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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K

ý ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2018
or
o 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
(State or other jurisdiction of
incorporation or organization)
 
45-3007926
(I.R.S. Employer
Identification No.)
15 W. Sixth Street, Suite 900
Tulsa, Oklahoma
(Address of principal executive offices)
 
74119
(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
 
Name of Each Exchange On Which Registered
Common Stock, $0.01 par value per share
 
New York Stock Exchange
Securities Registered Pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý    No o 
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 o    No ý
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý    No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted 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 and post such files). Yes ý    No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) 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.  o 
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 ý
 
Non-accelerated filer o
 
Smaller reporting company o
Accelerated filer o
 
 
 
Emerging growth company o
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o    No ý
Aggregate market value of the voting and non-voting common equity held by non-affiliates was approximately $1.5 billion on June 30, 2018, based on $9.62 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, 2019: 233,924,462
Documents Incorporated by Reference:
Portions of the registrant's definitive proxy statement for its 2019 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2018, are incorporated by reference into Part III of this report for the year ended December 31, 2018.





LAREDO PETROLEUM, INC.
TABLE OF CONTENTS
 
Page

2

Table of Contents

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.
"AFE"—Authorization for expenditure.
"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.
"Bcf"—One billion cubic feet of natural gas.
"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.
"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.
"Earth Model"—A proprietary integrated workflow process combining geoscience, production, operations and engineering data utilizing multivariate analytics.
"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.
"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.

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"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.
"HRGM"—High-resolution geocellular models.
"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, water, 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 British thermal units.
"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.
"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.
"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.

4

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"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.

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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, and substantial decline in, oil, natural gas liquids ("NGL") and natural gas prices;
our ability to discover, estimate, develop and replace oil, NGL and natural gas reserves;
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 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 tighter spacing of our wells;
capital requirements for our operations and projects;
impacts to our financial statements as a result of impairment write-downs;
the availability and costs of drilling and production equipment, labor and oil and natural gas processing and other services;
the availability 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;
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 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

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apply hydraulic fracturing to our oil and natural gas wells and to access and dispose of water used in these operations;
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; 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.

7

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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, and midstream and marketing services, 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, 2018, we had assembled 120,617 net acres in the Permian Basin and had total proved reserves, presented on a three-stream basis, of 238,167 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. Our midstream and marketing functions are integral to our exploration and production activities. We have a single company-wide management team that administers all properties as a whole rather than discrete operating segments and we allocate capital resources on a project-by-project basis across our asset base without regard to individual areas.
2018 operation highlights
Produced a Company record average of 68,168 BOE per day in full-year 2018, resulting in production growth of 17% from full-year 2017
Grew the value of our proved reserves by 19% from year-end 2017
Reduced unit cash general and administrative ("G&A") expense by 16% in full-year 2018
Recognized $31.9 million of net cash benefits from LMS field infrastructure investments through reduced capital and operating costs and increased revenue
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, 35 miles east of Midland, Texas. 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-Garden City" area. As of December 31, 2018, we held 120,617 net acres in the Permian Basin, all of which were held in 248 sections in the Permian-Garden City area, with an average working interest of 97% in all Laredo-operated currently producing wells.
We believe our acreage in the Permian-Garden City area is a resource play for multiple producing formations that make up a significant portion of the entire stratigraphic section. We are currently focusing the majority of our development activities on two horizontal drilling targets (Upper and Middle Wolfcamp formations) that have multiple landing points within each target. In addition, we have also established the existence of additional producing formations, including the Lower Wolfcamp, Cline, Spraberry and Canyon. From our inception in 2006 through December 31, 2018, we have drilled and completed (i.e., the particular well is flowing) 314 horizontal wells in the Upper and Middle Wolfcamp and 967 vertical wells in the Wolfberry interval. Of these 314 horizontal wells, 189 were horizontal Upper Wolfcamp wells and 125 were horizontal Middle Wolfcamp wells. We have also drilled and completed 33 horizontal Lower Wolfcamp wells and 64 horizontal Cline wells. We anticipate focusing our 2019 drilling program on the Upper and Middle Wolfcamp formations due to their lower development cost and superior production expectations.

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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. In 2019, we plan to widen the spacing between our wells and focus on achieving cash flow neutrality.
Because oil, NGL and natural gas prices and related margins continue to remain volatile, our board of directors approved a capital expenditures budget of approximately $365 million, based on annual benchmark averages of a $53.60 per barrel WTI NYMEX strip price and a $2.90 per MMBtu Henry Hub NYMEX strip price, for calendar year 2019, excluding non-budgeted acquisitions. We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted. Our goal is to achieve cash flow neutrality, and therefore, our capital spending in 2019 will ultimately be influenced by commodity price changes, as well as any changes in service costs and drilling and completions efficiencies. Of this budget, approximately $300 million is allocated to drilling and completion activities and approximately $65 million is allocated to production facilities, land and other capitalized costs. Substantially all of the planned capital budget is anticipated to be invested in the Permian-Garden City area, primarily in the Upper and Middle Wolfcamp formations.
Our near-term strategy is to continue to concentrate our drilling activities on multi-well packages around our previously established production corridors that have the infrastructure in place to provide us the flexibility to most efficiently and economically drill wells at an attractive rate of return. In the later part of the second quarter of 2019, we plan to widen the spacing between our wells as we seek to increase capital efficiency. In addition, in response to the continued volatile commodity price environment and our stated goal of achieving cash flow neutrality, we anticipate decreasing the number of drilling rigs and/or completions crews that we use. We continue to use our existing data (and acquire new data) to optimize completion designs and well spacing within the development plan in order to enhance inventory and net asset value. 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.
On December 31, 2018, we had a total of three drilling rigs drilling horizontal wells. Our current drilling schedule anticipates that we will utilize three horizontal rigs during the first part of 2019 and decrease our drilling rig count thereafter. We do not anticipate utilizing any vertical rigs throughout 2019. 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, as well as potentially result in contract termination penalties. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Obligations and commitments" and Note 14.c to our consolidated financial statements included elsewhere in this Annual Report for additional information.
In addition to the impact of commodity prices, the timing of drilling our potential locations is also influenced by several factors, including capital requirements and availability, the Texas Railroad Commission ("RRC") well-spacing requirements and the positive results from our ongoing development drilling program.
We expect our Permian-Garden City 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 strategic acquisitions. Our net proved reserves were estimated at 238,167 MBOE on a three-stream basis as of December 31, 2018, of which 91% are classified as proved developed reserves and 26% are attributed to oil reserves. We report our production volumes on a three-stream basis, which separately reports NGL from crude oil and natural gas. As part of our on-going reserves estimation process, for our year-end 2018 reserves estimation, we incorporated additional production data to reflect (i) the higher gas content and steeper oil declines on our historical wells and (ii) the negative effects on oil production from tighter spacing on our recent wells. This additional production history has led to more specific forecasts, including specific b-factors, for both developed and undeveloped locations as we take into account additional production data. There is inherent uncertainty in the reserves estimation process and therefore we will continue to monitor the future production of these wells as well as other available data. In this Annual Report, the information presented 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 periods presented.     
The following table summarizes our total estimated net proved reserves presented on a three-stream basis, net acreage and producing wells as of December 31, 2018, and average daily production presented on a three-stream basis for the year ended December 31, 2018. Based on estimates in the report prepared by Ryder Scott, we operated wells that represent 99.7% of the economic value of our proved developed oil, NGL and natural gas reserves as of December 31, 2018.

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As of December 31, 2018
 
Year ended
December 31, 2018
average daily
production (BOE/D)
 
 
Estimated net
proved reserves(1)
 
 
 
Producing
wells
 
 
 
MBOE
 
% of
total reserves
 
% Oil
 
Net
acreage
 
Gross
 
Net
 
Permian Basin
 
238,167

 
100
%
 
26
%
 
120,617

 
1,246

 
1,155

 
68,168

Other properties
 

 
%
 
%
 
170

 

 

 

Total
 
238,167

 
100
%
 
26
%
 
120,787

 
1,246

 
1,155

 
68,168

_____________________________________________________________________________
(1)
See "—Our operations—Estimated proved reserves" for discussion of the prices utilized to estimate our reserves.
Our net average daily production for the year ended December 31, 2018 was 68,168 BOE/D, 41% of which was oil, 29% of which was NGL and 30% of which was natural gas.
During 2015, commodity prices for crude oil, NGL and natural gas experienced sharp declines, and this downward trend accelerated further into 2016, with crude oil prices reaching their lowest level in February 2016 since 2003. In the second half of 2016 and through 2017, commodity prices increased and stabilized at relatively higher prices but at significantly lower levels than the first half of 2014. In 2018, commodity prices continued to remain volatile with significantly lower prices in the last quarter of the year. Our capital expenditures budget for 2019 is approximately $365 million, based on annual benchmark averages of a $53.60 per barrel WTI NYMEX strip price and a $2.90 per MMBtu Henry Hub NYMEX strip price, excluding non-budgeted acquisitions. Our goal is to achieve cash flow neutrality, and therefore, our capital spending in 2019 will ultimately be influenced by commodity price changes, as well as any changes in service costs and drilling and completions efficiencies.
Beginning in 2016, we deliberately and significantly reduced the portion of our reserves that had historically been categorized as "proved undeveloped" or "PUD." We adjusted our five-year SEC PUD bookings methodology because we believe it enables us to develop our acreage in the most efficient manner possible and determine which potential locations will be most profitable. We believe that we can optimize value for our shareholders by maintaining greater flexibility in choosing the specific drilling locations that will most efficiently develop our properties, particularly as technology changes and we continue to further understand the geology of our acreage.
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 insight gained as we drill and collect data across our acreage, regardless of SEC reserves-booking status. We converted all 26 PUD locations we booked at December 31, 2017 into proved producing locations in 2018. Reducing our future PUD commitments provides us the most flexibility to maximize our rate of return at prevailing conditions and minimize the requirement to drill wells previously assigned, under very different circumstances, as specific PUD locations. Accordingly, for 2019, we have continued to limit our booked PUD locations to those locations that we have a high degree of certainty that we will develop and have made a specific capital commitment to drill within the first six months of 2019. 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, we have built crude oil, natural gas and/or water systems in five production corridors on our Permian-Garden City acreage. These production corridors are designed to provide a combination of services which may include high-pressure centralized natural gas lift systems, crude oil and natural gas gathering and water delivery and takeaway capacity, with certain corridors also capable of accessing recycling facilities. We have built and maintain 60 miles of crude oil gathering pipelines to connect Laredo-operated wells in our Permian-Garden City acreage, providing a safer and more economic transportation alternative than trucking. We have also installed and maintain 159 miles of natural gas gathering pipelines across our Permian-Garden City acreage, providing us with takeaway optionality that enables us to maintain lower operating pressures and more consistent well performance. Our crude oil and natural gas gathering assets provided transportation for 55% of our production in 2018. Combined, our three water recycling facilities provide a 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 production corridors and associated facilities and infrastructure already in place is expected to enhance the value of our 2019 drilling program.
Our midstream and marketing activities continue to focus on achieving increased efficiencies and cost reductions for (i) the transportation and marketing of our oil and natural gas (through the utilization of our oil and natural gas gathering

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systems to provide access to multiple markets and reduce the potential for production shut-ins caused by downstream capacity issues) and (ii) the handling of fresh, recycled and produced water (through the use of our 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 several years, all at fluctuating market prices. We normally 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. This commitment will enhance our ability to move our crude oil out of the Permian Basin and give us access to potentially more favorable U.S. Gulf Coast pricing. See Note 4.c to our consolidated financial statements included elsewhere in this Annual Report for a further discussion of our firm transportation agreement with Medallion.
On October 30, 2017, LMS, together with Medallion Midstream Holdings, LLC ("MMH"), which was owned and controlled by an affiliate of The Energy & Minerals Group ("EMG"), 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, subject to customary post-closing adjustments (the "Medallion Sale"). LMS' net cash proceeds for its 49% ownership interest in Medallion in 2017 were $829.6 million, before post-closing adjustments and taxes, but after deduction of its proportionate share of fees and other expenses associated with the Medallion Sale. On February 1, 2018, closing adjustments were finalized and LMS received additional net cash of $1.7 million, for total net cash proceeds before taxes of $831.3 million. The proceeds were used to pay in-full borrowings on our Senior Secured Credit Facility, to redeem our May 2022 Notes (as defined below) and for working capital purposes. The Medallion Sale closed pursuant to the membership interest purchase and sale agreement, which provides for potential post-closing additional cash consideration that is structured based on GIP's realized profit at exit. There can be no assurance as to when and whether the additional consideration will be paid.
As of December 31, 2018, we were committed to deliver for sale or transportation the following fixed quantities of production under certain contractual arrangements that specify the delivery of a fixed and determinable quantity:
 
 
Total
 
2019
 
2020
 
2021
 
2022 and after
Crude oil (MBbl):
 
 
 
 
 
 
 
 
 
 
Sales commitments
 
730

 
730

 

 

 

Transportation commitments:
 
 
 
 
 
 
 
 
 
 
Field
 
68,224

 
13,414

 
10,980

 
10,950

 
32,880

To U.S. Gulf Coast
 
98,910

 
7,475

 
13,730

 
16,425

 
61,280

Natural gas (MMcf):
 
 
 
 
 
 
 
 
 
 
Sales commitments
 
69,109

 
10,339

 
9,578

 
5,620

 
43,572

Total commitments (MBOE)(1)
 
179,382

 
23,342


26,306


28,312


101,422

_____________________________________________________________________________
(1)
BOE equivalents are 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 going 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 will begin when the pipeline commences operations which is anticipated in the second half of 2019.
Our production has been substantially equivalent to or greater than our delivery commitments during the three most recent years, and we expect such production to meet our 2019 commitments. We are subject to firm transportation payments on excess pipeline capacity and other contractual penalties. In certain instances, we have used spot market purchases to meet commitments in certain locations or due to favorable pricing. We anticipate continuing this practice in the future. We incurred

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firm transportation payments on excess pipeline capacity and other contractual penalties of $4.7 million, $1.1 million and $2.2 million during the years ended December 31, 2018, 2017 and 2016, respectively. Also, if our production is not sufficient to satisfy our delivery commitments, we can and may use spot market purchases to fulfill the commitments.
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 information regarding each of our customers that accounted for the purchase of 10% or more of our oil, NGL and natural gas revenues during the last three calendar years, see Note 13 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 built an extensive proprietary technical database on our properties, including (but not limited to) 1,133 square miles of 3D seismic, 70 wells with microseismic, 7,073 feet of whole core in 18 wells, 958 sidewall cores in 24 wells, over 1,300 open and cased-hole logging suites with over 130 dipole sonic logs, 23 single-zone tests and 40 production logs. Our strategic interest in utilizing this database is directed at characterizing subsurface reservoir properties to gain insight into principles that potentially govern resource recovery, which can be subsequently leveraged during development planning, with the goal of maximizing the value of our entire asset base. 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.
HRGM’s integrate the above-described data with enhanced interpretations conducted in 2018 to provide 3D reservoir and mechanical property models across the majority of Laredo’s acreage. HRGM’s provide a sufficiently high resolution and accurate depiction of subsurface development potential to continue executing the "drill to plan" technical workflow, implemented in 2017. Drill to plan targets geological landing points in the perceived highest quality reservoir. This minimizes target changes during operations, increasing the accuracy of well positioning, while reducing time and costs associated with target changes and enhancing operational efficiencies. All of the 2019 planned wells are anticipated to utilize drill to plan.
HRGM’s provide the foundation for hydraulic fracture modeling, where hydraulic fracture and proppant transport models have been utilized to explicitly describe fracture networks. These fracture networks have then been used in conjunction with reservoir simulators to match specific packages of wells with unique landing points and completion designs. These models are then used to assess possible differences in fracture geometry and well productivity due to a multitude of variables, which include, but are not limited to, the landing point, well path, proppant loading, fluid loading, proppant concentration, pump rate and perforation design. Additionally, these models can be used for simulation of multi-well packages to assess potential interactions during the completion operation and total recovery factor of the resource in place.
Microseismic analysis continues to advance knowledge across various well spacing combinations and individual completion design field trials, improving our understanding of fracture geometry, cluster efficiency and proppant distribution associated with both well spacing and individual completion design. We consider our database and workflows advantageous in yielding important insights into subsurface behavior and consequently improved development decision making.
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 to be potentially significant tools in optimizing multi-well developments. We anticipate that all of our horizontal wells to be drilled in 2019 will utilize at least some aspects of the above workflows. If our preliminary applications of these workflows are replicated in forward-looking well planning, we anticipate this will positively impact our ability to select optimal multi-well development plans.
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, 2018, affiliates of Warburg Pincus LLC ("Warburg Pincus"), our founding member, owned 21.9% of our common stock.

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Debt
Laredo Petroleum, Inc. is the borrower under our Fifth Amended and Restated Credit Agreement (as amended, the "Senior Secured Credit Facility"), as well as the issuer of our $350.0 million in aggregate principal amount of 6 1/4% senior unsecured notes due 2023 (the "March 2023 Notes") and our $450.0 million in aggregate principal amount of 5 5/8% senior unsecured notes due 2022 (the "January 2022 Notes"). We refer to the March 2023 Notes and the January 2022 Notes collectively as the "Senior Unsecured Notes." Our subsidiaries, LMS and GCM, are guarantors of the obligations under our Senior Secured Credit Facility and Senior Unsecured Notes. The maturity date of our Senior Secured Credit Facility is April 19, 2023, provided that if either the January 2022 Notes or March 2023 Notes have not been refinanced on or prior to the date (as applicable, the "Early Maturity Date") that is 90 days before their respective stated maturity dates, the Senior Secured Credit Facility will mature on such Early Maturity Date.
On November 29, 2017 (the "May 2022 Notes Redemption Date"), following the Medallion Sale, we redeemed the entire $500.0 million outstanding principal amount of 7 3/8% senior unsecured notes due 2022 (the "May 2022 Notes") at a redemption price of 103.688% of the principal amount of the May 2022 Notes, plus accrued and unpaid interest up to, but not including, the May 2022 Notes Redemption Date.
Our business strategy
Our goal is to enhance shareholder value by executing the following strategy:
Maximize our capital efficiency by seeking to drill high rate of return wells through wider well spacing, reduced overhead and operational improvements
In 2019, we will seek to reduce overhead costs while increasing operational efficiency and in the later part of the second quarter of 2019, we will widen the spacing between our wells in order to target high rate of return well results.
In order to increase our operational flexibility, in the past three years, we deliberately reduced our PUD bookings within our reserves. While this decision impacts our total booked reserves in the short term, we believe that it enhances our ability to drill our most efficient wells by providing us with crucial flexibility in tailoring our drilling plans in a manner that is more cost-efficient. We converted all 26 PUD locations we booked at December 31, 2017 into proved producing locations in 2018.
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 accessing the capital markets.
Proactively manage risk to limit downside
We actively attempt to limit our business and operating risks by focusing on safety, flexibility in our financial profile, operational efficiencies, hedging, controlling costs and developing oil and natural gas takeaway capacity with multiple delivery points.
Seek accretive acquisitions
As we continue to develop our existing Permian-Garden City acreage position, we believe that the acquisition of additional acreage may be beneficial as consolidation and increased scale may lead to increased operational and corporate efficiencies.
Continue to hedge our production to protect cash flows, diminish the effects of commodity price fluctuations and maintain upside exposure
During 2018, 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.
Increase the use of our previously built 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 Permian-Garden City acreage position, as well as providing water transportation and recycling

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services for a significant portion of our planned drilling activities. Because of the value we ascribe to this infrastructure, we will continue to look for strategic expansion opportunities while maintaining 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
We have 120,617 net acres in the Permian-Garden City area that are largely contiguous with a high average working interest percentage (average working interest of 97% in all Laredo-operated producing wells), are 88% 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.
Drilling and lease operating efficiencies afforded by our acreage position and production corridors that enable low-cost operations
By making upfront investments in production infrastructure on our contiguous acreage position, we are now able to drill and operate in a more efficient and low-cost manner. We believe that this infrastructure will enable us to continue to be a low-cost operator while at the same time drilling facilitates productive new wells.
Significant cash flow from existing operations
Our Permian-Garden City acreage currently has approximately 1,155 net producing wells. That current base provides us with a significant amount of cash flow and such wells require little additional capital to maintain. In addition, we have few on-going drilling requirements to keep our Permian-Garden City acreage from lease expirations which further strengthens our flexibility to use cash flow from operations in a manner we see as most efficient.
Significant operational control
We operated wells that represent 99.7% of the economic value of our proved developed oil, NGL and natural gas reserves as of December 31, 2018, 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.
Our production corridors and water recycle facilities enable us to more efficiently develop our acreage and utilize/dispose of water that facilitates development and reduces our capital and operating expenses
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 use and disposal of water is one of the most challenging aspects of horizontal drilling in the Permian Basin and our production corridors 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 flowback and produced water.
Extensive infrastructure in place
We own and operate more than 238 miles of pipeline in our crude oil and natural gas gathering, fuel gas and gas lift systems in the Permian Basin as of December 31, 2018. These systems and pipelines provide greater operational efficiency, capital and cost savings and potentially better pricing for our production and enable us to coordinate our activities to connect our wells to market upon completion with minimal pipeline delays.


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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 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. Warburg Pincus has been the lead investor in many such companies, including two previous companies operated by certain members of our management team.
Our extensive Permian technical database
We have made a substantial upfront investment in technical data in order to accurately assess reservoir and production characteristics of our largely contiguous acreage. Our extensive 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
In addition to our Permian-Garden City acreage, as of December 31, 2018, we held 170 net acres in the Palo Duro Basin. Essentially all of this acreage will expire in 2019, absent drilling or renegotiation of the applicable leases. We anticipate little or no activity on these properties in 2019.
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 presented below has been prepared by Ryder Scott, in accordance with applicable SEC rules and regulations.
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"). 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:
 
 
As of December 31,
 
 
2018
 
2017
Benchmark Prices:
 
 
 
 
   Oil ($/Bbl)
 
$
62.04

 
$
47.79

   NGL ($/Bbl)(1)
 
$
31.46

 
$
26.13

   Natural gas ($/MMBtu)
 
$
1.76

 
$
2.63

Realized Prices:
 
 
 
 
   Oil ($/Bbl)
 
$
59.29

 
$
46.34

   NGL ($/Bbl)
 
$
21.42

 
$
18.45

   Natural gas ($/Mcf)
 
$
1.38

 
$
2.06

_____________________________________________________________________________
(1)
Based on the Company's average composite NGL Bbl.
    

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Our net proved reserves were estimated at 238,167 MBOE on a three-stream basis as of December 31, 2018, of which 91% were classified as proved developed reserves and 26% are attributable to oil reserves. The following table presents summary data for our operating area as of December 31, 2018.
 
 
As of December 31, 2018
 
 
Proved reserves
 
% of total
Area:
 
(MBOE)
 
 
Permian Basin
 
238,167

 
100
%
Other properties
 

 
%
Total
 
238,167

 
100
%
Our estimated proved reserves as of December 31, 2018 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."
The following table sets forth additional information regarding our estimated proved reserves as of December 31, 2018 and 2017. Ryder Scott estimated 100% of our proved reserves as of December 31, 2018 and 2017. The reserve estimates as of December 31, 2018 and 2017 were prepared in accordance with the applicable SEC rules regarding oil, NGL and natural gas reserves reporting.
 
 
As of December 31,
 
 
2018
 
2017
Proved developed producing:
 
 
 
 
Oil (MBbl)
 
55,893

 
68,877

NGL (MBbl)
 
79,241

 
60,441

Natural gas (MMcf)
 
491,828

 
371,946

Total proved developed producing (MBOE)
 
217,105

 
191,309

Proved undeveloped:
 
 
 
 
Oil (MBbl)
 
6,001

 
10,536

NGL (MBbl)
 
7,406

 
6,930

Natural gas (MMcf)
 
45,928

 
42,646

Total proved undeveloped (MBOE)
 
21,062

 
24,574

Estimated proved reserves:
 
 
 
 
Oil (MBbl)
 
61,894

 
79,413

NGL (MBbl)
 
86,647

 
67,371

Natural gas (MMcf)
 
537,756

 
414,592

Total estimated proved reserves (MBOE)
 
238,167

 
215,883

Percent developed
 
91
%

89
%
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.

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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.
During 2015, commodity prices for crude oil, NGL and natural gas experienced sharp declines, and this downward trend accelerated further into 2016, with crude oil prices reaching their lowest level in February 2016 since 2003. In the second half of 2016 and through 2017, commodity prices increased and stabilized at relatively higher prices but at significantly lower levels than the first half of 2014. In 2018, commodity prices continued to remain volatile with significantly lower prices in the last quarter of the year. Our capital expenditures budget for 2019 is approximately $365 million, based on annual benchmark averages of a $53.60 per barrel WTI NYMEX strip price and a $2.90 per MMBtu Henry Hub NYMEX strip price, excluding non-budgeted acquisitions. Our goal is to achieve cash flow neutrality, and therefore, our capital spending in 2019 will ultimately be influenced by commodity price changes, as well as any changes in service costs and drilling and completions efficiencies.
Beginning in 2016, we purposely significantly reduced the portion of our reserves that have historically been categorized as "proved undeveloped" or "PUD." We adjusted our five-year SEC PUD bookings methodology because we believe it enables us to develop our acreage in the most efficient manner possible and determine which potential locations best enhance our overall value. We believe that we can optimize value for our shareholders by maintaining greater flexibility in choosing the specific drilling locations that will most efficiently develop our properties, particularly as technology changes and we continue to further understand the geology of our acreage.
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 potential to provide the greatest 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 continuing insight as we drill and collect data across our acreage, regardless of SEC reserves booking status. We converted all 26 PUD locations booked at December 31, 2017 into proved producing locations in 2018. Reducing our future PUD commitments provides us the most flexibility to maximize our rate of return at prevailing conditions and minimize the requirement to drill wells previously assigned, under very different circumstances, as specific PUD locations. Accordingly, for 2019, we have continued to limit our booked PUD locations to those we have a high degree of certainty to believe that we will develop and have made a specific capital commitment to drill within the first six months of 2019. This strategy maintains our flexibility to add new PUD locations and convert other locations to proved developed reserves as our plans deem appropriate and opportunistic.
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, 2018 and 2017 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 Reservoir Engineering is the technical person primarily responsible for overseeing the preparation of our reserve estimates. He has more than 19 years of practical experience, with 10 years of this experience being in the estimation and evaluation of reserves. He has a Bachelors of Science in Chemical Engineering from Rice University, a Masters of Business Administration from the Kellogg School of Management and a Masters of Engineering Management from Northwestern University. Our Vice President of Reservoir Engineering reports to our Senior Vice President - Midstream,

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Marketing & Subsurface. 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 decreased from 24,574 MBOE as of December 31, 2017 to 21,062 MBOE as of December 31, 2018. We estimate that we incurred $215.1 million of costs to convert 24,574 MBOE of proved undeveloped reserves from 26 locations into proved developed reserves in 2018. New proved undeveloped reserves of 18,452 MBOE were added during the year from 18 new horizontal Wolfcamp locations. Positive revisions to proved undeveloped reserves of 2,610 MBOE were due to adding two undeveloped locations that were removed from reserves in a previous year. A final investment decision has been made on these 20 locations and they are scheduled to be drilled and completed in 2019.
Estimated total future development and abandonment costs related to the development of proved undeveloped reserves as shown in our December 31, 2018 reserve report are $159.0 million. Based on this report and our PUD booking methodology, the capital estimated to be spent in 2019 to develop the proved undeveloped reserves is $155.0 million and $0 for each of 2020, 2021, 2022 and 2023. 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 within the first six months of 2019. 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, 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 and price history
The following table presents information regarding our oil, NGL and natural gas sales volumes, revenues, average sales Realized Prices, and average costs and expenses per BOE sold for the periods presented. Our reserves and production 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."
 
 
For the years ended December 31,
(unaudited)
 
2018
 
2017
 
2016
Sales volumes:
 
 
 
 
 
 
Oil (MBbl)
 
10,175

 
9,475

 
8,442

NGL (MBbl)
 
7,259

 
5,800

 
4,784

Natural gas (MMcf)
 
44,680

 
35,972

 
29,535

Oil equivalents (MBOE)(1)(2)
 
24,881

 
21,270

 
18,149

Average daily sales volumes (BOE/D)(2)
 
68,168

 
58,273

 
49,586

Sales revenues (in thousands):
 
 
 
 
 
 
Oil
 
$
605,197

 
$
445,012

 
$
318,466

NGL
 
$
149,843

 
$
101,438

 
$
56,982

Natural gas
 
$
53,490

 
$
75,057

 
$
51,037

Average sales Realized Prices(2):
 
 
 
 
 
 
Oil, without derivatives ($/Bbl)(3)
 
$
59.48

 
$
46.97

 
$
37.73

NGL, without derivatives ($/Bbl)(3)
 
$
20.64

 
$
17.49

 
$
11.91

Natural gas, without derivatives ($/Mcf)(3)
 
$
1.20

 
$
2.09

 
$
1.73

Average price, without derivatives ($/BOE)(3)
 
$
32.50

 
$
29.22

 
$
23.50

Oil, with derivatives ($/Bbl)(4)
 
$
55.49

 
$
50.45

 
$
58.07

NGL, with derivatives ($/Bbl)(4)
 
$
20.03

 
$
16.91

 
$
11.91

Natural gas, with derivatives ($/Mcf)(4)
 
$
1.77

 
$
2.15

 
$
2.20

Average price, with derivatives ($/BOE)(4)
 
$
31.72

 
$
30.71

 
$
33.73

Average costs and expenses per BOE sold(2):
 
 
 
 
 
 
Lease operating expenses
 
$
3.67

 
$
3.53

 
$
4.15

Production and ad valorem taxes
 
$
1.99

 
$
1.78

 
$
1.58

Transportation and marketing expenses
 
$
0.47

 
$

 
$

Midstream service expenses
 
$
0.12

 
$
0.19

 
$
0.22

General and administrative:
 
 
 
 
 
 
Cash
 
$
2.40

 
$
2.85

 
$
3.45

Non-cash stock-based compensation, net
 
$
1.46

 
$
1.68

 
$
1.61

Depletion, depreciation and amortization
 
$
8.55

 
$
7.45

 
$
8.17

_______________________________________________________________________________
(1)
BOE is calculated using a conversion rate of six Mcf per one Bbl.
(2)
The numbers presented are based on actual results and are not calculated using the rounded numbers presented in the table above.
(3)
Realized oil, NGL and natural gas prices are the actual 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 wellhead.
(4)
Price reflects the after-effects of our derivative transactions on our average sales Realized Prices. Our calculation of such after-effects includes settlements of matured derivatives during the respective periods in accordance with GAAP and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to derivatives that settled during the respective periods.

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Productive wells
The following table sets forth certain information regarding productive wells in our core operating area as of December 31, 2018. 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 Basin:
 
 
 
 
 
 
 
 
 
 
Operated Permian-Garden City
 
766

 
412

 
1,178

 
1,141

 
97
%
Non-operated Permian-Garden City
 
61

 
7

 
68

 
14

 
21
%
Other properties
 

 

 

 

 
%
Total
 
827

 
419

 
1,246

 
1,155

 
93
%
Acreage
The following table sets forth certain information regarding the developed and undeveloped acreage in which we own an interest as of December 31, 2018 for our core operating area and other properties, 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
 
Permian Basin
 
119,433

 
105,998

 
16,082

 
14,619

 
135,515

 
120,617

 
88
%
Other properties
 

 

 
520

 
170

 
520

 
170

 
%
Total
 
119,433

 
105,998

 
16,602

 
14,789

 
136,035

 
120,787

 
88
%
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, 2018 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.
 
 
2019
 
2020
 
2021
 
2022
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Permian Basin
 
161

 
180

 
5,652

 
4,576

 
566

 
159

 

 
46

Other properties
 
520

 
170

 

 

 

 

 

 

Total
 
681

 
350

 
5,652

 
4,576

 
566

 
159

 

 
46

Of the total undeveloped acreage identified as expiring over the next four years, 690 net acres have associated PUD reserves as of December 31, 2018. All of those PUD reserves are scheduled to be drilled and completed in the first half of 2019.
At December 31, 2017, 0 net acres of potentially expiring leasehold were identified as attributable to PUD reserves.

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Drilling activity
The following table summarizes our drilling activity for the years ended December 31, 2018, 2017 and 2016. 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.
 
 
2018
 
2017
 
2016
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Development wells:
 
 
 
 
 
 
 
 
 
 
 
 
Productive
 
74

 
71.2

 
62

 
60.7

 
45

 
44.5

Dry
 

 

 

 

 

 

Total development wells
 
74

 
71.2

 
62

 
60.7

 
45

 
44.5

Exploratory wells:
 
 
 
 
 
 
 
 
 
 
 
 
Productive