPO during the year ended December 31, 2014, which is offset by increased professional fees and consultant costs incurred related to our status as a public company as well as increased rent expense 66 for our new corporate headquarters. On a per Boe basis, general and administrative expenses decreased $10.07 per Boe, or 59%, to $6.89 per Boe for the year ended December 31, 2015 from $16.96 per Boe for the year ended December 31, 2014. Exploration Costs. The following table provides a breakdown of exploration costs incurred during the years ended December 31, 2015 and 2014. Geological and geophysical costs ........................................... $ Leasehold abandonments ........................................................ Unproved leasehold amortization............................................ Total exploration costs ............................................................ $ Year Ended December 31, 2015 2014 (in thousands) 5,459 8,227 179 13,865 $ $ 2,394 430 312 3,136 Our geological and geophysical expenses primarily consist of the costs of acquiring and processing seismic data, geophysical data and core analysis, primarily relating to increased geoscientific analysis of our Delaware Basin assets. During the year ended December 31, 2015, we acquired additional geological and geophysical data related to our Delaware Basin acreage. During the year ended December 31, 2015, we recognized leasehold abandonment expenses of approximately $8.2 million, of which $6.4 million primarily relates to expired acreage and expiring acreage determined to be outside of our economically productive reserves. We also recognized a $1.8 million expense, which includes costs incurred to prepare a certain location for drilling that, based on our historical results and our estimates of reduced future commodity prices, we have no future intent to drill based on low rates of return. Impairment. We regularly review our long-lived assets to be held and used, including proved oil and natural gas properties accounted for under the successful efforts method of accounting. Due primarily to a decrease in our estimated future cash flows related to management’s outlook of future commodity prices and costs, we recognized a charge against earnings of $1.0 million during the year ended December 31, 2015, which was primarily attributable to properties in Upton County in our Midland Basin core area. Acquisition Costs. Acquisition costs during the year ended December 31, 2014 are attributable to a one time advisory and valuation fee related to the Cimarex Acquisition, as described in Note 5—Acquisitions of Oil and Gas Properties of our consolidated and combined financial statements included elsewhere in this Annual Report. Rig Termination. Rig termination costs increased $8.2 million to $9.0 million during the year ended December 31, 2015 from $0.8 million during the year ended December 31, 2014. The increase is related to additional termination costs incurred during the year ended December 31, 2015 including approximately $4.4 million related to the termination of drilling rig contracts entered into in 2014 and approximately $4.6 million for stacking fees associated with certain drilling rig contracts. Other Operating Expenses. During the year ended December 31, 2015, other operating expenses were approximately $1.7 million, which are related to operating expenses incurred during the normal course of business of our majority-owned subsidiary, Pacesetter Drilling, LLC. There were no such expenses incurred during the year ended December 31, 2014. 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 ................................................................ $ Loss on sale of property .......................................................... Prepayment premium on extinguishment of debt .................... Derivative income (loss) ......................................................... Other income (expense) .......................................................... Total other income (expense), net ..................................... $ * The percentage change is not considered meaningful. Year ended December 31, 2015 2014 $ Change % Change (45,581) $ (34,374) — 60,818 (3,111) (22,248) $ (39,624) $ (2,097) (5,107) 83,858 601 37,631 $ (5,957 ) (32,277 ) 5,107 (23,040 ) (3,712 ) (59,879 ) (15)% * 100% (27)% * (159)% 67 Interest Expense. Interest expense increased 15% to $45.6 million in the year ended December 31, 2015 from $39.6 million during the year ended December 31, 2014 primarily due to higher weighted-average outstanding borrowings under our credit facilities and interest under our Senior Notes due 2022 (the “Notes”). Loss on sale of property. Loss on sale of property increased $32.3 million in the year ended December 31, 2015 to $34.4 million from $2.1 million during the year ended December 31, 2014. This increase is attributable to the following divestiture activity: In December 2015, the Company sold its interest in 91 operated wells and 11,664 gross (7,155 net) acres for net proceeds of $39.4 million and realized a $36.7 million dollar loss, net of estimated purchase price adjustments. In July 2015, the Company sold 9,164 net acres for total proceeds of $9.3 million and recognized a gain on the sale of $3.2 million. In July 2015, Pacesetter, our majority-owned subsidiary sold certain noncurrent assets for net proceeds of $1.2 million and realized a $2.0 million loss 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. 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, 2015. Derivative Income (Loss). Income from derivative instruments decreased $23.0 million during the year ended December 31, 2015 to $60.8 million during the year ended December 31, 2015 from $83.9 million during the year ended December 31, 2014, primarily as a result of the impact of additional trades entered into during the year. We elected to lower certain strike prices for both long and short put positions during the year ended December 31, 2015. By lowering the strike prices for the put spreads, we collected approximately $87.7 million of cash for 15,539 notional MBbls. Other Income (Expense). Other expense decreased $3.7 million to an expense of $3.1 million during the year ended December 31, 2015 from income of $0.6 million during the year ended December 31, 2014 due to a $4.1 million reduction in inventory related to multiple inventory trades and a fair market value adjustment. In addition, our income from our equity investment in Spraberry Production Services LLC decreased by approximately $0.6 million, which is offset by a $1.1 million increase attributable to license fee income. Income Tax Expense For the year ended December 31, 2015, our operations were taxed at a combined U.S. federal and state effective tax rate of 24.5%. 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, 2015, we recognized an income tax benefit of $23.8 million, an increase of $60.3 million, or 165%, as compared to the income tax expense of $36.5 million we recognized during the year ended December 31, 2014. This increase was attributable to the corresponding decrease in net income during the applicable periods, as discussed above. During the year ended December 31, 2015, we were subject to the federal income tax rate for the entire period as compared to only the seven-month period subsequent to our IPO for the year ended December 31, 2014. 68 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, 2013 2014 $ Change % Change Revenues (in thousands, except percentages): Oil sales .................................................................................. $ Natural gas sales .................................................................... Natural gas liquids sales ......................................................... Total revenues .................................................................. $ 232,554 $ 30,642 38,561 301,757 $ 97,839 $ 23,179 — 121,018 $ 134,715 7,463 38,561 180,739 Average realized prices(1): Oil sales, without realized derivatives (per Bbls) ................... $ Oil sales, with realized derivatives (per Bbls) ........................ Natural gas, without realized derivatives (per Mcf) ............... Natural gas, with realized derivatives (per Mcf) .................... NGLs sales (per Bbls) ............................................................ Average price per Boe, without realized derivatives.............. Average price per Boe, with realized derivatives ................... Production: Oil (MBbls) ............................................................................ Natural gas (MMcf) ............................................................... Natural gas liquids (MBoe) .................................................... Total (MBoe)(2) ..................................................................... Average daily production volume: Oil (Bbls) ............................................................................... Natural gas (Mcf) ................................................................... Natural gas liquids (Boe) ....................................................... Total (Boe/d) .......................................................................... $ 81.91 81.33 4.23 4.32 33.83 58.19 58.00 2,839 7,245 1,140 5,186 7,778 19,849 3,123 14,207 $ 93.28 87.91 4.95 4.95 — 66.17 63.09 1,049 4,680 — 1,829 2,874 12,822 — 5,011 (11.37 ) (6.58 ) (0.72 ) (0.64 ) 33.82 (7.97 ) (5.09 ) 1,790 2,565 1,140 3,357 4,904 7,027 3,123 9,196 138% 32% 100% 149% (12)% (7)% (15)% (13)% 100% (12)% (8)% 171% 55% 100% 184% 171% 55% 100% 184% (1) Average prices shown in the table reflect prices both before and after the effects of our realized commodity hedging transactions. Our calculation of such effects includes both realized gains and losses on cash settlements for commodity derivative transactions and premiums paid or received on options that settled during the period. (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. 69 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 ................................................. Average realized NGLs price ($/Boe) .............................................................................. $ Average NYMEX ($/Boe) .......................................................................................... $ Differential to NYMEX .............................................................................................. $ Average realized NGLs price to NYMEX oil percentage .......................................... Year Ended December 31, 2014 2013 81.91 $ 80.27 $ 1.65 $ 102 % 4.23 $ 4.52 $ (0.29 ) $ 94 % 33.83 $ 80.27 $ (46.44 ) $ 42 % 93.28 98.61 (5.33) 95% 4.95 3.79 1.16 131% — 98.61 (98.61) 0% 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 revenue increase is attributable to an increase in oil production volumes of 1,790 MBbls offset by a decrease in average oil prices of $11.37 per barrel. Of the overall changes in oil sales, increases in oil production volumes accounted for a positive change of $167.0 million while the decrease in oil prices accounted for a negative change of $32.3 million. Natural gas revenues increased 32% to $30.6 million during the year ended December 31, 2014 from $23.2 million during the year ended December 31, 2013. The revenue increase is primarily a result of an increase in natural gas production volumes sold of 2,565 MMcf offset by a decrease in average natural gas prices of $0.72 per Mcf. Of the overall changes in natural gas sales, increases in production volume accounted for a positive change of $12.7 million while the decrease in natural gas price accounted for a negative change of $5.2 million. NGLs revenues increased $38.6 million during the year ended December 31, 2014. The revenue increase is primarily a result of an increase in volumes sold of 1,140 Boe due to not separately recording NGLs in 2013. 70 Operating Expenses. The following table summarizes our expenses for the periods indicated: Operating expenses (in thousands,(cid:3) except percentages): Lease operating expenses ....................................................... $ Production and ad valorem taxes ........................................... Depreciation, depletion and amortization .............................. General and administrative expenses (1) ............................... Exploration costs .................................................................... Acquisition costs .................................................................... Accretion of asset retirement obligations ............................... Rig termination costs ............................................................. 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 .................................................................... Accretion of asset retirement obligations ............................... Rig termination costs ............................................................. Total operating expenses per Boe ..................................... $ Year ended December 31, 2013 2014 $ Change % Change 38,071 $ 18,941 94,297 87,949 3,136 2,527 512 765 246,198 $ 7.34 $ 3.65 18.18 16.96 0.60 0.49 0.10 0.15 47.47 $ 16,572 $ 7,081 28,152 16,553 — — 181 — 68,539 $ 9.06 $ 3.87 15.39 9.05 — — 0.10 — 37.47 $ 21,499 11,860 66,145 71,396 3,136 2,527 331 765 177,659 (1.72 ) (0.22 ) 2.79 7.91 0.60 0.49 — 0.15 10.00 130% 167% * * 100% 100% 183% 100% * (19)% (6)% 18% 87% 100% 100% —% 100% 27% (1) General and administrative expenses include stock based compensation expense of $53.3 million and $1.2 million for the years ended December 31, 2014 and 2013, respectively. The percentage change is not considered meaningful. * 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 to $94.3 million for the year ended December 31, 2014 from $28.2 million during the year ended December 31, 2013. On a per Boe basis, DD&A increased $2.79, or 18%, to $18.18 per Boe for the year ended December 31, 2014 from $15.39 per Boe for the year ended December 31, 2013. The increases are due to an increase in capitalized costs from multiple acquisitions and development costs as well as production volumes. General and Administrative Expenses. General and administrative expenses increased $71.4 million to $88.0 million during the year ended December 31, 2014 from $16.6 million during the year ended December 31, 2013. On a per Boe basis, general and administrative expenses increased $7.91, or 87%, to $16.96 per Boe for the year ended December 31, 2014 from $9.05 for the year ended December 31, 2013. The increases are primarily due to the one-time $51.1 million incentive unit compensation expense recognized upon our Corporate Reorganization in 2014. In addition, we incurred higher payroll and payroll-related costs as we added additional personnel 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 leasehold impairment 71 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 5—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. 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. 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 ............................................................... $ (Loss) gain on sale of property............................................... Prepayment premium on extinguishment of debt ................... Derivative income (loss) ........................................................ Other income (expense) ......................................................... Total other expense, net ......................................................... $ * The percentage change is not considered meaningful. Year ended December 31, 2013 2014 $ Change % Change (39,624) $ (2,097) (5,107) 83,858 601 37,631 $ (13,733) $ 36 — (9,800) 434 (23,063) $ (25,891 ) (2,133 ) (5,107 ) 93,658 167 60,694 (189)% * (100)% * 38% 263% Interest Expense. Interest expense increased 189% to $39.6 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 Notes. (Loss) Gain on Sale of Property. (Loss) gain on sale of property decreased $2.1 million to a loss of $2.1 million for the year ended December 31, 2014 from a gain of $36 thousand during the year ended December 31, 2013. The decrease is attributable to the following divestiture activity: 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 thousand gain on the sale. 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. Income Tax Expense For the year ended December 31, 2014, our operations were 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 income tax expense of $36.5 million, an increase of $34.6 million, as compared to the income tax expense of $1.9 million we recognized during the year ended December 31, 2013. This increase was attributable to the corresponding increase in net income during the applicable periods, as discussed above. 72 Capital Requirements and Sources of Liquidity For the year ended December 31, 2015, our aggregate drilling and completion capital expenditures were $400.9 million. During the year ended December 31, 2014, our aggregate drilling and completion capital expenditures were $491.3 million. These capital expenditure totals exclude acquisitions. Our 2016 capital budget for drilling and completion is approximately $380 million to $430 million. Our capital budget excludes any amounts that may be paid for acquisitions or leaseholds. The amount and timing of 2016 capital expenditures is largely discretionary and within our control. We could choose to defer a portion of these planned 2016 capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other working interest owners. To fund a portion of our capital requirements for the year ended December 31, 2015, we issued shares of our Class A Common Stock in connection with the Private Placement, the September Offering, and the December Offering. During the year ended December 31, 2015, we received aggregate net proceeds of $669.4 million from the issuances, and made aggregate net debt payments in excess of borrowings of $120.8 million. Based upon current oil and natural gas price expectations for the fiscal year 2016, 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 2016. 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. As of December 31, 2015, pro forma for the acquisition described in Recent Transactions, our liquidity is as follows: Cash ........................................................................................................... $ Cash paid for acquisition ........................................................................... Revolving Credit Agreement Availability ................................................. Liquidity .................................................................................................... $ 343.1 (148.5 ) 574.7 769.3 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, 2015 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 2016 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. We may from time to time seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for other debt or equity securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. Cash Flows The following table summarizes our cash flows for the periods indicated: Net cash provided by operating activities ..................... $ Net cash used in investing activities ............................. Net cash provided by financing activities ..................... 2015 Year Ended December 31, 2014 172,290 $ (427,165) 547,409 184,983 $ (1,247,677 ) 1,093,851 2013 53,235 (425,611) 378,096 73 Cash Flow Provided by Operating Activities. Net cash provided by operating activities was approximately $168.1 million, $185.0 million, and $53.2 million for the years ended December 31, 2015, 2014, and 2013, respectively. The $12.7 million decrease in operating cash flows to $172.3 million during the year ended December 31, 2015 from $185.0 million during the year ended December 31, 2014 is primarily due to a $35.7 million decrease in total revenues directly related to the 30%, or $24.73, decrease in crude oil prices, including the effect of derivatives, and a 65% increase in lease operating expenses to $62.9 million during the year ended December 31, 2015 from $38.1 million during the year ended December 31, 2014. This decrease is offset by a 6% reduction in production and ad valorem taxes to $17.8 million during the year ended December 31, 2015 from $18.9 million during the year ended December 31, 2014 which is directly related to the decrease in oil, natural gas and NGLs revenues for the same period. The $131.7 million increase in operating cash flows to $185.0 million during the year ended December 31, 2014 from $53.2 million during the year ended December 31, 2013 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%, or 1,790 MBbls, 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 spending resulting from an increase in drilling activity. Cash Flow Used in Investing Activities. Net cash used in investing activities was approximately $427.2 million, $1.2 billion, and $425.6 million for the years ended December 31, 2015, 2014, and 2013, respectively. The decrease in the amount of cash used in investing activities in the year ended December 31, 2015 as compared to the year ended December 31, 2014 is directly attributable to the $688.4 million decrease in acquisition activity as discussed in Note 5— Acquisition of Oil and Gas Properties, the decrease in cash payments for development costs, and offset by the $50.0 million increase related to proceeds received from the sale of oil and natural gas properties. The decrease during 2015 from 2014 is also due to fewer rigs operating during the year. The increase in the amount of cash used in investing activities in the year ended December 31, 2014 as compared to the year ended December 31, 2013 was due primarily to the $553.9 million increase in oil and gas acquisition activity as discussed in Note 5— Acquisition of Oil and Gas Properties and a $267.8 million increase in cash payments for development costs. The increases during 2014 over 2013 is 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 $547.4 million, $1.1 billion, and $378.1 million for the years ended December 31, 2015, 2014, and 2013, respectively. Net cash provided by financing activities decreased during the year ended December 31, 2015 primarily because of the $366.2 million increase in net debt payments in excess of borrowings during 2015 as compared to 2014. In addition our issuances of Class A Common Stock decreased by $198.3 million in 2015 as compared to issuances made in 2014. 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. Capital Sources Revolving Credit Agreement. See Note 7—Debt to our consolidated and combined financial statements included elsewhere in this Annual Report for a description of the Revolving Credit Agreement. 7.500% Senior Unsecured Notes due 2022. See Note7—Debt to our consolidated and combined financial statements 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. Working Capital. Our working capital totaled $259.8 million, ($16.7) million, and ($54.2) at December 31, 2015, 2014 and 2013, respectively. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. Our cash balances totaled $343.1 million, $50.6 million, and $19.4 million at December 31, 2015, 2014, and 2013, respectively. The $292.5 million increase in cash is primarily attributable to the receipt of proceeds for the sale of Class A Common Stock in conjunction with issuances of Class A Common Stock during the year as well as proceeds from the 74 divestiture of certain oil and natural gas properties, as described in Note 6—Sales of Oil and Natural 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 believe that our cash on hand, cash flow from operations and availability under our Revolving Credit Agreement, will be sufficient to fund our working capital needs. We expect that our pace of development, production volumes, commodity prices and differentials to NYMEX prices for our oil and natural gas production will be the largest variables affecting our working capital. Contractual Obligations Our contractual obligations include long-term debt, cash interest expense on debt, operating lease obligations, drilling commitments, derivative liabilities and other obligations. We had the following contractual obligations at December 31, 2015: 2016 2017 2018 2019 2020 Thereafter Total Payments Due by Period For the Year Ended December 31, — $ Revolving Credit Agreement(1) ........ $ 7.50% Senior Unsecured Notes due 2022 (1) .................................. — 951 Capital lease obligations (2) .............. Operating lease obligations (3) ......... 11,571 Drilling commitments (4) .................. 21,735 Asset retirement obligations(5) ......... 4,698 Derivative obligations(6) .................. 11,675 Total ............................................. $ 50,630 $ — $ — $ — $ — $ — $ — — 1,000 5,264 8,449 — 4,950 19,663 $ — 265 5,314 — 78 — 5,657 $ — — 5,398 — 708 — 6,106 $ — — 5,395 — 656 — 6,051 $ 550,000 — 21,102 — 12,079 — 583,181 $ 550,000 2,216 54,044 30,184 18,219 16,625 671,288 (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) During 2014 and 2015, we entered into capital lease agreements payable in connection with the lease of vehicles for operations and field personnel. (3) We lease vehicles, equipment and office facilities under non-cancellable operating leases. (4) 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. (5) Amounts represent estimates of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. (6) We enter into derivative agreements to hedge future production. We have deferred payment of the premium for certain agreements until the period of settlement. 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. 75 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 DD&A are removed from the property accounts, and any gain or loss is recognized. Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts. Estimated dismantlement and abandonment costs for oil and natural gas properties are capitalized, net of salvage, 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 12-month period after drilling is complete. Under the successful efforts method, if an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive. Unproved 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 Annual Report presents estimates of our proved reserves as of December 31, 2015, 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, 2015 was based on an unweighted first day of the month average 12- month WTI Plains posted price, net of differential, of $46.54 per Bbl for oil and $16.42 per Bbl for NGLs, and a WAHA spot natural gas price, net of differential, of $2.53 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 76 geophysical data, or other economic factors. We cannot predict the amounts or timing of future reserve revisions. If such revisions are significant, they could significantly alter future depletion and result in impairment of long-lived assets that may be material. It should not be assumed that the Standardized Measure included in this Annual Report as of December 31, 2015 is the current market value of our estimated proved reserves. In accordance with SEC requirements, we based the 2015 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. Asset Retirement Obligations We have significant obligations to remove tangible equipment and facilities associated with our oil and natural gas wells and our service wells, 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 review 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, 2015, 2014, or 2013. 77 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. We apply the provisions of the “Derivatives and Hedging” topic of ASC 815, 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 and combined 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 and combined 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, 2015, we had no material off-balance sheet arrangements. 78 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 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 production. Pricing for oil, has been especially volatile and unpredictable for several years, and this volatility is expected to continue in the future. The prices we receive for our oil production depends 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 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. We also may continue to enter into basis swap transactions. 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, 2015, the fair market value of our oil derivative contracts was a net asset of $76.1 million. Based on our open oil derivative positions at December 31, 2015, a 10% increase in the NYMEX WTI price would decrease our net oil derivative asset by approximately $18.4 million, while a 10% decrease in the NYMEX WTI price would increase our net oil derivative asset by approximately $19.9 million. Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview—Realized Prices on the Sale of Oil, Natural Gas and NGLs.” Counterparty Risk Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require our counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as 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. The majority 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. As of December 31, 2015, however, we had no outstanding borrowings related to our Revolving Credit Agreement, and therefore an increase in interest rates will not result in increased interest expense until such time that we determine to make borrowings under our Revolving Credit Agreement. 79 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA PARSLEY ENERGY, INC. AND SUBSIDIARIES Our consolidated and combined financial statements and supplementary data are included in this Annual Report beginning on page F-1. ITEM 9. None. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 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, 2015. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2015, at the reasonable assurance level. Management’s Annual Report on Internal Control over Financial Reporting and Attestation Report of the Registered Public Accounting Firm Our management, including our principal executive officer and principal financial officer, is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Exchange Act. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated and combined financial statements for external purposes in accordance with GAAP. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Our management assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2015, using the criteria in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, our management believes that our internal control over financial reporting was effective as of December 31, 2015. This Annual Report includes an attestation report of KPMG LLP, our independent registered public accounting firm, on our internal control over financial reporting as of December 31, 2015, which is included in the Annual Report on page F-3. Changes in Internal Control over Financial Reporting There were no changes in our system of internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d- 15(f) under the Exchange Act) during the quarter ended December 31, 2015, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. ITEM 9B. OTHER INFORMATION None. 80 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 2016 annual meeting of stockholders and is incorporated herein by reference. Section 16(a) Beneficial Ownership Reporting Compliance The information required in response to this item will be set forth in our definitive proxy statement for the 2016 annual meeting of stockholders and is incorporated herein by reference. ITEM 11. EXECUTIVE COMPENSATION The information required in response to this item will be set forth in our definitive proxy statement for the 2016 annual meeting of stockholders and is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS The information required in response to this item will be set forth in our definitive proxy statement for the 2016 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 2016 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 2016 annual meeting of stockholders and is incorporated herein by reference. 81 PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES 1. The following documents are filed as part of this Annual Report or incorporated by reference: a. Financial Statements: 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. b. Financial Statement Schedules: All financial statement schedules have been omitted because they are not applicable or the required information is presented in the consolidated and combined financial statements and related notes 2. Exhibits The exhibits required to be filed by this Item 15 are set forth in the Exhibit Index included within this Annual Report. 82 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# 2.6# 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). Asset Purchase Agreement, dated October 20, 2015, by and between Parsley Energy, L.P. and ExL Petroleum Management, LLC (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on December 16, 2015). 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). 83 Exhibit No. 10.4* Third Amendment to Amended and Restated Credit Agreement, dated as of April 15, 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. Description 10.5* 10.6 10.7 10.8 10.9 10.10 Fourth Amendment to Amended and Restated Credit Agreement, dated as of May 2, 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. 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 (incorporated by reference to Exhibit 10.5 to the Company’s Annual Report on Form 10-K, File No. 001-36463, filed with the SEC on March 11, 2015). 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). Eighth Amendment to Amended and Restated Credit Agreement, dated as of April 21, 2015, 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 the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on April 27, 2015). Ninth Amendment to Amended and Restated Credit Agreement, dated as of November 3, 2015, 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 the Company’s Quarterly Report on Form 10-Q, File No. 001-36463, filed with the SEC on November 6, 2015). 10.11† 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). 10.12*† Employment Agreement, dated as of February 4, 2014, by and between Parsley Energy Operations, LLC and Ryan Dalton. 10.13† 10.14† 10.15† 10.16 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). Employment Agreement, dated as of December 8, 2014, by and between Parsley Energy Operations, LLC and Thomas Layman (incorporated by reference to Exhibit 10.12 to the Company’s Annual Report on Form 10-K, File No. 001-36463, filed with the SEC on March 11, 2015). 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). 84 Exhibit No. 10.17 Description 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). 10.18 10.19† 10.20† 10.21† 10.22† 10.23† 10.24† 10.25† 10.26† 10.27† 10.28† 10.29† 10.30† 10.31† Tax Receivable Agreement, dated as of May 29, 2014, by and among Parsley Energy, Inc., certain members of Parsley Energy, LLC and Bryan Sheffield (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on June 4, 2014). Indemnification Agreement, dated as of May 14, 2014, by and between Parsley Energy, Inc. and Bryan Sheffield (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on June 4, 2014). Indemnification Agreement, dated as of May 14, 2014, by and between Parsley Energy, Inc. and Ryan Dalton (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on June 4, 2014). Indemnification Agreement, dated as of May 14, 2014, by and between Parsley Energy, Inc. and Michael Hinson (incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on June 4, 2014). Indemnification Agreement, dated as of May 14, 2014, by and between Parsley Energy, Inc. and Matt Gallagher (incorporated by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on June 4, 2014). Indemnification Agreement, dated as of May 14, 2014, by and between Parsley Energy, Inc. and Paul Treadwell (incorporated by reference to Exhibit 10.7 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on June 4, 2014). Indemnification Agreement, dated as of May 14, 2014, by and between Parsley Energy, Inc. and Thomas Layman (incorporated by reference to Exhibit 10.8 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on June 4, 2014). Indemnification Agreement, dated as of May 14, 2014, by and between Parsley Energy, Inc. and Colin Roberts (incorporated by reference to Exhibit 10.9 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on June 4, 2014). Indemnification Agreement, dated as of May 14, 2014, by and between Parsley Energy, Inc. and Chris Carter (incorporated by reference to Exhibit 10.10 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on June 4, 2014). Indemnification Agreement, dated as of May 14, 2014, by and between Parsley Energy, Inc. and David Smith (incorporated by reference to Exhibit 10.11 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on June 4, 2014). Indemnification Agreement, dated as of May 14, 2014, by and between Parsley Energy, Inc. and A.R. Alameddine (incorporated by reference to Exhibit 10.12 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on June 4, 2014). Indemnification Agreement, dated as of May 14, 2014, by and between Parsley Energy, Inc. and Randy Newcomer (incorporated by reference to Exhibit 10.13 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on June 4, 2014). Indemnification Agreement, dated as of July 23, 2014, by and between Parsley Energy, Inc. and Hemang Desai (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on July 24, 2014). Indemnification Agreement, dated as of August 19, 2014, by and between Parsley Energy, Inc. and William Browning (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 001-36463, filed with the SEC on August 25, 2014). 10.32*† Indemnification Agreement, dated as of August 19, 2014, by and between Parsley Energy, Inc. and Brad Smith. 10.33*† Indemnification Agreement, dated as of January 1, 2016, by and between Parsley Energy, Inc. and Cecilia Camarillo. 85 Exhibit No. 10.34† Amended and Restated Parsley Energy, Inc. 2014 Long Term Incentive Plan (incorporated by reference to Exhibit 10.30 to the Company’s Annual Report on Form 10-K, File No. 001-36463, filed with the SEC on March 11, 2015). Description 10.35† 10.36† 10.37† 10.38† 10.39† 10.40† 10.41 10.42 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). Form of Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.34 to the Company’s Annual Report on Form 10-K, File No. 001-36463, filed with the SEC on March 11, 2015). Form of Notice of Grant of Restricted Stock Units (Time-Based) (incorporated by reference to Exhibit 10.35 to the Company’s Annual Report on Form 10-K, File No. 001-36463, filed with the SEC on March 11, 2015). Form of Notice of Grant of Restricted Stock Units (Performance-Based) (incorporated by reference to Exhibit 10.36 to the Company’s Annual Report on Form 10-K, File No. 001-36463, filed with the SEC on March 11, 2015). 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 Labels Linkbase Document. † Management contract or compensatory plan or agreement * Filed herewith. 86 ** # Furnished herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this Annual Report on Form 10-K and not “filed” as part of such report for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, except to the extent that the registrant specifically incorporates it by reference. Schedules and similar attachments have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The registrant will furnish a supplemental copy of any omitted schedule or similar attachment to the Commission upon request. 87 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. February 29, 2016 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. February 29, 2016 February 29, 2016 February 29, 2016 February 29, 2016 February 29, 2016 February 29, 2016 February 29, 2016 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/ Hemang Desai Hemang Desai Director By: /s/ Randolph Newcomer, Jr. Randolph Newcomer, Jr. Director By: /s/ David H. Smith David H. Smith Director 88 Index to Consolidated and Combined Financial Statements F-2 Reports of Independent Registered Public Accounting Firm ........................................................................................................ F-4 Consolidated and Combined Balance Sheets as of December 31, 2015 and 2014 ........................................................................ F-5 Consolidated and Combined Statements of Operations for the Years Ended December 31, 2015, 2014, and 2013 .................... F-6 Consolidated and Combined Statements of Changes in Equity for the Years Ended December 31, 2015, 2014, and 2013 ......... F-8 Consolidated and Combined Statements of Cash Flows for the Years Ended December 31, 2015, 2014, and 2013 ................... Notes to Consolidated and Combined Financial Statements ......................................................................................................... F-9 Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited) ................................................................................... F-42 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, 2015 and 2014, 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, 2015. These consolidated and combined financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the 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, 2015 and 2014, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles. As discussed in Note 2 to the consolidated and combined financial statements, on December 31, 2015 the Company adopted the provisions of Financial Accounting Standards Board Accounting Standards Update No. 2015-17 Balance Sheet Classification of Deferred Taxes. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Parsley Energy, Inc.’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 29, 2016 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting. Dallas, Texas February 29, 2016 (signed) KPMG LLP F-2 Report of Independent Registered Public Accounting Firm The Board of Directors and Stockholders Parsley Energy, Inc.: We have audited Parsley Energy, Inc.’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Parsley Energy, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, Parsley Energy, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on “criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated and combined balance sheets of Parsley Energy, Inc. and subsidiaries as of December 31, 2015 and 2014, 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, 2015, and our report dated February 29, 2016 expressed an unqualified opinion on the consolidated and combined financial statements. Dallas, Texas February 29, 2016 (signed) KPMG LLP F-3 PARSLEY ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED AND COMBINED BALANCE SHEETS December 31, 2015 December 31, 2014 (In thousands) ASSETS CURRENT ASSETS Cash and cash equivalents .................................................................................................................................................. $ Restricted cash ................................................................................................................................................................... Accounts receivable: 343,084 $ 1,139 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, amortization, and impairment .......................................................................... 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 ....................................................................................................................................... Current portion of asset retirement obligations ........................................................................................................... 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, $0.01 par value, 50,000,000 shares authorized, none issued and outstanding .................................... Common stock Class A, $0.01 par value, 600,000,000 shares authorized, 136,728,906 shares issued and 136,623,407 shares outstanding at December 31, 2015 and 93,937,947 shares issued and 93,901,208 shares outstanding at December 31, 2014 ....................................................................................... Class B, $0.01 par value, 125,000,000 shares authorized, 32,145,296 issued and outstanding at December 31, 2015 and none issued and outstanding at December 31, 2014 ............................. Additional paid in capital ............................................................................................................................................ Retained earnings ........................................................................................................................................................ Treasury stock, at cost, 105,421 shares and 36,739 at December 31, 2015 and December 31, 2014 ........................... Total stockholders' equity ............................................................................................................................. Noncontrolling interest ............................................................................................................................................... Total equity .................................................................................................................................................. TOTAL LIABILITIES AND EQUITY ................................................................................................................................. $ 14,998 21,219 390 83,262 — 24,234 488,326 2,246,161 (290,186 ) 1,955,975 29,778 1,985,753 25,839 — 11,378 2,896 40,113 2,514,192 $ 151,221 $ 37,109 951 34,518 — 4,698 228,497 555,924 13,522 62,962 51,504 15,142 — 699,054 — — — 1,360 321 1,252,020 10,868 (77 ) 1,264,492 322,149 1,586,641 2,514,192 $ The accompanying notes are an integral part of these consolidated and combined financial statements. F-4 50,550 — 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 — 12,943 2,308 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 PARSLEY ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS 2015 Year ended December 31, 2014 (in thousands, except per share data) 2013 REVENUES Oil sales ................................................................................................................ $ Natural gas sales ................................................................................................... Natural gas liquids sales ....................................................................................... Total revenues................................................................................................. 215,795 $ 26,582 23,680 266,057 232,554 $ 30,642 38,561 301,757 OPERATING EXPENSES Lease operating expenses ...................................................................................... Production and ad valorem taxes .......................................................................... Depreciation, depletion and amortization ............................................................. General and administrative expenses (including stock based compensation of $8,133, $53,297, and $1,233 for the years ended December 31, 2015, 2014, and 2013) ....................................... Exploration costs .................................................................................................. Impairment ........................................................................................................... Acquisition costs ................................................................................................... Accretion of asset retirement obligations .............................................................. Rig termination costs ............................................................................................ Other operating expenses ...................................................................................... Total operating expenses ................................................................................ OPERATING (LOSS) INCOME ............................................................................. OTHER INCOME (EXPENSE) Interest expense, net .............................................................................................. (Loss) gain on sale of property ............................................................................. Prepayment premium on extinguishment of debt ................................................. Derivative income (loss) ....................................................................................... Other income (expense) ........................................................................................ Total other income (expense), net ................................................................... (LOSS) INCOME BEFORE INCOME TAXES..................................................... INCOME TAX BENEFIT (EXPENSE) .................................................................. NET (LOSS) INCOME ............................................................................................ LESS: NET LOSS (INCOME) ATTRIBUTABLE TO NONCONTROLLING INTERESTS ................................................................... NET (LOSS) INCOME ATTRIBUTABLE TO PARSLEY ENERGY INC. STOCKHOLDERS ....................................................................................... $ 62,913 17,800 178,281 55,294 13,865 950 — 826 8,970 1,696 340,595 (74,538) (45,581) (34,374) — 60,818 (3,111) (22,248) (96,786) 23,755 (73,031) 38,071 18,941 94,297 87,949 3,136 — 2,527 512 765 — 246,198 55,559 (39,624 ) (2,097 ) (5,107 ) 83,858 601 37,631 93,190 (36,468 ) 56,722 97,839 23,179 — 121,018 16,572 7,081 28,152 16,553 — — — 181 — — 68,539 52,479 (13,733) 36 — (9,800) 434 (23,063) 29,416 (1,906) 27,510 22,547 (33,293 ) — (50,484) $ 23,429 $ 27,510 Net (loss) income per common share: (1) Basic ........................................................................................................................ $ Diluted ..................................................................................................................... $ (0.45) $ (0.45) $ Weighted average common shares outstanding: (1) Basic ........................................................................................................................ Diluted ..................................................................................................................... 111,271 111,271 0.65 0.65 93,168 93,271 The accompanying notes are an integral part of these consolidated and combined financial statements. (1) See Note 2—Summary of Significant Accounting Policies—Revision of 2014 Financial Statements and Note 8—Equity for additional discussion regarding revisions to the earnings per share (“EPS”) calculation. F-5 PARSLEY ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED AND COMBINED STATEMENT OF CHANGES IN EQUITY Issued Shares 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 Retained Earnings Treasury stock Treasury stock Total Stockholders' equity Noncontrolling interest Total Equity — 6,017 (1,723 ) (3,886 ) — — — — — — — — — 1,723 — — (6,726 ) — — — 77,158 — — (8,772 ) 78,881 — — — — — — — — 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 IPO .............. 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 IPO 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 IPO...................... Tax benefit from tax receivable agreement ............ Liability due to tax receivable agreement ............ Issuance of restricted stock and restricted stock units ........... Restricted stock forfeited............... Stock based compensation ...... Consolidated net income subsequent to the Corporate Reorganization and the IPO ......... Balance at 12/31/2014 .......... — 49,963 — — — — — — — — — — — — — — — — — — — — — — — — — — 93,937 32,145 770 — — — — — — — — — — — — (In thousands) — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — 6,017 — 77,158 — (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) — — — — — — — (41) 2,250 — — — — — — 61,352 932 321 644,636 61,352 — 37 — — 37 — — — — (41 ) — — — (41) 2,250 — 2,250 — 61,352 33,293 94,645 — 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 STATEMENT OF CHANGES IN EQUITY (continued) Issued Shares 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 Retained Earnings Treasury stock Treasury stock Total Stockholders' equity Noncontrolling interest Total Equity Issuance of Class A Common Stock, net of underwriters discount and expenses ....... Change in equity due to issuance of PE Units by Parsley LLC ........ Increase in net deferred tax liability due to issuance of PE Units by Parsley LLC ........ Tax benefit from tax receivable agreement ............ Initial noncontrolling interest allocation attributable to Pacesetter ............ Issuance of restricted stock .................... Restricted stock forfeited............... Vesting of restricted stock unit ...................... Stock based compensation ...... Net loss ................. Balance at December 31, 2015 ................... $ — — 42,748 — 428 — 668,990 — — — 669,418 — 669,418 — — — — — — (56,856) — — — (56,856 ) 56,856 — — — — — — — (18,383) — — — (18,383 ) — (18,383) — — — — — — 5,500 — — — 5,500 — 5,500 — — — — — — — — — — — 2,592 2,592 — — — — — — — — — — 42 — — — 2 — — — — — — — — — — — — — — — — (293) — — — — 8,426 — — (50,484) — 68 — — — — (71 ) (6 ) — — — (364 ) (6 ) — — — — (364) (6) 8,426 (50,484 ) — (22,547) 8,426 (73,031) — $ — 136,729 32,145 $ 1,360 $ 321 $ 1,252,020 $ 10,868 105 $ (77 ) $ 1,264,492 $ 322,149 $ 1,586,641 The accompanying notes are an integral part of these consolidated and combined financial statements F-7 PARSLEY ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS CASH FLOWS FROM OPERATING ACTIVITIES: Net (loss) income .......................................................................................................................... $ Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization ............................................................................... Exploration costs .................................................................................................................... Impairment expense ............................................................................................................... Inventory write down ............................................................................................................. Accretion of asset retirement obligations................................................................................ (Gain) loss on sale of oil and natural gas properties ............................................................... Loss on sale of other property and equipment ........................................................................ Amortization and write off of deferred loan origination costs ................................................ Amortization of bond premium .............................................................................................. Interest not paid in cash .......................................................................................................... Income tax (benefit) expense .................................................................................................. Stock based compensation expense ........................................................................................ Derivative (income) loss ......................................................................................................... Net cash received (paid) for derivative settlements ................................................................ Net cash received (paid) for option premiums ........................................................................ Net premiums received (paid) on options that settled during the period ................................. Changes in operating assets and liabilities, net of acquisitions: Restricted cash........................................................................................................................ Accounts receivable ............................................................................................................... Accounts receivable—related parties ..................................................................................... Materials and supplies ............................................................................................................ Other current assets ................................................................................................................ Other noncurrent assets .......................................................................................................... Accounts payable and accrued expenses ................................................................................ Revenue and severance taxes payable .................................................................................... Other noncurrent liabilities ..................................................................................................... Net cash provided by operating activities ...................................................................................... CASH FLOWS FROM INVESTING ACTIVITIES: Development of oil and natural gas properties ....................................................................... Acquisitions of oil and natural gas properties ......................................................................... Acquisition of Pacesetter ........................................................................................................ Additions to other property and equipment ............................................................................ Proceeds from sale of oil and natural gas properties ............................................................... Proceeds from sale of other property and equipment .............................................................. Net cash used in investing activities .............................................................................................. CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings under long-term debt ........................................................................................... Payments on long-term debt ................................................................................................... Debt issue costs ...................................................................................................................... Proceeds from issuance of common stock, net ....................................................................... Purchases of restricted stock ................................................................................................... Vesting of restricted stock ...................................................................................................... Payment of Preferred Return .................................................................................................. Proceeds from issuance of LLC interests ................................................................................ Equity issue costs ................................................................................................................... Net cash provided by financing activities ...................................................................................... Net increase in cash and cash equivalents ..................................................................................... Cash and cash equivalents at beginning of year ............................................................................ Cash and cash equivalents at end of year ...................................................................................... $ SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid for interest .............................................................................................................. $ Cash paid for income taxes ..................................................................................................... $ SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES: Asset retirement obligations incurred, including changes in estimate ..................................... $ Additions to oil and natural gas properties - change in capital accruals .................................. $ Additions to other property and equipment funded by capital lease borrowings..................... $ 2015 Year Ended December 31, 2014 (In thousands) 2013 (73,031) $ 56,722 $ 27,510 178,281 7,310 950 4,147 826 32,404 1,970 2,702 (764) — (23,755) 8,133 (60,818) 43,767 40,656 11,406 (1,139) 24,103 3,675 3,767 (22,793) (588) (7,287) (1,257) (375) 172,290 (382,550) (73,807) (2,408) (19,755) 50,138 1,217 (427,165) 105,000 (225,794) (1,138) 669,418 (71) (6) — — — 547,409 292,534 50,550 343,084 $ 43,993 $ — $ 3,441 $ 18,300 $ 939 $ 94,297 742 — — 512 2,097 — 2,327 (574 ) 234 36,468 53,297 (83,858 ) 3,311 193 (2,308 ) — 45,372 (3,055 ) (689 ) 2,229 (535 ) (32,121 ) 9,947 375 184,983 (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 $ 27,252 $ — $ 7,498 $ 13,658 $ 2,263 $ 28,152 — — — 181 (36) — 1,225 — 2,597 1,906 1,233 9,800 (198) (16,342) (6,928) — (77,086) (621) (867) 6,118 (184) 57,532 19,243 — 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 13,555 — 6,238 58,540 — The accompanying notes are an integral part of these consolidated and combined financial statements. F-8 PARSLEY ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS December 31, 2015 NOTE 1. ORGANIZATION AND NATURE OF OPERATIONS Parsley Energy, Inc. (individually or together with its subsidiaries, as the context requires, the “Company,” “we,” “us,” or “our”) 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 LLC, all of the interest holders of Parsley Energy, L.P. (“Parsley LP”), Parsley Energy Management, LLC (“PEM”) and Parsley Energy Operations, LLC (“Operations”) exchanged their interest in each entity in return for interest in Parsley LLC (the “Exchange”). Prior to the formation of Parsley LLC, 67.8% of Parsley LP, 100% of PEM and 100% of Operations were held by Mr. Bryan Sheffield, Parsley LLC’s President and Chief Executive Officer (“Sheffield”). Subsequent to Parsley LLC’s formation, Sheffield controlled 53.7% of Parsley LLC. As such, as all power and authority to control the core functions of Parsley LP, PEM and Operations 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 Operations 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. Operations 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 “IPO”) 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 IPO 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 IPO was used to repay all outstanding borrowings under our amended and restated credit agreement (as amended, the “Revolving Credit Agreement”) with Wells Fargo Bank, National Association, as the administrative agent, 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 IPO. 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 IPO, 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 F-9 PARSLEY ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS December 31, 2015 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. Upon completion of the IPO, 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 IPO 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 IPO (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 owned an approximate 74.3% interest in Parsley LLC, with the remaining holders of PE Units (the “PE Unitholders”) owning an approximate 25.7% interest in Parsley LLC. Private Placement of Common Stock On February 5, 2015, the Company entered into an agreement to sell 14,885,797 shares of its Class A Common Stock, par value $0.01 per share (“Class A Common Stock”), in a private placement (the “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 gross proceeds of approximately $230.7 million to the Company and net proceeds, after deducting underwriting discounts and commissions and offering expenses, of approximately $224.0 million. The net proceeds were used to repay a portion of outstanding borrowings under our Revolving Credit Agreement and for general corporate purposes. Upon completion of the Private Placement, the Company contributed all of the net proceeds to Parsley Energy, LLC (“Parsley LLC”) in exchange for 14,885,797 PE Units. As a result, the Company’s ownership of Parsley LLC increased to 77.2%, with the PE Unit Holders’ ownership of Parsley LLC decreasing to 22.8%. Pacesetter Drilling, LLC On April 21, 2015, Operations, established a limited liability company, Pacesetter Drilling, LLC (“Pacesetter”), as a wholly owned subsidiary. On June 15, 2015, Pacesetter entered into an asset purchase agreement with an oilfield drilling company to acquire certain property, equipment, and other assets (the “Pacesetter Acquisition”). The Pacesetter Acquisition was accounted for using the acquisition method under Accounting Standards Codification (“ASC”) Topic 805, “Business Combinations.” Operations and Pacesetter’s President contributed cash in exchange for ownership in Pacesetter. Pacesetter then paid total consideration of $7.0 million for its interest in the purchased assets, of which $4.4 million was allocated to Operations and $2.6 million was allocated to the noncontrolling interest. As a result of the Pacesetter Acquisition, Operations has a 63.0% interest in Pacesetter. Public Offerings of Common Stock On September 18, 2015, the Company entered into an agreement to sell 14,950,000 shares of its Class A Common Stock (including 1,950,000 shares issued pursuant to the underwriters’ option to purchase additional shares) at a price of $15.00 per share in an underwritten public offering (the “September Offering”). The September Offering resulted in gross proceeds of approximately $224.3 million to the Company and net proceeds, after deducting underwriting discounts and commissions and offering expenses, of approximately $217.0 million. A portion of the net proceeds was used to repay borrowings outstanding under our Revolving Credit Agreement and the remainder of the net proceeds were used to fund a portion of the Company’s capital program, including acquisitions. Upon completion of the September Offering, the Company contributed all of the net proceeds to Parsley LLC in exchange for 14,950,000 PE Units. As a result, the Company’s ownership of Parsley LLC increased to 79.4%, with the PE Unit Holders’ ownership of Parsley LLC decreasing to 20.6%. On December 9, 2015, the Company and NGP X US Holdings, L.P., one of the Company’s stockholders (“NGP”), entered into an agreement to sell 14,202,500 shares of Class A Common Stock, including 12,911,364 shares of Class A Common Stock issued and sold by the Company and 1,291,136 shares of Class A Common Stock sold by NGP, at a price of $18.00 per share in an underwritten public offering (the “December Offering”). On December 10, 2015, the underwriters exercised in full their option to purchase additional shares. The December Offering resulted in gross proceeds of approximately $228.7 million to the Company and net proceeds, after deducting underwriting discounts and commissions and offering expenses, of approximately $228.4 million. A portion F-10 PARSLEY ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS December 31, 2015 of the net proceeds from the offering was used to fund the acquisition of 6,040 gross (5,274 net) acres located in Upton, Reagan and Glasscock Counties, Texas, and the remaining net proceeds were used to fund a portion of the Company’s capital program and for general corporate purposes. The Company did not receive any of the proceeds from the sale of shares by NGP. Upon completion of the December Offering, the Company contributed all of the net proceeds to Parsley LLC in exchange for 12,911,364 PE Units. As a result, the Company’s ownership of Parsley LLC increased to 81.0%, with the PE Unit Holders’ ownership of Parsley LLC decreasing to 19.0%. NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Principles of Consolidation These consolidated and combined financial statements include the accounts of the Company and its majority-owned subsidiary, Parsley LLC, and its wholly owned subsidiaries: (i) Parsley LP, (ii) PEM, (iii) Operations, and its wholly owned subsidiary, Parsley Energy Aviation, LLC, and (iv) Parsley Finance Corp (“Finance Corp”). These consolidated and combined financial statements also include the accounts of Pacesetter, a majority-owned subsidiary of Operations. 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. Use of Estimates These consolidated and combined financial statements and related notes are presented in accordance with GAAP. For the year ended December 31, 2014, the financial statements are consolidated and for all prior years the financial statements are consolidated and combined. 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: (cid:121) 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; (cid:121) operating costs accrued and volumes and prices for revenues accrued; (cid:121) (cid:121) (cid:121) (cid:121) estimates of asset retirement obligations; estimates of the fair value assets acquired and liabilities assumed in business combinations; evaluations of impairment of proved and unproved properties are subject to number uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks; impairment of other assets; (cid:121) depreciation of property and equipment; (cid:121) valuation of commodity derivative instruments; and (cid:121) estimates of the fair value of stock based compensation. Although management believes these estimates are reasonable, actual results may differ from estimates and assumptions of future events and these revisions could be material. Future production may vary materially from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price assumptions used for determining proved reserves and for financial reporting. F-11 PARSLEY ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS December 31, 2015 Cash and Cash Equivalents The Company considers all cash on hand, depository accounts held by banks, money market accounts and investments with an original maturity of three months or less to be cash equivalents. The Company’s cash and cash equivalents are held in financial institutions in amounts that exceed the insurance limits of the Federal Deposit Insurance Corporation. However, management believes that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected. Restricted Cash Restricted cash at December 31, 2015 of $1.1 million includes cash that is contractually restricted involving a non-related party. The restricted cash includes revenues associated with an operating well. 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, 2015 or December 31, 2014. Significant Customers For the years ended December 31, 2015, 2014 and 2013, each of the following purchasers accounted for more than 10% of our revenue: Shell Trading (US) Company................................................................................ BML, Inc. .............................................................................................................. Targa Pipeline Mid-Continent, LLC ..................................................................... TransOil Marketing, LLC ..................................................................................... Plains Marketing, L.P. ........................................................................................... Permian Transport & Trading ............................................................................... Enterprise Crude Oil, LLC .................................................................................... 2015 23% 19% 12% 13% 6% 6% —% Year Ended December 31, 2014 4% 14% 20% —% 15% 11% 10% 2013 7% 2% 16% —% 22% 25% 20% 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 a tubing, casing and pumping units. These items are primarily acquired for use in future drilling or repair operations and are carried at lower of cost or market. “Market,” in the context of valuation, represents net realizable value, which is the amount that the Company is allowed to bill to the joint account under joint operating agreements to which the Company is a party. During 2015, the Company made significant materials and supplies purchases and evaluated assets based on current operations. The Company determined that these materials and supplies would not be utilized in the current year and therefore reclassified them to noncurrent assets as non-depreciable other property, plant and equipment. See Note 13 for additional information regarding the Company’s impairment of materials and supplies. F-12 PARSLEY ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS December 31, 2015 Oil and Natural Gas Properties Oil and natural gas exploration, development and production activities are accounted for in accordance with the successful efforts method of accounting. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation, depletion and amortization (“DD&A”). Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated reservoir. The Company capitalizes interest on expenditures made in connection with long term projects that are not subject to current depletion. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use and only to the extent the company has incurred interest expense. On the sale of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated DD&A are removed from the property accounts, and any gain or loss is recognized. For sales of entire working interests in unproved properties, gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property. Oil and Gas Reserves The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated 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 first day of the month 12-month average price, net of historical differentials, with no provision for price and cost escalations in future years except by contractual arrangements. Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. Oil and gas properties are depleted by field using the units-of-production method. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or decreased. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates. Asset Retirement Obligations For the Company, asset retirement obligations represent the future abandonment costs of tangible assets, namely the plugging and abandonment of wells and land remediation. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made and the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period. If the liability is settled for an amount other than the recorded amount, the difference is recorded in other income (expense) in the consolidated and combined statements of operations. Inherent to the present value calculation are numerous estimates, assumptions, and judgments, including, but not limited to: the ultimate settlement amounts, inflation factors, credit-adjusted risk-free rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. To the extent future revisions to these assumptions affect the present value of the abandonment liability, the Company makes corresponding adjustments to both the asset retirement obligation and the related oil and natural gas property asset balance. These revisions result in prospective changes to DD&A expense and accretion of the discounted abandonment liability. F-13 PARSLEY ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS December 31, 2015 The following table summarizes the changes in the Company’s asset retirement obligation for the periods indicated: Year ended December 31, 2015 2014 (in thousands) Asset retirement obligations, beginning of period ................................................................... $ Additional liabilities incurred .................................................................................................. Disposition of wells ................................................................................................................. Accretion expense .................................................................................................................... Liabilities settled upon plugging and abandoning wells .......................................................... Revision of estimates ............................................................................................................... Asset retirement obligations, end of period.............................................................................. $ 16,207 1,512 (2,254 ) 826 — 1,929 18,220 $ $ 8,277 6,604 (80) 512 (7) 901 16,207 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 Oil and Natural Gas Properties The Company reviews its long-lived assets to be held and used, including proved oil and natural gas properties by field. Whenever events or circumstances indicate that the carrying value of those assets may not be recoverable, an impairment loss is indicated if the sum of the expected future cash flows related to proved properties in the applicable field is less than the carrying amount of the assets. In this circumstance, the Company recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset. The Company reviews its oil and natural gas properties by amortization base or by individual well for those wells not constituting part of an amortization base. For each property determined to be impaired, an impairment loss equal to the difference between the carrying value of the properties and the estimated fair value (discounted future cash flows) of the properties would be recognized at that time. Estimating future cash flows involves the use of judgments, including estimation of the proved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs. See Note 13 for additional information regarding the Company’s impairment of proved oil and natural gas properties. 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 12-month period after drilling is complete. Unproved oil and natural gas properties are assessed quarterly for impairment by considering future drilling plans, the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. F-14 PARSLEY ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS December 31, 2015 The following table summarized exploration costs incurred by the Company for the periods indicated: 2015 Year Ended December 31, 2014 (in thousands) 2013 Geological and geophysical costs ..................... $ Leasehold abandonments .................................. Unproved leasehold amortization...................... Total exploration costs ...................................... $ 5,459 8,227 179 13,865 $ $ 2,394 430 312 3,136 $ $ — — — — 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 15 years. Depreciation expense on other property and equipment was $4.7 million, $1.5 million, and $1.1 million for the years ended December 31, 2015, 2014, and 2013, respectively. 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, 2015, 2014, or 2013. 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-15 PARSLEY ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS December 31, 2015 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: (cid:121) 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. (cid:121) 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. (cid:121) 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 or 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, 2015, 2014, and 2013, the Company did not have any natural gas imbalances. Transportation expenses are included as a reduction of natural gas revenue and are not material. Defined Contribution Plan The Company sponsors a 401(k) defined contribution plan for the benefit of all employees at their date of hire. The plan allows eligible employees to contribute a portion of their annual compensation, not to exceed annual limits established by the federal government. The Company makes matching contribution of up to a certain percentage of an employee’s contributions. For the year ended December 31, 2015, 2014, and 2013, the Company made contributions to the plan of $1.4 million, $0.8 million, and $0.2 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 F-16 PARSLEY ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS December 31, 2015 differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date. The 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. The Company has omitted EPS prior to the IPO on May 29, 2014. See “—Revision of 2014 Financial Statements” below. Comprehensive Income The Company has no elements of comprehensive income other than net income. Segment Reporting Operating segments are defined as components of an enterprise that (i) engage in activities from which it may earn revenues and incur expenses (ii) for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance. Based on the organization and management of the Company, the Company has only one reportable operating segment, which is oil and natural gas exploration and production. The Company considers drilling rig services ancillary to its oil and gas exploration and producing activities and manages these services to support such activities. Change in Accounting Principle The Company adopted Accounting Standards Update (“ASU”) No. 2015-17, Income Taxes (Topic 740), effective December 31, 2015. This standard requires companies that have historically presented current and noncurrent deferred tax assets and liabilities in a classified statement of financial position to present deferred tax assets and liabilities as noncurrent in a classified statement of financial position. The guidance may be applied either prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented. The Company has elected not to retrospectively adjust prior periods. Reclassifications Certain reclassifications have been made to prior period amounts to conform to the current presentation. These reclassifications include the reclassification of a one-time non-cash compensation expense of $51.1 million and $1.2 million from the line Incentive Unit Compensation and $2.2 million and none from the line Stock Based Compensation to the line General and Administrative expense on the consolidated and combined statements of operations for the year ended December 31, 2014 and 2013, respectively. These reclassifications also include the reclassification of NGLs sales of $38.6 million from the line Natural Gas Sales to the line Natural Gas Liquids Sales on the consolidated and combined statements of operations for the year ended December 31, 2014. In addition, we have reclassified other immaterial amounts. Recent Accounting Pronouncements 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 F-17 PARSLEY ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS December 31, 2015 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. The Company will analyze the effect of the standard on its ongoing financial reporting during 2016. In February 2015, the FASB issued ASU No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis, which changes the analysis to be performed in determining whether certain types of legal entities should be consolidated. Under the revised guidance, all legal entities are subject to reevaluation under the revised consolidation model, unless a scope exception applies. Though the revised guidance mostly affects asset managers, all reporting entities involved with limited partnerships or similar entities are required to reevaluate such entities for consolidation. The guidance is effective for public business entities for fiscal years and for interim periods within those fiscal years beginning after December 15, 2015. The amended guidance will not materially affect the Company’s consolidated and combined financial statements or notes to the consolidated and combined financial statements. In April 2015, the FASB issued ASU No. 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, as part of its simplification initiative to reduce the cost and complexity in accounting standards. In August 2015, they also issued ASU No. 2015-15, Interest—Imputation of Interest (Subtopic 835-30). The ASU requires that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of the related liability. The treatment is consistent with the current presentation of debt discounts or premiums. However, this does not address presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements. For public business entities, the guidance is effective for financial statements covering fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The amended guidance must be applied on a retrospective basis and will not materially affect the Company’s consolidated and combined financial statements or notes to the consolidated and combined financial statements. In May 2015, the FASB issued ASU No. 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory, which requires entities that value inventory using the first-in, first-out or average cost method to measure inventory at the lower of cost and net realizable value. For public business entities, the amended guidance is effective for fiscal years beginning after December 15, 2016, and for interim periods within those years. The amended guidance must be applied on a prospective basis and is not expected to materially affect the Company’s consolidated and combined financial statements or notes to the consolidated and combined financial statements. In September 2015, the FASB issued ASU No. 2015-16, Business Combinations, which requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. This amendment requires that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization or other income effects, if any, as a result of the change to provisional amounts, calculated as if the accounting had been completed at the acquisition date. For public business entities, the amended guidance is effective for fiscal years beginning after December 15, 2015, and for interim periods within those years. The amended guidance must be applied on a prospective basis and is not expected to materially affect the Company’s consolidated and combined financial statements or notes to the consolidated and combined financial statements. In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments—Overall, which addresses the fair value measurements, impairment assessment, and disclosure requirements of equity securities, equity investments, and other financial instruments, and also clarifies current guidance to aid in the reduction of diversity in practice. For public business entities, the amended guidance is effective for fiscal years beginning after December 15, 2017, and for interim periods within those years. The amended guidance should be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. The amendments related to equity securities without readily determinable fair values should be applied prospectively. The Company has not yet determined the effect of the standard on its ongoing financial reporting. F-18 PARSLEY ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS December 31, 2015 Revision of 2014 Financial Statements The Company has identified and corrected errors in the earnings per share (“EPS”) disclosure previously reported in the consolidated and combined financial statements for the period ended June 30, 2014; September 30, 2014; and December 31, 2014. The Company has revised the EPS calculation to include only the net income for the period subsequent to IPO and Corporate Reorganization. In addition, the weighted average shares outstanding included in the calculation has been revised to reflect the same period. As a result, the tables below set forth the effect of errors in the basic and diluted EPS disclosure in the consolidated and combined statement of operations for the three and six months ended June 30, 2014; the nine months ended September 30, 2014; and the year ended December 31, 2014. (cid:3) (cid:3)(cid:3) (cid:3)(cid:3) Basic net (loss) income attributable to Parsley Energy, Inc. Stockholders ............................... $ Basic weighted average shares outstanding ....... Basic EPS attributable to Parsley Energy, Inc. Stockholders .................................................... $ (cid:3)(cid:3) Diluted net (loss) income attributable to Parsley Energy, Inc. Stockholders ............................... $ Diluted weighted average shares outstanding ....... Diluted EPS attributable to Parsley Energy, Inc. Stockholders .................................................... $ (cid:3)(cid:3)(cid:3)(cid:3) (cid:3)(cid:3) (cid:3)(cid:3) (cid:3)(cid:3) Basic net (loss) income attributable to Parsley Energy, Inc. Stockholders ............................... $ Basic weighted average shares outstanding ....... Basic EPS attributable to Parsley Energy, Inc. Stockholders .................................................... $ (cid:3)(cid:3) Diluted net (loss) income attributable to Parsley Energy, Inc. Stockholders ............................... $ Diluted weighted average shares outstanding ....... Diluted EPS attributable to Parsley Energy, Inc. Stockholders .................................................... $ (cid:3)(cid:3) (cid:3)(cid:3)(cid:3)(cid:3) (cid:3)(cid:3) (cid:3)(cid:3) Basic net income attributable to Parsley Energy, Inc. Stockholders ............................... $ Basic weighted average shares outstanding ....... Basic EPS attributable to Parsley Energy, Inc. Stockholders .................................................... $ (cid:3)(cid:3) Diluted net income attributable to Parsley Energy, Inc. Stockholders ............................... $ Diluted weighted average shares outstanding ....... Diluted EPS attributable to Parsley Energy, Inc. Stockholders .................................................... $ Three months ended June 30, 2014 Six months ended June 30, 2014 As Reported As Revised Change As Reported As Revised Change (38,646) $ 32,453 1,265 $ 93,168 39,911 $ 60,715 (36,658 ) $ 16,136 1,265 $ 93,168 37,923 77,032 (1.19) $ 0.01 $ 1.20 $ (2.27 ) $ 0.01 $ 2.28 (38,646) $ 32,453 1,265 $ 93,286 39,911 $ 60,833 (36,658 ) $ 16,136 1,265 $ 93,286 37,923 77,150 (1.19) $ 0.01 $ 1.20 $ (cid:3) (cid:3) Nine Months Ended September 30, 2014 As Reported As Revised Change (19,791) $ 42,319 18,132 $ 93,168 37,923 50,849 (0.47) $ 0.19 $ 0.66 (19,791) $ 42,319 18,132 $ 93,276 37,923 50,957 (0.47) $ 0.19 $ 0.66 (cid:3) (cid:3) December 31, 2014 As Reported As Revised Change 23,429 $ 55,136 61,352 $ 93,168 37,923 38,032 0.42 $ 0.65 $ 0.23 23,429 $ 55,239 61,352 $ 93,271 37,923 38,032 0.42 $ 0.65 $ 0.23 F-19 (2.27 ) $ (cid:3)(cid:3)(cid:3)(cid:3)(cid:3)(cid:3) (cid:3)(cid:3)(cid:3)(cid:3)(cid:3)(cid:3) (cid:3)(cid:3)(cid:3)(cid:3)(cid:3)(cid:3) (cid:3)(cid:3)(cid:3)(cid:3)(cid:3)(cid:3) (cid:3)(cid:3)(cid:3)(cid:3)(cid:3)(cid:3) (cid:3)(cid:3)(cid:3)(cid:3)(cid:3)(cid:3) (cid:3)(cid:3)(cid:3)(cid:3)(cid:3)(cid:3) (cid:3)(cid:3)(cid:3)(cid:3)(cid:3)(cid:3) (cid:3)(cid:3)(cid:3)(cid:3)(cid:3)(cid:3) (cid:3)(cid:3)(cid:3)(cid:3)(cid:3)(cid:3) (cid:3)(cid:3)(cid:3)(cid:3)(cid:3)(cid:3) (cid:3)(cid:3)(cid:3)(cid:3)(cid:3)(cid:3) (cid:3)(cid:3)(cid:3)(cid:3)(cid:3)(cid:3) (cid:3)(cid:3)(cid:3)(cid:3)(cid:3)(cid:3) (cid:3)(cid:3)(cid:3)(cid:3)(cid:3)(cid:3) (cid:3)(cid:3)(cid:3)(cid:3)(cid:3)(cid:3) (cid:3)(cid:3)(cid:3)(cid:3)(cid:3)(cid:3) (cid:3)(cid:3)(cid:3)(cid:3)(cid:3)(cid:3) (cid:3)(cid:3)(cid:3)(cid:3)(cid:3)(cid:3) (cid:3)(cid:3)(cid:3)(cid:3)(cid:3)(cid:3) (cid:3) (cid:3) (cid:3) (cid:3) (cid:3) (cid:3) (cid:3) (cid:3) (cid:3) (cid:3) (cid:3) (cid:3) (cid:3) (cid:3) (cid:3) (cid:3) (cid:3) (cid:3) (cid:3) (cid:3) 0.01 $ 2.28 (cid:3) (cid:3) (cid:3) (cid:3) (cid:3) (cid:3) (cid:3) (cid:3) (cid:3) (cid:3) (cid:3) (cid:3) (cid:3) (cid:3) (cid:3) (cid:3) (cid:3) (cid:3) (cid:3) (cid:3) (cid:3)(cid:3) PARSLEY ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS December 31, 2015 The Company assessed the materiality of the errors in accordance with the SEC guidance considering the effects of misstatements based on an analysis of quantitative and qualitative factors. Based on such an analysis, we determined that the errors were immaterial to each of the three and six months ended June 30, 2014; the nine months ended September 30, 2014; and the year ended December 31, 2014. We have reflected the correction of these errors in the period in which they originated and revised our consolidated and combined statement of operations and EPS disclosure in the equity note to the consolidated and combined financial statements for each of the periods. NOTE 3. DERIVATIVE FINANCIAL INSTRUMENTS Commodity Derivative Instruments and Concentration of Risk Objective and Strategy The Company utilizes basis swap contracts and put spread options to (i) reduce the effect of price volatility on the commodities the Company produces and sells or consumes, (ii) support the Company's annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. The Company uses put spread options to manage commodity price risk for NYMEX WTI. A put spread option is a combination of two options: a purchased put and a sold put. The purchased put establishes the minimum price that the Company will receive for the contracted volumes unless the market price for the commodity falls below the sold put strike price, at which point the minimum price equals the reference price plus the excess of the purchased put strike price over the sold put strike price. Additionally, the Company uses basis swap contracts to mitigate basis risk caused by the volatility of the Company’s basis differentials. The basis swap contracts establish the differential between Cushing WTI prices and the relevant price index at which oil production is sold. Derivative Activities Oil production derivative activities. All material physical sales contracts governing the Company's oil production are tied directly to, or are highly correlated with, NYMEX WTI oil prices. The Company uses put spread options to manage oil price volatility and basis swap contracts to reduce basis risk between NYMEX prices and the actual index prices at which the oil is sold. The following table sets forth the volumes associated with the Company's outstanding oil derivative contracts as of December 31, 2015 and the weighted average oil prices for those contracts: (cid:3)(cid:3) Year Ending December 31, 2016 2017 (cid:3) Crude Options Purchased: Puts (1) (cid:3) (cid:3)(cid:3) Notional (MBbl) ............................................................................... Weighted average strike price .......................................................... $ Sold: Puts (1) (cid:3) (cid:3)(cid:3) Notional (MBbl) ............................................................................... Weighted average strike price .......................................................... $ Basis swap contracts: (2) Midland-Cushing index swap volume (MBbl) (3) .............................. Price differential ($/Bbl) ..................................................................... $ (cid:3)(cid:3)(cid:3)(cid:3) 7,950 49.74 (cid:3)(cid:3)(cid:3)(cid:3) (7,950 ) 35.83 1,516 (0.87 ) (cid:3)(cid:3) (cid:3)(cid:3) $ (cid:3)(cid:3) (cid:3)(cid:3) $ $ (cid:3) 2,334 53.46 (cid:3) (2,334) 38.46 4,290 (1.03) (1) The Company excluded from the tables above 14,239 notional MBbls with a fair value of $298.0 million related to amount recognized under master netting agreements with derivative counterparties. (2) Represents swaps that fix the basis differentials between the index prices at which the Company sells its oil produced in the Permian Basin and the Cushing WTI price. F-20 PARSLEY ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS December 31, 2015 (3) During 2015, the Company entered into basis swap contracts for 5,806 MBbls of the Company’s 2016 and 2017 production with a negative price differential ranging from $0.30 per MBbl to $1.70 per MBbl between the Midland WTI price index and the Cushing WTI price index. During 2015, the Company has entered into new contracts to lower certain strike prices for both long and short put positions. By lowering the strike prices for the put spreads, the Company collected approximately $87.7 million, net, for 15,539 notional MBbls during the year ended December 31, 2015, which is reflected in the year end cash balance. Gas production derivative activities. All material physical sales contracts governing the Company's gas production are tied directly or indirectly to NYMEX Henry Hub gas prices or regional index prices where the gas is sold. The Company uses three way options to manage gas price volatility. As of December 31, 2015, the Company did not have any outstanding gas derivative contracts. Effect of Derivative Instruments on the Consolidated and Combined Financial Statements All of the Company’s derivatives are accounted for as non-hedge derivatives and therefore all changes in the fair values of its derivative contracts are recognized as gains or losses in the earnings of the periods in which they occur. The Company recognized income from its derivative activities of $60.8 million, income of $83.9 million, and a loss of $9.8 for the years ended December 31, 2015, 2014, and 2013, respectively. These gains and losses are included in the consolidated and combined statements of operations line item, Derivative income (loss). The fair value of the derivative instruments is discussed in Note 13—Disclosures about Fair Value of Financial Instruments. The Company classifies the fair value amounts of derivative assets and liabilities as gross current or noncurrent derivative assets or gross current or noncurrent derivative liabilities, whichever the case may be, excluding those amounts netted under master netting agreements. The Company has agreements in place with all of its counterparties that allow for the financial right of offset for derivative assets and liabilities at settlement or in the event of default under the agreements. Additionally, the Company maintains accounts with its brokers to facilitate financial derivative transactions in support of its risk management activities. Based on the value of the Company’s positions in these accounts and the associated margin requirements, the Company may be required to deposit cash into these broker accounts. During the year ended December 31, 2015, the Company did not receive or post any margins in connection with collateralizing its derivative positions. During the year ended December 31, 2014 and 2013, the Company received and 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): December 31, 2015 Derivative assets with right of offset or master netting agreements .................................. $ Derivative liabilities with right of offset or master netting agreements .................................. December 31, 2014 Derivative assets with right of offset or master netting agreements .................................. $ Derivative liabilities with right of offset or master netting agreements .................................. Concentration of Credit Risk Gross Amount Presented on Balance Sheet Netting Adjustments Cash Collateral Posted (Received) Net Exposure 407,052 $ (297,951) $ — $ 109,101 (347,611) 297,951 — (49,660) 151,716 $ (60,601) $ — $ 91,115 (60,601) 60,601 — — The financial integrity of the Company’s exchange-traded contracts is assured by NYMEX through systems of financial safeguards and transaction guarantees, and is therefore subject to nominal credit risk. Over-the-counter traded options expose the Company to counterparty credit risk. These over-the-counter options are entered into with a large multinational financial institution with investment grade credit rating or through brokers that require all the transaction parties to collateralize their open option F-21 PARSLEY ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS December 31, 2015 positions. The gross and net credit exposure from our commodity derivative contracts as of December 31, 2015 and 2014 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 entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with each of its derivative counterparties. The terms of the ISDA Agreements provide the Company and its counterparties and brokers with rights of net settlement of gross commodity derivative assets against gross commodity derivative liabilities. The Company routinely exercises its contractual right to offset realized gains against realized losses when settling with derivative counterparties. The Company did not incur any losses due to counterparty bankruptcy filings during any of the years ended December 31, 2015, 2014 or 2013. 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, 2015 and 2014. NOTE 4. OIL AND NATURAL GAS PROPERTIES Oil and natural gas properties includes the following (in thousands): Oil and natural gas properties: Subject to depletion ........................................................................................................... $ Not subject to depletion Incurred in 2015 ........................................................................................................... Incurred in 2014 ........................................................................................................... Incurred in 2013 and prior ............................................................................................ 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 ................................................................................................... $ December 31, 2015 December 31, 2014 1,627,367 $ 1,248,376 118,101 459,505 41,188 618,794 2,246,161 (290,186 ) 1,955,975 37,253 (7,475 ) 29,778 1,985,753 $ — 562,046 62,194 624,240 1,872,616 (128,044) 1,744,572 19,177 (2,887) 16,290 1,760,862 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 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, 2015 and 2014, the Company had excluded $618.8 million and $624.2 million of capitalized costs from depletion, respectively. Depletion expense on capitalized oil and gas property was $173.6 million, $92.8 million and $27.1 million for the years ended December 31, 2015, 2014, and 2013, respectively. The Company had no exploratory wells in progress at December 31, 2015, 2014, and 2013. The Company capitalizes interest on expenditures made in connection with long term projects that are not subject to current depletion. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use and only to the extent the company has incurred interest expense. There was no capitalized interest recorded during 2015. During the years ended December 31, 2014 and 2013, the Company capitalized interest of $2.7 million and $3.4 million, respectively. F-22 PARSLEY ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS December 31, 2015 NOTE 5. ACQUISITIONS OF OIL AND GAS PROPERTIES The Company incurred $38.8 million, $54.0 million, and $32.7 million of leasehold acquisition costs during 2015, 2014 and 2013, respectively, which are included as part of costs not subject to depletion. 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 2015, 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 $35.0 million. The Company reflected $16.4 million of the total consideration paid as part of its costs subject to depletion and $18.6 million as unproved leasehold costs within its oil and gas properties. The revenues and operating expenses attributable to the working interest acquisitions during the years ended December 31, 2015, 2014 and 2013, were not material. 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. 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 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 ............................................................................................... $ 111,003 128,756 239,759 (219) 239,540 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 F-23 PARSLEY ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS December 31, 2015 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 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 ............................................................................................... $ 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. Total operating revenues ................................................... $ Total operating expenses ................................................... Operating income .............................................................. $ 19,401 3,111 16,290 Year Ended December 31, 2014 (in thousands) In addition to the acquisitions above, 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, respectively. The Company reflected the total consideration paid as part of its costs subject to depletion within its oil and gas properties. The revenues and operating expenses attributable to the working interest acquisitions during the years ended December 31, 2014 and 2013, were not material. 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 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 ............................................................................................... $ 24,365 8,062 32,427 (167) 32,260 F-24 PARSLEY ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS December 31, 2015 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 increased 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 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 ............................................................................................... $ 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) 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 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. In addition to the acquisitions above, 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. 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 and combined 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. F-25 PARSLEY ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS December 31, 2015 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 and combined 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 and combined financial information has been prepared as if the Material Acquisitions occurred on January 1, 2013 for the years ending December 31, 2014 and 2013 (in thousands, except per share data). Pro Forma 2014 2013 Revenue As reported ...................................................................................... $ Pro forma ......................................................................................... $ Net Income As reported ...................................................................................... $ Pro forma ......................................................................................... $ Basic net income per share As reported ...................................................................................... $ Pro forma ......................................................................................... $ Diluted net income per share As reported ...................................................................................... $ Pro forma ......................................................................................... $ 301,757 $ 307,999 $ 23,429 $ 24,894 $ 0.42 0.45 0.42 0.45 121,018 143,443 27,510 29,452 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. Net income per share is not applicable for the period prior to the IPO. NOTE 6. SALES OF OIL AND NATURAL GAS PROPERTIES In December 2015, the Company sold its interest in 91 operated wells and 11,664 gross (7,155 net) acres for net proceeds of $39.4 million and realized a $36.7 million dollar loss, net of estimated purchase price adjustments. In July 2015, the Company sold 9,164 net acres for total proceeds of $9.3 million and recognized a gain on the sale of $3.2 million. 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. 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. F-26 PARSLEY ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS December 31, 2015 NOTE 7. DEBT The Company’s debt consists of the following (in thousands): December 31, 2015 December 31, 2014 Revolving credit agreement ....................................................................... $ Senior unsecured notes .............................................................................. Capital leases ............................................................................................. Total debt ........................................................................................ Premium on senior unsecured notes .......................................................... Less: current portion ............................................................................ Total long-term debt ....................................................................... $ — $ 550,000 2,215 552,215 4,660 (951 ) 555,924 $ 120,000 550,000 2,069 672,069 5,426 (650) 676,845 Revolving Credit Agreement The Company maintains a Revolving Credit Agreement with a syndicate of financial institutions, which has been amended periodically. 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 and is secured by substantially all of the Company’s assets. The Revolving Credit Agreement provides for determination of the borrowing base based on the Company’s proved producing reserves and a portion of its proved undeveloped reserves. The borrowing base is redetermined by the lenders at least semi-annually on each April 1 and October 1, with the next redetermination on April 1, 2016. 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, whereby the borrowing base was reduced from $175.0 million to $143.8 million. On December 20, 2013, The Company entered into the First Amendment to the Amended and Restated Credit Agreement which increased the borrowing base from $143.8 million to $240.0 million. In addition, the amendment provided that the borrowing base would automatically increase from $240.0 million to $280.0 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 15 months to 18 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 IPO 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, whereby reporting requirements and deliverables were changed in response to the Company becoming a public company. On November 10, 2014, the Company entered into the Seventh Amendment to the Revolving 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, as a result of the Company restructuring its 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. F-27 PARSLEY ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS December 31, 2015 On April 21, 2015, the Company entered into the Eighth Amendment to the Revolving Credit Agreement whereby the borrowing base was adjusted to $500.0 million, with the commitment level increasing to $500.0 million. On November 3, 2015, the Company entered into the Ninth Amendment to the Revolving Credit Agreement whereby the commitment level of the lenders under the Revolving Credit Agreement was increased from $500.0 million to $575.0 million, and the borrowing base was increased from $500.0 million to $575.0 million. On December 14, 2015, the Company used proceeds from the December Offering to repay outstanding borrowings under the Revolving Credit Agreement. As of December 31, 2015 there were no borrowings outstanding and $0.3 million in letters of credit outstanding, resulting in availability of $574.7 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 LIBOR rate (equal to the product of: (a) the LIBOR 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 LIBOR 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, 2015, letters of credit outstanding under the Revolving Credit Agreement had a weighted average interest rate of 1.77%. 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: (cid:121) (cid:121) a current ratio, which is the ratio of consolidated current assets (including unused availability under its 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. At December 31, 2015, 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. 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 F-28 PARSLEY ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS December 31, 2015 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 12-month period beginning on February 15, 2017, 103.750% for the 12-month period beginning February 15, 2018, 101.875% for the 12-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, 2015, 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. Capital Lease The Company enters into capital lease agreements (“Capital Leases”) in connection with the lease of vehicles for operations and field personnel. The Capital Leases bear interest at annual rates ranging from 4.9% to 6.7% with varying maturities between February 2017 and November 2018. The Capital Leases require monthly payments of $88,280 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, 2015 are as follows (in thousands): 2016 ................................................................................................................................... $ 2017 ................................................................................................................................... 2018 ................................................................................................................................... 2019 ................................................................................................................................... 2020 ................................................................................................................................... Thereafter .......................................................................................................................... Total ............................................................................................................................. $ 951 1,000 264 — — 550,000 552,215 F-29 PARSLEY ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS December 31, 2015 Interest expense The following amounts have been incurred and charged to interest expense for the year ended December 31, 2015, 2014, and 2013 (in thousands): Cash payments for interest ............................................................. $ Change in interest accrual .............................................................. Payment-in-kind interest ................................................................ Amortization of deferred loan origination costs............................. Write-off of deferred loan origination costs ................................... Amortization of bond premium ...................................................... Other interest (expense) income..................................................... Interest costs incurred ......................................................... Less: capitalized interest .......................................................... Total interest expense, net .................................................. $ Year ended December 31, 2014 2013 2015 43,993 $ (348) — 2,170 532 (764) (2) 45,581 — 45,581 $ 27,252 $ 13,390 234 1,941 386 (574 ) (316 ) 42,313 (2,689 ) 39,624 $ 13,555 — 2,597 405 820 — (235) 17,142 (3,409) 13,733 NOTE 8. 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, 2015 and 2014. Class A Common Stock The Company has 136.6 million shares of its Class A Common Stock outstanding as of December 31, 2015, which includes 0.6 million shares of restricted stock. Holders of Class A Common Stock are entitled to one vote per share on all matters to be voted upon by the stockholders and are entitled to ratably receive dividends when and if declared by the Company’s board of directors. Upon liquidation, dissolution, distribution of assets or other winding up, the holders of Class A Common Stock are entitled to receive ratably the assets available for distribution to the stockholders after payment of liabilities and the liquidation preference of any of our outstanding shares of preferred stock. Class B Common Stock The Company has 32.1 million shares of its Class B Common Stock outstanding as of December 31, 2015. 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 F-30 PARSLEY ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS December 31, 2015 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, 2015, no PE Unit Holders elected to exchange pursuant to their Exchange Right. Earnings per Share Basic EPS measures the performance of an entity over the reporting period. Diluted EPS 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. EPS for the year ended December 31, 2015 is calculated using the 12 months ended December 31, 2015. EPS for the year ended December 31, 2014 is calculated for the period from May 29, 2014, the closing date of the IPO, to December 31, 2014. EPS information is not applicable for reporting periods prior to the completion of the IPO. 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, 2015 December 31, 2014, as revised (1) Basic EPS (in thousands, except per share data) Numerator: Basic net (loss) 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 (loss) 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 (loss) 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 (2) ...................... Diluted EPS attributable to Parsley Energy, Inc. Stockholders ........................................................................... $ (50,484) $ 111,271 (0.45) $ 61,352 93,168 0.65 (50,484) 61,352 — (50,484) $ 111,271 — — 111,271 (0.45) $ — 61,352 93,168 — 103 93,271 0.65 (1) See Note 2—Summary of Significant Accounting Policies—Revision of 2014 Financial Statements. (2) Approximately 211,935 shares related to performance based restricted stock units that could be converted to common shares in the future based on predetermined performance and market goals were not included in the computation of EPS for the year ended December 31, 2015, because the performance and market conditions had not been met, assuming the end of the reporting period was the end of the contingency period. F-31 PARSLEY ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS December 31, 2015 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. Noncontrolling Interest Concurrent with the closing of the Pacesetter Acquisition, Pacesetter’s President acquired a 37.0% interest in Pacesetter, with Operations retaining 63.0% of Pacesetter. As a result, the Company has consolidated the financial position and results of operations of Pacesetter due to Operations’ ownership interest. The 37.0% interest retained by Pacesetter’s President is reflected as a noncontrolling interest. As a result of the Corporate Reorganization and the IPO in 2014, the Company acquired 74.3% of Parsley LLC, with the Existing Owners retaining ownership of 25.7% of Parsley LLC. Upon completion of the additional public offerings of Class A Common Stock in 2015 as discussed in Note 1—Organization and Nature of Operations, at December 31, 2015, the Company’s ownership of Parsley LLC was 81.0% and with the PE Unit Holders’ ownership of Parsley LLC was 19.0%. The Company has consolidated the financial position and results of operations of Parsley LLC and reflected that portion retained by the PE Unit Holders as a noncontrolling interest. Because the increase in the Company’s ownership interest in Parsley LLC does not result in a change of control, the transaction is accounted for as an equity transaction under ASC Topic 810, “Consolidation,” which requires that any differences between the amount by which the carrying value of the Company’s basis in Parsley LLC is adjusted and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest. The following table summarizes the noncontrolling interest income (loss): Net income (loss) attributable to the noncontrolling interests of: Parsley LLC ................................................................................................................ $ Pacesetter .................................................................................................................... Total net income (loss) attributable to noncontrolling interest ......................................... $ (21,870 ) $ (677 ) (22,547 ) $ 33,293 — 33,293 Year ended December 31, 2014 2015 (in thousands) There was no noncontrolling interest during the year ended December 31, 2013. NOTE 9. STOCK BASED COMPENSATION In connection with the IPO in May 2014, the Company adopted the Parsley Energy, Inc. 2014 Long Term Incentive Plan for employees, consultants, and directors of the Company who perform services for the Company. Refer to “Executive Compensation and Other Information—Narrative Disclosure to Summary Compensation Table—2014 Long-Term Incentive Plan” in the Company’s Proxy Statement filed on Schedule 14A for the 2015 Annual Meeting of Stockholders for additional information related to this equity based compensation plan. F-32 PARSLEY ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS December 31, 2015 Restricted Stock 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. The stock based compensation expense for these awards was determined using the closing price on the date of grant applied to the total number of shares that were anticipated to fully vest. Time-Based Restricted Stock Unit Awards Restricted stock unit awards represent the right to receive Class A Common Stock at the end of the vesting period equal to the number of restricted stock units granted. Restricted stock units are subject to restrictions on transfer and are generally subject to a risk of forfeiture if the award recipient is no longer an employee or director of the Company for any reason prior to the lapse of the restriction. The stock based compensation expense of such restricted stock units was determined using the closing price on the date of grant applied to the total number of shares that were anticipated to fully vest. Performance Unit Awards In February 2015, performance-based, stock-settled restricted stock unit awards, which we refer to as performance unit awards, were granted with a performance period of three years. The number of shares of Class A Common Stock actually delivered pursuant to these performance unit awards depends on the Company’s performance over the performance period with respect to certain predetermined market conditions. The Company granted a target number of 211,935 performance unit awards, but the conditions of the grants allow for an actual payout ranging between no payout and 200% of target. The fair value of such performance units was determined using a Monte Carlo simulation and will be recognized over the next three years. The payout level is calculated based on actual performance achieved during the performance period compared to a defined peer group. The following table summarizes the Company’s restricted stock, restricted stock unit, and performance unit activity for the year ended December 31, 2015: Restricted Stock Restricted Stock Units (in thousands) Performance Units Outstanding at January 1, 2015 ............................................ Awards granted (a) ......................................................... Forfeited ......................................................................... Vested ............................................................................. Outstanding at December 31, 2015 ...................................... 733 42 (69) (45) 661 24 513 (22 ) (2 ) 513 — 212 — — 212 (a) Weighted average grant date fair value ..................... $ 16.99 $ 16.77 $ 24.20 Stock based compensation expense associated with restricted stock, restricted stock units, and performance units was $8.1 million and $2.2 million for the years ended December 31, 2015 and 2014, respectively, and is included in general and administrative expenses on the Company’s consolidated and combined statement of operations. The Company recognizes stock based compensation expense on restricted stock units with graded vesting on a straight-line basis over the requisite service period for each separately vesting portion of the award as if the award was, in-substance, multiple awards. There was approximately $16.7 million of unamortized compensation expense relating to outstanding restricted stock, restricted stock units, and performance units at December 31, 2015. 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-33 PARSLEY ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS December 31, 2015 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 the unrecognized cumulative incentive unit compensation expense of $51.1 million recognized during the year ended December 31, 2014 which is included in general and administrative expenses on the Company’s consolidated and combined statement of operations. NOTE 10. 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. The tax returns and the amount of taxable income or loss are subject to examination by federal and state taxing authorities. 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. At December 31, 2015, the Company did not have any accrued liability for uncertain tax positions and does not anticipate recognition of any significant liabilities for uncertain tax positions during the next twelve months. The Company’s policy is to record interest and penalties relating to uncertain tax positions in income tax expense. Parsley LLC, the Company’s accounting predecessor, is a limited liability company that is not subject to United States (“U.S.”) federal income tax. The Company is a corporation and is subject to U.S. federal income tax. The tax implications of the IPO and the Company’s concurrent Corporate Reorganization, and the tax impact of the Company’s status as a taxable corporation subject to U.S. federal income tax have been reflected in the accompanying consolidated and combined financial statements. The effective combined U.S. federal and state income tax rate as of December 31, 2015 was 24.5%. During the years ended December 31, 2015, 2014, and 2013, the Company recognized an income tax benefit of $23.8 million, an income tax expense of $36.5 million, and an income tax expense of $1.9 million, respectively. Total income tax differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due primarily to the change in corporate status, state taxes, and the impact of earnings (loss) attributable to noncontrolling ownership interests. 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, at December 31, 2015 the Company had recorded a long-term liability of $51.5 million for the TRA (as defined herein) and a corresponding deferred tax asset of $60.6 million. As a result of the public offerings of Class A Common Stock, as discussed in Note 1—Organization and Nature of Operations, the Company’s statutory rate related to certain tax and book basis timing differences increased by 2%, calculated by multiplying the 6.7% increase in the Company’s ownership of Parsley LLC by the Company’s federal tax rate of 35%. As a result, the Company recorded additional deferred tax liability of $18.4 million during the year ended December 31, 2015. F-34 PARSLEY ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS December 31, 2015 The components of the income tax (benefit) expense were as follows for the periods indicated (in thousands): Federal: Current ............................................................................................................ $ Deferred .......................................................................................................... Total federal .................................................................................................... State, net of federal benefit: Deferred .......................................................................................................... Total state ........................................................................................................ Income tax (benefit) expense .......................................................................... $ 2015 Year Ended December 31, 2014 2013 286 $ (27,535) (27,249) 3,494 3,494 (23,755) $ — $ 31,968 31,968 4,500 4,500 36,468 $ — — — 1,906 1,906 1,906 The following table reconciles the income tax (benefit) expense 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 loss (income) before income taxes 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 (benefit) expense ............................................................................. $ 2015 Year Ended December 31, 2014 2013 (96,785)$ — 93,190 $ 37,378 29,416 — 22,438 (33,293) — (74,347) (26,022) 3,494 — (1,217) (10) (23,755)$ 97,275 34,046 967 1,246 170 39 36,468 $ 29,416 — — 1,906 — — 1,906 Net (loss) income attributable to Parsley Energy Inc. Stockholders ............................................................................................. $ Net (loss) income attributable to noncontrolling interest ............................................................................................................. $ (50,484)$ 23,429 $ 27,510 (22,547)$ 33,293 $ — As of December 31, 2015, the Company had approximately $0.3 million of alternative minimum tax credits available that do not expire. In addition, the Company had approximately $50.4 million of federal net operating loss carryovers that expire during the years 2033 through 2035. Excess tax benefits of approximately $.2 million associated with the vesting of restricted stock awards are included in the federal net operating loss carryovers, but will not be recognized as a tax benefit recorded to additional paid-in capital until realized. Internal Revenue Code (“IRC”) Section 382 addresses company ownership changes and specifically limits the utilization of certain deductions and other tax attributes on an annual basis following an ownership change. The Company may be found to have experienced an ownership change within the meaning of IRC Section 382 during 2015 that could subject a portion of the federal net operation loss carryforwards to an IRC Section 382 limitation. Such limitation would not result in a current federal tax liability at December 31, 2015. F-35 PARSLEY ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS December 31, 2015 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 ................................................................................... $ NOTE 11. RELATED PARTY TRANSACTIONS Well Operations December 31, 2015 2014 — $ — — (12,601) (12,601) (12,601) 5,297 — 3,066 18,141 26,504 (64,792 ) (23,969 ) (705 ) (89,466 ) (62,962 ) $ 4,379 431 644 50,425 55,879 (108,825) (8,874) (514) (118,213) (62,334) During the years ended December 31, 2015, 2014, and 2013, several of the Company’s directors, officers, 10% 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, 2015, 2014, and 2013, totaled $5.2 million, $11.3 million, and $14.4 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 During the year 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 IPO, Diamond K exchanged its membership interest for shares of Class A Common Stock. As of May 29, 2014, Diamond K is no longer considered a related party as their ownership interest fell below 10% 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 F-36 PARSLEY ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS December 31, 2015 equipment used in its drilling operations totaling $29.3 million, from Tex-Isle. During the year ended December 31, 2013, the Company made purchases of equipment used in its drilling operations totaling $68.1 million. Spraberry Production Services LLC At December 31, 2015, the Company owns a 42.5% interest in SPS and accounts for this investment using the equity method. Using the equity method of accounting results in transactions between the Company and SPS and its subsidiaries being accounted for as related party transactions. During the years ended December 31, 2015, 2014 and 2013, the Company incurred charges totaling $4.8 million, $5.1 million, and $3.3 million, respectively, for services performed by SPS for the Company’s well operations and drilling activities. Lone Star Well Service, LLC The Company makes purchases of equipment used in its drilling operations from Lone Star Well Service, LLC (“Lone Star”). Lone Star is controlled by SPS. During the years ended December 31, 2015 and 2014, the Company incurred charges totaling $5.0 million and $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. Davis, Gerald, and Cremer During the years ended December 31, 2015, 2014, and 2013, the Company incurred charges totaling $0.2 million, $0.2 million, and $0.3 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 IPO, 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 IPO (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 IPO as a result of (i) any tax basis increases resulting from the contribution in connection with the IPO by such TRA Holder of all or a portion of its PE Units to the Company in exchange for shares of Class A Common Stock, (ii) the tax basis increases resulting from the exchange by such TRA Holder of PE Units for shares of Class A Common Stock 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. As of December 31, 2015 there have been no payments associated with the TRA. F-37 PARSLEY ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS December 31, 2015 NOTE 12. COMMITMENTS AND CONTINGENCIES Legal Matters 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. 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, 2015 and 2014, 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, 2015: (in thousands) Drilling commitments ....................... $ 21,735 $ 2016 2017 2018 2019 2020 Thereafter Total 8,449 $ — $ — $ — $ — $ 30,184 Payments Due by Period Derivative Obligations The future deferred premium payments related to derivative agreements as of December 31, 2015 was as follows (in thousands): (in thousands) Derivative obligations ....................... $ 11,675 $ 2016 2017 2018 2019 2020 Thereafter Total 4,950 $ — $ — $ — $ — $ 16,625 Payments Due by Period F-38 PARSLEY ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS December 31, 2015 Operating Leases The estimated future minimum lease payments under long-term operating lease agreements as of December 31, 2015 was as follows (in thousands): 2016 2017 2018 2019 2020 Thereafter Total For the years ended December 31, Office Leases .................................... $ 4,786 $ 6,625 Vehicle Operating Leases ................. Office Equipment .............................. 160 Total .................................................. $ 11,571 $ 5,158 $ — 106 5,264 $ 5,276 $ — 38 5,314 $ 5,398 $ — — 5,398 $ 5,395 $ — — 5,395 $ 21,102 $ — — 21,102 $ 47,115 6,625 304 54,044 Rent expense for the years ended December 31, 2015, 2014 and 2013 was $4.7 million, $1.5 million and $0.7 million, respectively. NOTE 13. DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS The Company uses a valuation framework based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized 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 Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis, but are subject to fair value adjustments in whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. These assets and liabilities can include inventory, proved and unproved oil and natural gas properties, and other long-lived assets that are written down to fair value when they are impaired. Materials and Supplies. During the year ended December 31, 2015, the Company recognized impairment of $4.1 million primarily to reduce the carrying value of oil and gas drilling and repair items. The Company calculated the estimated fair value of the inventory using significant Level 2 assumptions based on third-party price quotes for the asset in an active market. The impairment F-39 PARSLEY ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS December 31, 2015 charges are included in other income (expense) in the Company’s accompanying consolidated and combined statements of operations. No impairment charge was recorded during the years ended December 31, 2014 and 2013. Proved oil and natural gas properties. During the year ended December 31, 2015, reductions in management’s long-term commodity price outlooks provided indications of possible impairment. As a result of management’s assessments, during the year ended December 31, 2015, the Company recognized impairment charges of $1.0 million to reduce the carrying values of certain properties in Upton County to their estimated fair values. 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 Instruments not carried at Fair Value 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 $522.6 million. The fair value of the Notes is classified as a level 2 measurement as it is calculated based on market quotes. 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 3—Derivative Financial Instruments. The company adjusts the valuations from the valuation model for nonperformance risk and for counterparty risk. The fair values of the Company’s commodity derivative instruments are classified as level 2 measurements as they are calculated using industry standard models using assumptions and inputs which are substantially observable in active markets throughout the full term of the instruments. These include market price curves, contract terms and prices, credit risk adjustments, implied market volatility and discount factors. The following summarizes the fair value of the Company’s derivative assets and liabilities according to their fair value hierarchy as of the reporting dates indicated (in thousands): Level 1 Level 2 Level 3 Total December 31, 2015 Commodity derivative contracts Assets: Short-term derivative instruments ............................... $ Long-term derivative instruments ............................... Total derivative instrument - asset ......................... $ — — — $ $ 83,262 25,839 109,101 $ $ — — — $ $ 83,262 25,839 109,101 Liabilities: Short-term derivative instruments ............................... $ Long-term derivative instruments ............................... Total derivative instruments - liability ................... Net commodity derivative asset ....................... $ — — — — $ $ (34,518) (15,142) (49,660) 59,441 $ $ — — — — $ $ (34,518) (15,142) (49,660) 59,441 F-40 PARSLEY ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS December 31, 2015 Level 1 Level 2 Level 3 Total December 31, 2014 Commodity derivative contracts Assets: Short-term derivative instruments ............................... $ Long-term derivative instruments ............................... Total derivative instrument - asset ......................... $ — — — $ $ 80,911 70,805 151,716 $ $ — — — $ $ 80,911 70,805 151,716 Liabilities: Short-term derivative instruments ............................... $ Long-term derivative instruments ............................... Total derivative instruments - liability ................... Net commodity derivative asset ....................... $ — — — — $ $ (29,326) (31,275) (60,601) 91,115 $ $ — — — — $ $ (29,326) (31,275) (60,601) 91,115 There were no transfers in to or out of level 2 during the years ended December 31, 2015 or 2014. NOTE 14. SUBSEQUENT EVENTS The Company has evaluated subsequent events through the date these financial statements were issued. The Company determined there were no events, other than as described below, that required disclosure or recognition in these financial statements. During the first quarter of 2016, the Company acquired certain undeveloped acreage and producing oil and gas properties located adjacent to existing operating areas in Upton, Reagan, and Glasscock Counties for an aggregate purchase price of $148.5 million, of which the Company paid a deposit of $10.0 million during December 2015. The deposit is included in other current assets on the consolidated and combined balance sheets and as an operating activity on the consolidated and combined statement of cash flows, included herein. The acquisition added 260 gross (227 net) horizontal drilling locations across 6,040 gross (5,274 net) surface acres and production from three producing horizontal wells. The acquisition also included one drilled horizontal well that was completed by the seller during January 2016. F-41 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, 2015 2014 (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 ........................ $ 1,627,367 $ 618,794 2,246,161 (290,186) 1,955,975 $ 1,248,376 624,240 1,872,616 (128,044 ) 1,744,572 Costs Incurred for Oil and Natural Gas Producing Activities Acquisition costs: Proved properties ............................................................. $ Unproved properties......................................................... Development costs .............................................................. Total .................................................................................... $ 2015 Year Ended December 31, 2014 2013 (in thousands) 16,422 $ 57,385 404,291 478,098 $ 233,899 $ 528,301 488,673 1,250,873 $ 142,695 65,686 268,400 476,781 Reserve Quantity Information The following information represents estimates of the Company’s proved reserves as of December 31, 2015, 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, 2015 was based on an unweighted average 12-month average WTI 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) ................................................................................. $ 46.54 $ 16.42 $ 2.53 $ 85.99 $ 35.27 $ 4.28 $ 92.53 36.20 3.46 2015 Year Ended December 31, 2014 2013 Subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This requirement has limited, and may continue to limit, the Company’s potential to record additional proved undeveloped reserves as it pursues its drilling program. Moreover, the Company may be required to write down its proved undeveloped reserves if it does not drill on those reserves with the required five-year timeframe. The Company does not have any proved undeveloped reserves which have remained undeveloped for five years or more. The Company’s proved oil and natural gas reserves are located in the United States in the Permian Basin of West Texas. Proved reserves were estimated in accordance with the guidelines established by the SEC and the FASB. Oil and natural gas reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than F-42 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, 2015, 2014, and 2013, 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, 2015 Natural Gas Liquids (Bbls) (Mcf) Boe 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 .................................................................. (in thousands) 47,617 38,518 (6,688) 1,133 (1,896) (4,807) 73,877 22,667 9,232 (6,934) 551 (278) (1,500) 23,738 123,645 53,044 (11,825 ) 4,138 (1,488 ) (10,339 ) 157,175 90,891 56,590 (15,593) 2,374 (2,422) (8,030) 123,810 Proved Developed Reserves: Beginning of the year ........................................................ End of the year .................................................................. Proved Undeveloped Reserves: Beginning of the year ........................................................ End of the year .................................................................. 23,547 27,628 11,491 10,890 65,484 77,612 45,952 51,454 24,070 46,249 11,175 12,848 58,161 79,563 44,939 72,357 Crude Oil (Bbls) Liquids (Bbls) Year Ended December 31, 2014 Natural Gas (Mcf) Boe 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 .................................................................. (in thousands) 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 F-43 Proved Developed and Undeveloped Reserves: Beginning of the year .................................................................. Extensions and discoveries ......................................................... Revisions of previous estimates .................................................. Purchases of reserves in place ..................................................... Divestures of reserves in place .................................................... Production ................................................................................... End of the year ............................................................................ Proved Developed Reserves: Beginning of the year .................................................................. End of the year ............................................................................ Proved Undeveloped Reserves: Beginning of the year .................................................................. End of the year ............................................................................ Crude Oil (Bbls) Year Ended December 31, 2013 Liquids (Bbls) Natural Gas (Mcf) (in thousands) 12,987 10,378 (2,029) 9,223 (3) (1,049) 29,507 5,834 13,560 4,732 4,840 (796) 3,695 (1) (113) 12,357 30,214 29,489 (1,813) 23,937 (7) (4,002) 77,818 1,906 4,762 12,186 31,301 Boe 22,755 20,132 (3,127) 16,908 (5) (1,829) 54,834 9,771 23,539 7,153 15,947 2,826 7,595 18,028 46,517 12,984 31,295 Extensions and discoveries of 56,590 MBoe, 33,824 MBoe and 20,132 MBoe during the years ended December 31, 2015, 2014 and 2013, 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, 2015, 2014, and 2013 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: 2015 December 31, 2014 (in thousands) 2013 Future cash inflows (1) ...................................................... $ 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 ..... $ 4,225,912 $ (829,560) (1,534,011) (240,203) 1,622,138 (1,024,290) 597,848 $ 5,423,551 $ (642,746 ) (1,640,422 ) (903,354 ) 2,237,029 (1,281,400 ) 955,629 $ 3,446,766 (515,247) (1,097,734) (24,127) 1,809,658 (1,088,878) 720,780 (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. 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 Margin Tax, at a statutory rate of up to 1.0% of income that is apportioned to Texas. Following the Corporate Reorganization, the Company was F-44 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 would have been $562.5 million. The unaudited standardized measure at December 31, 2013 would have been $497.7 million. In the foregoing determination of future cash inflows, sales prices used for oil, NGLs, and natural gas for December 31, 2015, 2014, and 2013, 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 ............................................................................... $ 2015 Year Ended December 31, 2014 (in thousands) 2013 955,629 $ (185,344) 4,872 (53,018) 720,780 $ (244,745 ) 279,725 — 296,048 (97,365) 227,937 (122) 485,380 537,241 204,135 12,560 (821,783) 77,621 (225,485) 131,442 249,065 (33,091) 96,881 (74,080 ) (9,517 ) (126,395 ) 73,107 (348,501 ) 51,133 57,158 11,463 2,793 (41,242) 30,010 (6,240) 36,205 597,848 $ 955,629 $ 720,780 F-45 CORPORATE INFORMATION FROM LEFT TO RIGHT: CECILIA CAMARILLO, TOM LAYMAN, MATT GALLAGHER, PAUL TREADWELL, BRYAN SHEFFIELD, BRAD SMITH, RYAN DALTON, MIKE HINSON, STEPHANIE REED, COLIN ROBERTS MANAGEMENT BRYAN SHEFFIELD President, Chief Executive Officer and Chairman of the Board BRAD SMITH Vice President, Corporate Strategy and Investor Relations RYAN DALTON Vice President, Chief Financial Officer PAUL TREADWELL Vice President, Operations MATT GALLAGHER Vice President, Chief Operating Officer MIKE HINSON Vice President, Land THOMAS LAYMAN Vice President, Geoscience CECILIA CAMARILLO Vice President, Accounting STEPHANIE REED Manager, Investor Relations COLIN ROBERTS Vice President, General Counsel and Secretary BOARD OF DIRECTORS BRYAN SHEFFIELD Chairman of the Board A.R. ALAMEDDINE(2) Director WILLIAM BROWNING(1) Director DR. HEMANG DESAI(1)(2) 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 RONALD BROKMEYER(1)(2) Director RANDOLPH NEWCOMER, JR.(1)(3) Director m o c . s r o n n o c - n a r r u c . w w w / . c n I , s r o n n o C & n a r r u C y b n g i s e D t r o p e R l a u n n A CORPORATE OFFICES AUSTIN OFFICE 303 Colorado Street Suite 3000 Austin, TX 78701 737-704-2300 MIDLAND OFFICE 500 W. Texas Avenue Suite 200 Midland, TX 79701 432-818-2100 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 PETROLEUM ENGINEERS Netherland, Sewell & Associates, Inc. 2100 Ross Avenue Suite 2200 Dallas, TX 75201 TRANSFER AGENT For shareholder questions regarding transfer of shares, lost stock certificates, duplicate mail- ings, change of address or other similar matters, please contact our Transfer Agent: INVESTOR AND MEDIA RELATIONS 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 Vice President, Corporate Strategy and Investor Relations Parsley Energy, Inc. 512-505-5199 VISIT OUR WEBSITE www.parsleyenergy.com American Stock Transfer & Trust Company 6201 15th Avenue Brooklyn, NY 11219 800-937-5449 ANNUAL MEETING The Annual Meeting of Stockholders will be held Thursday, June 2, 2016, at 8:00 a.m. CT at: J.W. Marriott Austin 110 E. 2nd Street Austin, TX 78701 

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