Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2019

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number: 001-35380

Laredo Petroleum, Inc.

(Exact name of registrant as specified in its charter)



Delaware	45-3007926
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)



15 W. Sixth Street	Suite 900
Tulsa	Oklahoma	74119
(Address of principal executive offices)		(Zip code)

(918) 513-4570

(Registrant's telephone number, including area code)

Securities Registered Pursuant to Section 12(b) of the Act:



Title of each class	Trading symbol	Name of each exchange on which registered
Common stock, $0.01 par value per share	LPI	New York Stock Exchange

Securities Registered Pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):



Large accelerated filer	☒	Accelerated filer	☐

Non-accelerated filer	☐	Smaller reporting company	☐

Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

Aggregate market value of the voting and non-voting common equity held by non-affiliates was approximately $526.2 million on June 30, 2019, based on $2.90 per share, the last reported sales price of the common stock on the New York Stock Exchange on such date.

Number of shares of registrant's common stock outstanding as of February 11, 2020: 237,207,787

Documents Incorporated by Reference:

Portions of the registrant's definitive proxy statement for its 2020 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2019, are incorporated by reference into Part III of this report for the year ended December 31, 2019.



	Laredo Petroleum, Inc.

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	Page
Glossary of Oil and Natural Gas Terms	3
Cautionary Statement Regarding Forward-Looking Statements	6
Part I	8
Item 1. Business	8
Item 1A. Risk Factors	31
Item 1B. Unresolved Staff Comments	50
Item 2. Properties	50
Item 3. Legal Proceedings	50
Item 4. Mine Safety Disclosures	50
Part II	51
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	51
Item 6. Selected Historical Financial Data	53
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations	55
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	85
Item 8. Financial Statements and Supplementary Data	87
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	89
Item 9A. Controls and Procedures	89
Item 9B. Other Information	89
Part III	90
Item 10. Directors, Executive Officers and Corporate Governance	90
Item 11. Executive Compensation	90
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	90
Item 13. Certain Relationships and Related Transactions, and Director Independence	90
Item 14. Principal Accounting Fees and Services	90
Part IV	91
Item 15. Exhibits, Financial Statement Schedules	91
Signatures	95
Index to Consolidated Financial Statements	F-1

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Glossary of Oil and Natural Gas Terms

The following terms are used throughout this Annual Report on Form 10-K (this "Annual Report"):

"2D"—Method for collecting, processing and interpreting seismic data in two dimensions.

"3D"—Method for collecting, processing and interpreting seismic data in three dimensions.

"Allocation well"—A horizontal well drilled by an oil and gas producer under two or more leaseholds that are not pooled, under a permit issued by the Texas Railroad Commission.

"Basin"—A large natural depression on the earth's surface in which sediments, generally brought by water, accumulate.

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

"Benchmark Prices"—The unweighted arithmetic average first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period before differentials, as required by SEC guidelines.

"BOE"—One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.

"BOE/D"—BOE per day.

"Brent"—A light (low density) and sweet (low sulfur) crude oil sourced from the North Sea, used as a pricing benchmark for ICE oil futures contracts.

"Btu"—British thermal unit, the quantity of heat required to raise the temperature of a one pound mass of water by one degree 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.

"Developed acreage"—The number of acres that are allocated or assignable to productive wells or wells capable of production.

"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.

"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 or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

"Formation"—A layer of rock which has distinct characteristics that differ from nearby rock.

"Fracturing" or "Frac"—The propagation of fractures in a rock layer by a pressurized fluid. This technique is used to release petroleum and natural gas for extraction.

"GAAP"—Generally accepted accounting principles in the United States.

"Gross acres" or "gross wells"—The total acres or wells, as the case may be, in which a working interest is owned.

"HBP"—Acreage that is held by production.

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"Henry Hub"—A natural gas pipeline delivery point in south Louisiana that serves as the benchmark natural gas price underlying NYMEX natural gas futures contracts.

"Horizon"—A term used to denote a surface in or of rock, or a distinctive layer of rock that might be represented by a reflection in seismic data.

"Horizontal drilling"—A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

"ICE"—The Intercontinental Exchange.

"Initial Production"—The measurement of production from an oil or gas well when first brought on stream. Often stated in terms of production during the first thirty days.

"Liquids"—Describes oil, condensate and natural gas liquids.

"MBbl"—One thousand barrels of crude oil, condensate or natural gas liquids.

"MBOE"—One thousand BOE.

"MMBOE"—One million BOE.

"Mcf"—One thousand cubic feet of natural gas.

"MMBtu"—One million Btu.

"MMcf"—One million cubic feet of natural gas.

"Natural gas liquids" or "NGL"—Components of natural gas that are separated from the gas state in the form of liquids, which include propane, butanes and ethane, among others.

"Net acres"—The percentage of gross acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.

"NYMEX"—The New York Mercantile Exchange.

"Production corridor"—Infrastructure put in place over an extended area, usually several miles, containing multiple pipelines to facilitate the transfer of oil, natural gas and/or water. A specific production corridor may also contain water recycling facilities, artificial gas lift and fuel gas distribution lines.

"Productive well"—A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

"Proved developed non-producing reserves" or "PDNP"—Developed non-producing reserves.

"Proved developed reserves" or "PDP"—Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

"Proved reserves"—The estimated quantities of oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

"Proved undeveloped reserves" or "PUD"—Proved reserves that are expected to be recovered within five years from new wells on undrilled locations and for which a specific capital commitment has been made or from existing wells where a relatively major expenditure is required for recompletion.

"Realized Prices"—Prices which reflect adjustments to the Benchmark Prices for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead without giving effect to our commodity derivative transactions.

"Recompletion"—The process of re-entering an existing wellbore that is either producing or not producing and completing in new reservoirs in an attempt to establish or increase existing production.

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"Reservoir"—A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

"Resource play"—An expansive contiguous geographical area, potentially supporting numerous drilling locations, with prospective crude oil and/or natural gas reserves that has the potential to be developed uniformly with repeatable commercial success due to advancements in horizontal drilling and multi-stage fracturing technologies.

"Spacing"—The distance between wells producing from the same reservoir.

"Standardized measure"—Discounted future net cash flows estimated by applying Realized Prices to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the oil and natural gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.

"Three stream"—Production or reserve volumes of oil, natural gas liquids and natural gas, where the natural gas liquids have been removed from the natural gas stream and the economic value of the natural gas liquids is separated from the wellhead natural gas price.

"Undeveloped acreage"—Lease 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.

"Wellhead natural gas"—Natural gas produced at or near the well.

"Wolfberry"—A general industry term that applies to the vertical stratigraphic interval that can include the shallow Spraberry formation to the deeper Woodford formation throughout the Permian Basin.

"Working interest" or "WI"—The right granted to the lessee of a property to explore for and to produce and own crude oil, natural gas liquids, natural gas or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis.

"WTI"—West Texas Intermediate grade crude oil. A light (low density) and sweet (low sulfur) crude oil, used as a pricing benchmark for NYMEX oil futures contracts.

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Cautionary Statement Regarding Forward-Looking Statements

Various statements contained in or incorporated by reference into this Annual Report 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, NGL 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," "will," "foresee," "plan," "goal," "should," "intend," "pursue," "target," "continue," "suggest" or the negative thereof or other variations thereof or other words that convey the uncertainty of future events or outcomes. Forward-looking statements are not guarantees of performance. 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. Among the factors that significantly impact our business and could impact our business in the future are:


•	the volatility of oil, NGL and natural gas prices, including in our area of operation in the Permian Basin;


•	our ability to discover, estimate, develop and replace oil, NGL and natural gas reserves and inventory;


•	changes in domestic and global production, supply and demand for oil, NGL and natural gas;


•	revisions to our reserve estimates as a result of changes in commodity prices, decline curves and other uncertainties;


•	the long-term performance of wells that were completed using different technologies;


•	the ongoing instability and uncertainty in the United States and international financial and consumer markets that could adversely affect the liquidity available to us and our customers and the demand for commodities, including oil, NGL and natural gas;


•	the potential impact on production of oil, NGL and natural gas from our wells resulting from co-development considerations such as horizontal spacing, vertical spacing and parent-child interactions;


•	capital requirements for our operations and projects;


•	impacts of impairment write-downs on our financial statements;


•	the availability and costs of drilling and production equipment, supplies, labor and oil and natural gas processing and other services;


•	the availability and costs of sufficient pipeline and transportation facilities and gathering and processing capacity;


•	our ability to maintain the borrowing capacity under our Senior Secured Credit Facility (as defined below) or access other means of obtaining capital and liquidity, especially during periods of sustained low commodity prices;


•	our ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results and to successfully integrate acquired businesses, assets and properties;


•	our ability to generate sufficient cash to service our indebtedness, fund our capital requirements and generate future profits;


•	restrictions contained in our debt agreements, including our Senior Secured Credit Facility and the indentures governing our Senior Unsecured Notes (as defined below), as well as debt that could be incurred in the future;


•	our ability to recruit and retain the qualified personnel necessary to operate our business;

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•	the potentially insufficient refining capacity in the U.S. Gulf Coast to refine all of the light sweet crude oil being produced in the United States, which could result in widening price discounts to world crude prices and potential shut-in of production due to lack of sufficient markets;


•	risks related to the geographic concentration of our assets;


•	our ability to secure or generate sufficient electricity to produce our wells without limitations;


•	our ability to hedge and regulations that affect our ability to hedge;


•	changes in the regulatory environment and changes in U.S. or international legal, tax, political, administrative or economic conditions, including regulations that prohibit or restrict our ability to apply hydraulic fracturing to our oil and natural gas wells and to access and dispose of water used in these operations and outbreak of disease;


•	legislation or regulations that prohibit or restrict our ability to drill new allocation wells;


•	our ability to execute our strategies;


•	competition in the oil and natural gas industry;


•	drilling and operating risks, including risks related to hydraulic fracturing activities;


•	drilling and operating risks, including risks related to inclement weather impacting our ability to produce existing wells and/or drill and complete new wells over an extended period of time; and


•	our ability to comply with federal, state and local regulatory requirements.

These forward-looking statements involve a number of risks and uncertainties that could cause actual results to differ materially from those suggested by the forward-looking statements. Forward-looking statements should therefore be considered in light of various factors, including those set forth in this Annual Report under "Item 1A. Risk Factors," in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and elsewhere in this Annual Report. In light of such risks and uncertainties, we caution you not to place undue reliance on these 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 do not intend to, and disclaim any obligation to, update or revise any forward-looking statements unless required by securities law.

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Part I

Laredo Petroleum, Inc. is a Delaware corporation formed in 2011 for the purpose of merging with Laredo Petroleum, LLC (a Delaware limited liability company formed in 2007) to consummate an initial public offering of common stock in December 2011 ("IPO"). Laredo Petroleum, Inc. was the survivor of such merger and currently has two wholly-owned subsidiaries, Laredo Midstream Services, LLC, a Delaware limited liability company ("LMS"), and Garden City Minerals, LLC, a Delaware limited liability company ("GCM").

Unless the context otherwise requires, references in this Annual Report to "Laredo," the "Company," "we," "our," "us," or similar terms refer to Laredo Petroleum, Inc. and its subsidiaries at the applicable time, including former subsidiaries and predecessor companies, as applicable.

Except where the context indicates otherwise, amounts, numbers, dollars and percentages presented in this Annual Report are rounded and therefore approximate.



Item 1.	Business

Overview

Laredo is an independent energy company focused on the acquisition, exploration and development of oil and natural gas properties, primarily in the Permian Basin of West Texas. The oil and liquids-rich Permian Basin is characterized by multiple target horizons, extensive production histories, long-lived reserves, high drilling success rates and high initial production rates. As of December 31, 2019, we had assembled 133,512 net acres in the Permian Basin and had total proved reserves, presented on a three-stream basis, of 293,377 MBOE. Our wholly-owned subsidiary, LMS, buys, sells, gathers and transports oil, natural gas and water primarily for the account of Laredo. We have identified one operating segment: exploration and production.

2019 operation highlights


•	Generated $475.1 million of net cash provided by operating activities and $59.7 million of Free Cash Flow in 2019 as we reduced capital expenditures by 25% from full-year 2018 (See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP financial measures and other calculations—Free Cash Flow")


•	Executed two accretive acquisitions of high-margin, oily inventory at valuations significantly below historic averages while maintaining a competitive leverage ratio


•	Produced 28,429 Bbl/D of oil and 80,883 BOE/D, increases of 2% and 19%, respectively, from full-year 2018


•	Grew total proved reserves by 55 million BOE and proved oil reserves by 17 million barrels, increases of 23% and 27%, respectively, versus year-end 2018


•	Drove well costs down to $6.6 million for a 10,000-foot lateral with our standard completion design, a decrease from $7.7 million at year-end 2018


•	Reduced controllable cash costs of combined unit lease operating expenses ("LOE") and unit cash general and administrative ("G&A") to $4.65 per BOE, a 23% decrease from full-year 2018 results of $6.07 per BOE


•	Received net cash of $48.7 million on settlements of derivatives, as our hedges mitigated the impact of commodity price declines

Our core assets

The Permian Basin is comprised of several distinct geological provinces, including the Midland Basin to the east, the Delaware Basin to the west and the Central Platform in the middle. Our primary development and production fairway is located on the east side of the Midland Basin. Our acreage is largely contiguous in the neighboring Texas counties of Howard, Glasscock, Reagan, Sterling and Irion. We refer to this acreage block in this Annual Report as our "Permian-Midland Basin" area. As of

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December 31, 2019, we had assembled 133,512 net acres in the Permian Basin, all of which were held in 294 sections in the Permian-Midland Basin area, with an average working interest of 97% in Laredo-operated active productive wells and 89% in all wells in which Laredo has an interest. This Permian-Midland Basin area includes two acreage blocks in Howard and Glasscock counties, respectively, that we acquired in separate transactions in the fourth quarter of 2019. We anticipate shifting much of our drilling focus to these newly acquired areas during the course of 2020 as we believe that wells in this area will produce with a higher oil content percentage than many of our previously drilled wells. We will continue to look for additional acquisition opportunities in the future.

We believe our acreage in the Permian-Midland Basin area is a resource play for multiple producing formations that make up a significant portion of the entire stratigraphic section. We are currently focusing our development activities on horizontal drilling targets in the Middle Wolfcamp, Upper Wolfcamp and Lower Spraberry formations. Other potential formations for future development are in the Upper Spraberry, Middle Spraberry, Lower Wolfcamp, Cline and Canyon. From our inception in 2006 through December 31, 2019, we have drilled and completed (i.e., the particular well is flowing) 373 horizontal wells in the Upper and Middle Wolfcamp and 967 vertical wells in the Wolfberry interval. Of these 373 horizontal wells, 206 were horizontal Upper Wolfcamp wells and 167 were horizontal Middle Wolfcamp wells. We have also drilled and completed 33 horizontal Lower Wolfcamp wells and 64 horizontal Cline wells.

Beginning in mid-2012, we started focusing our horizontal activity on drilling longer laterals. Since that time, our average lateral length has grown to 10,000 feet and longer in areas where our contiguous acreage position allows. Starting in the second quarter of 2019, we increased the spacing between our wells in an effort to increase capital efficiency. In 2020, we plan to continue to drill wells with wide spacing as we believe that this leads to increased productivity and decreased well-to-well interference; however, we believe that different areas of our acreage support different spacing plans and will drill accordingly. We continue to use our existing data (and newly acquired data from both our ongoing operations and numerous public data sources) to optimize completion designs and well spacing optimization within the development plan. We will also continue to pursue cost saving measures, but given the volatile commodity price environment, we are unsure what, if any, changes there will be to service costs.

Despite volatility in the price of oil, NGL and natural gas and their related margins, our goal continues to be to achieve cash flow neutrality or positive free cash flow (excluding acquisitions). We will adjust our 2020 capital spending to attempt to meet this goal and such spending will be influenced by commodity price changes, as well as any changes in individual well performance, service costs and drilling and completions efficiencies and lease operating costs. Our near-term strategy is to concentrate our drilling activities on multi-well packages on our newly acquired acreage in Howard and Glasscock counties and around our previously established production corridors.

On December 31, 2019, we had a total of three drilling rigs drilling horizontal wells. Our current drilling schedule anticipates that we will utilize four horizontal drilling rigs during the first half of 2020 and decrease our drilling count thereafter. We do not anticipate utilizing any vertical drilling rigs in 2020. If we decrease our drilling rig count and/or completion crews, it will have a negative impact on our production, especially oil production and reserves. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Obligations and commitments" and Note 15.b to our consolidated financial statements included elsewhere in this Annual Report for additional information.

While we continue to look at potential acquisitions on a going forward basis, both within our Permian-Midland Basin area and in other locations, we expect our Permian-Midland Basin acreage to continue to be the primary driver for the growth of our reserves, production and cash flow for the foreseeable future.

Since our inception, we have established and realized our reserves, production and cash flow primarily through our drilling program, coupled with select targeted acquisitions. Our net proved reserves were estimated at 293,377 MBOE on a three-stream basis as of December 31, 2019, of which 83% are classified as proved developed reserves and 27% are attributable to oil reserves. We report our production volumes on a three-stream basis, which separately reports NGL from crude oil and natural gas.

In this Annual Report, the information with respect to our estimated proved reserves has been prepared by Ryder Scott Company, L.P. ("Ryder Scott"), our independent reserve engineers, in accordance with the rules and regulations of the Securities and Exchange Commission ("SEC") applicable to the reporting dates presented.

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The following table summarizes our total estimated net proved reserves presented on a three-stream basis, net acreage and producing wells as of the date presented, and net average daily production presented on a three-stream basis for the period presented. Based on estimates in the report prepared by Ryder Scott, we operated wells that represent 99.8% of the economic value of our proved developed oil, NGL and natural gas reserves as of December 31, 2019.



	December 31, 2019						Year ended December 31, 2019
	Estimated proved reserves⁽¹⁾				Producing wells		Average daily production
	MBOE	% Oil		Net acreage	Gross	Net	(BOE/D)	% Oil		% NGL		% Natural gas
Permian-Midland Basin	293,377	27	%	133,512	1,337	1,251	80,883	35	%	31	%	34	%

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(1)	See "—Our operations—Estimated proved reserves" for discussion of the prices utilized to estimate our reserves.

In the second half of 2017 and through the majority of 2018, crude oil, NGL and natural gas prices gradually and continually increased to levels greater than what was experienced in 2015, 2016 and the first half of 2017 with crude oil, NGL and natural gas prices reaching their highest level in the last four months of 2018 since 2014. However, in the last quarter of 2018 for crude oil and NGL, and in the first quarter of 2019 for natural gas, commodity prices significantly decreased. Throughout the majority of 2019, crude oil, NGL and natural gas prices continued to remain volatile.

In order to maximize operational flexibility through the commodity price declines experienced during 2014 through 2016, we reduced the portion of reserves categorized as "proved undeveloped" or "PUD." Beginning in 2016, we adjusted our five-year SEC PUD booking methodology to approximately one year of activity. This allowed us to emphasize operations on our most economic investments and maintain conservative assurance that all PUD locations would be converted despite commodity price volatility. In light of commodity price volatility, we have hedged the majority of our oil for 2020, we have increased our PUD reserves to approximately two years of drilling inventory. In 2019, we acquired two new development areas, and in order to align with our commitment to develop this acreage, the majority of our added proved undeveloped reserves are in these areas.

As our activities to date have indicated, the majority of our acreage represents a resource play. In the near term, our goal is to drill those locations that we anticipate have the greatest potential to enhance shareholder value. We have determined that the most efficient way to accomplish this is to maintain the flexibility to choose those locations based upon our insight gained as we drill and collect data across our acreage. We converted all 20 PUD locations we booked as of December 31, 2018 into proved producing locations in 2019. For 2020, we have increased our PUD count to 109 locations, which represent those that we have a high degree of confidence will be developed and have made a specific capital commitment to drill within a two year time frame. This strategy maintains our flexibility to add new PUD locations and convert other locations to proved developed reserves as we deem appropriate and opportunistic. See "—Proved undeveloped reserves" for additional information on our PUD reserves.

Capitalizing on our large contiguous acreage blocks in our Glasscock and Reagan County areas, we have built crude oil, natural gas and water pipeline systems and facilities. These pipeline systems and facilities are designed to provide a combination of services to certain portions of our acreage which may include high-pressure centralized natural gas lift systems and facilities, crude oil, natural gas and produced water gathering, fresh and recycled frac water distribution and produced water recycling. We have built and maintain 61 miles of crude oil gathering pipelines and 109 miles of produced water gathering pipelines connected to our operated wells in our Glasscock and Reagan County acreage, providing a safer, more economic and lower emission transportation alternative than trucking. We have also installed and maintain 141 miles of natural gas gathering pipelines, providing us with takeaway optionality that enables us to maintain lower operating pressures, decreased non-productive time and more consistent well performance. Our crude oil and natural gas gathering assets provided transportation for 72% and 43% of our production in 2019, respectively. Combined, our three water recycling facilities provide recycling capacity of more than 54,000 Bbls of water per day, and a storage capacity of more than 3.6 million Bbls. Having these pipeline systems and associated facilities in place is expected to enhance the value of our 2020 drilling program for the portion of our acreage in this area.

The leaseholds we recently acquired in central Howard County, Texas and western Glasscock County, Texas are situated on or near previously existing third-party oil, gas and water gathering infrastructure. As such, we plan to leverage this third-party infrastructure through market-based midstream and marketing contractual arrangements, allowing for our 2020 drilling

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program and recently commenced operations in said regions to experience economic, environmental and operating benefits. We anticipate conducting produced water recycling on our central Howard County and western Glasscock County acreage through the relocation and construction of our existing recycling facilities.

Our midstream and marketing infrastructure activities continue to focus on achieving increased efficiencies, cost reductions, safe operating practices and reducing emissions for (i) the transportation and marketing of our oil and natural gas, (ii) the centralization and operation of natural gas lift facilities and (iii) the handling of fresh, recycled and produced water (through the use of our integrated water pipelines and water recycling facilities).

We market the majority of production from properties we operate for both our account and the account of the other working interest owners in our operated properties. We sell substantially all of our production under contracts ranging from one month to multiple years in length of term, all at monthly calculated market prices. We typically sell production to a relatively limited number of customers, as is customary in the exploration, development and production business; however, we believe that our customer diversification affords us optionality in our sales destination. We have committed a portion of our Permian crude oil production under firm transportation agreements, including with Medallion Gathering & Processing, LLC, a Texas limited liability company formed on October 12, 2012, which, together with its wholly-owned subsidiaries (collectively, "Medallion"), was established for the purpose of developing midstream solutions and providing midstream infrastructure to bring oil to market in the Midland Basin.

On October 30, 2017, our subsidiary LMS, together with Medallion Midstream Holdings, LLC , which is owned and controlled by an affiliate of the third-party interest-holder, The Energy & Minerals Group, completed the sale of 100% of the ownership interests in Medallion to an affiliate of Global Infrastructure Partners ("GIP"), for cash consideration of $1.825 billion (the "Medallion Sale"). LMS' total net cash proceeds before taxes for its 49% ownership interest in Medallion in 2017 were $831.3 million.

As of December 31, 2019, we were committed to deliver, for sale or transportation, fixed volumes of product under certain contractual arrangements that specify the delivery of a fixed and determinable quantity:



	Total	2020	2021	2022	2023 and after
Crude oil (MBbl):
Sales commitments	31,110	12,875	9,125	8,210	900
Transportation commitments:
Field	54,810	10,980	10,950	10,950	21,930
To U.S. Gulf Coast	95,985	12,810	15,525	13,365	54,285
Natural gas (MMcf):
Sales commitments	64,215	14,215	5,712	5,712	38,576
Total commitments (MBOE)⁽¹⁾	192,608	39,034	36,552	33,477	83,545

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(1)	BOE is calculated using a conversion rate of six Mcf per one Bbl.

We have firm field transportation agreements that enable us or the purchasers of our oil production to move oil from our production area to major market hubs, including Colorado City, Texas; Midland, Texas; and Crane, Texas. One of these agreements is with Medallion and it remains in place and unchanged following the Medallion Sale. Effective as of June 1, 2017, we signed a Dedication and Connection Agreement with Medallion whereby we dedicated to Medallion for transportation the oil from a significant portion of our acreage, subject to certain exceptions. We also have a firm transportation agreement to move oil from Colorado City, Texas to the U.S. Gulf Coast. In 2018, we signed an agreement with Gray Oak Pipeline, LLC to initially transport 25,000 barrels of oil per day increasing to 35,000 barrels of oil per day of our production from Crane, Texas to the U.S. Gulf Coast. Our shipments under this contract began in the fourth quarter of 2019. We believe these commitments will enhance our ability to move our crude oil out of the Permian Basin and give us access to U.S. Gulf Coast pricing. See Note 4.d to our consolidated financial statements included elsewhere in this Annual Report for a further discussion of our firm transportation agreement with Medallion.

We have committed to deliver, for sale or transportation, fixed volumes of product under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. If not fulfilled, we are subject to firm transportation payments

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on excess pipeline capacity and other contractual penalties. These commitments are normal and customary for our business. In certain instances, we have used spot market purchases to meet our commitments in certain locations or due to favorable pricing. We anticipate continuing this practice in the future. We incurred firm transportation payments on excess pipeline capacity and other contractual penalties of $0.9 million, $4.7 million and $1.1 million during the years ended December 31, 2019, 2018 and 2017, respectively.

In the current market environment, we believe that we could sell our production to numerous companies, so that the loss of any one of our major purchasers would not have a material adverse effect on our financial condition and results of operations solely by reason of such loss. For discussion on purchasers that individually accounted for 10% or more of each (i) oil, NGL and natural gas sales and (ii) sales of purchased oil in at least one of the years ended December 31, 2019, 2018 and 2017, see Note 14 to our consolidated financial statements included elsewhere in this Annual Report. See "Item 1A. Risk Factors—Risks related to our business—The inability of our significant customers to meet their obligations to us may materially adversely affect our financial results."

We have assembled a multidisciplinary technical database that characterizes subsurface reservoir properties with the goal of maximizing value. Our reservoir characterization process encompasses four fundamental areas: (i) high-resolution geocellular modeling, (ii) well spacing and completions optimization, (iii) reservoir engineering studies and (iv) predictive analytics. This process along with applicable data and our talented workforce across various disciplines are key to operational results, identification of additional resources and evaluation of strategic acquisitions.

Geocellular models integrate the above-described data with enhanced interpretations conducted in 2019 to provide 3D reservoir and mechanical property models across the majority of our acreage. These models are relied on in well planning, allowing us to optimize landing targets and geosteering in the highest quality reservoir. This minimizes target changes during operations which enhances operational efficiencies.

Hydraulic fracture modeling, integrated with microseismic data is used to estimate fracture geometries in an effort to optimize well spacing and completion design for multiple reservoir targets. This work assists in predicting key drivers that affect fracture geometry such as landing point, proppant and fluid loading, pump rate, perforation design and cluster efficiency. This analysis yields important insights into subsurface behavior and improves development planning.

Predictive analytical modeling includes non-linear multivariate regression and machine learning algorithms facilitating the detection and assessment of the impact of individual parameters on fundamental value drivers. Proprietary software and workflows quantify the effects of individual parameters within completion designs, well spacing and rock properties on production. This knowledge can be leveraged to generate optimized, capital-efficient development plans.

We consider the above technical workflows as tools in optimizing multi-well developments. We anticipate that all of our horizontal wells to be drilled in 2020 will utilize at least some aspects of the above workflows which we believe will positively impact results. The workflows are also used in our basin-wide geocellular models, creating a competitive edge for our future acquisition analysis.

Corporate history and structure

Laredo Petroleum, Inc. is a Delaware corporation formed in 2011 for the purpose of merging with Laredo Petroleum, LLC (a Delaware limited liability company formed in 2007) to consummate an IPO in December 2011. Laredo Petroleum, Inc. was the survivor of such merger and currently has two wholly-owned subsidiaries, LMS and GCM. As of December 31, 2019, affiliates of Warburg Pincus LLC ("Warburg Pincus"), our founding member, owned 21.6% of our common stock.

Our business strategy

Maximize our capital efficiency by seeking to drill high rate of return wells with continued low overhead and operational productivity


•	In 2019, we undertook an effort to increase our capital efficiency by (i) acquiring acreage that we believe will result in higher rate of return wells, (ii) reducing our overhead costs and (iii) increasing operational productivity through, among other things, spacing and completions design. We plan to continue to focus on maximizing capital efficiency in 2020.

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Continue to grow our Permian-Midland Basin position

•

As we continue to grow while focusing on areas with higher oil content and develop our existing Permian-Midland Basin acreage position, we believe that additional acreage may be beneficial as consolidation and increased scale may lead to increased operational and corporate efficiencies along with increased inventory of wells that we expect to produce a higher percentage of oil than our established acreage.

Deploy our capital in a strategic manner while considering value-enhancing acquisitions, divestitures, mergers, redemptions, repurchases, delevering and similar transactions

•

We will be highly selective in the projects that we consider, and we will continue to monitor the market for strategic opportunities that we believe could be accretive and enhance shareholder value. These opportunities may take the form of acquisitions, divestitures, mergers, redemptions, repurchases, delevering or other similar transactions, any of which could result in the utilization of our Senior Secured Credit Facility and/or further accessing the capital markets.

Proactively manage risk to limit downside

•

We actively attempt to limit our business and operating risks by focusing on safe and environmentally sound work practices, meeting all regulatory requirements, reliable operations execution and contingency planning, rigorous supply chain management and cost control processes, flexibility in our financial profile, operational efficiencies, hedging, controlling costs and developing oil and natural gas takeaway capacity with multiple delivery points.

Continue to hedge our production to protect cash flows, diminish the effects of commodity price fluctuations and maintain upside exposure


•	During 2019, our hedging program provided us with cash flow certainty. In the future, we will continue to seek hedging opportunities on a multi-year basis to further protect our cash flows from commodity price fluctuations while maintaining upside exposure if commodity prices increase.

Use our existing infrastructure and evaluate opportunities for strategic expansion


•	We believe that our infrastructure provides us with optionality and efficiencies in developing and transporting production from our established Permian-Midland Basin acreage position. Because of the value we ascribe to this infrastructure, we will continue to utilize it to supplement our core strategy of providing marketing optionality for our oil, NGL and natural gas production.

Our competitive strengths

We have a number of competitive strengths that we believe will assist in the successful execution of our business strategy:

Contiguous acreage position with high working interests and extensive interests in leases held by production containing multiple formations, resulting in a substantial drilling inventory

•

As of December 31, 2019, we have 133,512 net acres in the Permian-Midland Basin area that are largely contiguous with a high average working interest percentage (average working interest of 97% in Laredo-operated active productive wells and 89% in all wells in which Laredo has an interest), are 85% held by production and have identified up to seven targets to date from which we can produce, resulting in a long-term drilling inventory. Our contiguous acreage position also enables us to drill long laterals (10,000 feet or greater) in many locations, which may provide an even greater rate of return as we continue to refine our spacing, drilling and completions techniques.

Significant cash flow from existing operations with no near-term debt maturities

•

Our Permian-Midland Basin acreage has 1,251 net producing wells as of December 31, 2019. That current base provides us with a significant amount of cash flow and such wells require less additional capital to maintain. With such cash flow we can fund drilling on acreage that we believe will result in higher oil producing wells. In addition, we have few on-going drilling requirements to keep our Permian-Midland Basin acreage from lease expirations, which further strengthens our flexibility to use cash flow from operations in a manner we see as most efficient.

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•

We recently issued two series of senior unsecured notes and used the proceeds therefrom to, among other things, repay our then outstanding senior unsecured notes, which we expect to be completed on March 15, 2020, all as described below. As a result, the maturity dates on our new senior unsecured notes were extended to 2025 and 2028. We believe that this extension in the date of maturity provides us with financial flexibility to execute on our strategy.

Significant operational control

•

We operated wells that represent 99.8% of the economic value of our proved developed oil, NGL and natural gas reserves as of December 31, 2019, based on our reserve report prepared by Ryder Scott. We believe that maintaining operating control permits us to better pursue our strategy of enhancing returns through operational and cost efficiencies and maximizing cost-efficient ultimate hydrocarbon recoveries through reservoir analysis and evaluation and continuous improvement of drilling, completions and stimulation techniques. We expect to maintain operating control over nearly all of our potential drilling locations.

Low cost drilling & completions and operating expenses

•

We have successfully operated in the Permian-Midland Basin for over a decade. We have very experienced and capable employees in all areas of our operations, including environmental & safety, drilling, completions, facilities, production, mid-stream and supply chain management. In 2019, we delivered low well costs and operating costs as well as delivered production above guidance for all four quarters as a result of significant operational efficiencies.

Our production corridors, owned oil, gas and water pipeline infrastructure and facilities and contracted third-party oil, gas and water infrastructure enable us to more efficiently, safely and economically develop our acreage

•

We believe that our previously built production corridors increase field level operating efficiencies in oil and natural gas gathering and takeaway capacity, water supply and operations. We have demonstrated that our production corridors provide us with identified areas within which we can achieve material cost savings and efficiencies through the use of our previously built infrastructure, including water recycling. In addition, drilling wells within these corridors increases our production consistency through increased knowledge, thus enabling us to better plan our development program.

•

The reuse and disposal of produced water is one of the most challenging aspects of horizontal drilling in the Permian Basin. Our water recycle facilities, together with our integrated owned water pipeline infrastructure and contracted third-party water pipeline infrastructure provide us with a reliable and consistent means to ensure that we have the water we need to complete our wells while also providing low-cost takeaway capacity for our flowback and produced water.

Extensive infrastructure in place

•

We own and operate more than 340 miles of pipeline in our crude oil gathering, natural gas gathering, fuel gas and natural gas lift distribution systems and produced water gathering and fresh and recycled water distribution systems in the Permian Basin as of December 31, 2019. These systems and pipelines, in conjunction with contracted third-party pipelines, provide safe operational practices, greater operational efficiency including minimizing natural gas disruptions and fluid spills, capital and cost savings and potentially better market pricing for our production and enable us to coordinate our activities to connect our wells to market upon completion with minimal delays.

Strong corporate governance and institutional investor support

•

Our board of directors is well qualified and represents a meaningful resource to our management team. Our board of directors, which is comprised of representatives of Warburg Pincus, other independent directors, our founder and former Chief Executive Officer and our Chief Executive Officer, has extensive oil and natural gas industry and general business expertise. We actively engage our board of directors, on a regular basis, for their expertise on strategic, financial, governance and risk management activities. In addition, Warburg Pincus has many years of relevant experience in financing and supporting exploration and production companies and management teams.

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Our extensive Permian technical database

•

Our multidisciplinary proprietary technical data set, in combination with industry-leading technologies and in-house workflows, enables a comprehensive characterization and visualization of the total subsurface resource potential. This, in turn, facilitates a development planning workflow that seeks to maximize resource recovery and achieve an attractive return on capital employed with respect to each discrete development package of wells.

Other properties

We do not have any other properties in addition to our Permian-Midland Basin acreage.

Our operations

Estimated proved reserves

Our reserves are reported in three streams: crude oil, NGL and natural gas. In this Annual Report, the information with respect to our estimated proved reserves has been prepared by Ryder Scott, our independent reserve engineers, in accordance with the rules and regulations of the SEC applicable to the reporting dates presented.

SEC guidelines require companies to use the unweighted arithmetic average first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period before differentials ("Benchmark Prices"). The Benchmark Prices are then adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead ("Realized Prices") without giving effect to our commodity derivative transactions. The Realized Prices are utilized to calculate estimated reserves and the associated discounted future cash flows. The following table presents the Benchmark Prices and Realized Prices as of the dates presented:



	December 31, 2019		December 31, 2018
Benchmark Prices:
Oil ($/Bbl)	$	52.19	$	62.04
NGL ($/Bbl)⁽¹⁾	$	21.14	$	31.46
Natural gas ($/MMBtu)	$	0.87	$	1.76
Realized Prices:
Oil ($/Bbl)	$	52.12	$	59.29
NGL ($/Bbl)	$	12.21	$	21.42
Natural gas ($/Mcf)	$	0.53	$	1.38

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(1)	Based on our average composite NGL barrel.

Our net proved reserves were estimated at 293,377 MBOE on a three-stream basis as of December 31, 2019, of which 83% are classified as proved developed reserves and 27% are attributable to oil reserves.

Our estimated proved reserves as of December 31, 2019 assume our ability to fund the capital costs necessary for their development and are affected by pricing assumptions. See "Item 1A. Risk Factors—Risks related to our business—Estimating reserves and future net revenues involves uncertainties. Negative revisions to reserve estimates, decreases in oil, NGL and natural gas prices or increases in service costs, may lead to decreased earnings and increased losses or impairment of oil and natural gas properties."

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The following table sets forth additional information regarding our estimated proved reserves as of the dates presented.



	December 31, 2019		December 31, 2018
Proved developed producing:
Oil (MBbl)	52,711		55,893
NGL (MBbl)	90,861		79,241
Natural gas (MMcf)	600,334		491,828
Total proved developed producing (MBOE)	243,628		217,105
Proved undeveloped:
Oil (MBbl)	25,928		6,001
NGL (MBbl)	11,337		7,406
Natural gas (MMcf)	74,903		45,928
Total proved undeveloped (MBOE)	49,749		21,062
Estimated proved reserves:
Oil (MBbl)	78,639		61,894
NGL (MBbl)	102,198		86,647
Natural gas (MMcf)	675,237		537,756
Total estimated proved reserves (MBOE)	293,377		238,167
Percent developed	83	%	91	%

Technology used to establish proved reserves

Under SEC rules, proved reserves are those quantities of oil, NGL and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible within five years from a given date forward from known reservoirs, and under existing economic conditions, operating methods and government regulations. The term "reasonable certainty" implies a high degree of confidence that the quantities of oil, NGL and/or natural gas actually recovered will equal or exceed the estimate. 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, our internal reserve engineers and Ryder Scott, our independent reserve engineers, employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, open-hole logs, core analyses, geologic maps, available downhole and production data and seismic data. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves, including individual b-factors, material balance calculations or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated primarily by performance from analogous wells in the surrounding area and the use of geologic data to assess the reservoir continuity. These wells were considered to be analogous based on production performance from the same formation, well spacing and completion using similar techniques.

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Qualifications of technical persons and internal controls over reserves estimation process

In accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers ("SPE Reserves Auditing Standards") and guidelines established by the SEC, Ryder Scott, our independent reserve engineers, estimated 100% of our proved reserve information as of December 31, 2019 and 2018 included in this Annual Report. The technical persons responsible for preparing the reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the SPE Reserves Auditing Standards.

We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to Ryder Scott in their reserves estimation process. Our technical team meets regularly with representatives of Ryder Scott to review properties and discuss methods and assumptions used in Ryder Scott's preparation of the year-end reserve estimates. The Ryder Scott reserve report is reviewed with representatives of Ryder Scott and our internal technical staff before dissemination of the information.

Our Vice President of Planning and Business Development is the technical person primarily responsible for overseeing the preparation of our reserve estimates. He has more than 30 years of practical experience, with 29 years of this experience being in the estimation and evaluation of reserves. He has a Bachelors and Masters of Science in Petroleum Engineering from Texas A&M University. Our Vice President of Planning and Business Development reports to our President and Chief Executive Officer. Reserve estimates are reviewed and approved by our senior engineering staff, other members of senior management and our technical staff, our audit committee and our Chief Executive Officer.

Proved undeveloped reserves

Our proved undeveloped reserves increased from 21,062 MBOE as of December 31, 2018 to 49,749 MBOE as of December 31, 2019. We estimate that we incurred $141.3 million of costs to convert 21,062 MBOE of proved undeveloped reserves from 20 locations into proved developed reserves in 2019. New proved undeveloped reserves of 49,749 MBOE were added during the year from 2 Cline, 19 Spraberry and 88 new horizontal Wolfcamp locations. 29,082 MBOE were added in our new acreage position in Howard County, Texas, 5,217 MBOE were added in our new acreage position in western Glasscock County, Texas and 15,450 MBOE were added in our established acreage. A final investment decision has been made on these 109 locations, and they are scheduled to be drilled and completed in 2020 to 2022.

Estimated total future development and abandonment costs related to the development of proved undeveloped reserves as shown in our December 31, 2019 reserve report are $540.8 million. Based on this report and our PUD booking methodology, the capital estimated to be spent in 2020 to develop the proved undeveloped reserves is $271.4 million, $207.9 million for 2021, $54.8 million for 2022 and $0 for each of 2023 and 2024. Based on our anticipated cash flows and capital expenditures, as well as the availability of capital markets transactions, all of the proved undeveloped locations are expected to be drilled and completed in 2020 to 2022. Reserve calculations at any end-of-year period are representative of our development plans at that time. Changes in circumstance, including commodity pricing, oilfield service costs, drilling and production results, technology, acreage position and availability and other economic and regulatory factors may lead to changes in development plans.

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Sales volumes, revenues, prices and costs and expenses history

The following table presents information regarding our oil, NGL and natural gas sales volumes, sales revenues, average sales prices, and average selected costs and expenses per BOE sold for the periods presented. Our reserves and sales volumes are reported in three streams: crude oil, NGL and natural gas. For additional information on price calculations, see the information in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."



	Years ended December 31,						2019 compared to 2018
(unaudited)	2019		2018		2017		Change (#)			Change (%)
Sales volumes:
Oil (MBbl)	10,376		10,175		9,475		201			2	%
NGL (MBbl)	9,118		7,259		5,800		1,859			26	%
Natural gas (MMcf)	60,169		44,680		35,972		15,489			35	%
Oil equivalents (MBOE)⁽¹⁾⁽²⁾	29,522		24,881		21,270		4,641			19	%
Average daily oil equivalent sales volumes (BOE/D)⁽²⁾	80,883		68,168		58,273		12,715			19	%
Average daily oil sales volumes (Bbl/D)⁽²⁾	28,429		27,878		25,958		551			2	%
Sales revenues (in thousands):
Oil	$	572,918	$	605,197	$	445,012	$	(32,279	)	(5	)%
NGL	$	100,330	$	149,843	$	101,438	$	(49,513	)	(33	)%
Natural gas	$	33,300	$	53,490	$	75,057	$	(20,190	)	(38	)%
Average sales prices⁽²⁾:
Oil ($/Bbl)⁽³⁾	$	55.21	$	59.48	$	46.97	$	(4.27	)	(7	)%
NGL ($/Bbl)⁽³⁾	$	11.00	$	20.64	$	17.49	$	(9.64	)	(47	)%
Natural gas ($/Mcf)⁽³⁾	$	0.55	$	1.20	$	2.09	$	(0.65	)	(54	)%
Average sales price ($/BOE)⁽³⁾	$	23.93	$	32.50	$	29.22	$	(8.57	)	(26	)%
Oil, with commodity derivatives ($/Bbl)⁽⁴⁾	$	54.37	$	55.49	$	50.45	$	(1.12	)	(2	)%
NGL, with commodity derivatives ($/Bbl)⁽⁴⁾	$	13.61	$	20.03	$	16.91	$	(6.42	)	(32	)%
Natural gas, with commodity derivatives ($/Mcf)⁽⁴⁾	$	1.05	$	1.77	$	2.15	$	(0.72	)	(41	)%
Average sales price, with commodity derivatives ($/BOE)⁽⁴⁾	$	25.45	$	31.72	$	30.71	$	(6.27	)	(20	)%
Average selected costs and expenses per BOE sold⁽²⁾:
Lease operating expenses	$	3.08	$	3.67	$	3.53	$	(0.59	)	(16	)%
Production and ad valorem taxes	$	1.38	$	1.99	$	1.78	$	(0.61	)	(31	)%
Transportation and marketing expenses	$	0.86	$	0.47	$	—	$	0.39		83	%
Midstream service expenses	$	0.15	$	0.12	$	0.19	$	0.03		25	%
General and administrative:
Cash	$	1.57	$	2.40	$	2.85	$	(0.83	)	(35	)%
Non-cash stock-based compensation, net⁽⁵⁾	$	0.28	$	1.46	$	1.68	$	(1.18	)	(81	)%
Depletion, depreciation and amortization	$	9.00	$	8.55	$	7.45	$	0.45		5	%

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(1)	BOE is calculated using a conversion rate of six Mcf per one Bbl.


(2)	The numbers presented in the years ended December 31, 2019, 2018 and 2017 columns are based on actual amounts and are not calculated using the rounded numbers presented in the table above.


(3)	Price reflects the average of actual sales prices received when control passes to the purchaser/customer adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the delivery point.

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(4)

Price reflects the after-effects of our commodity derivative transactions on our average sales prices. Our calculation of such after-effects includes settlements of matured commodity derivatives during the respective periods in accordance with GAAP and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to commodity derivatives that settled during the respective periods.


(5)	For the year ended December 31, 2019, non-cash stock-based compensation, net, excluding forfeitures related to our organizational restructuring on a per BOE sold basis was $0.66.

Productive wells

The following table sets forth certain information regarding productive wells in our core operating area as of December 31, 2019. All but three of our wells are classified as oil wells, all of which also produce liquids-rich natural gas and condensate. Wells are classified as oil or natural gas wells according to the predominant production stream. We also own royalty and overriding royalty interests in a small number of wells in which we do not own a working interest.



	Total producing wells				Average WI %
	Gross			Net
	Vertical	Horizontal	Total	Total
Permian-Midland Basin:
Operated	794	475	1,269	1,236	97	%
Non-operated	59	9	68	15	22	%
Total	853	484	1,337	1,251	94	%

Acreage

The following table sets forth certain information regarding the developed and undeveloped acreage in which we own an interest as of December 31, 2019 for our core operating area, including acreage HBP. A majority of our developed acreage is subject to liens securing our Senior Secured Credit Facility.



	Developed acres		Undeveloped acres		Total acres		% HBP
	Gross	Net	Gross	Net	Gross	Net	% HBP
Permian-Midland Basin	129,708	114,107	21,751	19,406	151,459	133,512	85	%

Undeveloped acreage expirations

The following table sets forth the gross and net undeveloped acreage in our core operating area and other properties as of December 31, 2019 that will expire over the next four years unless production is established within the spacing units covering the acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates.



	Years ended December 31,
	2020		2021		2022		2023
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Permian-Midland Basin	5,630	4,980	5,091	3,357	2,328	2,129	—	—

Of the total undeveloped acreage identified as potentially expiring over the next four years as of December 31, 2019, 3,799 net acres have associated PUD reserves on our reserve report as of December 31, 2019, which we anticipate drilling to hold or renewing the associated leases. These PUD reserves represent 28% of our total PUD reserves as of December 31, 2019.

Of the total undeveloped acreage identified as potentially expiring over the next four years as of December 31, 2018, 690 net acres had associated PUD reserves on our reserve report as of December 31, 2018, which all were retained by drilling in 2019.

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Drilling activity

The following table summarizes our drilling activity with respect to the number of wells completed for the periods presented. Gross wells reflect the sum of all wells in which we own an interest. Net wells reflect the sum of our working interests in gross wells.



	Years ended December 31,
	2019		2018		2017
	Gross	Net	Gross	Net	Gross	Net
Development wells:
Productive	59	56.2	74	71.2	62	60.7
Dry	—	—	—	—	—	—
Total development wells	59	56.2	74	71.2	62	60.7
Exploratory wells:
Productive	—	—	—	—	—	—
Dry	—	—	—	—	—	—
Total exploratory wells	—	—	—	—	—	—

Title to properties

We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards. As is customary in the industry, in the case of undeveloped properties, often cursory investigation of record title is made at the time of lease acquisition. Investigations are made before the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. Individual properties may be subject to burdens that we believe do not materially interfere with the use or affect the value of the properties. Burdens on properties may include customary royalty interests, liens incident to operating agreements and for current taxes, obligations or duties under applicable laws, development obligations under oil and gas leases or net profit interests.

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, NGL 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 12.5% to 25%, resulting in a net revenue interest to us generally ranging from 75% to 87.5%. As of December 31, 2019, 85% of our Permian-Midland Basin acreage was HBP.

Seasonality

Demand for oil and natural gas generally decreases during the spring and fall months and increases during the summer and winter months. However, seasonal anomalies such as mild winters or mild summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. These seasonal anomalies can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations.

Competition

The oil and natural gas industry is intensely competitive, and we compete with a wide range of companies in our industry, including those that have greater resources than we do and those that are smaller with fewer ongoing obligations. Many of the larger companies not only explore for and produce oil and natural gas, but also conduct refining operations and market petroleum and other products on a regional, national or worldwide basis. Many of the smaller companies have a lower cost structure and more liquidity. These companies may be able to pay more for productive properties and exploratory locations or

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evaluate, bid for and purchase a greater number of properties and locations than our financial or human resources permit and may be able to expend greater resources to attract and maintain industry personnel. In addition, these companies may have a greater ability to continue exploration and production activities during periods of low market prices. 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. 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 of the inherent advantages of some of our competitors, those companies may have an advantage in bidding for exploratory and producing properties.

Hydraulic fracturing

We use hydraulic fracturing as a means to maximize the productivity of almost every well that we drill and complete. Hydraulic fracturing is a necessary part of the completion process for our producing properties in Texas because our properties are dependent upon our ability to effectively fracture the producing formations in order to produce at economic rates. We are currently conducting hydraulic fracturing activity in the completion of our wells in the Permian Basin. While hydraulic fracturing is not required to maintain any of our leasehold acreage that is currently held by production from existing wells, it will be required in the future to develop the proved non-producing and proved undeveloped reserves associated with this acreage. Nearly all of our proved undeveloped reserves associated with future drilling, recompletion and refracture stimulation projects require hydraulic fracturing.

We have and continue to follow standard industry practices and applicable legal requirements. State and federal regulators impose requirements on our operations designed to ensure protection of human health and the environment. These protective measures include setting surface casing at a depth sufficient to protect fresh water formations and cementing the well to create a permanent isolating barrier between the casing pipe and surrounding geological formations. This well design is intended to eliminate a pathway for the fracturing fluid to contact any aquifers during the hydraulic fracturing operations. For recompletions of existing wells, the production casing is pressure tested prior to perforating the new completion interval.

Injection rates and pressures are monitored instantaneously and in real time at the surface during our hydraulic fracturing operations. Pressure is monitored on both the injection string and the immediate annulus to the injection string. Hydraulic fracturing operations would be shut down immediately if an abrupt change occurred to the injection pressure or annular pressure.

Certain state regulations require disclosure of the components in the solutions used in hydraulic fracturing operations. Approximately 99% of the hydraulic fracturing fluids we use are made up of water and sand. The remainder of the constituents in the fracturing fluid are managed and used in accordance with applicable requirements. In accordance with Texas regulations, we report the constituents of the hydraulic fracturing fluids utilized in our well completions on FracFocus (www.fracfocus.org). Hydraulic fracture stimulation requires the use of a significant volume of water. Upon flowback of the water, we dispose of it by recycling or by discharging into the approved disposal wells. We currently do not discharge water to the surface. Based upon results of testing the performance of recycled flowback/produced water in our fracing operations, we have constructed and currently operate three water recycling facilities on our production corridors providing a recycling capacity of more than 54,000 Bbls of water per day, and a storage capacity of more than 3.6 million Bbls.

For information regarding existing and proposed governmental regulations regarding hydraulic fracturing and related environmental matters, please read "-Regulation of environmental and occupational health and safety matters-Hydraulic fracturing." For related risks to our stockholders, please read "Item 1A. Risk Factors—Risks related to our business—Federal and state legislation and regulatory initiatives relating to hydraulic fracturing and water disposal wells could prohibit projects or result in materially increased costs and additional operating restrictions or delays because of the significance of hydraulic fracturing and water disposal wells in our business."

Regulation of the oil and natural gas industry

Our operations are substantially affected by federal, state and local laws and regulations. In particular, the production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning

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operations. The State of Texas has regulations governing environmental and conservation matters, including provisions for the pooling of oil and natural gas properties, the permitting of allocation wells, the establishment of maximum allowable rates of production from oil and natural gas wells (including the proration of production to the market demand for oil, NGL and natural gas), the regulation of well spacing, the handling and disposing or discharge of waste materials and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil, NGL and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, Texas imposes a production or severance tax with respect to the production and sale of oil, NGL and natural gas within its jurisdiction. Texas further regulates drilling and operating activities by, among other things, requiring permits and bonds for the drilling and operation of wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The failure to comply with these rules and regulations 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.

The regulatory burden on the industry increases the cost of doing business and affects profitability. Additional proposals and proceedings that affect the natural gas industry are regularly considered by the current administration, Congress, the states, the Environmental Protection Agency ("EPA"), the Federal Energy Regulatory Commission ("FERC") and the courts. We cannot predict when or whether any such proposals may become effective, under the current or any future administration.

We believe we are in substantial compliance with currently applicable laws and regulations and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirements may change, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered, and such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impacts of compliance.

Regulation of environmental and occupational health and safety matters

Our operations are subject to numerous stringent federal, state and local statutes and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. Numerous governmental agencies, such as the EPA, issue regulations that often require difficult and costly compliance measures, the noncompliance with which carries substantial administrative, civil and criminal penalties and may result in injunctive obligations to remediate noncompliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines, govern the sourcing and disposal of water used in the drilling, completion and production process, limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier, seismically active areas and other protected areas, require some form of remedial action to prevent or mitigate pollution from current or former operations such as plugging abandoned wells or closing earthen pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from operations or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of production.

Certain of these laws and regulations impose strict liability (i.e., no showing of "fault" is required) that, in some circumstances, may be joint and several. Public interest in the protection of the environment has tended to increase over time. The trend of more expansive and stringent environmental legislation and regulations applied to the oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. Changes in environmental laws and regulations occur frequently, and 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 clean-up requirements, our business and prospects, as well as the oil and natural gas industry in general, could be materially adversely affected.

Hazardous substance and waste handling

Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, solid and hazardous wastes, and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict and, in some cases, joint and

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several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. The Comprehensive Environmental Response, Compensation, and Liability Act, as amended (referred to as "CERCLA" or the "Superfund law") and comparable state laws, impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons deemed "responsible parties." These persons include current owners or operators of the site where a release of hazardous substances occurred, prior owners or operators that owned or operated the site at the time of the release or disposal of hazardous substances, and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to strict and joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible classes of persons. Despite the "petroleum exclusion" of Section 101(14) 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 may have liability for releases of hazardous substances at our properties by prior owners or operators or other third parties. Finally, it is not uncommon for neighboring landowners and other third parties to file common law based claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.

The Oil Pollution Act of 1990 (the "OPA") is the primary federal law imposing oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. Under the OPA, strict, joint and several liability may be imposed on "responsible parties" for all containment and clean-up costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters and natural resource damages, resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A "responsible party" includes the owner or operator of an onshore facility. The OPA establishes a liability limit for onshore facilities, but these liability limits may not apply if: a spill is caused by a party's gross negligence or willful misconduct; the spill resulted from a violation of a federal safety, construction or operating regulation; or a party fails to report a spill or to cooperate fully in a clean-up. We are also subject to analogous state statutes that impose liabilities with respect to oil spills.

We also generate solid wastes, including hazardous wastes, which are subject to the requirements of the Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. Although RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. Certain petroleum production wastes are excluded from RCRA's hazardous waste regulations. These wastes, instead, are regulated under RCRA's less stringent solid waste provisions, state laws or other federal laws. It is also possible that these wastes, which could include wastes currently generated during our operations, will be designated as "hazardous wastes" in the future and, therefore, be subject to more rigorous and costly disposal requirements. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration and production wastes as "hazardous wastes." Also, in December 2016, the EPA agreed in a consent decree to review its regulation of oil and gas waste. It had until March 2019 to determine whether any revisions are necessary. However, in April 2019, the EPA concluded that revisions to the federal regulations for the management of oil and gas waste are not necessary at this time. Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses.