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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, 2013

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 1800 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, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ý		Accelerated filer o		Non-accelerated filer o		Smaller reporting company o
				(Do not check if a smaller reporting company)

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

Aggregate market value of the voting and non-voting common equity held by non-affiliates was approximately $870.1 million on June 28, 2013, based on $20.56 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 24, 2014: 142,618,804

Documents Incorporated by Reference:

Portions of the registrant's definitive proxy statement for its 2014 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2013, are incorporated by reference into Part III of this report for the year ended December 31, 2013.

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Laredo Petroleum, Inc.

Table of Contents

	Glossary of Oil and Natural Gas Terms	3
	Cautionary Statement Regarding Forward-Looking Statements	5
	Part I
Item 1.	Business	6
Item 1A.	Risk Factors	29
Item 1B.	Unresolved Staff Comments	45
Item 2.	Properties	45
Item 3.	Legal Proceedings	45
Item 4.	Mine Safety Disclosures	45
	Part II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	46
Item 6.	Selected Historical Financial Data	48
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	51
Item 7A.	Quantitative and Qualitative Disclosure About Market Risk	73
Item 8.	Financial Statements and Supplementary Data	75
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	75
Item 9A.	Controls and Procedures	75
Item 9B.	Other Information	78
	Part III
Item 10.	Directors, Executive Officers and Corporate Governance	79
Item 11.	Executive Compensation	79
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	79
Item 13.	Certain Relationships and Related Transactions, and Director Independence	79
Item 14.	Principal Accounting Fees and Services	79
	Part IV
Item 15.	Exhibits, Financial Statement Schedules	80

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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.

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

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

"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.

"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.

"Facies"—A lateral change in a stratigraphic rock unit due to variance in the formation's petrophysical attribute(s).

"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 differs from nearby rock.

"Fracturing ("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.

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

"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.

"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.

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

"MMBtu"—One million British thermal units.

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

"Natural gas liquid"—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 total 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.

"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 ("PDNP")"—Developed non-producing reserves.

"Proved developed reserves ("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 which 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 ("PUD")"—Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

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

"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 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. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

"Standardized measure"—Discounted future net cash flows estimated by applying year-end 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.

"Two stream"—Production or reserve volumes of oil and wet natural gas, where the natural gas liquids have not been removed from the natural gas stream and the economic value of the natural gas liquids is included in 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.

"Working interest" or "WI"—The right granted to the lessee of a property to explore for and to produce and own 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 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 recent instability and uncertainty in the U.S. and international financial and consumer markets that is adversely affecting the liquidity available to us and our customers and is adversely affecting the demand for commodities, including oil and natural gas;

•	the volatility of oil and natural gas prices;

•	the possible introduction of regulations that prohibit or restrict our ability to apply hydraulic fracturing to our oil and natural gas wells;

•	the possible introduction of regulations that prohibit or restrict our ability to drill new allocation wells;

•	discovery, estimation, development and replacement of oil and natural gas reserves, including our expectations that estimates of our proved reserves will increase;

•	uncertainties about the estimates of our oil and natural gas reserves;

•	competition in the oil and natural gas industry;

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

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

•	risks related to the geographic concentration of our assets;

•	changes in domestic and global demand for oil and natural gas, as well as the continuation of restrictions on the export of domestic crude oil;

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

•	changes in the regulatory environment and changes in international, legal, political, administrative or economic conditions;

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

•	our ability to execute our strategies, including but not limited to our hedging strategies;

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

•	evolving industry standards and adverse changes in global economic, political and other conditions;

•	restrictions contained in our debt agreements, including our senior secured credit facility and the indentures governing our senior unsecured notes, as well as debt that could be incurred in the future;

•	our ability to access additional borrowing capacity under our senior secured credit facility or other means of providing liquidity; and

•	our ability to generate sufficient cash to service our indebtedness and to generate future profits.

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

     On December 31, 2013, Laredo Petroleum Holdings, Inc., a Delaware corporation, completed an internal corporate reorganization and changed its name to Laredo Petroleum, Inc. See "Item 1. Business — Corporate history and structure" for more information. Unless the context otherwise requires, references in this Annual Report to “Laredo,” the “Company,” “we,” “our,” “us,” or similar terms refer to Laredo Petroleum Holdings, Inc. and its subsidiaries, including Laredo Petroleum, Inc., a Delaware corporation, before the completion of our internal corporate reorganization and to Laredo Petroleum, Inc. and its subsidiary, Laredo Midstream Services, LLC, as of the completion of our internal corporate reorganization and thereafter.

In this Annual Report, the consolidated and historical financial information, operational data and reserve information for Laredo and our acquired subsidiary Broad Oak Energy, Inc. ("Broad Oak"), a Delaware corporation, present the assets and liabilities of Laredo and its subsidiaries and Broad Oak at historical carrying values and their operations as if they were consolidated for all periods presented prior to July 1, 2011. Although the financial and other information is reported on a consolidated basis, such presentation is not necessarily indicative of the results that would have been obtained if Laredo had owned and operated Broad Oak from its inception. See Notes A and B in our audited consolidated financial statements included elsewhere in this Annual Report for more information.

All amounts, 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 exploration, development and acquisition of oil and natural gas properties primarily in the Permian region of the United States. The oil and liquids-rich Permian Basin in West Texas 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, 2013, we had assembled 202,084 net acres in the Permian Basin and had total proved reserves, presented on a two-stream basis, of 203,615 MBOE.

On August 1, 2013, we completed the sale of our assets in the Anadarko Basin in the Texas Panhandle and Western Oklahoma (the “Anadarko Basin Sale”) which represented 15% of our proved reserve volumes as of December 31, 2012. Following the Anadarko Basin Sale, the percentage of our proved reserves attributable to oil increased to 55% as of December 31, 2013 from 52% prior to such sale.

Our primary exploration and production fairway in the Permian Basin is centered on the eastern side of the basin 35 miles east of Midland, Texas and extends 20 miles wide (east/west) and 85 miles long (north/south) in Glasscock, Howard, Reagan, Sterling and Tom Green counties, and is referred to in this Annual Report as the "Permian-Garden City" area. As of December 31, 2013, we held 143,212 net acres in more than 300 sections in the Permian-Garden City area, with an average working interest of 96% in all Laredo-operated producing wells.

We believe our acreage in the Permian-Garden City area is a resource play for the Wolfberry interval, comprised of multiple producing formations, including the initial four identified shale zones targeted for horizontal drilling (Upper, Middle and Lower Wolfcamp and Cline shales). From our inception through December 31, 2013, we have drilled and completed 96 horizontal wells in these four target zones, and 818 vertical wells in the Wolfberry interval. We have completed (i.e., the particular well is flowing) 40 horizontal Upper Wolfcamp wells, 13 horizontal Middle Wolfcamp wells, six horizontal Lower Wolfcamp wells and 37 horizontal Cline wells. Our horizontal activity since mid-2012 has moved toward drilling longer laterals (typically 7,000 to 7,500 feet) and increased frac density (typically 25 to 28 stages) as we continue the optimization of our completion techniques.

    

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As illustrated in the following table, as a result of our drilling activity through 2013 coupled with our technical data and well performance, we believe that as of December 31, 2013 we have confirmed the horizontal development potential for the equivalent of 360,000 net acres from the four zones, as well as our entire Permian-Garden City acreage position for vertical development.

		Horizontal development de-risked net acreage as of December 31, 2013
Upper Wolfcamp		80,000
Middle Wolfcamp		80,000
Lower Wolfcamp		73,000
Cline		127,000
Total		360,000

Going forward, we plan to continue drilling and collecting technical data across our Permian-Garden City acreage, as reflected in our 2014 capital drilling budget allocation. As a result, we expect our Permian-Garden City acreage to be the primary driver of our reserves, production and cash flow growth for the foreseeable future.

Laredo was founded in October 2006 by our Chairman and Chief Executive Officer Randy A. Foutch, who was later joined by other members of our management team. Prior to founding Laredo, Mr. Foutch formed, built and sold three private oil and natural gas companies. All of these companies executed the same fundamental business strategy employed by Laredo and created significant economic value through growth in reserves, production and cash flow.

In December 2011, we completed a Corporate Reorganization and IPO and in December 2013, we completed a separate internal corporate reorganization. See "—Corporate history and structure."

Since our inception, we have rapidly grown our reserves, production and cash flow through both our drilling program and strategic acquisitions, including our July 2011 acquisition of Broad Oak. Our net proved reserves were estimated at 203,615 MBOE as of December 31, 2013, of which 35% are classified as proved developed reserves and 55% are attributed to oil reserves. Our reserves and production are reported in two streams: crude oil and liquids-rich natural gas. The economic value of the natural gas liquids in our natural gas is included in the wellhead natural gas price. 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.

    

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The following table summarizes our total estimated net proved reserves presented on a two-stream basis, net acreage and producing wells as of December 31, 2013, and average daily production presented on a two-stream basis for the year ended December 31, 2013. Based on estimates in the report prepared by Ryder Scott, we operate wells that represent 98% of the economic value of our proved developed oil and natural gas reserves as of December 31, 2013.

		As of December 31, 2013																		Year ended December 31, 2013 average daily production(3) (BOE/D)
		Estimated net proved reserves(1)(2)												Producing wells
		MBOE			% of total reserves			% Oil			Net acreage			Gross			Net
Permian		203,564			99	%		55	%		202,084			1,060			940			24,897
Anadarko Granite Wash(4)		—			—	%		—	%		—			—			—			4,615
Other Areas(5)		—			—	%		—	%		—			—			—			1,141
New Ventures(6)		51			1	%		100	%		80,143			1			1			63
Total		203,615			100	%		55	%		282,227			1,061			941			30,716

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(1)

Our estimated net proved reserves were prepared by Ryder Scott, presented on a two-stream basis as of December 31, 2013 and are based on reference oil and natural gas prices. In accordance with applicable rules of the SEC, the reference oil and natural gas prices are derived from the average trailing 12-month index prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the applicable 12-month period), held constant throughout the life of the properties. The reference prices were $93.52 per Bbl for oil and $3.57 per MMBtu for natural gas for the 12 months ended December 31, 2013.

(2)

Because our reserves are reported in two streams, the economic value of the natural gas liquids in our natural gas is included in the wellhead natural gas price. The reference prices referred to above that were utilized in the December 31, 2013 reserve report prepared by Ryder Scott are adjusted for natural gas liquids content, quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. The adjusted reference price was $5.52 per Mcf.

(3)	Our average daily production volumes are reported in two streams: crude oil and liquids-rich natural gas. The economic value of the natural gas liquids in our natural gas is included in the wellhead natural gas price.

(4)	We sold these assets on August 1, 2013.

(5)	We sold these assets on August 1, 2013, which included our acreage in the gas prone Eastern Anadarko (21,000 net acres) and Central Texas Panhandle (43,450 net acres).

(6)	On December 20, 2013, we completed the sale of certain properties in the Dalhart Basin, which included 37,000 net acres. The remaining 50,000 net acres that we own in the Dalhart Basin are included in New Ventures. See "—New Ventures."

Our net average daily production for the year ended December 31, 2013 was 30,716 BOE/D, 49% of which was oil and 51% of which was primarily liquids-rich natural gas. Our drilling activity has been and is expected to continue to be focused on oil opportunities in the Permian Basin.

Following the sale of our assets in the Anadarko Basin and Dalhart Basin, we continue to focus on horizontal drilling in the Permian Basin. This Permian Basin horizontal drilling program comprises an extensive, multi-year, multiple-zone inventory of exploratory and development opportunities.

As of December 31, 2013 we had completed 96 gross horizontal Wolfcamp and Cline shale wells in our Permian-Garden City area.

Substantially all of our $1 billion planned capital budget for 2014 is anticipated to be invested in the Permian Basin. We anticipate that we will continue to drill vertical wells for purposes of further delineating our Permian Basin acreage and holding all prospective targeted zones. We are increasingly allocating a greater percentage of both capital and human resources towards our horizontal drilling activity, which generally produces even more attractive economics than our vertical program. Because of the stacked multiple-zone horizontal targets underlying our acreage, we are continuing to refine the optimal geometry relative to well spacing, both vertically and horizontally, lateral placement, completion and production practices. Work to date has included the pad drilling of side-by-side wells within the same zone, stacked lateral wells and extensive reservoir modeling.

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On December 31, 2013 we had a total of 11 operated drilling rigs working on our properties in the Permian-Garden City area, consisting of six rigs drilling vertical wells and five rigs drilling horizontal wells.

We have assembled a multi-year inventory of development drilling and exploitation projects as a result of our early acquisition of technical data, early establishment of significant concentrated acreage positions and successful exploratory drilling.

While our horizontal drilling programs will be focused primarily on developing the four zones already identified in the liquids-rich Wolfcamp and Cline intervals underlying our Permian-Garden City properties, we believe, based on petrophysical analysis, additional potential may exist in both shallower and deeper formations. The testing of these new targeted intervals will be integrated into our drilling program during 2014 and beyond.

We maintain a financial profile that provides operational flexibility. At December 31, 2013, we had $825 million available for borrowings under our Fourth Amended and Restated Credit Agreement (as amended, the "Senior Secured Credit Facility") and total debt of $1.05 billion, of which no amount was outstanding under our Senior Secured Credit Facility. Our total debt, less available cash on the balance sheet, was 1.8 times our Adjusted EBITDA (a non-GAAP financial measure, see "Item 6. Selected Historical Financial Data—Non-GAAP financial measures and reconciliations") for the year ended December 31, 2013. We believe that our operating cash flow and the aforementioned liquidity sources provide us with the capability to implement our planned exploration and development activities as well as the ability to accelerate our capital program, if deemed appropriate. We use derivatives to reduce exposure to fluctuations in the prices of oil and natural gas. By removing a significant portion of the price volatility associated with future production, we expect to mitigate, but not eliminate, the potential effects of variability in cash flows from operations due to fluctuations in commodity prices.

We carefully assess and monitor many factors in our drilling and exploration projects. Our drilling activities in areas containing extensive historical industry activity have enabled us to determine whether a prospective reservoir underlies our acreage position, and whether it can be defined both vertically and horizontally. We use a number of proven mapping techniques to understand the physical extent of the targeted reservoir. This includes 2D and 3D seismic data, as well as Laredo-owned and historical public well databases (which in the Permian Basin may extend back more than 80 years). We also utilize our laboratory and field derived data from whole cores, sidewall cores, well cuttings, mudlogs and open-hole well logs to understand the petrophysics of the rock characteristics prior to the commencement of any completion operations. Finally, after defining the reservoir, our engineers utilize their technical expertise to develop completion programs that we believe will maximize the amount of hydrocarbons that can be economically recovered. As more wells are completed in the targeted reservoir and additional data becomes available, the process is further refined. Based on these and other factors, we consider our acreage to be "de-risked" (i.e., having reduced the risk and uncertainty associated therewith) when we believe we have established the ability to commercially produce from a certain area.

In the Permian-Garden City area, the Wolfberry interval, comprised of multiple producing formations, including the Wolfcamp and Cline shale formations targeted for horizontal drilling in four zones (Upper, Middle and Lower Wolfcamp and Cline shales), is considered a resource play. While the vertical component of the drilling program will continue, our emphasis is now centered on bringing forward the upside potential in the Wolfcamp and Cline shales in our Permian-Garden City acreage through horizontal drilling. As resource plays, the mapping of the gross interval for each of the producing formations underlying a majority of our acreage position is the primary factor in identifying our potential drilling locations. In the general region and immediately around our acreage position, publicly available well data exists from a significant number of vertical wells (in excess of several thousand for the Wolfcamp and Cline shales alone) that allows us to better define the potential areal extent of each of the producing intervals. In addition to the publicly available well data, we have also incorporated our internally generated information from cores, 3D seismic, open-hole logging, production and reservoir engineering data into defining the extent of the targeted formations, the ability of such formations to produce commercial quantities of hydrocarbons, and the viability of the potential locations. We are refining a development plan for a portion of our Permian-Garden City area in order to minimize costs and maximize recoveries and began its implementation in 2013. As of December 31, 2013, we had drilled and completed 10 horizontal wells as a part of our pad drilling program.

The timing of drilling our potential locations is influenced by several factors, including commodity prices, capital requirements, the Texas Railroad Commission ("RRC") well-spacing requirements and the continuation of the positive results from our ongoing development drilling program.

Corporate history and structure

Laredo Petroleum Holdings, Inc. was incorporated in August 2011 pursuant to the laws of the State of Delaware for purposes of a corporate reorganization and initial public offering ("IPO"). The corporate reorganization, pursuant to which Laredo Petroleum, LLC was merged with and into Laredo Petroleum Holdings, Inc., with Laredo Petroleum Holdings, Inc.

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surviving the merger, was completed on December 19, 2011 (the "Corporate Reorganization"). Laredo Petroleum, LLC was formed in 2007 pursuant to the laws of the State of Delaware by affiliates of Warburg Pincus LLC ("Warburg Pincus"), our institutional investor, and the management of Laredo Petroleum, Inc., which was founded in 2006 by Randy A. Foutch, our Chairman and Chief Executive Officer, to acquire, develop and operate oil and natural gas properties in the Permian and Mid-Continent regions of the United States. In the Corporate Reorganization, all of the outstanding preferred equity interests and certain of the incentive equity interests in Laredo Petroleum, LLC were exchanged for shares of common stock of Laredo Petroleum Holdings, Inc. Laredo Petroleum Holdings, Inc. completed an IPO of its common stock on December 20, 2011. As of December 31, 2013, Warburg Pincus owned 49.1% of our common stock.

On July 1, 2011, we completed the acquisition of Broad Oak, which became a wholly-owned subsidiary of Laredo Petroleum, Inc. Broad Oak was formed in 2006 with financial support from its management and Warburg Pincus. On July 19, 2011, we changed the name of Broad Oak to Laredo Petroleum—Dallas, Inc.

Effective December 31, 2013, we completed an internal corporate reorganization, which simplified our corporate structure. Our two former subsidiaries Laredo Petroleum Texas, LLC and Laredo Petroleum—Dallas, Inc. were merged with and into Laredo Petroleum, Inc. The sole remaining wholly-owned subsidiary of Laredo Petroleum, Inc., formerly known as Laredo Gas Services, LLC, changed its name to Laredo Midstream Services, LLC. Laredo Petroleum, Inc., a wholly-owned subsidiary of Laredo Petroleum Holdings, Inc. ("Holdings"), merged with and into Holdings with Holdings surviving and changing its name to “Laredo Petroleum, Inc.” We refer to the events described in this paragraph collectively as the "Internal Consolidation." The Corporate Reorganization, IPO and Internal Consolidation are discussed in Note A to our audited consolidated financial statements included elsewhere in this Annual Report.

Laredo Petroleum, Inc. is the borrower under our Senior Secured Credit Facility, as well as the issuer of our $550 million 9 1/2% senior unsecured notes due 2019 (the "2019 senior unsecured notes") issued in January and October 2011, our $500 million 7 3/8% senior unsecured notes due 2022 issued in April 2012 (the "2022 senior unsecured notes") and our $450 million 5 5/8% senior unsecured notes due 2022 issued in January 2014 (the "new senior unsecured notes"). We refer to the 2019 senior unsecured notes, the 2022 senior unsecured notes and the new senior unsecured notes collectively as the "senior unsecured notes." Our subsidiary, Laredo Midstream Services, LLC ("Laredo Midstream"), is a guarantor of the obligations under our Senior Secured Credit Facility and senior unsecured notes.

Our business strategy

Our goal is to enhance stockholder value by economically growing our reserves, production and cash flow by executing the following strategy:

Grow reserves, production and cash flow.    As of December 31, 2013, we had 143,212 net acres in the Permian-Garden City area. As of such date we believe we have established the economic horizontal potential of 80,000 net acres for horizontal Upper Wolfcamp drilling, 80,000 net acres for horizontal Middle Wolfcamp drilling, 73,000 net acres for Lower Wolfcamp drilling and 127,000 net acres for horizontal Cline drilling. We are continuing to de-risk the remaining acreage for these zones, although at a slower pace than in the past. We believe the opportunities afforded in our Permian-Garden City area will support consistent, predictable, annual growth in reserves, production and cash flow.    

Initiating a development plan for our Permian-Garden City acreage. We believe our Permian-Garden City acreage will be the primary driver of our reserves, production and cash flow growth for the foreseeable future. Based on additional drilling results through December 31, 2013, coupled with our technical data and well performance, we believe we have confirmed the vertical development potential of our entire Permian-Garden City acreage position (utilizing more than 800 vertical wells across our acreage position, of which more than 300 have been drilled through the Wolfcamp, Cline and Atoka formations). The equivalent of 360,000 net acres for commercial horizontal development has been proven from all four targeted zones based on 96 horizontal wells drilled and completed as of December 31, 2013. We further believe this de-risked acreage position provides a multi-year development inventory to support consistent growth of reserves, production and cash flow. We are implementing a systematic pad development drilling program that will allow us to optimize spacing, minimize drainage interference and maximize our frac design. Because of the complexities of developing a field that has multi-dimensional aspects (vertical and horizontal reservoir components), we have drilled and tested side-by-side horizontal wells (same reservoir) with the initial results supporting 660-ft. spacing at or above our internal production estimates. The stacked lateral program (up to four different zones) has been initiated with multiple tests planned in several areas of our acreage in 2014. Our objectives with the stacked lateral program are to optimize the vertical distance between the laterals, minimize interference, enhance frac design and maximize scheduling of rig operations on multi-well pads. The plan also calls for having the flexibility to include the de-risking of additional acreage for both the Wolfcamp and the Cline shale intervals while furthering the development of the Middle and Lower Wolfcamp zones in the southern half of the Permian-Garden City acreage. The drilling and testing of other potential zones (i.e., Spraberry and ABW) will likely also be part of the 2014 drilling program. Going

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forward, we plan to continue drilling and collecting technical data across our Permian-Garden City acreage position.

Capitalize on technical expertise and database. We are leveraging our operating and technical expertise to further delineate and develop our core acreage positions. We believe that we have de-risked a significant portion of our Permian-Garden City acreage through the utilization of an extensive technical petrophysical database, a vertical drilling program covering a majority of our core acreage position, numerous vertical single-zone tests in our horizontal targets, and the production data from the 96 completed horizontal wells in all three Wolfcamp zones and the Cline shale zones.

We intend to continue to make upfront investments in technology to understand the geology, geophysics and reservoir parameters of the rock formations that define our exploration and development programs. Through comprehensive coring programs, acquisition and evaluation of high-quality 3D seismic data and advance logging/simulation technologies, we expect to continue to both economically de-risk our remaining property sets to the extent possible before committing to a drilling program, and assist in the evaluation of emerging opportunities.

Enhance returns through prudent capital allocation, optimization of our development program and continued improvements in operational and cost efficiencies. In the current commodity price environment, we have directed our capital spending toward oil and liquids-rich drilling opportunities that provide attractive returns. We believe by emphasizing our horizontal program, we can increase the efficiency of our resource recovery in the multiple vertically stacked producing horizons on our acreage in our Permian-Garden City area. We initiated a development plan for a portion of our Permian-Garden City area in order to minimize costs and maximize recoveries. We began implementing this plan in 2013, commencing with a single zone side-by-side test and vertically stacked horizontal wellbores in multiple zones to test optimal spacing of the laterals, both vertically and horizontally, in the four initial zones targeted for horizontal development. We are now drilling longer laterals and optimizing our completion process to enhance the cost-efficient recovery of our resource potential. In addition, horizontal drilling may be economic in areas where vertical drilling is currently not economical or logistically viable. We will continue to utilize our vertical drilling program to de-risk additional acreage for all zones. Our management team is focused on continuous improvement of our operating practices and has significant experience in successfully converting exploration programs into cost-efficient development projects. We are the operator for 88% of our Permian-Garden City wells which allows us to more effectively manage operating costs, the pace of development activities, technical applications, the gathering and marketing of our production and capital allocation.

Evaluate and pursue value-enhancing acquisitions, mergers, joint ventures and divestitures. While we believe our multi-year inventory of potential drilling locations provides us with significant growth opportunities, we continue to evaluate strategically compelling and/or value enhancing asset acquisitions, mergers, joint ventures and divestitures. Any transaction we pursue will either generally complement our asset base, provide an anticipated competitive economic proposition relative to our existing opportunities or market conditions, or provide an avenue to accelerate the development of our potentially higher return acreage and maximize the value of the total Company.

Proactively manage risk to limit downside. We continually monitor and control our business and operating risks through various risk management practices, including maintaining a flexible financial profile, making upfront investment in research and development as well as data acquisition, seeking multiple sales outlets, minimizing long-term contracts, maintaining an active commodity hedging program and employing prudent safety and environmental practices.

Our competitive strengths

We have a number of competitive strengths that we believe will help us to successfully execute our business strategy:

Significant de-risked Permian Basin acreage position and multi-year drilling inventory. From our inception in 2006 through December 31, 2013, we have completed 818 gross vertical and 98 gross horizontal wells with a success rate of 99% in our Permian-Garden City area. The 98 gross horizontal wells are comprised of 96 wells in the Upper, Middle and Lower Wolfcamp and Cline shales and two wells in other zones. Based on our drilling results through December 31, 2013, we believe we had confirmed the economic horizontal development potential of the equivalent of 360,000 net acres from the four zones that includes 80,000 net acres in the Upper Wolfcamp, 80,000 net acres in the Middle Wolfcamp, 73,000 net acres in the Lower Wolfcamp and 127,000 net acres in the Cline shale. We believe these locations provide a multi-year drilling inventory supporting future growth in reserves, production and cash flow.

Extensive Permian technical database and expertise. We have made a substantial upfront investment to understand the geology, geophysics and reservoir parameters of the rock formations that define our drilling and development program. We have an extensive library of data applicable to our Permian-Garden City acreage base that includes 774 square miles of proprietary/licensed 3D seismic (covering 95% of our acreage position), 225 proprietary petrophysical logs (fully core calibrated), and more than 13,500 historical open-hole logs from the general area, as of December 31, 2013. We have also run 96 dipole sonic longs which play a key role in our petrophysical analysis. Approximately 470 square miles of the total 3D seismic coverage has been merged into one volume, allowing for maximum utilization and interpretation of the data set. In

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addition, membership in an industry core consortium has provided us access to additional petrophysical data across a larger area outside our core Permian-Garden City acreage position. In coordination with a major oil-field consultant, we are in the process of creating a model (utilizing a majority of the data listed above) that we anticipate will assist in developing our Permian-Garden City acreage with the best reservoir characteristics early in the life of the field. Another important objective of the modeling program includes how to maximize hydrocarbon recovery by utilizing the minimum required number of wells through proper well spacing.

Significant operational control. We operate wells that represent 98% of the economic value of our proved developed reserves as of December 31, 2013, based on a report prepared by Ryder Scott. We believe that maintaining operating control permits us to better pursue our strategies of enhancing returns through operational and cost efficiencies and maximizing ultimate hydrocarbon recoveries from mature producing basins through reservoir analysis and evaluation and continuous improvement of drilling, completion and stimulation techniques. We expect to maintain operating control over most of our potential drilling locations.

Owned gathering infrastructure. Our wholly-owned subsidiary, Laredo Midstream, has more than 125 miles of pipeline in our natural gas gathering systems in the Permian Basin as of December 31, 2013. These systems and flow lines provide greater operational efficiency and lower price differentials for our natural gas production in our liquids-rich Permian play and enable us to coordinate our activities to connect our wells to market upon completion with minimal days waiting on pipeline. Additionally, on a portion of our production, this provides us with multiple sales outlets through interconnection pipelines, potentially minimizing the risks of both shut-ins awaiting pipeline connection and curtailment of downstream pipelines. We continue to expand this concept by building out our crude oil transportation infrastructure in order to attempt to minimize the risks of shut-in or curtailment. We have constructed crude oil truck stations in Glasscock and Reagan counties, Texas. We have also commenced construction of a crude oil gathering system in Reagan County, Texas.

Financial strength and flexibility. We maintain a financial profile that provides operational flexibility. As of December 31, 2013, we had $825 million available for borrowings under our Senior Secured Credit Facility and total liquidity of $1.0 billion, with no amounts outstanding on our Senior Secured Credit Facility. As of such date, we had $1.05 billion of total debt consisting of two series of senior unsecured notes with maturities in 2019 and 2022. We use derivatives to reduce exposure to fluctuations in the prices of oil and natural gas. By removing a portion of the price volatility associated with future production, we expect to mitigate, but not eliminate, the potential volatility in cash flows from operations due to fluctuations in commodity prices.

Subsequent to December 31, 2013, we issued the new senior unsecured notes that increased our total long-term indebtedness to $1.5 billion and decreased the amount available for borrowings under our Senior Secured Credit Facility to $812.5 million.

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, which is comprised of Laredo management and representatives of Warburg Pincus, our institutional investor, as well as independent individuals, 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. During the last two decades, Warburg Pincus has been the lead investor in dozens of such companies, including Broad Oak and two previous companies operated by members of our management team.

Focus areas

Our properties are currently located in the prolific Permian region of the United States, where we leverage our experience and knowledge to identify, exploit and acquire additional upside potential. We have been successful in delivering repeatable results through internally generated vertical and horizontal drilling programs. We expect our Permian-Garden City acreage, which is characterized by a high oil content, to be the primary driver of our reserves, production and cash flow growth for the foreseeable future.

Permian Basin

The oil and liquids-rich Permian Basin, located in West Texas and Southeastern New Mexico, where we have assembled 202,084 net acres as of December 31, 2013, is one of the most productive onshore oil and natural gas producing regions in the United States. It is characterized by an extensive production history, mature infrastructure, long reserve life and hydrocarbon potential in multiple intervals. Our primary production and exploitation fairway (Permian-Garden City area) is centered on the eastern side of the basin 35 miles east of Midland, Texas and extends 20 miles wide (east/west) and 85 miles long (north/south) in Howard, Glasscock, Reagan, Sterling and Tom Green counties. As of December 31, 2013, we held

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143,212 net acres in more than 300 sections in the Permian-Garden City area with an average working interest of 96% in all Laredo-operated producing wells.

During 2013, we continued to expand our horizontal development program for the Wolfberry and Cline shales. Our results indicate that our acreage in the Permian-Garden City area can be produced horizontally, with even stronger economic results than our vertical program. Within the Wolfcamp, we have three distinct zones; the Upper, Middle and Lower Wolfcamp shales, which together with the Cline shale provide at least four horizontal targets in the Permian-Garden City area. During 2013, we drilled and completed 36 horizontal wells and now have a total of 96 horizontal wells, confirming production and attractive returns from all four zones. Today, we are continuing our drilling focus on a horizontal development and exploitation program supported by vertical wells that help us define and optimize the horizontal targets.

As of December 31, 2013, our proprietary and industry data includes 774 square miles of proprietary/licensed 3D seismic, 13 whole and more than 335 sidewall cores in the four zones we are currently targeting, providing extensive production and reservoir engineering data. From our analysis of this data, we believe each of these zones has the potential to be a stand-alone resource play with significant areal extent, the ability to produce commercial quantities of hydrocarbons and the viability of repeatable well performance from multiple potential locations. Based on our analysis, we also believe the Wolfcamp and Cline shales exhibit similar petrophysical attributes to other large, domestic oil and liquids-rich shale plays, such as the Eagle Ford and Bakken.

The Wolfcamp shale resource play

The Wolfcamp shale continues to be a focus of active drilling by the industry and is encountered at depths ranging from 7,000 to 9,000 feet under our Permian-Garden City acreage. We have been able to further define the gross Wolfcamp shale formation into three discernible zones: the Upper, Middle and Lower Wolfcamp. Under our Permian-Garden City acreage, each of these zones ranges in thickness between 300 and 600 feet. Based on our proprietary data and analysis, we believe we have confirmed that all three Wolfcamp zones share many similar petrophysical and production attributes.

As of December 31, 2013, we had successfully drilled and completed 40 horizontal wells in the Upper Wolfcamp, 13 horizontal wells in the Middle Wolfcamp and six horizontal wells in the Lower Wolfcamp.

Upper Wolfcamp.    As of December 31, 2013, we estimated that 80,000 net acres of our Permian-Garden City area had been de-risked for horizontal Upper Wolfcamp development. In the Upper Wolfcamp, we have identified a facies change progressing from west to east across our acreage, with the shale becoming increasingly carbonate. To date we have drilled and completed more wells in the southern third of our de-risked Upper Wolfcamp acreage, while continuing to explore and develop the entire area.

Middle and Lower Wolfcamp.    In the Middle and Lower Wolfcamp, we continue to expand our evaluation efforts across our acreage. Production from our vertical drilling program has confirmed that both the Middle and Lower Wolfcamp zones underlie the majority of our acreage. As with the Upper Wolfcamp, there appears to be a similar facies change in these zones. As of December 31, 2013, we had drilled and completed 13 horizontal wells in the Middle Wolfcamp zone and six horizontal wells in the Lower Wolfcamp zone. As of the same date we estimated that 80,000 net acres in the Middle Wolfcamp and 73,000 net acres in the Lower Wolfcamp had been de-risked for horizontal development. Through the combination of our drilling activities, the initial production results from these wells and our extensive technical database, we will continue our efforts to fully evaluate the potential of both the Middle and Lower Wolfcamp over our whole Permian-Garden City acreage position.

The Cline shale resource play

As of December 31, 2013, we estimated that 127,000 net acres of our Permian-Garden City area had been de-risked for horizontal Cline development. In 2013, we successfully drilled and completed three horizontal wells and now have a total of 37 horizontal wells in the Cline shale.

We first recognized the potential of the Cline shale in 2008, took our first Cline cores in 2009 and drilled our first horizontal well in the formation in early 2010. We are now in the horizontal development phase on this de-risked acreage. We believe the petrophysical data indicates that this is a repeatable economic resource play, and we continue to delineate and define the Cline potential on our remaining Permian-Garden City acreage. Industry activity relative to the Cline shale has also been initiated with several horizontal wells being drilled and/or permitted immediately north and east of our Permian-Garden City acreage position.

The Cline shale is encountered at a depth of 9,000 to 9,500 feet in our Permian-Garden City acreage. Our proprietary petrophysical data indicates that the Cline is a laterally extensive, high-quality, over-pressured source rock with an abundance of oil-prone organic matter and high generation potential. Cline conventional cores contain numerous vertical extension

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fractures that are partially open, significantly enhancing system permeability across the matrix. Multiple thermal maturity indices show the Cline to be in a "peak liquids" stage in the late oil to early gas/condensate window. As our drilling and data acquisition programs progress, we are beginning to define those areas that show commonality in terms of reservoir type, quality and repeatability.

Other areas

On August 1, 2013 we completed the sale of our assets in the Anadarko Basin in the Texas Panhandle and Western Oklahoma. Included in this sale were 43,450 net acres in the Central Texas Panhandle and 21,000 net acres in the eastern end of the Anadarko Basin, in Caddo, Grady and Comanche counties, Oklahoma.

New Ventures

In addition to our Permian Basin acreage, we continue to evaluate new opportunities in other areas within our core operating regions, which we refer to as our "New Ventures."

The Dalhart Basin is located on the western side of the Texas Panhandle. On December 20, 2013 we completed the sale of 37,000 net acres of our position in the Dalhart Basin. As of December 31, 2013, we held 50,000 net acres in the Dalhart Basin, which is included in New Ventures.

In addition, as of December 31, 2013, we held 29,459 net acres in other New Venture areas.

Our operations

Estimated proved reserves

Our reserves are reported in two streams: crude oil and liquids-rich natural gas. The economic value of the natural gas liquids in our natural gas is included in the wellhead natural gas price. In this Annual Report, the information with respect to our estimated proved reserves presented below has been prepared by Ryder Scott, our independent reserve engineers, in accordance with the rules and regulations of the SEC applicable to the periods presented. Our net proved reserves were estimated at 203,615 MBOE as of December 31, 2013, of which 35% were classified as proved developed reserves, and 55% are attributable to oil reserves. The following table presents summary data for each of our core operating areas as of December 31, 2013. Our estimated proved reserves as of December 31, 2013 assume our ability to fund the capital costs necessary for their development and are affected by pricing assumptions. In addition, we may not be able to raise the amounts of capital that would be necessary to drill a substantial portion of our proved undeveloped reserves. See "Item 1A. Risk Factors—Risks related to our business—Estimating reserves and future net revenues involves uncertainties. Decreases in oil and natural gas prices, or negative revisions to reserve estimates or assumptions as to future oil and natural gas prices, may lead to decreased earnings, losses or impairment of oil and natural gas assets."

		As of December 31, 2013
		Proved reserves			% of total
Area:		(MBOE)
Permian Basin		203,564			99	%
New Ventures(1)		51			1	%
Total		203,615			100	%

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(1)   Includes Dalhart Basin and other New Ventures.

    

    

    

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The following table sets forth more information regarding our estimated proved reserves as of December 31, 2013 and 2012. Ryder Scott, our independent reserve engineers, estimated 100% of our proved reserves as of December 31, 2013 and 2012. The reserve estimates as of December 31, 2013 and 2012 were prepared in accordance with the SEC's rules regarding oil and natural gas reserve reporting currently in effect. The information does not give any effect to our commodity hedges.

		As of December 31,
		2013			2012(1)
Estimated proved reserves:
Oil and condensate (MBbl)		111,498			98,141
Natural gas (MMcf)		552,702			542,946
Total estimated proved reserves (MBOE)		203,615			188,632
Proved developed producing (MBOE)		67,968			76,777
Proved developed non-producing (MBOE)		3,757			4,713
Proved undeveloped (MBOE)		131,890			107,142
Percent developed		35	%		43	%

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(1) Includes proved reserves attributable to the acreage sold in the Anadarko Basin Sale.

Technology used to establish proved reserves.    Under the SEC rules, proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs, and under existing economic conditions, operating methods and government regulations. The term "reasonable certainty" implies a high degree of confidence that the quantities of oil 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, material balance calculations or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using pore volume calculations and performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity. These wells were considered to be analogous based on production performance from the same formation and completion using similar techniques.

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 and guidelines established by the SEC, Ryder Scott, our independent reserve engineers, estimated 100% of our proved reserve information as of December 31, 2013 and 2012 included in this Annual Report. The technical persons responsible for preparing the reserves estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

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 reserves estimates. The Ryder Scott reserve report is reviewed with representatives of Ryder Scott and our internal technical staff before dissemination of the information. Additionally, our senior management reviews the Ryder Scott reserve report.

Gary B. Smallwood, our Vice President of Reservoir Modeling and Field Development Planning, is the technical person primarily responsible for overseeing the preparation of our reserves estimates. He has more than 38 years of practical experience with 30 years of this experience being in the estimation and evaluation of reserves. He has a Bachelors of Science

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degree in Chemical Engineering and is a life member in good standing of the Society of Petroleum Engineers. Mr. Smallwood reports directly to our President and Chief Operating Officer. Reserves estimates are reviewed and approved by our senior engineering staff with final approval by our President and Chief Operating Officer and certain other members of our senior management. Our senior management also reviews our independent engineers' reserves estimates and related reports with our senior reservoir engineering staff and other members of our technical staff.

Proved undeveloped reserves

Our proved undeveloped reserves, reported on a two-stream basis, increased from 107,142 MBOE as of December 31, 2012 to 131,890 MBOE as of December 31, 2013. During 2013, 5,782 MBOE of proved undeveloped reserves from 25 locations were converted to proved developed reserves. New proved undeveloped reserves of 47,643 MBOE were added during the year, with 96% coming from new horizontal Upper, Middle and Lower Wolfcamp and Cline locations. Negative revisions of 11,944 MBOE were due to the combined effect of removing 174 proved locations and the net effect of redetermining 501 undeveloped locations. The 174 locations that were removed were comprised of vertical Wolfberry and short horizontal laterals. They were replaced with longer horizontal laterals to better align with future drilling plans.

    

Estimated total future development and abandonment costs related to the development of proved undeveloped reserves as shown in our December 31, 2013 reserves report are $2.2 billion. Based on this report, the capital estimated to be spent in 2014, 2015, 2016, 2017 and 2018 to develop the proved undeveloped reserves is $359 million, $482 million, $558 million, $499 million and $232 million, respectively. All of the proved undeveloped locations are expected to be drilled within a five-year period.

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Production, revenues and price history

The following table sets forth information regarding production, revenues and realized prices and production costs for the years ended December 31, 2013, 2012 and 2011. Our reserves and production are reported in two streams: crude oil and liquids-rich natural gas. The economic value of the natural gas liquids in our liquids-rich natural gas is included in the wellhead natural gas price. 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)		2013				2012				2011
Production data:
Oil (MBbl)		5,487				4,775				3,368
Natural gas (MMcf)		34,348				39,148				31,711
Oil equivalents (MBOE)(1)		11,211				11,300				8,654
Average daily production (BOE/D)(1)		30,716				30,874				23,709
Revenues (in thousands):
Oil		$	494,676			$	414,932			$	306,481
Natural gas		$	170,168			$	168,637			$	199,774
Average sales prices without hedges:
Benchmark oil ($/Bbl)(2)		$	97.97			$	94.20			$	95.01
Realized oil ($/Bbl)(3)		$	90.16			$	86.89			$	91.00
Benchmark natural gas ($/MMBtu)(2)		$	3.65			$	2.80			$	4.02
Realized natural gas ($/Mcf)(3)		$	4.95			$	4.31			$	6.30
Average price ($/BOE)		$	59.29			$	51.65			$	58.50
Average sales prices with hedges(4):
Oil ($/Bbl)		$	88.68			$	85.59			$	88.16
Natural gas ($/Mcf)		$	4.98			$	4.92			$	6.59
Average price ($/BOE)		$	58.66			$	53.22			$	58.47
Average cost per BOE:
Lease operating expenses		$	7.06			$	5.96			$	5.00
Production and ad valorem taxes		$	3.78			$	3.33			$	3.70
Depletion, depreciation and amortization		$	20.87			$	21.33			$	20.12
General and administrative(5)		$	8.00			$	5.50			$	5.90

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(1)	The volumes presented for the years ended December 31, 2013, 2012 and 2011 are based on actual results and are not calculated using the rounded numbers in the table above.

(2)	Benchmark oil prices are the simple average of the daily settlement price for NYMEX West Texas Intermediate Light Sweet Crude Oil each month for the period indicated. Benchmark natural gas prices are the simple arithmetic average of the last day settlement price for NYMEX natural gas each month for the period indicated.

(3)	Realized crude oil and natural gas prices are the actual prices realized at the wellhead after all adjustments for natural gas liquids content, quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price at the wellhead.

(4)

Hedged prices reflect the after effect of our commodity hedging transactions on our average sales prices. Our calculation of such after effects include current period settlements of matured derivative instruments in accordance with the applicable generally accepted accounting principles in the United States of America (“GAAP”) and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to instruments settled in the period. The prices presented are based on actual results and are not calculated using the rounded numbers presented in the table above

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(5)	General and administrative includes non-cash stock-based compensation of $21.4 million, $10.1 million and $6.1 million for the years ended December 31, 2013, 2012 and 2011, respectively. Excluding stock-based compensation from the above metric results in average general and administrative cost per BOE of $6.09, $4.61 and $5.19 for the years ended December 31, 2013, 2012 and 2011, respectively.

Productive wells

The following table sets forth certain information regarding productive wells in each of our core areas as of December 31, 2013. Our wells are classified as oil wells, all of which also produce natural gas, condensate and natural gas liquids. Wells are classified as oil or gas wells according to the predominant production stream, except that a well with multiple completions is classified as an oil well if one or more of the completions is an oil completion. We only have two wells that primarily produce gas; however, they both also have completions that produce oil. 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
		Vertical			Horizontal			Total			Net
Permian Basin:
Operated Permian-Garden City		838			97			935			902			96	%
Non-Operated Permian Garden City		122			1			123			36			29	%
Operated Permian-China Grove(1)		1			1			2			2			99	%
Operated New Ventures(2)		1			—			1			1			95	%
Total		962			99			1,061			941			89	%

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(1) Located primarily in Mitchell County, Texas.

(2)  Includes Dalhart Basin and other New Ventures.

Acreage

The following table sets forth certain information regarding the developed and undeveloped acreage in which we own an interest as of December 31, 2013 for each of our core operating areas, including acreage held by production ("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:
Permian-Garden City		102,355			93,149			75,968			50,063			178,323			143,212			65	%
Permian-China Grove		478			454			74,737			58,418			75,215			58,872			1	%
New Ventures(1)		640			502			89,495			79,641			90,135			80,143			1	%
Total		103,473			94,105			240,200			188,122			343,673			282,227			33	%

_______________________________________________________________________________

(1)   Includes Dalhart Basin and other New Ventures.

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Undeveloped acreage expirations

The following table sets forth the gross and net undeveloped acreage in our core operating areas as of December 31, 2013 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.

		2014						2015						2016						2017
		Gross			Net			Gross			Net			Gross			Net			Gross			Net
Permian Basin:
Permian-Garden City		11,319			10,929			23,596			15,214			5,409			2,515			—			—
Permian-China Grove		21,734			16,692			48,318			38,083			4,686			3,643			—			—
New Ventures(1)		39,981			35,825			31,742			26,804			2,741			2,411			10,841			10,714
Total		73,034			63,446			103,656			80,101			12,836			8,569			10,841			10,714

_______________________________________________________________________________

(1)   Includes Dalhart Basin and other New Ventures.

Drilling activity

The following table summarizes our drilling activity for the years ended December 31, 2013, 2012 and 2011. 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.

		2013						2012						2011
		Gross			Net			Gross			Net			Gross			Net
Development wells:
Productive		171			127.2			199			183.2			260			233.2
Dry		—			—			—			—			—			—
Total development wells		171			127.2			199			183.2			260			233.2
Exploratory wells:
Productive		2			2.0			1			1.0			2			1.4
Dry		—			—			1			0.9			—			—
Total exploratory wells		2			2.0			2			1.9			2			1.4

Marketing and major customers

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 to a variety of purchasers under contracts ranging from one month to several years, all at market prices. We normally sell production to a relatively small number of customers, as is customary in the exploration, development and production business. We have committed a portion of our Permian crude oil production under firm transportation agreements which will enhance our ability to move our crude oil out of the Permian Basin and give us access to potentially more favorable Gulf Coast pricing.

As of December 31, 2013, we were committed to deliver the following fixed quantities of production under certain contractual arrangements that specify the delivery of a fixed and determinable quantity.

		Total			2014			2015			2016			2017 and beyond
Oil and condensate (MBbl)		100,314			6,570			9,490			11,802			72,453
Natural gas (MMcf)		70,192			1,170			3,393			4,796			60,833
Total (MBOE)		112,013			6,765			10,055			12,601			82,591

Subsequent to December 31, 2013, we entered into additional agreements to deliver fixed quantities of production. As of February 26, 2014, we were committed to deliver the following fixed quantities of production under certain contractual

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arrangements that specify the delivery of a fixed and determinable quantity.

		Total			2014			2015			2016			2017 and beyond
Oil and condensate (MBbl)		131,948			6,570			9,490			14,235			101,653
Natural gas (MMcf)		70,192			1,170			3,393			4,796			60,833
Total (MBOE)		143,646			6,765			10,055			15,034			11,791

We expect to fulfill our delivery commitments over the next three years with production from our proved reserves. We expect to fulfill our longer-term delivery commitments beyond three years primarily with our proved undeveloped reserves.

Our proved reserves have been sufficient to satisfy our delivery commitments during the three most recent years, and we expect such reserves will continue to satisfy our future commitments. However, should our proved reserves not be sufficient to satisfy our delivery commitments, we can and may use spot market purchases to fulfill the commitments.

Based on the current demand for oil and natural gas and the availability of alternate purchasers, we believe 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. For information regarding each of our customers that accounted for 10% or more of our oil and natural gas revenues during the last three calendar years, see Note I in our audited 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."

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 natural gas leases, or net profits 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 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, 2013, 33% of our leasehold 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 other companies in our industry that have greater resources than we do, especially in our focus areas. Many of these companies not only explore for and produce oil and natural gas, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive properties and exploratory locations or define, 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 development 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 we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory and producing properties.

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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 both our vertical and horizontal 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 developed non-producing and 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 (including the U.S. Bureau of Land Management on federal acreage) 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 zones, and cementing the well to create a permanent isolating barrier between the casing pipe and surrounding geological formations. It is believed that this well design effectively eliminates 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 discharge into approved disposal wells, so as to minimize the potential for impact to nearby surface water. We currently do not discharge water to the surface. We are in the process of testing recycled flowback/produced water in our fracing operations, and are evaluating the performance of the limited number of wells in which we have used this process to determine if there is any impact on productivity.

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—Water and other waste discharges and spills." 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 could prohibit projects or result in materially increased costs and additional operating restrictions or delays because of the significance of hydraulic fracturing 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, natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. The state of Texas has statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area and the pooling of crude oil and natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Additional proposals and proceedings that affect the natural gas industry are regularly considered by Congress, the states, the Environmental Protection Agency ("EPA"), Federal Energy Regulatory Commission ("FERC") and the courts. We cannot predict when or whether any such proposals may become effective.

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

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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 production of oil and natural gas

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 operations. The State of Texas has regulations governing conservation matters, including provisions for the pooling of oil and natural gas properties, including the permitting of "allocation wells," the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil 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, natural gas and natural gas liquids within its jurisdiction. Texas further regulates drilling and operating activities by requiring, among other things, permits for the drilling of wells, maintaining bonding requirements in order to drill or operate 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. State laws also govern a number of environmental and conservation matters, including the handling and disposing or discharge of waste materials, the size of drilling and spacing units or proration units and the density of wells that may be drilled, pooling of oil and natural gas properties and establishment of maximum rates of production from oil and natural gas wells. Texas further has the power to prorate production to the market demand for oil and natural gas. 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.

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, which 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 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 and joint and several liability penalties that could impose liability upon us regardless of fault. Public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the 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 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

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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 of $350 million. These liability limits may not apply if: a spill is caused by a party's gross negligence or willful misconduct; the spill resulted from 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, as amended ("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. It is possible, however, 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." Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses.

We believe that we are in substantial compliance with the requirements of CERCLA, RCRA, OPA and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations required under such laws and regulations. Although we believe that the current costs of managing our wastes as they are presently classified are reflected in our budget, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

Water and other waste discharges and spills

The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act, the Safe Drinking Water Act ("SDWA"), the OPA and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other natural gas wastes, into federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. The State of Texas also maintains groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. The underground injection of fluids is subject to permitting and other requirements under state laws and regulation. Obtaining permits has the potential to delay the development of oil and natural gas projects. These same regulatory programs also limit the total volume of water that can be discharged, hence limiting the rate of development, and require us to incur compliance costs. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages. Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and the underground injection of fluids and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as "SPCC plans," in connection with on-site storage of significant quantities of oil. We maintain all required discharge permits necessary to conduct our operations, and we believe we are in substantial compliance with their terms.

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Hydraulic fracturing is a practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. Although hydraulic fracturing has historically been regulated by state oil and gas commissions, the EPA recently asserted federal regulatory authority over the process under the SDWA's Underground Injection Control ("UIC") Program. Under this assertion of authority, the EPA requires facilities to obtain permits to use diesel fuel in hydraulic fracturing operations, specifically in Class II wells, which are those wells injecting fluids associated with oil and natural gas production activities. The U.S. Energy Policy Act of 2005, which exempts hydraulic fracturing from regulation under the SDWA, prohibits the use of diesel fuel in the fracturing process without a UIC permit. On February 12, 2014, the EPA published a revised UIC Program permitting guidance for oil and natural gas hydraulic fracturing activities using diesel fuel. The guidance document describes how Class II regulations may be tailored to address the purported unique risks of diesel fuel injection during the hydraulic fracturing process. Although the EPA is not the permitting authority for UIC Class II programs in Texas, where we maintain acreage, the EPA is encouraging state programs to review and consider use of this permit guidance. On November 3, 2011, the EPA released its Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources. The study will include both analysis of existing data and investigative activities designed to generate future data. The EPA issued a progress report in December 2012, and expects to release a draft report for public comment and peer review in 2014. In addition, legislation is pending in Congress to repeal the hydraulic fracturing exemption from the SDWA, provide for federal regulation of hydraulic fracturing, and require public disclosure of the chemicals used in the fracturing process. Finally, on October 20, 2011, the EPA announced its plan to propose federal pre-treatment standards for wastewater generated during the hydraulic fracturing process. Hydraulic fracturing stimulation requires the use of a significant volume of water with some resulting "flowback," as well as "produced water." The EPA asserts that this water may contain radioactive materials and other pollutants and, therefore, may deteriorate drinking water quality if not properly treated before discharge. The Clean Water Act prohibits the discharge of wastewater into federal or state waters. Thus, "flowback" and "produced water" must either be injected into permitted disposal wells, transported to public or private treatment facilities for treatment, or recycled. The EPA asserts that due to some contaminants in hydraulic fracturing wastewater, most treatment facilities are unable to treat the wastewater before introducing it into public waters. If adopted, the new pre-treatment rules will require shale gas operations to pre-treat wastewater before transferring it to treatment facilities. A proposed rule is expected in April 2014. We cannot predict the impact that these standards may have on our business at this time, but these standards could have a material impact on our business, financial condition and results of operation.

Some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances or otherwise require the public disclosure of chemicals used in the hydraulic fracturing process. For example, pursuant to legislation adopted by the State of Texas in June 2011, beginning February 1, 2012, companies were required to disclose to the RRC and the public the chemical components used in the hydraulic fracturing process, as well as the volume of water used. In addition to state law, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. Furthermore, on May 16, 2013, the United States Department of the Interior ("DOI") issued a revised proposed rule that seeks to require companies operating on federal and Indian lands to (i) publicly disclose the chemicals used in the hydraulic fracturing process; (ii) confirm its wells meet certain construction standards and (iii) establish site plans to manage flowback water. Under current federal law, there is no requirement for operators to disclose the use of such chemicals, although Laredo has already commenced similar disclosure with state regulators.

If these or any other new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to drill and produce from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings. In addition, if hydraulic fracturing is regulated at the federal level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. These developments, as well as new laws or regulations, could cause us to incur substantial compliance costs, and compliance or the consequences of failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the potential impact on our business that may arise if federal or state legislation governing hydraulic fracturing is enacted into law.

Air emissions

The federal Clean Air Act, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including compressor stations, through the issuance of permits and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. In August 2012, the EPA adopted rules that subject oil and natural gas production, processing, transmission, and storage operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAP, programs. The rule includes NSPS standards for completions of hydraulically fractured

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gas wells and establishes specific new requirements for emissions from compressors, controllers, dehydrators, storage vessels, natural gas processing plants and certain other equipment. The final rule seeks to achieve a 95% reduction in volatile organic compounds ("VOC") emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. These rules may require a number of modifications to our operations, including the installation of new equipment to control emissions from our wells by January 1, 2015. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. The EPA intends to issue revised rules that may be responsive to some of these requests. On September 23, 2013, the EPA finalized the portion of the rule addressing VOC emissions from storage tanks, including a phase-in period and an alternative emissions limit for older tanks. These standards, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or utilize specific equipment or technologies to control emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions.

We have incurred additional capital expenditures to insure compliance with these new regulations as they come into effect. We may also be required to incur additional capital expenditures in the next few years for air pollution control equipment in connection with maintaining or obtaining operating permits addressing other air emission related issues, which may have a material adverse effect on our operations. Obtaining permits also has the potential to delay the development of oil and natural gas projects. We believe that we currently are in substantial compliance with all air emissions regulations and that we hold all necessary and valid construction and operating permits for our current operations.

Regulation of "greenhouse gas" emissions

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as "greenhouse gases" ("GHGs") and including carbon dioxide and methane, may be contributing to warming of the earth's atmosphere and other climatic changes. In response to such studies, Congress has from time to time considered legislation to reduce emissions of GHGs. One bill approved by the House of Representatives in June 2009, known as the American Clean Energy and Security Act of 2009, would have required an 80% reduction in emissions of GHGs and almost one-half of the states have already taken legal measures to reduce emissions of GHGs through the planned development of GHG emission inventories and/or regional GHG cap and trade programs, although in recent years some states have scaled back their commitment to GHG initiatives. Most cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances corresponding with their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. Some states have enacted renewable portfolio standards, which require utilities to purchase a certain percentage of their energy from renewable fuel sources.

In addition, in December 2009, the EPA determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment, because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. In response to its endangerment finding, the EPA recently adopted two sets of rules regarding possible future regulation of GHG emissions under the Clean Air Act. The motor vehicle rule, which became effective in January 2011, purports to limit emissions of GHGs from motor vehicles. The EPA adopted the stationary source rule (or the "tailoring rule") in May 2010, and it became effective in January 2011, although on October 15, 2013, the U.S. Supreme Court granted review of certain issues related to the EPA's authority to regulate such emissions from stationary sources. Oral arguments on the issues before the Supreme Court were heard on February 24, 2014, and a decision is expected by July 2014. In September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA published a final rule expanding the GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage and distribution facilities. This rule requires reporting of GHG emissions from such facilities on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. In addition, the EPA has continued to adopt GHG regulations of other industries, such as a September 2013 proposed GHG rule that, if finalized, would set NSPS for new coal-fired and natural-gas fired power plants.

The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce.

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Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations.

Occupational Safety and Health Act

We are also subject to the requirements of the federal Occupational Safety and Health Act, as amended ("OSHA") and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA's hazard communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements.

National Environmental Policy Act

Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act ("NEPA"). NEPA requires federal agencies, including the Departments of Interior and Agriculture, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency prepares an environmental assessment to evaluate the potential direct, indirect and cumulative impacts of a proposed project. If impacts are considered significant, the agency will prepare a more detailed environmental impact study that is made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This environmental impact assessment process has the potential to delay the development of oil and natural gas projects. Authorizations under NEPA also are subject to protest, appeal or litigation, which can delay or halt projects.

Endangered Species Act

The Endangered Species Act ("ESA") was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species' habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We conduct operations on federal oil and natural gas leases in areas where certain species that are listed as threatened or endangered and where other species, such as the sage grouse, potentially could be listed as threatened or endangered under the ESA exist. The U.S. Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit land access for oil and natural gas development. If we were to have a portion of our leases designated as critical or suitable habitat, it could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas, which could adversely impact the value of our leases.

Summary

In summary, we believe we are in substantial compliance with currently applicable environmental laws and regulations. Although we have not experienced any material adverse effect from compliance with environmental requirements, there is no assurance that this will continue. We did not have any material capital or other non-recurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2012 or 2013.

Disclosures required pursuant to Section 13(r) of the Securities Exchange Act of 1934

Under the Iran Threat Reduction and Syrian Human Rights Act of 2012 (the “Act”), which added Section 13(r) of the Exchange Act, we are required to include certain disclosures in our periodic reports if we or any of our “affiliates” (as defined in Rule 12b-2 under the Exchange Act) knowingly engaged in certain specified activities, transactions or dealings relating to Iran or with certain individuals or entities targeted by United States' economic sanctions during the period covered by the report. Disclosure is generally required even where the activities, transactions or dealings were conducted in compliance with applicable law. Neither we nor any of our controlled affiliates or subsidiaries knowingly engaged in any of the specified activities relating to Iran or otherwise engaged in any activities associated with Iran during the reporting period. However, because the SEC defines the term “affiliate” broadly, it includes any entity controlled by us as well as any person or entity that controlled us or is under common control with us.

The description of the activities below has been provided to us by Warburg Pincus, affiliates of which: (i) beneficially own more than 10% of our outstanding common stock and are members of our board of directors and (ii) beneficially own more than 10% of the equity interests of, and have the right to designate members of the board of directors of, Endurance International Group (“EIG”) and Santander Asset Management Investment Holdings Limited (“SAMIH”). EIG and SAMIH may therefore be deemed to be under "common control" with us; however, this statement is not meant to be an admission that common control exists.

    

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As to EIG:

The disclosure below relates solely to activities conducted by EIG and its affiliates. The disclosure does not relate to any activities conducted by Laredo or by Warburg Pincus and does not involve our or Warburg Pincus' management. Neither Laredo nor Warburg Pincus had any involvement in or control over the disclosed activities of EIG, and neither Laredo nor Warburg Pincus has independently verified or participated in the preparation of the disclosure. Neither Laredo nor Warburg Pincus is representing as to the accuracy or completeness of the disclosure nor do we or Warburg Pincus undertake any obligation to correct or update it.

Laredo understands that EIG’s affiliates intend to disclose in their next annual or quarterly SEC report that:

“EIG's business activities are subject to various restrictions under U.S. export controls and trade and economic sanctions laws, including the U.S. Commerce Department’s Export Administration Regulations and economic and trade sanctions regulations maintained by the U.S. Treasury Department’s Office of Foreign Assets Control, or OFAC. If EIG fails to comply with these laws and regulations, EIG could be subject to civil or criminal penalties and reputational harm. In addition, if EIG's third-party resellers fail to comply with these laws and regulations in their dealings, EIG could face potential liability or penalties for violations. Furthermore, U.S. export control laws and economic sanctions laws prohibit certain transactions with U.S. embargoed or sanctioned countries, governments, persons and entities.

Although EIG takes precautions to prevent transactions with U.S. sanctions targets, EIG has in the past identified limited instances of non-compliance with these rules and believes EIG has taken appropriate corrective actions in such instances. For example, on May 1, 2013, during a routine compliance scan of EIG's new and existing subscriber accounts, EIG discovered a new subscriber account that was created on April 6, 2013 with information matching ORT France, identified by OFAC as a Specially Designated National, or SDN, under the Global Terrorism Sanctions Regulations, 31 C.F.R. Part 594. EIG had charged the subscriber $114.10 for web hosting and domain name registration services at the time the account was opened and without knowledge of any SDN issue. Upon discovery of the potential SDN match, EIG promptly suspended the subscriber account, deactivated the website, locked the domain name to prevent it from being transferred and ceased providing services to the subscriber. EIG also promptly reported the potential SDN match to OFAC. To date, EIG has not received any correspondence from OFAC regarding the matter.

Although EIG has implemented compliance measures that are designed to prevent transactions with U.S. sanction targets, there is risk that in the future EIG or its resellers could provide its solutions or services to such targets despite such compliance measures. This could result in negative consequences to EIG, including government investigations, penalties and reputational harm.

Changes in EIG's solutions or changes in export and import regulations may create delays in the introduction and sale of EIG's solutions in international markets, prevent EIG's subscribers with international operations from deploying its solutions or, in some cases, prevent the export or import of EIG's solutions to certain countries, governments or persons altogether. Any change in export or import regulations, shift in the enforcement or scope of existing regulations, or change in the countries, governments, persons or technologies targeted by such regulations, could result in decreased use of EIG's solutions or decreased ability to export or sell its solutions to existing or potential subscribers with international operations. Any decreased use of EIG's solutions or limitation on its ability to export or sell its solutions could adversely affect EIG's business, financial condition and operating results.”

As to SAMIH:

The disclosure below relates solely to activities conducted by SAMIH and its non-U.S. affiliates. The disclosure does not relate to any activities conducted by Laredo or by Warburg Pincus and does not involve our or Warburg Pincus’ management. Neither Laredo nor Warburg Pincus has had any involvement in or control over the disclosed activities of SAMIH, and neither Laredo nor Warburg Pincus has independently verified or participated in the preparation of the disclosure. Neither Laredo nor Warburg Pincus is representing to the accuracy or completeness of the disclosure nor do we or Warburg Pincus undertake any obligation to correct or update it.

Laredo understands that SAMIH’s affiliates intend to disclose in their next annual or quarterly SEC report that an Iranian national, resident in the U.K., who is currently designated by the U.S. and the U.K. under the Iran Sanctions regime, holds two investment accounts with Santander Asset Management UK Limited, a subsidiary of SAMIH and part of the Banco Santander group. The accounts have remained frozen throughout 2013. The investment returns are being automatically reinvested, and no disbursements have been made to the customer. Total revenue in connection with the investment accounts in 2013 was £247 and net profits in 2013 were negligible relative to the overall profits of Banco Santander, S.A.

Employees

As of December 31, 2013, we had 340 full-time employees. We also employed a total of 31 contract personnel who assist our full-time employees with respect to specific tasks and perform various field and other services. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective

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bargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees to be satisfactory.

Our offices

Our executive offices are located at 15 W. Sixth Street, Suite 1800, Tulsa, Oklahoma 74119, and the phone number at this address is (918) 513-4570. We also lease corporate offices in Midland and Dallas, Texas.

Available information

We are required to file annual, quarterly and current reports, proxy statements and other information with the SEC. You may read and copy any documents filed by us with the SEC at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Our filings with the SEC are also available to the public from commercial document retrieval services and at the SEC's website at http://www.sec.gov.

Our common stock is listed and traded on the New York Stock Exchange under the symbol "LPI." Our reports, proxy statements and other information filed with the SEC can also be inspected and copied at the New York Stock Exchange, 20 Broad Street, New York, New York 10005.

We also make available on our website (http://www.laredopetro.com) all of the documents that we file with the SEC, free of charge, as soon as reasonably practicable after we electronically file such material with the SEC. Our Code of Conduct and Business Ethics, Code of Ethics For Senior Financial Officers, Corporate Governance Guidelines and the charters of our audit committee, compensation committee and nominating and corporate governance committee are also available on our website and in print free of charge to any stockholder who requests them. Requests should be sent by mail to our corporate secretary at our executive office at 15 W. Sixth Street, Suite 1800, Tulsa, Oklahoma 74119. Information contained on our website is not incorporated by reference into this Annual Report. We intend to disclose on our website any amendments or waivers to our Code of Ethics that are required to be disclosed pursuant to Item 5.05 of Form 8-K.

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Item 1A.    Risk Factors

     Our business involves a high degree of risk. If any of the following risks, or any risks described elsewhere in this Annual Report, were actually to occur, our business, financial condition or results of operations could be materially adversely affected and the trading price of our shares could decline resulting in the loss of part or all of your investment. The risks described below are not the only ones facing us. Additional risks not presently known to us or which we currently consider immaterial may also adversely affect us.

Risks related to our business

Oil and natural gas prices are volatile. A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The prices we receive for our oil and natural gas production heavily influence our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities, and therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the market for oil and natural gas has been volatile. This market will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:

•	worldwide and regional economic and financial conditions impacting the global supply and demand for oil and natural gas;

•	the price and quantity of imports of foreign oil and natural gas, including liquefied natural gas;

•	political conditions in or affecting other oil and natural gas-producing countries, including the current conflicts in the Middle East, and conditions in South America, Africa and Russia;

•	the level of global oil and natural gas exploration and production;

•	future regulations prohibiting or restricting our ability to apply hydraulic fracturing to our wells;

•	the level of global oil and natural gas inventories;

•	prevailing prices on local oil and natural gas price indexes in the areas in which we operate;

•	localized and global supply and demand fundamentals and transportation availability;

•	weather conditions;

•	technological advances affecting energy consumption;

•	the price and availability of alternative fuels; and

•	domestic, local and foreign governmental regulation and taxes.

Lower oil and natural gas prices will reduce our cash flows and borrowing ability. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our oil and natural gas reserves as existing reserves are depleted. Substantial decreases in oil and natural gas prices could render uneconomic a significant portion of our exploration, development and exploitation projects. This may result in our having to make significant downward adjustments to our estimated proved reserves. As a result, a substantial or extended decline in oil and natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

Our business requires significant capital expenditures and we may be unable to obtain needed capital or financing on satisfactory terms or at all.

Our exploration, development and acquisition activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flows from operations, capital contributions, borrowings on our Senior Secured Credit Facility, equity offerings and proceeds from our senior unsecured notes. We do not have commitments from anyone to contribute capital to us. Future cash flows are subject to a number of variables, including the level of production from existing wells, prices of oil and natural gas and our success in developing and producing new reserves. If our cash flow from operations is not sufficient to fund our capital expenditure budget, we may have limited ability to obtain the additional capital necessary to sustain our operations at current levels. We may not be able to obtain debt or equity financing on terms favorable to us or at all. The failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to a decline in our oil and natural gas production or reserves and, in some areas, a loss of properties.

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Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our future financial condition and results of operations will depend on the success of our exploration, exploitation, development and production activities. Our oil and natural gas exploration, exploitation, development and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and natural gas production. Our decisions to purchase, explore, develop or otherwise exploit locations or properties will depend in part on the evaluation of information obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see "—Estimating reserves and future net revenues involves uncertainties. Decreases in oil and natural gas prices, or negative revisions to reserves estimates or assumptions as to future oil and natural gas prices, may lead to decreased earnings, losses or impairment of oil and natural gas assets." In addition, our cost of drilling, completing and operating wells is often uncertain before drilling commences. Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

•	delays imposed by or resulting from compliance with regulatory and contractual requirements and related lawsuits, which may include limitations on hydraulic fracturing or the discharge of greenhouse gases;

•	pressure or irregularities in geological formations;

•	shortages of or delays in obtaining equipment and qualified personnel;

•	equipment failures or accidents;

•	fires and blowouts;

•	adverse weather conditions, such as hurricanes, blizzards and ice storms;

•	declines in oil and natural gas prices;

•	limited availability of financing at acceptable rates;

•	title problems; and

•	limitations in the market for oil and natural gas.

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.

Hydraulic fracturing is a practice that is used to stimulate production of oil and/or natural gas from tight formations. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. Nearly all of our proved non-producing and proved undeveloped reserves associated with future drilling, recompletion and refracture stimulation projects require hydraulic fracturing. If we are unable to apply hydraulic fracturing to our wells or the process is prohibited or significantly regulated or restricted, we would lose the ability to (i) drill and complete the projects for such proved reserves and (ii) maintain the associated acreage, which would have a material adverse effect on our future business, financial condition, operating results and prospects.

The process is typically regulated by state oil and gas commissions. The U.S. Environmental Protection Agency (the "EPA"), however, recently asserted federal regulatory authority over hydraulic fracturing under the federal Safe Drinking Water Act's ("SDWA") Underground Injection Control ("UIC") Program. Under this assertion of authority, the EPA requires facilities to obtain permits to use diesel fuel in hydraulic fracturing operations. The U.S. Energy Policy Act of 2005, which exempts hydraulic fracturing from regulation under the SDWA, prohibits the use of diesel fuel in the fracturing process without a UIC permit. On February 12, 2014, the EPA published a revised UIC Program guidance for oil and natural gas hydraulic fracturing activities using diesel fuel. The guidance document describes how regulations of Class II wells, which are those wells injecting fluids associated with oil and natural gas production activities, may be tailored to address the purported unique risks of diesel fuel injection during the hydraulic fracturing process. Although the EPA is not the permitting authority for UIC Class II programs in Texas, where we maintain acreage, the EPA is encouraging state programs to review and consider use of the above-mentioned draft guidance. On November 3, 2011, the EPA released its Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources. The study will include both analysis of existing data and investigative activities designed to generate future data. The EPA issued a progress report in December 2012, held several technical workshops during 2013, and expects to release a draft report for public comment and peer review in 2014.

In August 2012, the EPA adopted rules that subject oil and natural gas production, processing, transmission, and storage operations to regulation under the New Source Performance Standards ("NSPS") and National Emission Standards for

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Hazardous Air Pollutants ("NESHAP") programs. The rule includes NSPS standards for completions of hydraulically fractured gas wells and establishes specific new requirements for emissions from compressors, controllers, dehydrators, storage vessels, natural gas processing plants and certain other equipment. The final rule became effective October 15, 2012; however, a number of the requirements did not take immediate effect. The rule established a phase-in period to allow for the manufacture and distribution of required emissions reduction technology. During the first phase, ending December 31, 2014, owners and operators of gas wells must either flare their emissions or use emissions reduction technology called "green completions" technologies already deployed at wells. On or after January 1, 2015, all newly fractured gas wells will be required to use green completions. Controls for certain storage vessels and pneumatic controllers may phase-in over one year beginning August 16, 2012, while certain compressors, dehydrators and other equipment must comply with the final rule immediately or up to three years and 60 days after the August 16, 2012 publication of the final rule, depending on the construction date and/or nature of the unit. We continue to evaluate the EPA's final rule, as it may require changes to our operations, including the installation of new emissions control equipment. Furthermore, with respect to our operations that occur on federally managed public lands, on May 16, 2013, the United States Department of the Interior ("DOI") issued a revised proposed rule that seeks to require companies operating on federal and Indian lands to (i) publicly disclose the chemicals used in the hydraulic fracturing process; (ii) confirm their wells meet certain construction standards and (iii) establish site plans to manage flowback water. The revised proposed rule is presently subject to an extended 90-day public comment period, which ends on August 23, 2013. DOI is expected to issue a final rule in 2014. Under current federal law, there is no requirement for operators to disclose the use of such chemicals, although we have already commenced similar disclosure with state regulators. In addition, legislation is pending in Congress to repeal the hydraulic fracturing exemption from the SDWA, provide for federal regulation of hydraulic fracturing, and require public disclosure of the chemicals used in the fracturing process. Finally, on October 20, 2011, the EPA announced its plan to propose federal pre-treatment standards for wastewater generated during the hydraulic fracturing process. Hydraulic fracturing stimulation requires the use of a significant volume of water with some resulting "flowback," as well as "produced water." The EPA asserts that this water may contain radioactive materials and other pollutants and, therefore, may deteriorate drinking water quality if not properly treated before discharge. The Clean Water Act prohibits the discharge of wastewater into federal or state waters. Thus, "flowback" and "produced water" must either be injected into permitted disposal wells or transported to public or private treatment facilities for treatment, or recycled. The EPA asserts that due to some contaminants in hydraulic fracturing wastewater, most treatment facilities are unable to properly treat the wastewater before introducing it into public waters. If adopted, the new pre-treatment rules will require shale gas operations to pre-treat wastewater before transferring it to treatment facilities. A proposed rule is expected in April 2014.

Some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances or otherwise require the public disclosure of chemicals used in the hydraulic fracturing process. For example, pursuant to legislation adopted by the State of Texas in June 2011, the chemical components used in the hydraulic fracturing process, as well as the volume of water used, must be disclosed to the Railroad Commission of Texas (“RRC”) and the public beginning February 1, 2012. Furthermore, on May 23, 2013, the RRC issued the “well integrity rule,” which updates the RRC's Rule 13 requirements for drilling, putting pipe down and cementing wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit to the RRC cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The “well integrity rule” takes effect in January 2014. In addition to state law, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular.

Studies have been commissioned to determine if the use of water disposal wells increases the likelihood, frequency and/or severity of seismic activity. Water disposal wells are used to store the water produced during the drilling and production activities of our wells.

If these or any other new laws or regulations that significantly restrict hydraulic fracturing are adopted or laws or regulations are adopted to restrict water disposal wells, such laws could make it more difficult or costly for us to drill and produce from conventional or tight formations as well as make it easier for third parties opposing the oil and natural gas industry to initiate legal proceedings. In addition, if these matters are regulated at the federal level, fracturing and disposal activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. These developments, as well as new laws or regulations, could cause us to incur substantial compliance costs, and compliance or the consequences of failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the potential impact on our business that may arise if federal or state legislation governing hydraulic fracturing or water disposal wells are enacted into law.

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If we are unable to drill new allocation wells it could have a material adverse impact on our future production results.

In the State of Texas, “allocation wells” allow an oil and gas producer to drill a horizontal well under two or more leaseholds that are owned by the producer. We are active in drilling and producing allocation wells. The RRC has not provided definitive rules on the allocation well permitting process. If the RRC denies or significantly delays the permitting of allocation wells, it could have an adverse impact on our ability to drill long horizontal lateral wells on some of our leases, which in turn could have a material adverse impact on our anticipated future production.

Estimating reserves and future net revenues involves uncertainties. Decreases in oil and natural gas prices, or negative revisions to reserve estimates or assumptions as to future oil and natural gas prices, may lead to decreased earnings, losses or impairment of oil and natural gas assets.

The reserve data included in this Annual Report represent estimates. Reserves estimation is a subjective process of evaluating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Reserves that are "proved reserves" are those estimated quantities of oil and natural gas that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions and that relate to projects for which the extraction of hydrocarbons must have commenced or the operator must be reasonably certain will commence within a reasonable time.    

The estimation process relies on interpretations of available geological, geophysical, engineering and production data. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of developmental expenditures, including many factors beyond the control of the producer. In addition, the estimates of future net revenues from our proved reserves and the present value of such estimates are based upon certain assumptions about future production levels, prices and costs that may not prove to be correct. Further, initial production rates reported by us or other operators may not be indicative of future or long-term production rates. A production decline may be rapid and irregular when compared to a well's initial production.

Quantities of proved reserves are estimated based on economic conditions in existence during the period of assessment. Changes to oil and natural gas prices in the markets for such commodities may have the impact of shortening the economic lives of certain fields because it becomes uneconomic to produce all recoverable reserves on such fields, which reduces proved property reserves estimates. Negative revisions of 11,944 MBOE were due to the combined effect of removing 174 proved locations and the net effect of redetermining 501 undeveloped locations. The 174 locations that were removed were comprised of vertical Wolfberry and short horizontal laterals. They were replaced with longer horizontal laterals to better align with future drilling plans

Negative revisions in the estimated quantities of proved reserves have the effect of increasing the rates of depletion on the affected properties, which decrease earnings or result in losses through higher depletion expense. These revisions, as well as revisions in the assumptions of future cash flows of these reserves, may also trigger impairment losses on certain properties, which would result in a non-cash charge to earnings. See Note P.4 in our audited consolidated financial statements included elsewhere in this Annual Report.

The potential drilling locations for our future wells that we have tentatively identified are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling, which in certain instances could prevent production prior to the expiration date of leases for such locations. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill a substantial portion of our identified potential drilling locations.

Although our management team has scheduled certain potential drilling locations as an estimation of our future multi-year drilling activities on our existing acreage, our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, the availability of drilling services and equipment, drilling results (including the impact of increased horizontal drilling and longer laterals), lease expirations, gathering systems, marketing and pipeline transportation constraints, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the numerous potential drilling locations we have currently identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently anticipated.

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Our producing properties are in a concentrated geographic area, making us vulnerable to risks associated with operating in one major geographic area.

Our producing properties are geographically concentrated in the Permian Basin. At December 31, 2013, substantially all of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, water shortages or other drought-related conditions or interruption of the processing or transportation of oil or natural gas.

Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Oil and natural gas operations in our operating areas can be adversely affected by seasonal weather conditions and lease stipulations designed to protect various wildlife. This limits our ability to operate in those areas and can later intensify competition during certain months for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. In addition, the Permian Basin has recently experienced severe winter weather and, as a consequence, our operating results during similar periods may ultimately be adversely affected.

If commodity prices decrease, we may be required to take write-downs of the carrying values of our properties.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. A write-down constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken. See Note B.8 to our audited consolidated financial statements included elsewhere in this Annual Report for additional information.

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

The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of transportation facilities owned by third parties. We do not control many of the trucks and other third-party transportation facilities necessary for the transportation of our product and our access to them may be limited or denied. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of our or third-party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, we may be required to shut in or curtail production. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, would materially and adversely affect our financial condition and results of operations.

Our oil and natural gas is sold to a limited number of geographic markets so an oversupply in any of those areas could have a material negative effect on the price we receive.

Our oil and natural gas is sold to a limited number of geographic markets which each have a fixed amount of storage and processing capacity. As a result, if such markets become oversupplied with oil and/or natural gas it could have a material negative effect on the price we receive for our products and therefore an adverse effect on our financial condition. The current United States restrictions on the export of oil and natural gas increase the possibility of an oversupply in any of the markets into which we sell our products.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploration, development and exploitation activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future oil and natural gas reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely

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affected.

Currently, we receive incremental cash flows as a result of our hedging activity. To the extent we are unable to obtain future hedges at effective prices consistent with those we have received to date and oil and natural gas prices do not improve, our cash flows and financial condition may be adversely impacted.

To achieve more predictable cash flows and reduce our exposure to downward price fluctuations, as of December 31, 2013, we have entered into hedge contracts for 14.5 million Bbls of our projected crude oil production and 17.8 million MMBtu of our projected natural gas production for settlement between January 2014 and December 2016. If we are unable to enter into new hedge contracts in the future at favorable pricing and for a sufficient amount of our production, our financial condition and results of operations could be materially adversely affected. For additional information regarding our hedging activities, please see "Item 7. Management's discussion and analysis of financial condition and results of operations—Results of operations—Commodity derivatives."

Our derivative activities could result in financial losses or could reduce our earnings.

To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we enter into derivative instrument contracts for a portion of our oil and natural gas production, including swaps, collars, puts and basis swaps. In accordance with applicable accounting principles, we are required to record our derivatives at fair market value, and they are included on our consolidated balance sheet as assets or liabilities and in our consolidated statement of operation gain (loss) on derivatives. Losses on derivatives are included in our cash flows from operating activities. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair market value of our derivative instruments. Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:

•	production is less than the volume covered by the derivative instruments;

•	the counter-party to the derivative instrument defaults on its contractual obligations;

•	there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or

•	there are issues with regard to legal enforceability of such instruments.

In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for oil and natural gas, which could also have a material adverse effect on our financial condition.

The inability of our significant customers to meet their obligations to us may materially adversely affect our financial results.

In addition to credit risk related to receivables from commodity derivative contracts, our principal exposure to credit risk is through net joint operations receivables ($16.6 million as of December 31, 2013) and the sale of our oil and natural gas production ($57.6 million in receivables as of December 31, 2013), which we market to energy marketing companies, refineries and affiliates. Joint interest receivables arise from billing entities who own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We are generally unable to control which co-owners participate in our wells. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. The largest purchaser of our oil and natural gas accounted for 28.3% of our total oil and natural gas revenues for the year ended December 31, 2013. We do not require our customers to post collateral. The inability or failure of our significant customers or joint working interest owners to meet their obligations to us or their insolvency or liquidation may materially adversely affect our financial results.

We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

•	environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;

•	abnormally pressured formations;

•	mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;

•	fires, explosions and ruptures of pipelines;

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•	personal injuries and death;

•	natural disasters; and

•	terrorist attacks targeting oil and natural gas related facilities and infrastructure.

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:

•	injury or loss of life;

•	damage to and destruction of property, natural resources and equipment;

•	pollution and other environmental damage and associated clean-up responsibilities;

•	regulatory investigations, penalties or other sanctions;

•	suspension of our operations; and

•	repair and remediation costs.

We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

Locations that we decide to drill may not yield oil or natural gas in commercially viable quantities.

Locations that we decide to drill that do not yield oil or natural gas in commercially viable quantities will adversely affect our results of operations and financial condition. In this Annual Report, we describe some of our current drilling locations and our plans to explore those drilling locations. Our drilling locations are in various stages of evaluation, ranging from those that are ready to drill to those that will require substantial additional seismic data processing and interpretation before a decision can be made to proceed with the drilling of such locations. There is no way to predict in advance of drilling and testing whether any particular drilling location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored locations or producing fields will result in successfully locating oil or natural gas in commercial quantities on our prospective acreage.

Our use of 2D and 3D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2D and 3D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable geoscientists to know whether hydrocarbons are, in fact, present in those structures or the amount of hydrocarbons. We employ 3D seismic technology with respect to certain of our projects. The implementation and practical use of 3D seismic technology is relatively unproven, which can lessen its effectiveness, at least in the near term, and increase our costs. In addition, the use of 3D seismic and other advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur greater drilling and exploration expenses as a result of such expenditures, which may result in a reduction in our returns. As a result, our drilling activities may not be successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline.

We often gather 3D seismic data over large areas. Our interpretation of seismic data delineates those portions of an area that we believe are desirable for drilling. Therefore, we may choose not to acquire option or lease rights prior to acquiring seismic data, and in many cases, we may identify hydrocarbon indicators before seeking option or lease rights in the location. If we are not able to lease those locations on acceptable terms, we will have made substantial expenditures to acquire and analyze 3D data without having an opportunity to attempt to benefit from those expenditures.

Market conditions, the unavailability of satisfactory oil and natural gas gathering, processing or transportation arrangements or operational impediments may adversely affect our access to oil, natural gas and natural gas liquids markets or delay our production.

The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines, trucking and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, trucking and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms

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could materially harm our business. We may be required to shut in wells due to lack of a market or inadequacy or unavailability of oil and natural gas pipeline, trucking, gathering system or processing capacity. In addition, if oil or natural gas quality specifications for the third-party oil or natural gas pipelines with which we connect change so as to restrict our ability to transport oil or natural gas, our access to oil and natural gas markets could be impeded. If our production becomes shut in for any of these or other reasons, we would be unable to realize revenue from those wells until other arrangements were made to deliver the products to market.

Our operations are substantially dependent on the availability, use and disposal of water. Restrictions on our ability to obtain or dispose of water may have an adverse effect on our operations, cash flow and financial condition.

Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners and other sources for use in our operations. During the past several years, Texas has experienced the lowest inflows of water in recent history. As a result of this severe drought, some local water districts may begin restricting the use of water subject to their jurisdiction for drilling and hydraulic fracturing in order to protect the local water supply. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and natural gas, which could have an adverse effect on our results of operations, cash flows and financial condition.

Additionally, our drilling procedures produce large volumes of water that we must properly dispose. If we are unable, due to government regulations or otherwise, to dispose of our water or face increased costs and procedures for disposal, it could have an adverse effect on our results of operations, cash flows and financial condition.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.

Our oil and natural gas exploration, production and gathering operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Such costs could have a material adverse effect on our business, financial condition and results of operations. Failure to comply with laws and regulations applicable to our operations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition and results of operations.

See "Item 1. Business—Regulation of the oil and natural gas industry" for a further description of the laws and regulations that affect us.

Our operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to our business activities.

We may incur significant delays, costs and liabilities as a result of federal, state and local environmental, health and safety requirements applicable to our exploration, development and production activities. These laws and regulations may require us to obtain a variety of permits or other authorizations governing our air emissions, water discharges, waste disposal or other environmental impacts associated with drilling, production and transporting product pipelines or other operations; regulate the sourcing and disposal of water used in the drilling, fracturing and completion processes; limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas; require remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; and/or impose substantial liabilities for spills, pollution or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of oil or natural gas production. These laws and regulations are complex, change frequently and have tended to become increasingly stringent over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations.

Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. In addition, accidental spills or releases from our operations could expose us to significant

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liabilities under environmental laws. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.

See "Item 1. Business—Regulation of environmental and occupational health and safety matters" for a further description of the laws and regulations that affect us.

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services as well as fees for the cancellation of such services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.

The demand for and availability of qualified and experienced personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling and workover rigs, pipe and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. In particular, the high level of drilling activity in the Permian Basin has resulted in equipment shortages in those areas. We committed to several short-term drilling contracts with various third parties in order to complete various drilling projects. An early termination clause in these contracts requires us to pay significant penalties to the third party should we cease drilling efforts. These penalties could significantly impact our financial statements upon contract termination. As a result of these commitments, $1.6 million in stacked rig fees were incurred in 2009. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. The shortages as well as rig related fees could result in delays or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

Section 1(b) of the Natural Gas Act of 1938 (the "NGA") exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission ("FERC"). We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish whether a pipeline performs a gathering function and therefore is exempt from the FERC's jurisdiction under the NGA. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is a fact-based determination. The classification of facilities as unregulated gathering is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress, which could cause our revenues to decline and operating expenses to increase and may materially adversely affect our business, financial condition or results of operations. In addition, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability, which could have a material adverse effect on our business, financial condition or results of operations.

The adoption of climate change legislation or regulations restricting emissions of "greenhouse gases" could result in increased operating costs and reduced demand for the oil and natural gas we produce.

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as "greenhouse gases" ("GHGs"), including carbon dioxide and methane, may be contributing to warming of the earth's atmosphere and other climatic changes. In response to such studies, Congress has from time to time considered legislation to reduce emissions of GHGs. One bill approved by the House of Representatives in June 2009, known as the American Clean Energy and Security Act of 2009, would have required an 80% reduction in emissions of GHGs and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, through the planned development of GHG emission inventories and/or regional GHG cap and trade programs or other mechanisms. Most cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances corresponding with their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. Some states have enacted renewable portfolio standards, which require utilities to purchase a certain percentage of their energy from renewable fuel sources.

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In addition, in December 2009, the EPA determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment, because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. In response to its endangerment finding, the EPA recently adopted two sets of rules regarding possible future regulation of GHG emissions under the Clean Air Act. The motor vehicle rule, which became effective in January 2011, purports to limit emissions of GHGs from motor vehicles. The EPA adopted the stationary source rule (or the "tailoring rule") in May 2010, and it became effective in January 2011, although on October 15, 2013, the U.S. Supreme Court granted review of certain issues related to the EPA's authority to regulate such emissions from stationary sources. Oral arguments on the issues before the Supreme Court were heard on February 24, 2014 and a decision is expected by July 2014. In September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA published a final rule expanding the GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage and distribution facilities. This rule requires reporting of GHG emissions from such facilities on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. In addition, the EPA has continued to adopt GHG regulations of other industries, such as a September 2013 proposed GHG rule that, if finalized, would set NSPS for new coal-fired and natural-gas fired power plants.

The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations.

The derivatives reform legislation adopted by the U.S. Congress could have a negative impact on our ability to hedge risks associated with our business.

In 2010, Congress adopted the Dodd Frank Wall Street Reform and Consumer Protection Act (the “Dodd Frank Act”), which, among other matters, provides for federal oversight of the over-the-counter derivatives market and entities that participate in that market. The Dodd Frank Act mandates that the Commodity Futures Trading Commission (“CFTC”) adopt rules and regulations implementing the Dodd Frank Act and further define certain terms used in the Dodd Frank Act. The Dodd Frank Act also requires the CFTC and the banking regulators to establish margin requirements for uncleared swaps. Although there is an exception from swap clearing and trade execution requirements for commercial end users that meet certain conditions (the “End User Exception”), certain market participants, including most if not all of our counterparties, will also be required to clear many of their swap transactions with entities that do not satisfy the End User Exception and will have to transact many of their swaps on swap execution facilities or designated contract markets, rather than over-the-counter on a bilateral basis. These requirements may increase the cost to our counterparties of hedging the swap positions they enter into with us, and thus may increase the cost to us of entering into our hedges. The changes in the regulation of swaps may result in certain market participants deciding to curtail or cease their derivatives activities. While many regulations have been promulgated and are already in effect, the rulemaking and implementation process is still ongoing, and the ultimate effect of the adopted rules and regulations and any future rules and regulations on our business remains uncertain.

A rule adopted under the Dodd Frank Act imposing position limits in respect of transactions involving certain commodities, including oil and natural gas, was vacated and remanded to the CFTC for further proceedings by order of the United States District Court for the District of Columbia, U.S. District Judge Robert L. Wilkins on September 28, 2012. The CFTC appealed this decision and on November 5, 2013, filed a consensual motion to dismiss its appeal. The same day, the CFTC proposed a new position limits rule which would limit trading in NYMEX contracts for Henry Hub Natural Gas, Light Sweet Crude Oil, New York Harbor Ultra Low Sulfur No. 2 Diesel and Reformulated Blendstock for Oxygen Blending Gasoline and other futures and swap contracts that are economically equivalent to such NYMEX contracts. Comments on the proposed rule were due on February 10, 2014. We cannot predict whether or when the proposed rule will be adopted or the effect of the proposed rule on our business. The Dodd Frank Act, the rules already promulgated thereunder and the proposed rule, if adopted, could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our potential exposure to less creditworthy counterparties. In addition, the Dodd Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity contracts related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd Frank Act and regulations is to lower commodity prices. If we reduce our use of derivatives or commodity prices decline as a result of the Dodd Frank Act and

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regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and our results of operations. Any of these consequences could have a material and adverse effect on our business, financial condition and results of operations.

Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas and secure trained personnel.

Our ability to acquire additional locations and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry, especially in our focus areas. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and exploratory locations and to evaluate, bid for and purchase a greater number of properties and locations than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.

Technological advancements and trends in our industry affect the demand for certain types of equipment.

Technological advancements and trends in our industry affect the demand for certain types of equipment. During 2013, the demand for traditional drilling rigs in vertical markets has softened due to increased demand for drilling rigs that are able to drill horizontally. In addition, oil and gas exploration and production companies have increased the use of "pad drilling" in recent years whereby a series of horizontal wells are drilled in succession by walking or skidding a drilling rig at a single-site location. As a result, the demand for rigs capable of carrying out pad drilling techniques has increased. If we are unable to secure such rigs in a timely or cost-efficient manner it could have a material adverse effect on our business.

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

We depend on the services of our senior management and technical personnel. The loss of the services of our senior management or technical personnel, including Randy A. Foutch, our Chairman and Chief Executive Officer, could have a material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.

A significant reduction by Warburg Pincus of its ownership interest in us could adversely affect us.

Warburg Pincus is our largest stockholder and two members of our board of directors are affiliates of Warburg Pincus. As of December 31, 2013, Warburg Pincus owned 49.1% of our outstanding common stock. We believe that Warburg Pincus' substantial ownership interest in us provides them with an economic incentive to assist us to be successful. However, Warburg Pincus is not obligated to maintain its ownership interest in us and may elect at any time to sell all or a substantial portion of or otherwise reduce its ownership interest in us. If Warburg Pincus sells all or a substantial portion of its ownership interest in us, Warburg Pincus may have less incentive to assist in our success and its affiliates that are members of our board of directors may resign. Such actions could adversely affect our ability to successfully implement our business strategies which could adversely affect our cash flows or results of operations.

We have limited control over activities on properties we do not operate, which could materially reduce our production and revenues.

A portion of our business activities is conducted through joint operating agreements under which we own partial interests in oil and natural gas properties. If we do not operate the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of the underlying properties. The failure of an operator of our wells to adequately perform operations or an operator's breach of the applicable agreements could materially reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others, therefore, depends upon a number of factors outside of our control, including the operator's timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology. Because we do not have a majority interest in most wells that we do not operate, we may not be in a position to remove the operator in the event of poor performance.

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We are involved as a passive minority-interest partner in joint ventures and are subject to risks associated with joint venture partnerships.

We are involved as a passive minority-interest partner in joint venture relationships and may initiate future joint venture projects. Entering into a joint venture as a passive minority-interest partner involves certain risks which include: the need to contribute funds to the joint venture to support its operating and capital needs; the inability to exercise voting control over the joint venture; economic or business interests which are not aligned with our venture partners, including the holding period and timing of ultimate sale of the ventures' underlying assets; and the inability for the venture partner to fulfill its commitments and obligations due to financial or other difficulties.

Increases in interest rates could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce our cash flow available for drilling and place us at a competitive disadvantage. For example, as of February 26, 2014 we have $812.5 million of borrowing capacity on our Senior Secured Credit Facility, subject to compliance with financial covenants. The impact of a 1.0% increase in interest rates on an assumed borrowing of the full $812.5 million available on our Senior Secured Credit Facility would result in increased annual interest expense of $8.1 million and a decrease in our net income before income taxes. Recent and continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in our cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

We may be subject to risks in connection with acquisitions of properties.

The successful acquisition of producing properties requires an assessment of several factors, including:

•	recoverable reserves;

•	future oil and natural gas prices and their applicable differentials;

•	operating costs; and

•	potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain. Our assessment will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an "as is" basis. Even in those circumstances in which we have contractual indemnification rights for pre-closing liabilities, it remains possible that the seller will not be able to fulfill its contractual obligations. Problems with properties we acquire could have a material adverse effect on our business, financial condition and results of operations.

We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.

In the future we may make acquisitions of businesses that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.

The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to incorporate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

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We have incurred losses from operations for various periods since our inception and may do so in the future.

We incurred net losses from our inception to December 31, 2006 of $1.8 million and for each of the years ended December 31, 2007, 2008 and 2009 of $6.1 million, $192.0 million and $184.5 million, respectively. Our financial statements include deferred tax assets, which require management's judgment when evaluating whether they will be realized. Our development of and participation in an increasingly larger number of locations has required and will continue to require substantial capital expenditures. The uncertainty and factors described throughout this section may impede our ability to economically find, develop, exploit and acquire oil and natural gas reserves and realize our deferred tax assets. As a result, we may not be able to achieve or sustain profitability or positive cash flows from operating activities in the future. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical accounting policies and estimates."

The inability of one or more of our customers to meet their obligations may adversely affect our financial results.

Substantially all of our accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the energy industry. As of December 31, 2013, the Company had two customers accounting for 36.0% and approximately 15.7% of oil and natural gas sales accounts receivable. As of December 31, 2013, we had four customers whose joint operations accounts receivable accounted for 16.0%, 14.1%, 13.1% and 10.9% of our total joint operations accounts receivable. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our oil and natural gas hedging arrangements expose us to credit risk in the event of nonperformance by counterparties. Current economic circumstances may further increase these risks.

We require a significant amount of cash to service our indebtedness. Our ability to generate cash depends on many factors beyond our control.

Our ability to make payments on and to refinance our indebtedness and to fund planned capital expenditures depends on our ability to generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. We cannot assure you that we will generate sufficient cash flow from operations or that future funding will be available to us under our Senior Secured Credit Facility, equity offerings or other actions in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs. We may need to refinance all or a portion of our indebtedness at or before maturity. We cannot assure you that we will be able to refinance any of our indebtedness on commercially reasonable terms or at all.

We may incur significant additional amounts of debt.

As of February 26, 2014, we had total long-term indebtedness of $1.5 billion. In addition, we may be able to incur substantial additional indebtedness, including secured indebtedness, in the future. The restrictions on the incurrence of additional indebtedness contained in the indentures governing our senior unsecured notes and in our Senior Secured Credit Facility are subject to a number of significant qualifications and exceptions, and under certain circumstances, the amount of indebtedness that could be incurred in compliance with these restrictions could be substantial. If new debt is added to our existing debt levels, the related risks that we face would increase and may make it more difficult to satisfy our existing financial obligations. In addition, the restrictions on the incurrence of additional indebtedness contained in the indentures governing the senior unsecured notes apply only to debt that constitutes indebtedness under the indentures.

Our debt agreements contain restrictions that will limit our flexibility in operating our business.

Our Senior Secured Credit Facility and the indentures governing our senior unsecured notes each contain, and any future indebtedness we incur may contain, various covenants that limit our ability to engage in specified types of transactions. These covenants limit our ability to, among other things:

•	incur additional indebtedness;

•	pay dividends on, repurchase or make distributions in respect of our capital stock or make other restricted payments;

•	make certain investments;

•	sell certain assets;

•	create liens;

•	consolidate, merge, sell or otherwise dispose of all or substantially all of our assets; and

•	enter into certain transactions with our affiliates.

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As a result of these covenants, we are limited in the manner in which we may conduct our business and we may be unable to engage in favorable business activities or finance future operations or our capital needs. In addition, the covenants in our Senior Secured Credit Facility require us to maintain a minimum working capital ratio and minimum interest coverage ratio and also limit our capital expenditures. A breach of any of these covenants could result in a default under one or more of these agreements, including as a result of cross default provisions and, in the case of our Senior Secured Credit Facility, permit the lenders to cease making loans to us. Upon the occurrence of an event of default under our Senior Secured Credit Facility, the lenders could elect to declare all amounts outstanding under our Senior Secured Credit Facility to be immediately due and payable and terminate all commitments to extend further credit. Such actions by those lenders could cause cross defaults under our other indebtedness, including the senior unsecured notes. If we were unable to repay those amounts, the lenders under our Senior Secured Credit Facility could proceed against the collateral granted to them to secure that indebtedness. We pledged a significant portion of our assets as collateral under our Senior Secured Credit Facility. If the lenders under our Senior Secured Credit Facility accelerate the repayment of the borrowings thereunder, the proceeds from the sale or foreclosure upon such assets will first be used to repay debt under our Senior Secured Credit Facility, and we may not have sufficient assets to repay our unsecured indebtedness thereafter.

We have substantial cash balances that we invest in what we believe to be relatively short-term, highly-liquid and high credit quality investments. In addition, our management has broad discretion as to the use of our cash and might invest or spend our cash in ways that may not yield a return. This could result in a material adverse effect on our results of operations, liquidity or financial condition.

We have substantial cash balances that we maintain for working capital and general corporate purposes, which may include acquisitions. Our management has considerable discretion in the use of our cash, and might not be able to use our cash for purposes that increase our operating results or market value. Until the cash is used, it may from time to time be invested in what we believe to be relatively short-term, highly-liquid and high credit quality investments. We intend the investment risks, including counterparty default and lack of liquidity, on these types of investments to be relatively low, but market rates of return on these types of investments are also generally relatively low. Our efforts to manage the investment risks could be unsuccessful and this could result in a material adverse effect on our results of operations, liquidity or financial condition.

We may incur more taxes and certain of our projects may become uneconomic if certain federal income tax deductions currently available with respect to oil and natural gas exploration and development are eliminated as a result of future legislation.

Legislation has been proposed that would, if enacted, eliminate certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any of the foregoing changes will actually be enacted or how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar change in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development. Any such change could materially adversely affect our financial condition and results of operations by increasing the costs we incur which would in turn make it uneconomic to drill some locations if commodity prices are not sufficiently high, resulting in lower revenues and decreases in production and reserves.

Loss of our information and computer systems could adversely affect our business.

We are heavily dependent on our information systems and computer based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure or we were subject to cyberspace breaches or attacks, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

Our business could be negatively impacted by security threats, including cyber-security threats, and other disruptions.

As an oil and natural gas producer, we face various security threats, including cyber-security threats to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the safety of our employees, threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. Cyber-security attacks in particular are evolving and include, but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data.

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Although we utilize various procedures and controls to monitor and protect against these threats and to mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows.

Risks relating to our common stock

Our amended and restated certificate of incorporation, amended and restated bylaws, and Delaware state law contain provisions that may have the effect of delaying or preventing a change in control and may adversely affect the market price of our capital stock.

Our amended and restated certificate of incorporation authorizes our board of directors to issue preferred stock without any further vote or action by the stockholders. The rights of the holders of our common stock will be subject to the rights of the holders of any preferred stock that may be issued in the future. The issuance of preferred stock could delay, deter or prevent a change in control and could adversely affect the voting power or economic value of our shares.

In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

•	limitations on the ability of our stockholders to call special meetings;

•	a separate vote of 75% of the voting power of the outstanding shares of capital stock in order for stockholders to amend the bylaws in certain circumstances;

•	our board of directors is divided into three classes with each class serving staggered three-year terms;

•	stockholders do not have the right to take any action by written consent; and

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

Delaware law prohibits us from engaging in any business combination with any "interested stockholder," meaning generally that a stockholder who owns 15% of our stock cannot acquire us for a period of three years from the date such stockholder became an interested stockholder, unless various conditions are met, such as the approval of the transaction by our board of directors. Warburg Pincus, however, is not subject to this restriction.

The concentration of our capital stock ownership among our largest stockholder will limit your ability to influence corporate matters.

As of December 31, 2013, Warburg Pincus owned 49.1% of our outstanding common stock. Consequently, Warburg Pincus has significant influence over all matters that require approval by our stockholders, including the election of directors and approval of significant corporate transactions. This concentration of ownership limits the ability of other stockholders to influence corporate matters.

Furthermore, conflicts of interest could arise in the future between us, on the one hand, and Warburg Pincus and its affiliates, including its portfolio companies, on the other hand, concerning among other things, potential competitive business activities or business opportunities. Warburg Pincus LLC is a private equity firm that has invested in, among other things, companies in the energy industry. As a result, Warburg Pincus' existing and future portfolio companies which it controls may compete with us for investment or business opportunities. These conflicts of interest may not be resolved in our favor.

We have also renounced our interest in certain business opportunities. Our amended and restated certificate of incorporation provides that, to the fullest extent permitted by applicable law, we renounce any interest or expectancy in any business opportunity, transaction or other matter in which Warburg Pincus or any private fund that it manages or advises, any of their respective officers, directors, partners and employees, and any portfolio company in which such persons or entities have an equity interest (other than us and our subsidiaries) (each, a "specified party") participates or desires or seeks to participate and that involves any aspect of the energy business or industry, even if the opportunity is one that we might reasonably have pursued or had the ability or desire to pursue if granted the opportunity to do so, and no such specified party shall be liable to us for breach of any fiduciary or other duty, as a director or officer or controlling stockholder or otherwise, by reason of the fact that such specified party pursues or acquires any such business opportunity, directs any such business opportunity to another person or fails to present any such business opportunity, or information regarding any such business opportunity, to us. Notwithstanding the foregoing, we do not renounce any interest or expectancy in any business opportunity, transaction or other matter that is offered in writing solely to (i) one of our directors or officers who is not also a specified party or (ii) a specified party who is one of our directors, officers or employees and is offered such business opportunity solely in his or her capacity as

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our director, officer or employee. By renouncing our interest and expectancy in any business opportunity that from time to time may be presented to Warburg Pincus and its affiliates, our business and prospects could be adversely affected if attractive business opportunities are procured by such parties for their own benefit rather than for ours.

Because we have no plans to pay, and are currently restricted from paying dividends on our common stock, investors must look solely to stock appreciation for a return on their investment in us.

We do not anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain all future earnings to fund the development and growth of our business. Any payment of future dividends will be at the discretion of our board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that our board of directors deems relevant. Covenants contained in our Senior Secured Credit Facility and the indentures governing our senior unsecured notes restrict the payment of dividends. Investors must rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize a return on their investment. Investors seeking cash dividends should not purchase our common stock.

The availability of shares for sale in the future could reduce the market price of our common stock.

In the future, we may issue securities to raise cash for acquisitions. We may also acquire interests in other companies by using a combination of cash and our common stock or just our common stock. We may also issue securities convertible into, or exchangeable for, or that represent the right to receive, our common stock. Any of these events may dilute your ownership interest in our company, reduce our earnings per share and have an adverse impact on the price of our common stock.

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Item 1B.    Unresolved Staff Comments

Not applicable.

Item 2.    Properties

The information required by Item 2. is contained in Item 1. Business.

Item 3.    Legal Proceedings

From time to time, we are subject to various legal proceedings arising in the ordinary course of business, including proceedings for which we have insurance coverage. As of the date hereof, we are not party to any legal proceedings which we currently believe will have a material adverse effect on our business, financial position, results of operations or liquidity.

Item 4.    Mine Safety Disclosures

Not applicable.

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Part II

Item 5.    Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market for Registrant's Common Equity.    Our common stock is listed on the New York Stock Exchange ("NYSE") under the symbol "LPI." The following table sets forth the range of high and low sales prices of our common stock as reported by the NYSE:

		Price per share
		High				Low
2013:
Fourth Quarter		$	33.52			$	25.30
Third Quarter		$	30.00			$	20.21
Second Quarter		$	20.85			$	15.95
First Quarter		$	20.03			$	16.56
2012:
Fourth Quarter		$	22.37			$	17.11
Third Quarter		$	24.09			$	21.10
Second Quarter		$	26.63			$	18.79
First Quarter		$	26.80			$	20.84

On February 26, 2014, the last sale price of our common stock, as reported on the NYSE, was $27.43 per share.

Holders.    As of February 24, 2014, there were 59 holders of record of our common stock.

Dividends.    We have not paid any cash dividends since our inception. Covenants contained in our senior secured credit facility and the indentures governing our senior unsecured notes restrict the payment of cash dividends on our common stock. See "Item 1A. Risk Factors—Risks related to our business—Our debt agreements contain restrictions that will limit our flexibility in operating our business" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Cash flows—Debt." We currently intend to retain all future earnings for the development and growth of our business, and we do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future.

Repurchase of Equity Securities.

Period		Total number of shares withheld(1)			Average price per share				Total number of shares purchased as part of publicly announced plans			Maximum number of shares that may yet be purchased under the plan
October 1, 2013 - October 31, 2013		1,911			$	32.42			—			—
November 1, 2013 - November 30, 2013		8,317			$	28.91			—			—
December 1, 2013 - December 31, 2013		11,618			$	26.24			—			—

______________________________________________________________________________

(1)	Represents shares that were withheld by us to satisfy employee tax withholding obligations that arose upon the lapse of restrictions on restricted stock.

Unregistered Sales of Equity Securities and Use of Proceeds.   None.

    

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Stock Performance Graph.    The following performance graph and related information shall not be deemed "soliciting material" or to be "filed" with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or Exchange Act, except to the extent that we specifically request that such information be treated as "soliciting material" or specifically incorporate such information by reference into such a filing.

The performance graph below shows the cumulative total return to our common stockholders from December 15, 2011, the date on which our common stock began trading on the NYSE, through December 31, 2013, as compared to the returns on the Standard and Poor's 500 Index ("S&P 500") and the Standard and Poor's 500 Oil & Gas Exploration & Production Index ("S&P O&G E&P"). The comparison was prepared based upon the following assumptions:

1.     $100 was invested in our common stock at its initial public offering price of $17 per share and invested in the S&P 500 and the S&P O&G E&P on December 15, 2011 at the closing price on such date; and

2.     Dividends, if any, are reinvested.

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Item 6.    Selected Historical Financial Data

The selected historical consolidated financial data presented below is not intended to replace our audited consolidated financial statements. You should read the following data along with "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and the consolidated financial statements and related notes, each of which is included elsewhere in this Annual Report. We believe that the assumptions underlying the preparation of our financial statements are reasonable. The financial information included in this Annual Report may not be indicative of our future results of operations, financial position and cash flows.

Presented below is our historical financial data for the periods and as of the dates indicated. The historical financial data for the years ended December 31, 2013, 2012 and 2011 and the balance sheet data as of December 31, 2013 and 2012 are derived from our audited consolidated financial statements and the notes thereto included elsewhere in this Annual Report. The historical financial data for the years ended December 31, 2010 and 2009 and the balance sheet data as of December 31, 2011, 2010 and 2009 are derived from our audited financial statements not included in this Annual Report.

		For the years ended December 31,
(in thousands, except per share data)		2013(1)				2012				2011				2010				2009
Statement of operations data(2):
Total revenues		$	665,257			$	583,894			$	506,347			$	239,791			$	94,347
Total costs and expenses		450,906				411,954				303,827				164,230				345,613
Operating income (loss)		214,351				171,940				202,520				75,561				(251,266		)
Non‑operating expense, net		(23,267		)		(77,176		)		(36,932		)		(12,516		)		(4,888		)
Income (loss) from continuing operations before income taxes		191,084				94,764				165,588				63,045				(256,154		)
Income tax (expense) benefit		(74,507		)		(33,003		)		(59,612		)		24,847				73,181
Income (loss) from continuing operations		116,577				61,761				105,976				87,892				(182,973		)
Income (loss) from discontinued operations, net of tax		1,423				(107		)		(422		)		(1,644		)		(1,522		)
Net income (loss)		$	118,000			$	61,654			$	105,554			$	86,248			$	(184,495	)
Net income per common share:
Basic:
Income from continuing operations		$	0.88			$	0.49			$	0.99
Income (loss) from discontinued operations		0.01				—				(0.01		)
Net income per share		$	0.89			$	0.49			$	0.98
Diluted:
Income from continuing operations		$	0.87			$	0.48			$	0.98
Income (loss) from discontinued operations		0.01				—				—
Net income per share		$	0.88			$	0.48			$	0.98

_______________________________________________________________________________

(1)	See Note C to our audited consolidated financial statements included elsewhere in this Annual Report for additional information regarding our Anadarko Basin Sale.

(2)

The oil and natural gas properties that were a component of the Anadarko Basin Sale are not presented as held for sale nor are their results of operations presented as discontinued operations for the historical periods presented pursuant to the rules governing full cost accounting for oil and gas properties. The results of operations of the associated pipeline assets and various other associated property and equipment are presented as results of discontinued operations, net of tax.

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		As of December 31,
(in thousands)		2013				2012				2011				2010				2009
Balance sheet data:
Cash and cash equivalents		$	198,153			$	33,224			$	28,002			$	31,235			$	14,987
Net property and equipment		2,204,324				2,113,891				1,378,509				809,893				396,100
Total assets		2,623,760				2,338,304				1,627,652				1,068,160				625,344
Current liabilities		253,969				262,068				214,361				150,243				79,265
Long-term debt		1,051,538				1,216,760				636,961				491,600				247,100
Stockholders' equity		1,272,256				831,723				760,013				411,099				289,107

		For the years ended December 31,
(in thousands)		2013				2012				2011				2010				2009
Other financial data:
Net cash provided by operating activities		$	364,729			$	376,776			$	344,076			$	157,043			$	112,669
Net cash used in investing activities(1)		(329,884		)		(940,751		)		(706,787		)		(460,547		)		(361,333		)
Net cash provided by financing activities		130,084				569,197				359,478				319,752				250,139

_______________________________________________________________________________

(1)	Net cash used in investing activities for the year ended December 31, 2013 is offset by proceeds received for the Anadarko Basin Sale. See Note C to our audited consolidated financial statements included elsewhere in this Annual Report for additional information.

   

		For the years ended December 31,
(in thousands, unaudited)		2013				2012				2011				2010				2009
Adjusted EBITDA(1)		$	472,166			$	443,434			$	384,342			$	188,568			$	97,823

_______________________________________________________________________________

(1)	Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income (loss) see "—Non-GAAP financial measures and reconciliations" below.

Non-GAAP financial measures and reconciliations

Adjusted EBITDA is a non-GAAP financial measure that we define as net income or loss plus adjustments for interest expense, depletion, depreciation and amortization, impairment of long-lived assets, write-off of deferred loan costs, bad debt expense, gains or losses on disposal of assets, total gains or losses on derivatives, cash settlements of matured commodity derivatives, cash settlements on early terminated derivatives, premiums paid for derivatives that matured during the period, non-cash stock-based compensation and income tax expense or benefit. Adjusted EBITDA provides no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, working capital movement or tax position. Adjusted EBITDA does not represent funds available for discretionary use because those funds are required for debt service, capital expenditures and working capital, income taxes, franchise taxes and other commitments and obligations. However, our management believes Adjusted EBITDA is useful to an investor in evaluating our operating performance because this measure:

•	is widely used by investors in the oil and natural gas industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods, book value of assets, capital structure and the method by which assets were acquired, among other factors;

•	helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and

•	is used by our management for various purposes, including as a measure of operating performance, in presentations to our Board, as a basis for strategic planning and forecasting.

There are significant limitations to the use of Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations to different companies and the different methods of calculating Adjusted EBITDA

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reported by different companies. Our measurements of Adjusted EBITDA for financial reporting as compared to compliance under our debt agreements differ.

The following presents a reconciliation of net income (loss) for continuing and discontinued operations to Adjusted EBITDA:

		For the years ended December 31,
(in thousands, unaudited)		2013				2012				2011				2010				2009
Net income (loss)		$	118,000			$	61,654			$	105,554			$	86,248			$	(184,495	)
Plus:
Interest expense		100,327				85,572				50,580				18,482				7,464
Depletion, depreciation and amortization		234,571				243,649				176,366				97,411				58,005
Impairment of long-lived assets		—				—				243				—				246,669
Write-off of deferred loan costs		1,502				—				6,195				—				—
Bad debt expense		653				—				—				—				—
Loss on disposal of assets, net		1,508				52				40				30				85
Gain on derivatives, net		(79,878		)		(8,388		)		(19,736		)		(5,815		)		(2,350		)
Cash settlements received for matured commodity derivatives, net		4,046				27,025				3,719				22,701				52,117
Cash settlements received for early terminations and modifications of derivatives, net		6,008				—				—				—				—
Premiums paid for derivatives that matured during the period(1)		(11,292		)		(9,135		)		(4,104		)		(5,934		)		(7,085		)
Non-cash stock-based compensation		21,433				10,056				6,111				1,257				1,419
Income tax expense (benefit)		75,288				32,949				59,374				(25,812		)		(74,006		)
Adjusted EBITDA		$	472,166			$	443,434			$	384,342			$	188,568			$	97,823

______________________________________________________________________________

(1) Reflects premiums incurred previously or upon settlement that are attributable to instruments settled in the respective periods presented.

 

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Item 7.    Management's Discussion and Analysis of Financial Condition and Results of Operations

           The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and notes thereto appearing elsewhere in this Annual Report. The following discussion contains "forward-looking statements" that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors which could cause actual results to vary from our expectations include changes in oil and natural gas prices, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, potential failure to achieve production from development projects, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital and financial markets generally, as well as our ability to access them, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Annual Report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See "Cautionary Statement Regarding Forward-Looking Statements" and "Item 1A. Risk Factors."

Executive overview

We are an independent energy company focused on the exploration, development and acquisition of oil and natural gas properties primarily in the Permian Basin in West Texas. On August 1, 2013, we sold our properties in the Anadarko Granite Wash, Eastern Anadarko and Central Texas Panhandle (the "Anadarko Basin") in the Mid-Continent region of the United States.

We have grown rapidly through our drilling program and by making strategic acquisitions and joint ventures. In December 2011, we completed the Corporate Reorganization and IPO and in December 2013, we completed the Internal Consolidation. See Note A to our consolidated financial statements included elsewhere in this Annual Report for definitions of and additional information regarding the Corporate Reorganization, the IPO and the Internal Consolidation.

Our financial and operating performance for the year ended December 31, 2013 included the following:

•	Oil and natural gas sales of $664.8 million, compared to $583.6 million for the year ended December 31, 2012;

•	Average daily production of 30,716 BOE/D, compared to 30,874 BOE/D for the year ended December 31, 2012;

•	Estimated net proved reserves of 203,615 MBOE as of December 31, 2013, compared to 188,632 MBOE as of December 31, 2012; and

•	Adjusted EBITDA (a non-GAAP financial measure) of $472.2 million, compared to $443.4 million for the year ended December 31, 2012.

Recent Developments

Notes Offering

On January 23, 2014, we completed an offering of $450.0 million in aggregate principal amount of 5 5/8% senior unsecured notes due 2022, and entered into an indenture among Laredo, Laredo Midstream and Wells Fargo Bank, National Association, as trustee. The new senior unsecured notes will mature on January 15, 2022 with interest accruing at a rate of 5 5/8% per annum and payable semi-annually in cash in arrears on January 15 and July 15 of each year, commencing July 15, 2014. The new senior unsecured notes are guaranteed on a senior unsecured basis by Laredo Midstream.

The new senior unsecured notes were issued pursuant to the indenture in a transaction exempt from the registration requirements of the Securities Act. The new senior unsecured notes were offered and sold only to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. We received net proceeds of $442.2 million from the offering, after deducting the initial purchasers’ discount and offering expenses. We plan to use the net proceeds of the offering for general working capital purposes.

In connection with the issuance of the new senior unsecured notes, Laredo and Laredo Midstream entered into a registration rights agreement with the initial purchasers of the new senior unsecured notes and have agreed to use commercially reasonable efforts to file a registration statement with the SEC relating to an offer to exchange the new senior unsecured notes for substantially identical notes (other than with respect to restrictions on transfer or any increase in annual interest rate) that are registered under the Securities Act so as to permit the exchange offer to be consummated within 365 days after the issuance of the new senior unsecured notes. Under certain circumstances, Laredo and Laredo Midstream will be obligated to pay additional interest if they fail to comply with their obligations to register the new senior unsecured notes within the specified time periods.

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Unwinding of commodity contract

In February 2014, we unwound a physical commodity contract with a Light Louisiana Sweet Argus reference price and the associated oil basis swap financial derivative contract which hedged the differential between the Light Louisiana Sweet Argus and the Brent International Petroleum Exchange index oil prices. We received net proceeds of $76.7 million from the early termination of these contracts. We agreed to settle the contracts early due to our counterparty's decision to exit the physical commodity trading business. It is not our past practice nor do we expect to settle physical contracts financially in the future.

Mergers and acquisitions

Our use of capital for development and acquisitions allows us to direct our capital resources toward what we believe to be the most attractive opportunities as market conditions evolve. We have historically developed properties that we believe will meet or exceed our rate of return criteria. For acquisitions of properties with additional development and exploration potential, we have focused on acquiring properties that we expect to operate so that we can control the timing and implementation of capital spending. We also make acquisitions in core, mature areas where management can leverage knowledge and experience to identify upsides in the assets.

On July 1, 2011, we consummated the acquisition of Broad Oak for consideration consisting of (i) cash payments totaling $82.0 million to certain members of Broad Oak management and employees, (ii) equity issuances of 86.5 million preferred Laredo Petroleum, LLC units to Warburg Pincus, (iii) equity issuances of 2.4 million preferred Laredo Petroleum, LLC units to certain directors and management of Broad Oak and (iv) repayment of the $265.4 million of outstanding debt under the Broad Oak credit facility. Immediately following the consummation of such transaction, Laredo Petroleum, LLC assigned 100% of its ownership interest in Broad Oak to Laredo Petroleum, Inc. as a contribution to capital.

On July 12, 2012, we completed the acquisition of additional working interest in certain oil and natural gas properties located in Glasscock County, Texas, for a contract price of $20.5 million from a private company, net of closing purchase price adjustments.

On September 6, 2013, we completed the acquisition of proved and unproved oil and natural gas properties located in Glasscock County, TX, from private parties for $36.7 million consisting of cash and 123,803 shares of our restricted common stock, subject to customary closing adjustments.

Divestitures

On August 1, 2013, we completed the sale of oil and gas properties located in the Anadarko Basin in the State of Oklahoma and the State of Texas, associated pipeline assets and various other related property and equipment (the "Anadarko Basin Sale") for a purchase price of $438.0 million. The purchase price (including the buyers' deposits) consisted of $400.0 million from certain affiliates of EnerVest, Ltd. and $38.0 million from other third parties in connection with the exercise of such third parties' preferential rights associated with certain of the oil and gas properties. Approximately $388.0 million of the purchase price, excluding closing adjustments, was allocated to oil and natural gas properties pursuant to the rules governing full cost accounting. After transaction costs and adjustments at closing reflecting an economic effective date of April 1, 2013, the net proceeds were $428.3 million, net of working capital adjustments. The net proceeds were used to pay off our Senior Secured Credit Facility and for working capital purposes.

Effective August 1, 2013, the operations and cash flows of these properties were eliminated from our ongoing operations and we do not have continued involvement in the operation of these properties. The oil and natural gas properties, which are a component of the assets sold, are not presented as discontinued operations pursuant to the rules governing full cost accounting for oil and gas properties. The results of operations of the associated pipeline assets and various other associated property and equipment have been presented as results of discontinued operations, net of tax. Accordingly we have reclassified certain prior period amounts in the consolidated financial statements included elsewhere in this Annual Report as discontinued operations. See Notes B.3 and C to our consolidated financial statements included elsewhere in this Annual Report for additional discussion of these reclassifications and the Anadarko Basin Sale.

On December 20, 2013, we completed the sale of 37,000 net acres in the Dalhart Basin, including one producing well, for $20.4 million, subject to customary closing adjustments. The net proceeds were used for working capital purposes.

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Management and board changes

During the year ended December 31, 2013, our board of directors appointed Jay P. Still to become President and Chief Operating Officer, effective July 8, 2013. Our board of directors also appointed Mr. Still to become a member of the board of directors, effective July 8, 2013, and hold office until the next annual meeting of stockholders or until his successor has been duly elected and qualified. Jerry R. Schuyler, our former President and Chief Operating Officer and formerly one of our directors, resigned as an officer and director of Laredo effective July 8, 2013, and continued with Laredo in an advisory capacity until he retired on November 21, 2013. In connection with Mr. Schuyler's retirement, the compensation committee of our board of directors elected to accelerate the vesting of all of his restricted stock and restricted stock options, as well as all of his performance unit awards (as if the performance criteria had been fully satisfied) to the date of his retirement.

John E. Minton, who had been with us since October 2007, elected to retire from his position as Senior Vice President - Reservoir Engineering effective December 6, 2013. In connection with his retirement, the compensation committee of our board of directors elected to accelerate the vesting of all of his restricted stock and restricted stock options, as well as all of his performance unit awards (as if the performance criteria had been fully satisfied) to the date of his retirement.

Common stock transactions

On August 19, 2013, we, together with certain affiliates of Warburg Pincus and members of our management (together with Warburg Pincus, the "Selling Stockholders") completed the sale of (i) 13,000,000 shares of our common stock by us and (ii) 3,000,000 shares of our common stock by the Selling Stockholders, at a price to the public of $23.75 per share ($22.9781 per share, net of underwriting discounts) (the "Follow-on Offering"). On August 27, 2013, certain of the Selling Stockholders sold an additional 1,577,583 shares of our common stock pursuant to the option to purchase additional shares of our common stock granted to the associated underwriters. We intend to use the $298.1 million net proceeds from the Follow-on Offering to implement our planned exploration and development activities, accelerate our capital program and for general working capital purposes. We did not receive any proceeds from the sale of the shares of our common stock by the Selling Stockholders.

On September 6, 2013, we issued 123,803 restricted shares of our common stock to third parties as partial consideration for an acquisition of proved and unproved oil and natural gas properties. See Note C to our audited consolidated financial statements included elsewhere in the Annual Report for additional information.

During the year ended December 31, 2013, Warburg Pincus distributed our common stock pro rata to certain of the Warburg Pincus limited partners. As of February 24, 2014, Warburg Pincus owned 49.1% of our outstanding common stock. The following details the distributions throughout the year ended December 31, 2013:

Date of distribution		Number of shares distributed			Distribution % of Warburg Pincus' holdings of our common stock prior to the distribution
June 25, 2013		3,515,263			4	%
August 19, 2013		2,890,000			3	%
August 27, 2013		1,577,583			2	%
September 24, 2013		3,515,263			4	%
November 25, 2013		6,008,476			8	%

Derivative terminology modifications

We have modified our terminology describing gains and losses on derivatives. In our revised presentation, "Cash settlements received for matured derivatives" describe the gain or loss from contracts that settled during the current period, calculated as the difference between the contract price and the market settlement price of the matured derivatives. In addition, we have revised our non-GAAP financial measure Adjusted EBITDA and our average hedged sale price calculation to include "Premiums paid for derivatives that matured during the period" which represents current period settlements of matured derivatives and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to instruments settled in the period.

Related Party

We have a gathering and processing arrangement with affiliates of Targa Resources, Inc. ("Targa"). Until May 2013, Warburg Pincus Private Equity IX, L.P., a major stockholder of Laredo, and other affiliates of Warburg Pincus, held material investment interests in Targa. We considered Targa a related party until May 2013, and accordingly have continued our disclosure of our net oil and natural gas sales and our oil and natural gas sales receivable attributable to Targa throughout 2013. As we no longer consider Targa a related party, we will discontinue this disclosure in 2014.

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Core area of operations

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, 2013, we had assembled 202,084 net acres in the Permian Basin.

Reserves and pricing

Ryder Scott, our independent reserve engineers, estimated 100% of our proved reserves, reported on a two-stream basis, as of December 31, 2013, 2012 and 2011. As of December 31, 2013, we had 203,615 MBOE of estimated net proved reserves as compared to 188,632 MBOE of estimated net proved reserves as of December 31, 2012 and 156,453 MBOE of estimated net proved reserves as of December 31, 2011.

Our results of operations are heavily influenced by commodity prices. Prices for oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas, market uncertainty, economic conditions and a variety of additional factors. Since the inception of our oil and natural gas activities, commodity prices have experienced significant fluctuations, and additional changes in commodity prices may affect the economic viability of drilling projects, as well as the economic valuation and economic recovery of oil and natural gas reserves.

Our reserves are reported in two streams: crude oil and liquids-rich natural gas. The economic value of the natural gas liquids in our natural gas is included in the wellhead natural gas price. The unweighted arithmetic average first-day-of-the-month index prices for the prior 12 months were $93.52 per Bbl for oil and $3.57 per MMBtu for natural gas as of December 31, 2013, $91.21 per Bbl for oil and $2.63 per MMBtu for natural gas as of December 31, 2012 and $92.71 per Bbl for oil and $3.99 per MMBtu for natural gas as of December 31, 2011. The prices used to estimate proved reserves for all periods did not give effect to derivative transactions. These prices were held constant throughout the life of the properties and have been adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

We have entered into a number of commodity derivatives, which have allowed us to offset a portion of the changes caused by price fluctuations on our oil and natural gas production as discussed in “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

Sources of our revenue

Our revenues are derived from the sale of oil and natural gas within the continental United States and do not include the effects of derivatives. For the year ended December 31, 2013, our revenues from continuing operations are comprised of sales of 74% oil and 26% gas. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

Principal components of our cost structure

Lease operating and transportation and treating expenses.    These are daily costs incurred to bring oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include maintenance, repairs and workover expenses related to our oil and natural gas properties.

Production and ad valorem taxes.    Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at market prices or at fixed rates established by federal, state or local taxing authorities. We take full advantage of all credits and exemptions in our various taxing jurisdictions. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues. Ad valorem taxes are property taxes based on the value of our reserves attributed to our properties located in Texas.

Drilling and production.    These are costs incurred to maintain facilities that support our drilling activities.

General and administrative.    These are costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, audit and other fees for professional services and legal compliance.

Stock-based compensation.    These are costs incurred for compensation expense related to employee and director stock and option awards granted which have been recognized on a straight-line basis over the vesting period associated with the award.

Accretion of asset retirement obligations. Accretion is a non-cash charge which represents changes in our asset retirement liability due to the passage of time.

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Depletion, depreciation and amortization.    Under the full cost accounting method, we capitalize all acquisition, exploration and development costs, including certain related employee costs, incurred for the purpose of finding oil and natural gas within a cost center and then systematically expense those costs on a units of production basis based on proved oil and natural gas reserve quantities. We calculate depletion on the following types of costs: (i) all capitalized costs, other than the cost of investments in unproved properties and major development projects for which proved reserves cannot yet be assigned, less accumulated amortization; (ii) the estimated future expenditures to be incurred in developing proved reserves; and (iii) the estimated dismantlement and abandonment costs, net of estimated salvage values. We calculate depreciation on the cost of fixed assets related to our pipelines and other fixed assets utilizing the straight-line method over the useful life of the asset.

Other income (expense)

Gain (loss) on commodity derivatives. We utilize commodity derivatives to reduce our exposure to fluctuations in the price of crude oil and natural gas. This amount represents (i) the recognition of gains and losses associated with our open derivatives as commodity prices change and commodity derivatives expire or new ones are entered into, and (ii) our gains and losses on the settlement of these commodity derivatives. We classify these gains and losses as operating activities in our consolidated statements of cash flows.

Gain (loss) on interest rate derivatives. We utilized interest rate swaps and caps to reduce our exposure to fluctuations in interest rates on our outstanding debt. This amount represents (i) the recognition of gains and losses associated with interest rate derivatives as interest rates change and interest rate derivatives expire or new ones are entered into, and (ii) our gains and losses on the settlement of these interest rate contracts. We classify these gains and losses as operating activities in our consolidated statements of cash flows. During each of the years ended December 31, 2013 and 2012, we had one interest rate swap and one interest rate cap outstanding for a total notional amount of $100.0 million with fixed pay rates ranging from 1.11% to 3.00% until their expiration in September 2013.

Income from equity method investee. We have invested in a company where we own 49% of the ownership units. As such, we account for this investment under the equity method of accounting with our proportionate share of net gain (loss) reflected in the consolidated statements of operations as "Income from equity method investee" and the carrying amount reflected in the audited consolidated balance sheet as "Investment in equity method investee." See Note M to our audited consolidated financial statements included elsewhere in this Annual Report for additional information regarding this investment.

Interest expense.    We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our Senior Secured Credit Facility, our senior unsecured notes and, prior to its termination on July 1, 2011, the Broad Oak credit facility. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We have entered into various interest rate derivatives to mitigate the effects of interest rate changes. We do not designate these derivatives as hedges and therefore hedge accounting treatment is not applicable. Gains or losses on these interest rate contracts are included in non-operating income (expense) as discussed above. We reflect interest paid to the lenders and bondholders in interest expense. In addition, we include the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees in interest expense.

Interest and other income.    This represents the interest received on our cash and cash equivalents as well as other miscellaneous income.

Income tax expense.    Income taxes in our financial statements are generally presented on a consolidated basis. However, U.S. tax laws do not allow tax losses of Laredo Petroleum—Dallas, Inc. to offset income and losses of another entity until after the consummation of the Broad Oak acquisition on July 1, 2011. As such, the financial accounting for the income tax consequences of each taxable entity is calculated separately for all periods prior to July 1, 2011.

We are subject to federal and state corporate income taxes and Texas franchise tax. These taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating losses and tax credit carry-forwards. Under this method, deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax laws or tax rates is recognized in income in the period that includes the enactment date.

On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realization of the deferred tax assets and adjusts the amount of such allowances, if necessary. We considered all available evidence, both positive and negative, in determining whether, based on the weight of that evidence, a valuation allowance was needed on either the federal or Oklahoma net operating loss carry-forwards. Such consideration included estimated future projected earnings based on existing reserves and projected future cash flows from its oil and natural gas reserves (including the

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timing of those cash flows), the reversal of deferred tax liabilities recorded as of December 31, 2013, our ability to capitalize intangible drilling costs, rather than expensing these costs in order to prevent an operating loss carry-forward from expiring unused, and future projections of Oklahoma sourced income.

Results of operations

For the year ended December 31, 2013 as compared to the year ended December 31, 2012, and for the year ended December 31, 2012 as compared to the year ended December 31, 2011

Production, revenue and pricing

    

The following table sets forth information regarding production and revenue and average sales prices from continuing operations per BOE, for the periods presented:

		For the years ended December 31,
(unaudited)		2013				2012				2011
Production data:
Oil (MBbl)		5,487				4,775				3,368
Natural gas (MMcf)		34,348				39,148				31,711
Oil equivalents (MBOE)(1)		11,211				11,300				8,654
Average daily production (BOE/D)(1)		30,716				30,874				23,709
% Oil		49		%		42		%		39		%
Revenues (in thousands):
Oil		$	494,676			$	414,932			$	306,481
Natural gas		170,168				168,637				199,774
Transportation and treating		413				325				92
Total revenues		$	665,257			$	583,894			$	506,347
Average sales prices:
Oil, realized ($/Bbl)(2)		$	90.16			$	86.89			$	91.00
Natural gas, realized ($/Mcf)(2)		4.95				4.31				6.30
Average price, realized ($/BOE)(2)		59.29				51.65				58.50
Oil, hedged ($/Bbl)(3)		88.68				85.59				88.16
Natural gas, hedged ($/Mcf)(3)		4.98				4.92				6.59
Average price, hedged ($/BOE)(3)		58.66				53.22				58.47

_______________________________________________________________________________

(1)	The volumes presented are based on actual results and are not calculated using the rounded numbers presented in the table above.

(2)

Realized oil and natural gas prices are the actual prices realized at the wellhead after all adjustments for natural gas liquid content, quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price at the wellhead. The prices presented are based on actual results and are not calculated using the rounded numbers presented in the table above.

(3)

Hedged prices reflect the after effect of our commodity hedging transactions on our average sales prices. Our calculation of such after effects include current period settlements of matured commodity derivatives in accordance with GAAP and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to instruments that settled in the period. The prices presented are based on actual results and are not calculated using the rounded numbers presented in the table above.

    

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The following table presents cash settlements received (paid) for matured commodity derivatives and premiums incurred previously or upon settlement attributable to instruments that settled during the periods utilized in our calculation of the hedged prices presented above:    

		For the years ended December 31,
(in thousands)		2013				2012				2011
Cash settlements received (paid) for matured commodity derivatives:
Oil		$	(149	)		$	(944	)		$	(7,973	)
Natural gas		4,195				27,969				11,692
Total		$	4,046			$	27,025			$	3,719
Premiums paid attributable to contracts that matured during the respective period:
Oil		$	(7,970	)		$	(5,278	)		$	(1,549	)
Natural gas		(3,322		)		(3,857		)		(2,555		)
Total		$	(11,292	)		$	(9,135	)		$	(4,104	)

 

The changes in volumes and prices shown in the production, revenue and pricing table above caused the following changes to our oil and natural gas revenue between the years ended December 31, 2011 and 2012 and 2013:

(in thousands)		Oil				Natural gas				Total net dollar effect of change
2011 Revenue		$	306,481			$	199,774			$	506,255
Effect of changes in price		(19,627		)		(77,904		)		(97,531		)
Effect of changes in volumes		128,032				46,848				174,880
Other		46				(81		)		(35		)
2012 Revenue		$	414,932			$	168,637			$	583,569
Effect of changes in price		17,942				21,982				39,924
Effect of changes in volumes		61,812				(20,688		)		41,124
Other		(10		)		237				227
2013 Revenue		$	494,676			$	170,168			$	664,844

Oil and natural gas revenues. Our revenues are a function of oil and natural gas production volumes sold and average sales prices received for those volumes. The total increase in oil and natural gas revenues of $81.3 million, or 14%, for the year ended December 31, 2013 as compared to the year ended December 31, 2012 is largely due to a 15% increase in oil production in our Permian area and an increase in both oil and natural gas prices realized for the year, which were offset by a decrease in natural gas production volumes attributable to the divestiture of our Anadarko Basin assets and by severe winter weather in the Permian region during the fourth quarter of 2013. The total increase in oil and natural gas revenues of $77.3 million, or 15%, for the year ended December 31, 2012 as compared to the year ended December 31, 2011 is largely due to a 42% increase in oil production and a 23% increase in natural gas production volumes attributable mainly to our Permian and Anadarko Granite Wash areas, which were offset by lower prices received for oil and natural gas.

Transportation and treating. Our transportation and treating revenue from continuing operations increased by $0.09 million during the year ended December 31, 2013 as compared to the year ended December 31, 2012 and $0.2 million during the year ended December 31, 2012 as compared to the year ended December 31, 2011. These increases were due to the sale of condensate from our pipeline assets during each respective period, which occurs on an infrequent basis, as well as an increase in the volumes transported through our pipeline.

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Costs and expenses

The following table sets forth information regarding costs and expenses from continuing operations and average costs per BOE for the periods presented:

		For the years ended December 31,
(in thousands except for per BOE data)		2013				2012				2011
Costs and expenses:
Lease operating expenses		$	79,136			$	67,325			$	43,306
Production and ad valorem taxes		42,396				37,637				31,982
Transportation and treating		680				162				65
Transportation and treating - affiliates		891				—				—
Drilling and production		2,688				2,452				2,675
General and administrative(1)		89,696				62,106				51,064
Accretion of asset retirement obligations		1,475				1,200				616
Depletion, depreciation and amortization		233,944				241,072				174,119
Total costs and expenses		$	450,906			$	411,954			$	303,827
Average costs per BOE:
Lease operating expenses		$	7.06			$	5.96			$	5.00
Production and ad valorem taxes		3.78				3.33				3.70
General and administrative(1)		8.00				5.50				5.90
Depletion, depreciation and amortization		20.87				21.33				20.12
Total		$	39.71			$	36.12			$	34.72

_________________________________________________________________________

(1)	General and administrative includes non-cash stock-based compensation of $21.4 million, $10.1 million and $6.1 million for the years ended December 31, 2013, 2012 and 2011, respectively. Excluding stock-based compensation from the above metric results in general and administrative cost per BOE of $6.09, $4.61 and $5.19 for the years ended December 31, 2013, 2012 and 2011, respectively.

Lease operating expenses.    Lease operating expenses, which include workover expenses, increased by $11.8 million, or 18%, compared to a 1% decrease in production, for the year ended December 31, 2013 compared to 2012. On a per-BOE basis, lease operating expenses increased in total to $7.06 per BOE as of December 31, 2013 from $5.96 per BOE as of December 31, 2012. The increases were mainly due to (i) higher average lease operating expenses per-BOE on our higher oil-weighted Permian production following the Anadarko Basin Sale and (ii) the implementation of best practices with respect to workover operations. We expect that these practices will result in longer term well tubing integrity, which should improve overall well performance and production in the long term, in addition to decreasing unit lease expenses as a result of reduced well tubing failures.

    Lease operating expenses, which include workover expenses, increased by $24.0 million, or 55%, compared to a 31% increase in production, for the year ended December 31, 2012 compared to 2011. The increases were primarily due to an increase in exploration and development activity, which resulted in additional producing wells during the year ended December 31, 2012 compared to 2011. The increase in well count also led to increases in routine repairs and maintenance. On a per-BOE basis, lease operating expenses increased in total to $5.96 per BOE as of December 31, 2012 from $5.00 per BOE as of December 31, 2011. The majority of the increase is mainly due to implementation of best practices with respect to workover operations. We expect that these practices will result in longer term well tubing integrity, which should improve overall well performance and production in the long term, in addition to decreasing unit lease expenses as a result of reduced well tubing failures.

Production and ad valorem taxes.    Production and ad valorem taxes increased to $42.4 million for the year ended December 31, 2013 from $37.6 million for the year ended December 31, 2012, an increase of $4.8 million, or 13%. Our production taxes are based on a percentage of our oil and natural gas revenue, and therefore increase in proportion to our oil and natural gas revenues. Our ad valorem taxes have increased primarily as a result of increased valuations on our Texas properties and an increase in the number of wells included in those valuations as a result of our 2012 and 2013 drilling activity in our Permian and Anadarko Granite Wash areas.

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Production and ad valorem taxes increased to $37.6 million for the year ended December 31, 2012 from $32.0 million for the year ended December 31, 2011, an increase of $5.7 million, or 18%. Our ad valorem taxes have increased primarily as a result of increased valuations on our Texas properties and an increase in the number of wells included in those valuations as a result of our 2011 and 2012 drilling activity in our Permian and Anadarko Granite Wash areas.

Drilling and production.    Drilling and production costs increased to $2.7 million for the year ended December 31, 2013 from $2.5 million for the year ended December 31, 2012 as a result of increased maintenance costs. Drilling and production costs decreased to $2.5 million for the year ended December 31, 2012 from $2.7 million for the year ended December 31, 2011 as a result of decreased maintenance costs.

General and administrative ("G&A").    G&A expense, excluding stock-based compensation, increased to $68.3 million as of December 31, 2013 from $52.1 million as of December 31, 2012, an increase of $16.2 million, or 31%. The increase is primarily due to $17.5 million in additional salary, benefits and bonuses due to the growth of our business and employee base. Additionally, the issuance of our cash-settled performance unit liability awards in February 2012 and 2013, which are revalued at the end of each reporting period using a Monte Carlo simulation, accounted for $2.9 million of the total increase. Computer, relocation, aircraft, rent and miscellaneous other expenses also contributed to the increase by $4.4 million due to the growth of our business and employee base. The overall increase in G&A expense was offset by $11.0 million in greater production income, capitalized salary and benefits, billable vehicle expense and lower professional fees, travel costs, production data costs, and legal fees for 2013 as compared to 2012. On a per-BOE basis, G&A expense, excluding stock-based compensation, increased to $6.09 per BOE during the year ended December 31, 2013 from $4.61 per BOE as of December 31, 2012. This increase was a result of the growth in our employee base combined with not as significant production growth due to the divestiture of our Anadarko Basin assets.

G&A expense, excluding stock-based compensation, increased to $52.1 million as of December 31, 2012 from $45.0 million as of December 31, 2011, an increase of $7.1 million, or 16%. The increase is primarily due to $6.4 million in additional salary and benefits due to the growth of our business and employee base. Additionally, the issuance of our cash-settled performance unit liability awards in February 2012, which are revalued at the end of each reporting period using a Monte Carlo simulation, accounted for $1.8 million of the total increase. These increases were partially offset by a decrease in legal and professional fees of $2.1 million for the year ended December 31, 2012, as we incurred higher fees in 2011 related to the issuance of our 2019 senior unsecured notes in January 2011 and October 2011, the acquisition of Broad Oak in July 2011 and our IPO in December 2011. The remaining change is made up of smaller increases in a number of areas such as vehicle expenses, insurance expenses and computer and software costs that are largely a result of increasing our workforce and growing our business. On a per-BOE basis, G&A expense, excluding stock-based compensation, decreased to $4.61 per BOE during the year ended December 31, 2012 from $5.19 per BOE as of December 31, 2011. This decrease was a result of a significant increase in production during the year ended December 31, 2012 as compared to the year ended December 31, 2011.

Employee compensation.    Stock-based compensation increased to $21.4 million as of December 31, 2013 from $10.1 million as of December 31, 2012, an increase of $11.4 million largely due to the issuance of 1,469,295 restricted stock awards and 1,018,849 non-qualified restricted stock options during 2013. Additionally, during the year ended December 31, 2013, we accelerated the vestings of certain officers' and employees' restricted stock awards and restricted stock options awards upon retirement or termination of employment due to the Anadarko Basin Sale. These modifications accounted for $4.7 million of the stock-based compensation expense increase over the prior year.

Stock-based compensation increased to $10.1 million as of December 31, 2012 from $6.1 million as of December 31, 2011, an increase of $3.9 million due largely to the issuance of 932,084 restricted stock awards and 602,948 non-qualified restricted stock options during 2012.

The performance unit awards increased in fair value by $4.1 million at year-end 2013 as compared to the year-end 2012, mainly as a result of the quarterly re-measurement, issuance of a new tranche of performance units during 2013 and the performance of our stock price relative to our peer group utilized in the forward-looking Monte Carlo simulation. During the year ended December 31, 2013, certain officers' performance unit awards were modified to vest upon the officers' retirement in 2013. The cash payments for these performance unit awards were paid at $100.00 per unit totaling $2.1 million.

    We have a 2011 Omnibus Equity Incentive Plan, which allows for the issuance of restricted stock awards, non-qualified restricted stock option awards and performance unit awards to directors, officers, employees, consultants and advisers. The fair value of the restricted stock awards issued during 2013 and 2012 was calculated based on the value of our stock price on the date of grant in accordance with GAAP and is being recognized on a straight-line basis over the requisite service period of the awards. The fair value of our non-qualified restricted stock option awards was determined using a Black-Scholes valuation model in accordance with applicable GAAP accounting and is being recognized on a straight-line basis over the four-year requisite service period of the awards. See Note E to our audited consolidated financial statements included elsewhere in the Annual Report for additional information.

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Depletion, depreciation and amortization ("DD&A").    DD&A was $233.9 million as of December 31, 2013 as compared to $241.1 million as of December 31, 2012 and $174.1 million as of December 31, 2011.

The following table provides components of our DD&A expense from continuing operations for the periods presented:

		For the years ended December 31,
(in thousands except for per BOE data)		2013				2012				2011
Depletion of proved oil and natural gas properties		$	227,992			$	237,130			$	171,517
Depreciation of pipeline assets		1,510				797				398
Depreciation and amortization of fixed assets		4,442				3,145				2,204
DD&A		$	233,944			$	241,072			$	174,119
DD&A per BOE		$	20.87			$	21.33			$	20.12

The decrease in depletion of proved oil and natural gas properties of $9.1 million and $0.64 per BOE for the year ended December 31, 2013 compared to 2012 is mainly a result of the Anadarko Basin Sale. We expect depletion of proved oil and natural gas properties to increase as our focus remains on drilling higher-valued oil-rich assets. The increase in depletion of proved oil and natural gas properties of $65.6 million and $1.16 per BOE for the year ended December 31, 2012 compared to 2011 resulted primarily from (i) decreases in the natural gas price between periods utilized to determine proved reserves, (ii) increased net book value on new reserves added, (iii) higher total production levels and (iv) increased capitalized costs for new wells completed in 2012.

Non-operating income and expense. The following table sets forth the components of non-operating income and expense from continuing operations for the periods presented:

		For the years ended December 31,
(in thousands)		2013				2012				2011
Non-operating income (expense):
Gain (loss) on derivatives:
Commodity derivatives, net		$	79,902			$	8,800			$	21,047
Interest rate derivatives, net		(24		)		(412		)		(1,311		)
Income from equity methods investee		29				—				—
Interest expense		(100,327		)		(85,572		)		(50,580		)
Interest and other income		163				59				108
Write-off of deferred loan costs		(1,502		)		—				(6,195		)
Loss on disposal of assets		(1,508		)		(51		)		(1		)
Non-operating expense, net		$	(23,267	)		$	(77,176	)		$	(36,932	)

Commodity derivatives. Total gain on commodity derivatives increased by $71.1 million for the year ended December 31, 2013 compared to 2012 and decreased $12.2 million for the year ended December 31, 2012 compared to 2011. Net cash settlements on matured commodity derivatives decreased by $23.0 million for the year ended December 31, 2013 compared to 2012 and increased $23.3 million for the year ended December 31, 2012 compared to 2011, based on the cash settlement prices of our matured commodity derivatives compared to the prices specified in the derivative contracts. Additionally, during the current year, we received net cash settlements on early terminations and modifications of derivatives of $6.0 million as a result of unwinding nine natural gas commodity contracts in connection with the Anadarko Basin Sale. There were no comparable amounts in 2012.

The change in fair value of commodity derivatives still held increased by $88.1 million for the year ended December 31, 2013 compared to 2012 and decreased $35.5 million for the year ended December 31, 2012 compared to 2011. This increase is mainly due to our oil basis swap differential between the Light Louisiana Sweet Argus and the Brent International Petroleum Exchange index oil prices, which was entered into during 2013 and was valued at $92.8 million at December 31, 2013. We subsequently settled this contract in February 2014. Refer to Note O of our audited consolidated financial statements included elsewhere in this Annual Report for additional information regarding this subsequent event. The remainder of the change in the fair value of commodity derivatives still held is a result of the changing relationships between our contract prices and the associated forward curves used to calculate the fair value of our commodity derivatives in relation to expected market

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prices. In general, we experience gains during periods of decreasing market prices and losses during periods of increasing market prices.

See Notes B.6, G and H to our audited consolidated financial statements included elsewhere in this Annual Report and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for additional information regarding our commodity derivatives.

Income from equity methods investee. Income from equity methods investee increased by $0.03 million for the year ended December 31, 2013 compared to 2012. This increase is due to our 2013 equity method investment, which had profits during its first year of operation. See Note M to our audited consolidated financial statements included elsewhere in the Annual Report for additional information.

Interest expense and gains and losses on interest rate swaps. Interest expense increased by $14.8 million, or 17%, for the year ended December 31, 2013 compared to 2012, and $35.0 million, or 69%, for the year ended December 31, 2012 compared to 2011. These increases are largely due to the issuance of (i) $200.0 million of 9 1/2% senior unsecured notes due 2019 in October of 2011 in addition to the previously outstanding $350.0 million of 9 1/2% senior unsecured notes due in 2019, and (ii) $500.0 million of 7 3/8% senior unsecured notes due 2022 in April of 2012.

The table below shows the changes in the significant components of interest expense for the periods presented:

(in thousands)		Year ended December 31, 2013 compared to 2012				Year ended December 31, 2012 compared to 2011
Changes in interest expense:
Senior Secured Credit Facility, net of capitalized interest(1)		$	2,931			$	(3,497	)
2019 senior unsecured notes		(20		)		16,661
2022 senior unsecured notes		12,189				24,686
Broad Oak credit facility(2)		—				(4,928		)
Change in net present value of deferred premiums paid for derivatives		(206		)		197
Amortization of deferred loan costs		168				1,327
Other		(307		)		546
Total change in interest expense		$	14,755			$	34,992

_______________________________________________________________________

(1) The Senior Secured Credit Facility was paid in full on August 1, 2013 and remained undrawn for the remainder of the year ended December 31, 2013.

(2)	The Broad Oak credit facility was paid-in-full and terminated on July 1, 2011 in connection with the Broad Oak acquisition.

We had entered into certain variable-to-fixed interest rate derivatives that hedge our exposure to interest rate variations on our variable interest rate debt that expired in September 2013. During the year ended December 31, 2013 and 2012, we had one interest rate swap and one interest rate cap outstanding for a total notional amount of $100.0 million with fixed pay rates ranging from 1.11% to 3.00% until their expiration in September 2013.

Loss on disposal of assets. Loss on disposal of assets increased by $1.5 million for the year ended December 31, 2013 compared to 2012 and $0.05 million for the year ended December 31, 2012 compared to 2011. The 2013 increase over the prior year is largely due to losses sustained from a fire at a truck station on one of our properties and a loss on disposal of a portion of our inventory. These losses were offset by a gain of $3.2 million on the pipeline assets and various other associated property and equipment disposed of in the Anadarko Basin Sale.

Write-off of deferred loan costs.    In August 2013, we wrote-off $1.5 million in deferred loan costs as a result of changes in the borrowing base under the Senior Secured Credit Facility due to the Anadarko Basin Sale. As of December 31, 2013, the borrowing base of our Senior Secured Credit Facility was $925.0 million with an aggregated elected commitment of $825.0 million.

In January 2011, we used a portion of the net proceeds from the issuance of our 2019 senior unsecured notes to pay in full and retire our term loan. Additionally, concurrent with the issuance of our senior unsecured notes in January 2011, the amount available for borrowings under our Senior Secured Credit Facility was decreased. As a result, in January 2011, we took a charge to expense for the debt issuance costs attributable to our term loan and a proportionate percentage of the costs incurred for our Senior Secured Credit Facility, which totaled $2.9 million and $0.3 million, respectively.

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On July 1, 2011, in conjunction with the Broad Oak acquisition, the Broad Oak credit facility was paid in full and terminated and the related debt issuance costs of $2.9 million were charged to expense.

Income tax expense. We recorded a deferred income tax expense from continuing operations of $74.5 million, $33.0 million and $59.6 million for the years ended December 31, 2013, 2012 and 2011, respectively, due to fluctuations in income before income taxes as shown in the table below.

		For the years ended December 31,
(in thousands)		2013				2012				2011
Income from continuing operations before income taxes		$	191,084			$	94,764			$	165,588
Income tax expense		(74,507		)		(33,003		)		(59,612		)
Income from continuing operations, net		$	116,577			$	61,761			$	105,976
Effective tax rate		39		%		35		%		36		%

Our effective tax rate is based on our annual permanent tax differences and annual pre-tax book income. The Company's effective tax rate is affected by recurring permanent differences and by discrete items that may occur in any given year, but are not consistent from year to year. During the year ended December 31, 2013, certain shares related to restricted stock awards vested at times when our stock price was lower than the fair value of those shares at the time of grant. As a result, the income tax deduction related to such shares is less than the expense previously recognized for book purposes. During the year ended December 31, 2013, certain restricted stock options were exercised. The income tax deduction related to the options' intrinsic value was less than the expense previously recognized for book purposes. In accordance with GAAP, such shortfalls reduce additional paid-in capital to the extent windfall tax benefits have been previously recognized. However, we have not previously recognized any windfall tax benefits. Therefore, the tax impact of these shortfalls totaling $0.6 million for the year ended December 31, 2013 is included in income tax expense attributable to continuing operations for the period. There were no comparative amounts for the years ended December 31, 2012 or 2011.

Income from discontinued operations, net of tax. The table below shows our income from discontinued operations for the periods presented:

		For the years ended December 31,
(in thousands)		2013				2012				2011
Income (loss) from discontinued operations, net of tax		$	1,423			$	(107	)		$	(422	)

    

Income (loss) from discontinued operations, net of tax, increased by $1.5 million for the year ended December 31, 2013 compared to 2012 and $0.3 million for the year ended December 31, 2012 compared to 2011. The increases are a result of increased production over time that has attributed to our growth in transportation and gathering revenue. The majority of our discontinued operations was a significant portion of Laredo Midstream's operations, which was included in the Anadarko Basin Sale.

Our loss from discontinued operations, net of tax for the year ended December 31, 2011, is inclusive of impairment expense of $0.2 million to reflect our materials and supplies inventory at the lower of cost or market value calculated as of December 31, 2011. It was determined for the years ended December 31, 2013 and 2012, that a lower of cost or market adjustment was not needed for materials and supplies.

Liquidity and capital resources

Since our IPO, our primary sources of liquidity have been cash flows from operations, proceeds from our IPO, proceeds from our senior unsecured notes offerings, borrowings under our Senior Secured Credit Facility, proceeds from the Anadarko Basin Sale and proceeds from our Follow-on Offering. Our primary use of capital has been for the exploration, development and acquisition of oil and natural gas properties.

On March 22, 2013, we filed a shelf registration statement, which became automatically effective, that permits us to sell equity and/or debt in one or more offerings of an indeterminate aggregate amount. As we pursue reserves and production growth, we continually consider which capital resources, including equity and debt financings, are available to meet our future financial obligations, capital expenditure activities and liquidity requirements. Our future ability to grow proved reserves and production will be highly dependent on the capital resources available to us. We continually monitor market conditions and may consider issuing more equity or taking on additional debt.

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On January 23, 2014, we completed an offering of $450.0 million in aggregate principal amount of 5 5/8% senior notes due 2022, which will mature on January 15, 2022 with interest accruing at a rate of 5 5/8% per annum and payable semi-annually in cash in arrears on January 15 and July 15 of each year, commencing July 15, 2014.

As of December 31, 2013, we had no amounts of principal outstanding under our Senior Secured Credit Facility and $1.05 billion in senior unsecured notes, excluding the unamortized premium of $1.5 million received on the October 2011 offering of our 2019 senior unsecured notes. We had $825.0 million available for borrowings under our Senior Secured Credit Facility and $198.2 million in cash on hand for total available liquidity of $1.0 billion as of December 31, 2013. We believe such availability as well as cash flows from operations provide us with the ability to implement our planned exploration and development activities. As a result of the issuance of the new senior unsecured notes on January 23, 2014, the borrowing base under our Senior Secured Credit Facility was reduced to $812.5 million.

As of February 26, 2014 we had $1.5 billion in debt outstanding (including the new senior unsecured notes), $812.5 million available for borrowings under our Senior Secured Credit Facility, and $624.2 million in cash on hand for total available liquidity of $1.4 billion.

We expect, in the future, our commodity derivative positions will help us stabilize a portion of our expected cash flows from operations despite possible declines in the price of oil and natural gas. Please see "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" below.

Cash flows

Our cash flows from continued and discontinued operations for the periods presented are as follows:

		For the years ended December 31,
(in thousands)		2013				2012				2011
Net cash provided by operating activities		$	364,729			$	376,776			$	344,076
Net cash used in investing activities		(329,884		)		(940,751		)		(706,787		)
Net cash provided by financing activities		130,084				569,197				359,478
Net increase (decrease) in cash		$	164,929			$	5,222			$	(3,233	)

The results of operations of the pipeline assets and various other associated property and equipment sold as a component of the Anadarko Basin Sale have been presented as results of discontinued operations, net of tax. We do not disclose discontinued operations separately from cash flows from continued operations due to the immateriality of the cash flows from discontinued operations. The absence of these discontinued operations will not materially affect future liquidity or capital resources.

Cash flows provided by operating activities

Net cash provided by operating activities was $364.7 million, $376.8 million and $344.1 million for the years ended December 31, 2013, 2012 and 2011, respectively. The decrease of $12.0 million from 2012 to 2013 is largely due to an increase in our gains on derivatives and various expense items, which were offset by our increased revenues due to production growth driven by our successful drilling program as well as increases in the market prices for oil and natural gas. The increase of $32.7 million from 2011 to 2012 was largely due to significant increases in revenue due to production growth driven by our successful drilling program, offset by decreases in the market prices for oil and natural gas.

Our operating cash flows are sensitive to a number of variables, the most significant of which are production levels and the variability of oil and natural gas prices. Regional and worldwide economic activity, weather, infrastructure, capacity to reach markets, costs of operations and other variable factors significantly impact the prices of these commodities. These factors are not within our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see "Item 7A. Quantitative and Qualitative Disclosures About Market Risk."

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Cash flows used in investing activities

Our cash used in investing activities for acquisitions and capital expenditures and our proceeds from asset disposals for the periods presented are summarized in the table below.

		For the years ended December 31,
(in thousands)		2013				2012				2011
Acquisitions		$	(33,710	)		$	(20,496	)		$	—
Capital expenditures:
Investment in equity method investee		(3,287		)		—				—
Oil and natural gas properties		(702,349		)		(895,312		)		(687,062		)
Pipeline and gathering assets		(24,409		)		(16,241		)		(13,368		)
Other fixed assets		(16,257		)		(8,755		)		(6,413		)
Proceeds from other asset disposals		450,128				53				56
Net cash used in investing activities		$	(329,884	)		$	(940,751	)		$	(706,787	)

Net cash flows used in investing activities were $329.9 million, $940.8 million and $706.8 million for the years ended December 31, 2013, 2012 and 2011, respectively. The decrease of $610.9 million from 2012 to 2013 was largely due to the proceeds we received from the Anadarko Basin Sale as well as decreased capital expenditures for 2013 compared to 2012. The increase of $234.0 million from 2011 to 2012 was due to (i) an increase in our drilling efforts in our Permian Basin and Anadarko Granite Wash areas in order to take advantage of strategic vertical and horizontal drilling opportunities, (ii) the increased stabilization of oil prices and (iii) additional efforts on delineation drilling.

Capital expenditure budget

Our board of directors approved a budget of approximately $1.0 billion for calendar year 2014, excluding acquisitions. We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted.

The amount, timing and allocation of capital expenditures are largely discretionary and within management's control. If oil and natural gas prices decline to levels below our acceptable levels, or costs increase to levels above our acceptable levels, we may choose to defer a portion of our budgeted capital expenditures until later periods in order to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow. We may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We consistently monitor and adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, contractual obligations, internally generated cash flow and other factors both within and outside our control.

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Cash flows provided by financing activities

Our cash provided by financing activities for the periods presented is summarized in the table below.

		For the years ended December 31,
(in thousands)		2013				2012				2011
Broad Oak transaction		$	—			$	—			$	(81,963	)
Borrowings on revolving credit facilities		230,000				360,000				790,100
Payments on revolving credit facilities		(395,000		)		(280,000		)		(1,096,700		)
Payments on term loan		—				—				(100,000		)
Issuance of 2019 Notes		—				—				552,000
Issuance of 2022 Notes		—				500,000				—
Proceeds from issuance of common stock, net of offering costs		298,104				—				319,378
Purchase of equity interests and units, net		—				—				(164		)
Proceeds from exercise of employee stock options		2,050				—				—
Purchase of treasury stock		(2,083		)		—				(3		)
Payments for loan costs		(2,987		)		(10,803		)		(23,170		)
Net cash provided by financing activities		$	130,084			$	569,197			$	359,478

Net cash provided by financing activities for the year ended December 31, 2013 was the result of proceeds from the Follow-on Offering of $298.1 million and proceeds from the exercise of employee stock options of $2.1 million. These cash inflows were partially offset by the $165.0 million net payments on our Senior Secured Credit Facility, payments for loan costs totaling $3.0 million and the purchase of treasury stock to satisfy employee tax withholding obligations that arise upon the lapse of restrictions on restricted stock totaling $2.1 million.

For the year ended December 31, 2012, net cash provided by financing activities was primarily the result of $500.0 million in gross proceeds from the issuance of our 2022 senior unsecured notes on April 27, 2012 and net borrowings on our Senior Secured Credit Facility of $80.0 million. These cash inflows were partially offset by payments of $10.8 million for loan costs.

For the year ended December 31, 2011, net cash provided by financing activities was primarily the result of $552.0 million in gross proceeds from the issuance of our 2019 senior unsecured notes of $350.0 million on January 20, 2011 and $202.0 million on October 19, 2011, net proceeds from our IPO of $319.4 million, net payments on our Senior Secured Credit Facility and former Broad Oak credit facility totaling $306.6 million, the payment of $100.0 million to pay in full and terminate our term loan and payments of $23.2 million for loan costs. Additionally, we incurred $82.0 million in debt to facilitate the Broad Oak acquisition.

Debt

As of December 31, 2013, we were a party only to our Senior Secured Credit Facility and the indentures governing our 2019 and 2022 senior unsecured notes. The Broad Oak credit facility was terminated on July 1, 2011 in conjunction with the Broad Oak acquisition. Our term loan facility was paid in full and retired in conjunction with the closing of the January 2011 offering of our 2019 senior unsecured notes.

Senior Secured Credit Facility.    As of December 31, 2013, our Senior Secured Credit Facility, which matures November 4, 2018, had a capacity of $2.0 billion and a borrowing base of $925.0 million with an aggregate elected commitment of $825.0 million and no amounts outstanding.

    Principal amounts borrowed under the Senior Secured Credit Facility are payable on the final maturity date with such borrowings bearing interest that is payable, at our election, either on the last day of each fiscal quarter at an Adjusted Base Rate or at the end of one-, two-, three-, six- or, to the extent available, 12-month interest periods (and in the case of six- and 12-month interest periods, every three months prior to the end of such interest period) at an Adjusted London Interbank Offered Rate ("LIBOR"), in each case, plus an applicable margin based on the ratio of the outstanding amount on the Senior Secured Credit Facility to the elected commitment. We are also required to pay an annual commitment fee on the unused portion of the bank's commitment of 0.375% to 0.5%.

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As of December 31, 2013, 2012 and 2011, borrowings outstanding under our Senior Secured Credit Facility totaled zero, $165.0 million and $85.0 million, respectively. As of February 26, 2014, no amounts were outstanding under our Senior Secured Credit Facility and the amount available for borrowings was $812.5 million.

Our Senior Secured Credit Facility is secured by a first-priority lien on our assets, including oil and natural gas properties constituting at least 80% of the present value of our proved reserves owned now or in the future. As of December 31, 2013, we were subject to the following financial and non-financial ratios on a consolidated basis:

•	a current ratio at the end of each fiscal quarter, as defined by the agreement, that is not permitted to be less than 1.00 to 1.00; and

•	at the end of each fiscal quarter, the ratio of earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses and other non-cash charges ("EBITDAX") for the four fiscal quarters ending on the relevant date to the sum of net interest expense plus letter of credit fees, in each case for such period, is not permitted to be less than 2.50 to 1.00.

Our Senior Secured Credit Facility contains both financial and non-financial covenants. We were in compliance with these covenants as of December 31, 2013, 2012 and 2011.

Our Senior Secured Credit Facility contains various covenants that limit our ability to:

•	incur indebtedness;

•	pay dividends and repay certain indebtedness;

•	grant certain liens;

•	merge or consolidate;

•	engage in certain asset dispositions;

•	use proceeds for any purpose other than to finance the acquisition, exploration and development of mineral interests and for working capital and general corporate purposes;

•	make certain investments;

•	enter into transactions with affiliates;

•	engage in certain transactions that violate ERISA or the Internal Revenue Code or enter into certain employee benefit plans and transactions;

•	enter into certain swap agreements or hedge transactions;

•	incur, become or remain liable under any operating lease which would cause rentals payable to be greater than $10.0 million in a fiscal year;

•	acquire all or substantially all of the assets or capital stock of any person, other than assets consisting of oil and natural gas properties and certain other oil and natural gas related acquisitions and investments; and

•	repay or redeem our senior unsecured notes, or amend, modify or make any other change to any of the terms in our senior unsecured notes that would change the term, life, principal, rate or recurring fee, add call or pre-payment premiums, or shorten any interest periods.

As of December 31, 2013, we were in compliance with the terms of our Senior Secured Credit Facility. If an event of default exists under our Senior Secured Credit Facility, the lenders will be able to accelerate the maturity of our Senior Secured Credit Facility and exercise other rights and remedies. As of December 31, 2013, each of the following would be an event of default:

•	failure to pay any principal of any note or any reimbursement obligation under any letter of credit when due or any interest, fees or other amount within certain grace periods;

•	failure to perform or otherwise comply with the covenants in the Senior Secured Credit Facility and other loan documents, subject, in certain instances, to certain grace periods;

•	a representation, warranty, certification or statement is proved to be incorrect in any material respect when made;

•	failure to make any payment in respect of any other indebtedness in excess of $25.0 million, any event occurs that permits or causes the acceleration of any such indebtedness or any event of default or termination event under a hedge agreement occurs in which the net hedging obligation owed is greater than $25.0 million;

•	voluntary or involuntary bankruptcy or insolvency events involving us or our subsidiary and in the case of an involuntary proceeding, such proceeding remains undismissed and unstayed for the applicable grace period;

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•	one or more adverse judgments in excess of $25.0 million to the extent not covered by acceptable third party insurers, are rendered and are not satisfied, stayed or paid for the applicable grace period;

•	incurring environmental liabilities which exceed $25.0 million to the extent not covered by acceptable third party insurers;

•	the loan agreement or any other loan paper ceases to be in full force and effect, or is declared null and void, or is contested or challenged, or any lien ceases to be a valid, first priority, perfected lien;

•	failure to cure any borrowing base deficiency in accordance with the Senior Secured Credit Facility;

•	a change of control, as defined in our Senior Secured Credit Facility; and

•	notification if an "event of default" shall occur under the indentures governing our senior unsecured notes.

Additionally, our Senior Secured Credit Facility provides for the issuance of letters of credit, limited in the aggregate to the lesser of $20.0 million and the total availability under the facility. No letters of credit were outstanding as of December 31, 2013.

Termination of the Broad Oak credit facility.    At June 30, 2011, Broad Oak had a $600.0 million revolving credit facility under its seventh amendment executed on February 1, 2011 between Broad Oak and certain financial institutions. Under the seventh amendment, the borrowing base was redetermined at $375.0 million. As defined in the Broad Oak credit facility, the Adjusted Base Rate Advances and Eurodollar Advances under the facilities bore interest payable quarterly at an Adjusted Base Rate or Adjusted LIBOR plus an applicable margin based on the ratio of outstanding revolving credit to the conforming borrowing base. At June 30, 2011, the applicable margin rates were 1.50% for the Adjusted Base Rate advances and 2.50% for the Eurodollar advances. Additionally, Broad Oak was also required to pay a quarterly commitment fee of 0.5% on the unused portion of the bank's commitment. The Broad Oak credit facility was secured by a first priority lien on Broad Oak's oil and natural gas properties. Concurrently with the Broad Oak acquisition on July 1, 2011, the Broad Oak credit facility was paid in full and terminated.

Senior unsecured notes. On January 20, 2011 and October 19, 2011, Laredo Petroleum, Inc. completed the offerings of $350.0 million principal amount and $200.0 million principal amount, respectively, 9 1/2% senior unsecured notes due 2019. The 2019 senior unsecured notes will mature on February 15, 2019 and bear an interest rate of 9 1/2% per annum, payable semi-annually, in cash in arrears on February 15 and August 15 of each year. Our 2019 senior unsecured notes were fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by Laredo Petroleum Holdings, Inc. and its subsidiaries (other than Laredo Petroleum, Inc.) (collectively, the “guarantors”), and, following the Internal Consolidation, they are fully and unconditionally guaranteed on a senior unsecured basis by Laredo Midstream. Our 2019 senior unsecured notes were issued under and are governed by an indenture dated January 20, 2011, among Laredo Petroleum, Inc., Wells Fargo Bank, National Association, as trustee, and the guarantors (as supplemented, the “2011 indenture”). The 2011 indenture contains customary terms, events of default and covenants relating to, among other things, the incurrence of debt, the payment of dividends or similar restricted payments, entering into transactions with affiliates and limitations on asset sales. Indebtedness under our 2019 senior unsecured notes may be accelerated in certain circumstances upon an event of default as set forth in the 2011 indenture.

On April 27, 2012, Laredo Petroleum, Inc. completed an offering of $500.0 million aggregate principal amount of 7 3/8% senior unsecured notes due 2022. The 2022 senior unsecured notes will mature on May 1, 2022 and bear an interest rate of 7 3/8% per annum, payable semi-annually, in cash in arrears on May 1 and November 1 of each year, commencing November 1, 2012. The 2022 senior unsecured notes were fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by Laredo Petroleum Holdings, Inc. and the guarantors, and, following the Internal Consolidation, they are fully and unconditionally guaranteed on a senior unsecured basis by Laredo Midstream. Our 2022 senior unsecured notes were issued under and are governed by an indenture and supplement thereto, each dated April 27, 2012 (collectively, and as further supplemented, the “2012 indenture”), among Laredo Petroleum, Inc., Wells Fargo Bank, National Association, as trustee, and the guarantors. The 2012 indenture contains customary terms, events of default and covenants relating to, among other things, the incurrence of debt, the payment of dividends or similar restricted payments, entering into transactions with affiliates and limitations on asset sales. Indebtedness under our 2022 senior unsecured notes may be accelerated in certain circumstances upon an event of default as set forth in the 2012 indenture. The net proceeds from the 2022 senior unsecured notes were used (i) to pay in full $280.0 million outstanding under our Senior Secured Credit Facility, and (ii) for general working capital purposes.

Refer to Note D of our audited consolidated financial statements included elsewhere in this Annual Report for further discussion of the 2019 senior unsecured notes and the 2022 senior unsecured notes.

On January 23, 2014, Laredo completed an offering of $450.0 million in aggregate principal amount of 5 5/8% senior unsecured notes due 2022, which will mature on January 15, 2022 with interest accruing at a rate of 5 5/8% per annum and

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payable semi-annually in cash in arrears on January 15 and July 15 of each year, commencing July 15, 2014. The notes are guaranteed on a senior unsecured basis by Laredo Midstream and certain of our future restricted subsidiaries. As a result of the issuance of these notes, the amount available for borrowings under our Senior Secured Credit Facility was decreased to $812.5 million.

As of February 26, 2014, we had a total of $1.5 billion of senior unsecured notes outstanding.

Obligations and commitments

We had the following significant contractual obligations and commitments that will require capital resources as of December 31, 2013:

		Payments due
(in thousands)		Less than 1 year				1 - 3 years				3 - 5 years				More than 5 years				Total
Senior Secured Credit Facility(1)		$	—			$	—			$	—			$	—			$	—
2019 and 2022 Senior unsecured notes(2)		89,125				178,250				178,250				1,205,188				1,650,813
Drilling rig commitments(3)		40,799				—				—				—				40,799
Derivatives(4)		7,419				5,524				—				—				12,943
Asset retirement obligations(5)		265				2,399				1,250				17,829				21,743
Office and equipment leases(6)		1,994				4,011				3,561				1,367				10,933
Performance unit liability awards(7)		—				4,450				—				—				4,450
Capital contribution commitment to equity method investee(8)		25,693				—				—				—				25,693
Total		$	165,295			$	194,634			$	183,061			$	1,224,384			$	1,767,374

___________________________________________________________________________

(1)	As of December 31, 2013, our Senior Secured Credit Facility had no amounts outstanding.

(2)	Values presented include both our principal and interest obligations.

(3)

As of December 31, 2013, we had several drilling rigs under term contracts which expire during 2014. Any other rig performing work for us is doing so on a well-by-well basis and therefore can be released without penalty at the conclusion of drilling on the current well. Therefore, drilling obligations on well-by-well rigs have not been included in the table above. The value in the table represents the gross amount that we are committed to pay. However, we will record our proportionate share based on our working interest in our audited consolidated financial statements as incurred. See Note J to our audited consolidated financial statements included elsewhere in this Annual Report for additional discussion of our drilling contract commitments.

(4)	Represents payments due for deferred premiums on our commodity hedging contracts.

(5)

Amounts represent our estimate of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See Note B to our audited consolidated financial statements included elsewhere in this Annual Report.

(6)	See Note J to our audited consolidated financial statements included elsewhere in this Annual Report for a description of lease obligations.

(7)

Represents cash awards that were granted on February 3, 2012 and February 15, 2013 under the 2011 Omnibus Equity Incentive Plan. The payout of the performance units is dependent upon our relative total shareholder return performance against a set of peers and will be paid out in 2015 and 2016. See Note B to our audited consolidated financial statements included elsewhere in this Annual Report for additional discussion of our performance units.

(8)	See Note M to our consolidated financial statements included elsewhere in this Annual Report for a discussion of our equity method investee.

Critical accounting policies and estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and

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uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our consolidated financial statements. See Note B to our consolidated financial statements included elsewhere in this Annual Report for a discussion of additional accounting policies and estimates made by management.

Method of accounting for oil and natural gas properties

The accounting for our business is subject to special accounting rules that are unique to the oil and natural gas industry. There are two allowable methods of accounting for oil and natural gas business activities: the successful efforts method and the full cost method. We follow the full cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized. We also capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities.

Under the full cost method, capitalized costs are amortized on a composite unit of production method based on proved oil and natural gas reserves. If we maintain the same level of production year over year, the depletion, depreciation and amortization expense may be significantly different if our estimate of remaining reserves or future development costs changes significantly. Proceeds from the sale of properties are accounted for as reductions of capitalized costs unless such sales involve a significant change in the relationship between costs and proved reserves, in which case a gain or loss is recognized. The costs of unproved properties are excluded from amortization until the properties are evaluated. We review all of our unevaluated properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties, and otherwise if impairment has occurred.

Oil and natural gas reserve quantities and standardized measure of future net revenue

Our independent reserve engineers prepare the estimates of oil and natural gas reserves and associated future net cash flows. The SEC has defined proved reserves as the estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The process of estimating oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.

Revenue recognition

Revenue from our interests in producing wells is recognized when the product is delivered, at which time the customer has taken title and assumed the risks and rewards of ownership and collectability is reasonably assured. The sales prices for oil and natural gas are adjusted for transportation and other related deductions. These deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these revenue deductions are adjusted to reflect actual charges based on third party documents. Since there is a ready market for oil and natural gas, we sell the majority of production soon after it is produced at various locations.

Variable interest entities   

An entity is referred to as a variable interest entity ("VIE") pursuant to accounting guidance for consolidation if it possesses one of the following criteria: (i) it is thinly capitalized, (ii) the residual equity holders do not control the entity, (iii) the equity holders are shielded from the economic losses, (iv) the equity holders do not participate fully in the entity's residual economics, or (v) the entity was established with non-substantive voting interests. We would consolidate a VIE when we are the primary beneficiary of a VIE. A primary beneficiary has the power to direct the activities that most significantly impact the activities of the VIE and the right to receive the benefits or the obligation to absorb the losses of the entity that could be potentially significant to the VIE. We continually monitor our unconsolidated VIE exposure in order to determine if any events have occurred that could cause the primary beneficiary to change. See Note M to our consolidated financial statements included elsewhere in this Annual Report for a discussion of our unconsolidated VIE.

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Impairment of oil and natural gas properties

We review the carrying value of our oil and natural gas properties under the full cost accounting rules of the SEC on a quarterly basis. This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. For the years ended December 31, 2013, 2012 and 2011, the result of the ceiling test concluded that the carrying amount of our oil and natural gas properties was significantly below the calculated ceiling test value and as such, our properties were not impaired and a write-down was not required. In calculating future net revenues, current prices are calculated as the average oil and natural gas prices during the 12-month period prior to the end of the current reporting period, determined as the unweighted arithmetic average first-day-of-the-month prices for the prior 12-month period and costs used are those as of the end of the appropriate quarterly period.

Asset retirement obligations

In accordance with the Financial Accounting Standard Board's (the "FASB") authoritative guidance on asset retirement obligations ("ARO"), we record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. For oil and natural gas properties, this is the period in which the well is drilled or acquired. The ARO represents the estimated amount we will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable state laws. The liability is accreted to its present value each period and the capitalized cost is depreciated on the unit of production method. The accretion expense is recorded as a component of depletion, depreciation and amortization in our consolidated statement of operations.

We determine the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. Included in the fair value calculation are assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

Derivatives

We record all derivatives on the balance sheet as either assets or liabilities measured at their estimated fair value. We have not designated any derivatives as hedges for accounting purposes and we do not enter into such instruments for speculative trading purposes. Gains and losses from the settlement of commodity derivatives and gains and losses from valuation changes in the remaining unsettled commodity derivatives are reported under "Non-operating income (expense)" in our consolidated statements of operations.

Stock-based compensation

We measure stock-based compensation expense at the grant date based on the fair value of an award and recognize the compensation expense on a straight-line basis over the service period, which is usually the vesting period. The fair value of the awards is based on the value of our common stock on the date of grant. The determination of the fair value of an award requires significant estimates and subjective judgments regarding, among other things, the appropriate option pricing model, the expected life of the award and forfeiture rate assumptions. Beginning in the first quarter of 2012, we utilized the Black-Scholes option pricing model to measure the fair value of stock options granted under our 2011 Omnibus Equity Incentive Plan. As there are inherent uncertainties related to these factors and our judgment in applying them to the fair value determinations, there is risk that the recorded stock compensation may not accurately reflect the amount ultimately earned by the employee. Refer to Note E of our consolidated financial statements included elsewhere in this Annual Report for additional information regarding our stock-based compensation.

Performance unit compensation

For performance unit awards issued to management, we utilized a Monte Carlo simulation prepared by an independent third party to determine the fair value of the awards at the date of grant and to re-measure the fair value at the end of each reporting period until settlement in accordance with GAAP. The volatility criteria utilized in the Monte Carlo simulation is based on the stock prices' expected volatility. The performance unit awards are classified as liability awards as they have a combination of performance and service criteria and will be settled in cash at the end of the requisite service period based on the achievement of certain performance criteria. The liability and related compensation expense for each period for these awards is recognized by dividing the fair value of the total liability by the requisite service period and recording the pro rata share for the period for which service has already been provided. Compensation expense for the performance units is included

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in “General and administrative” expense in our consolidated statements of operations with the corresponding liability recorded in the “Other noncurrent liabilities” section of our consolidated balance sheet. As there are inherent uncertainties related to the factors and our judgment in applying them to the fair value determinations, there is risk that the recorded performance unit compensation may not accurately reflect the amount ultimately earned by the member of management. Refer to Note E of our consolidated financial statements included elsewhere in this Annual Report for additional information regarding our performance unit awards.

Income taxes

As of December 31, 2013, we had a deferred tax liability of $12.7 million and as of December 31, 2012 and 2011, we had deferred tax assets of $62.6 million and $95.6 million, respectively.

As part of the process of preparing the consolidated financial statements, we are required to estimate the federal and state income taxes in each of the jurisdictions in which we operate. This process involves estimating the actual current tax exposure together with assessing temporary differences resulting from differing treatment of items such as derivative instruments, depletion, depreciation and amortization, and certain accrued liabilities for tax and financial accounting purposes. These differences and our net operating loss carry-forwards result in deferred tax assets and liabilities, which are included in our consolidated balance sheet. We must then assess, using all available positive and negative evidence, the likelihood that the deferred tax assets will be recovered from future taxable income. If we believe that recovery is not likely, we must establish a valuation allowance. Generally, to the extent we establish a valuation allowance or increase or decrease this allowance in a period, we must include an expense or reduction of expense within the tax provision in the consolidated statement of operations.

Under accounting guidance for income taxes, an enterprise must use judgment in considering the relative impact of negative and positive evidence. The weight given to the potential effect of negative and positive evidence should be commensurate with the extent to which it can be objectively verified. The more negative evidence that exists (i) the more positive evidence is necessary and (ii) the more difficult it is to support a conclusion that a valuation allowance is not needed for all or a portion of the deferred tax asset. Among the more significant types of evidence that we consider are:

•	our earnings history exclusive of the loss that created the future deductible amount coupled with evidence indicating that the loss is an aberration rather than a continuing condition;

•	the ability to recover our net operating loss carry-forward deferred tax assets in future years;

•	the existence of significant proved oil and natural gas reserves;

•	our ability to use tax planning strategies as well as current price protection utilizing oil and natural gas hedges; and

•	future revenue and operating cost projections that indicate we will produce more than enough taxable income to realize the deferred tax asset based on existing sales prices and cost structures.

During 2013, in evaluating whether it was more-likely-than-not that our deferred tax asset was recoverable from future net income, we considered our strong earnings history for the current and most recent two years.

We also determined through our analysis that our net operating loss carry-forward deferred tax asset was recoverable over future years and that we had no material net operating losses expiring prior to 2026. In performing our analysis, we used inputs from third party sources, which came primarily from our reserve reports that were independently estimated by a third party engineer. Based on our forecasted results from multiple analyses, as of December 31, 2013 and 2012, future taxable income from our oil and natural gas reserves is expected to be sufficient to utilize the entire net operating loss carry-forward in approximately seven to ten years. We believe this analysis provides significant positive evidence that is objectively verifiable, as it uses three-year historical operating results to predict future taxable income. We considered all applicable tax deductions in our analysis which were substantially known and were not subject to significant estimates.

As of December 31, 2013, we had charitable contribution carry-forwards of $0.4 million, which will begin to expire in 2013. The utilization of charitable contributions for any tax year is limited to 10% of taxable income without regard to charitable contributions, net operating losses, and dividend received deductions. A corporation is permitted to carry-over to the five succeeding tax years contributions that exceeded the 10% limitation, but deductions in those years are also subject to the maximum limitation. Based on our analysis, we do not believe it is more-likely-than-not that we will utilize the carry-forward in its entirety before expiration, therefore, a full valuation allowance of $0.1 million has been recorded against the related deferred tax asset.

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Based on our analysis, we determined as of December 31, 2013 that given the proper weight of the positive evidence noted above, it was more-likely-than-not that our deferred tax asset would be recovered with the exception of the deferred tax asset related to the charitable contribution carry-over.

We will continue to assess the need for a valuation allowance against deferred tax assets considering all available evidence obtained in future reporting periods. If our assumptions regarding forecasted production, pricing and margins are not achieved by amounts in excess of our sensitivity analysis, it may have a significant impact on the corresponding taxable income which may require a valuation allowance to be recorded against our deferred tax assets at that time.

Income tax windfalls and shortfalls. For certain stock-based compensation awards that are expected to result in a tax deduction under existing tax law, a deferred tax asset is established as we recognize compensation cost for book purposes. Book compensation cost is determined on the grant date and recognized over the award's requisite service period, whereas the related tax deduction is measured on the vesting date for restricted stock and on the exercise date for stock options. The corresponding deferred tax asset also is measured on the grant date and recognized over the service period. As a result, there will almost always be a difference in the amount of compensation cost recognized for book purposes versus the amount of tax deduction that a company may receive. If the tax deduction exceeds the cumulative book compensation cost that we recognized, the tax benefit associated with any excess deduction will be considered an excess benefit or windfall and will be recognized as additional paid-in capital (“APIC”). If the tax deduction is less than the cumulative book compensation cost, the tax effect of the resulting difference is a deficiency or shortfall, and should be charged first to APIC, to the extent of our pool of windfall tax benefits, with any remainder recognized in income tax expense. We utilize a one-pool approach when accounting for the pool of windfall tax benefits. In the one-pool approach, employees and non-employees are grouped into a single pool. As of December 31, 2013, we did not have any eligible windfall tax benefits to offset future shortfalls as no excess tax benefits have been recognized.

Recent accounting pronouncements

In July 2013, the FASB issued guidance on the presentation of unrecognized tax benefits when a net operating loss carry-forward, a similar tax loss, or a tax credit carry-forward exists at the reporting date. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. We do not expect the adoption to have an impact on our consolidated financial statements.

Inflation

Inflation in the U.S. has been relatively low in recent years and did not have a material impact on our results of operations for the period from December 31, 2011 through the year ended December 31, 2013. Although the impact of inflation has been insignificant in recent years, it continues to be a factor in the U.S. economy and we do experience inflationary pressure on the costs of oilfield services and equipment as drilling activity increases in the areas in which we operate.

Off-balance sheet arrangements

Currently, we do not have any off-balance sheet arrangements other than operating leases, which are included in "—Obligations and commitments."

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Item 7A.    Quantitative and Qualitative Disclosures About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for hedging purposes, rather than for speculative trading.

     Commodity price exposure. Due to the inherent volatility in oil and natural gas prices, we use commodity derivatives, such as collars, swaps, puts and basis swaps to hedge price risk associated with a significant portion of our anticipated oil and natural gas production. By removing a majority of the price volatility associated with future production, we expect to reduce, but not eliminate, the potential effects of variability in cash flows from operations due to fluctuations in commodity prices. We have not elected hedge accounting on these derivatives and, therefore, the gains and losses on open positions are reflected in earnings. At each period end, we estimate the fair value of our commodity derivatives using an independent third-party valuation and recognize the associated gain or loss in our consolidated statements of operations included elsewhere in this Annual Report.

     Our hedged positions as of December 31, 2013 are as follows:

		Year  2014				Year  2015				Year  2016				Year 2017				Year 2018				Total
Oil(1)
Total volume hedged with ceiling price (Bbl)		5,103,496				6,557,020				1,860,000				—				—				13,520,516
Weighted average ceiling price ($/Bbl)		$	100.01			$	95.40			$	91.37			$	—			$	—			$	96.59
Total volume hedged with floor price (Bbl)		5,643,496				7,013,020				1,860,000				—				—				14,516,516
Weighted average floor price ($/Bbl)		$	87.97			$	79.50			$	80.00			$	—			$	—			$	82.86
Natural gas(2)
Total volume hedged with ceiling price (MMBtu)		9,600,000				8,160,000				—				—				—				17,760,000
Weighted average ceiling price ($/MMBtu)		$	5.50			$	6.00			$	—			$	—			$	—			$	5.73
Total volume hedged with floor price (MMBtu)		9,600,000				8,160,000				—				—				—				17,760,000
Weighted average floor price ($/MMBtu)		$	3.00			$	3.00			$	—			$	—			$	—			$	3.00
Oil basis swaps
Total volume hedged (Bbl)		2,252,000				—				—				—				—				2,252,000
Weighted average price ($/Bbl)(3)		$	(1.04	)		$	—			$	—			$	—			$	—			$	(1.04	)
Total volume hedged (Bbl)		1,840,000				3,650,000				3,660,000				3,650,000				1,810,000				14,610,000
Weighted average price ($/Bbl)(4)		$	(2.85	)		$	(2.85	)		$	(2.85	)		$	(2.85	)		$	(2.85	)		$	(2.85	)

_______________________________________________________________________________

(1)     Oil derivatives are settled based on the average of the daily settlement prices for the First Nearby Month of the NYMEX Light Sweet Crude Oil Futures Contract for each NYMEX Trading Day during each month. Weighted average prices include the West Texas Intermediate Argus Midland and the West Texas Intermediate Argus Cushing basis swaps.

 (2)     Natural gas derivatives are settled based on the Inside FERC index price for West Texas Waha for the calculation period.

 (3)      The associated oil basis swap is settled on the differential between the West Texas Intermediate Argus Midland and the West Texas Intermediate Argus Cushing index oil prices.

 (4)     The associated oil basis swap is settled on the differential between the Light Louisiana Sweet Argus and the Brent International Petroleum Exchange index oil prices.

The fair values of our commodity derivatives are largely determined by estimates of the forward curves of the relevant price indices. As of December 31, 2013, a 10% change in the forward curves associated with our commodity derivatives would have changed our net positions to the following amounts: 

(in thousands)		10% Increase				10% Decrease
Commodity derivatives		$	959			$	153,420

 

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As of December 31, 2013 and 2012, the fair values of our open derivatives contracts were assets of approximately $82.1 million and $2.1 million, respectively. Refer to Notes G and H of our audited consolidated financial statements included elsewhere in this Annual Report for additional disclosures regarding our derivatives.

Interest rate risk. Our Senior Secured Credit Facility bears interest at a floating rate, and as of December 31, 2013, we had no indebtedness outstanding on our Senior Secured Credit Facility. Our 2019 and 2022 senior unsecured notes bear fixed interest rates and we had $550.0 million (excluding the remaining premium of $1.5 million) and $500.0 million outstanding, respectively, as of December 31, 2013, as shown in the table below. 

		Expected maturity date
(in millions except for interest rates)		2013				2014				2015				2016				2017				Thereafter				Total
2019 senior unsecured notes - fixed rate		$	—			$	—			$	—			$	—			$	—			$	550.0			$	550.0
Average interest rate		—		%		—		%		—		%		—		%		—		%		9.5		%		9.5		%
2022 senior unsecured notes - fixed rate		$	—			$	—			$	—			$	—			$	—			$	500.0			$	500.0
Average interest rate		—		%		—		%		—		%		—		%		—		%		7.375		%		7.375		%
Senior Secured Credit Facility - variable rate		$	—			$	—			$	—			$	—			$	—			$	—			$	—
Average interest rate		—		%		—		%		—		%		—		%		—		%		—		%		—		%

 

Refer to Note O.1 of our audited consolidated financial statements included elsewhere in this Annual Report for discussion of our issuance in January 2014 of $450.0 million in aggregate principal amount of 5 5/8% senior notes due 2022.

Through interest rate derivatives, we have attempted to mitigate our exposure to changes in interest rates. In prior years, we have entered into various fixed interest rate swaps and a cap agreement which hedge our exposure to interest rate variations on our Senior Secured Credit Facility. During 2013, we had one interest rate swap and one interest rate cap outstanding for a notional amount of $100.0 million with fixed pay rates of 1.11% and 3.00%, respectively, until their expiration in September 2013.

 

Counterparty and customer credit risk. Our principal exposures to credit risk are through receivables resulting from derivatives ($95.5 million as of December 31, 2013), joint interest receivables ($16.6 million as of December 31, 2013) and the receivables from the sale of our oil and natural gas production ($57.6 million as of December 31, 2013), which we market to energy marketing companies and refineries.

 

We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

 

We have entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with each of our derivative counterparties, who are each lenders in our Senior Secured Credit Facility. The terms of the ISDA Agreements provide us and the counterparties with rights of offset upon the occurrence of defined acts of default by either us or a counterparty to a derivative, whereby the party not in default may offset all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party.

 

Refer to Note I of our audited consolidated financial statements included elsewhere in this Annual Report for additional disclosures regarding credit risk, including from related parties.

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Item 8.    Financial Statements and Supplementary Data

Our consolidated financial statements and supplementary financial data are included in this Annual Report beginning on page F-1.

Item 9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

We had no changes in, and no disagreements with, our accountants on accounting and financial disclosure.

Item 9A.    Controls and Procedures

Evaluation of Disclosure Controls and Procedures.    As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2013 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting.    There have been no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed under the supervision of the Company’s Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with generally accepted accounting principles.

As of December 31, 2013, management assessed the effectiveness of the Company’s internal control over financial reporting based on the criteria for effective internal control over financial reporting established in the 1992 “Internal Control - Integrated Framework,” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment and those criteria, management determined that the Company maintained effective internal control over financial reporting as of December 31, 2013.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

    

Grant Thornton LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Annual Report on Form 10-K, has issued their report on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2013. The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2013, is included in this Item under the heading “Report of Independent Registered Public Accounting Firm.”

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

Laredo Petroleum, Inc.

We have audited the internal control over financial reporting of Laredo Petroleum, Inc. (formerly known as Laredo Petroleum Holdings, Inc.) (a Delaware corporation) and subsidiary (formerly subsidiaries) (the “Company”) as of December 31, 2013, based on criteria established in the 1992 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in the 1992 Internal Control-Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of the Company as of and for the year ended December 31, 2013, and our report dated February 27, 2014 expressed an unqualified opinion on those financial statements.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

February 27, 2014

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Item 9B.    Other Information

None.

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Part III

Item 10.    Directors, Executive Officers and Corporate Governance

Information regarding our Code of Conduct and Business Ethics, Code of Ethics For Senior Financial Officers and Corporate Governance Guidelines for our principal executive officer and principal financial and accounting officer are described in "Item 1. Business" in this Annual Report. Pursuant to paragraph 3 of General Instruction G to Form 10-K, we incorporate by reference into this Item 10 the information to be disclosed in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2013.

Item 11.    Executive Compensation

Pursuant to paragraph 3 of General Instruction G to Form 10-K, we incorporate by reference into this Item 11 the information to be disclosed in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2013.

Item 12.    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Pursuant to paragraph 3 of General Instruction G to Form 10-K, we incorporate by reference into this Item 12 the information to be disclosed in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2013.

Item 13.    Certain Relationships and Related Transactions, and Director Independence

Pursuant to paragraph 3 of General Instruction G to Form 10-K, we incorporate by reference into this Item 13 the information to be disclosed in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2013.

Item 14.    Principal Accounting Fees and Services

Pursuant to paragraph 3 of General Instruction G to Form 10-K, we incorporate by reference into this Item 14 the information to be disclosed in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2013.

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Part IV

Item 15.    Exhibits, Financial Statement Schedules

(a)(1)  Financial Statements

Our consolidated financial statements are included under Part II, Item 8 of this Annual Report. For a listing of these statements and accompanying footnotes, see "Index to Consolidated Financial Statements" on page F-1 of this Annual Report.

(a)(2)  Financial Statement Schedules

All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto.

(a)(3)  Exhibits

Exhibit Number			Description
2.1			Agreement and Plan of Merger by and between Laredo Petroleum, LLC and Laredo Petroleum Holdings, Inc., dated as of December 19, 2011 (incorporated by reference to Exhibit 2.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on December 22, 2011).
3.1			Amended and Restated Certificate of Incorporation of Laredo Petroleum Holdings, Inc. (incorporated by reference to Exhibit 3.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on December 22, 2011).
3.2			Certificate of Ownership and Merger, dated as of December 30, 2013 (incorporated by reference to Exhibit 3.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on January 6, 2014).
3.3			Amended and Restated Bylaws of Laredo Petroleum Holdings, Inc. (incorporated by reference to Exhibit 3.2 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on December 22, 2011).
4.1			Form of Common Stock Certificate (incorporated by reference to Exhibit 4.1 of Laredo's Registration Statement on Form 8-A12B/A (File No. 001-35380) filed on January 7, 2014).
4.2			Indenture, dated as of January 20, 2011, among Laredo Petroleum, Inc., the several guarantors named therein, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 of Laredo's Registration Statement on Form S-1 (File No. 333-176439) filed on August 24, 2011).
4.3			Supplemental Indenture, dated as of July 20, 2011, among Laredo Petroleum, Inc., Laredo Petroleum—Dallas, Inc., the guarantors listed on Schedule A thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 of Laredo's Registration Statement on Form S-1 (File No. 333-176439) filed on August 24, 2011).
4.4			Second Supplemental Indenture, dated as of December 19, 2011, among Laredo Petroleum, Inc., Laredo Petroleum Holdings, Inc., the guarantors listed on Schedule A thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.2 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on December 22, 2011).
4.5			Third Supplemental Indenture, dated as of December 19, 2011, among Laredo Petroleum, Inc., Laredo Petroleum Holdings, Inc., the guarantors listed on Schedule A thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.3 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on December 22, 2011).
4.6			Fourth Supplemental Indenture, dated as of December 31, 2013, among the Laredo Petroleum, Inc., Laredo Midstream Services, LLC, and Wells Fargo Bank, National Association, as trustee under the 2011 Indenture (incorporated by reference to Exhibit 4.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on January 6, 2014).

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Exhibit Number			Description
4.7			Indenture, dated as of April 27, 2012, among Laredo Petroleum, Inc., the several guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on April 30, 2012).
4.8			Supplemental Indenture, dated as of April 27, 2012, among Laredo Petroleum, Inc., the several guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on April 30, 2012).
4.9			Second Supplemental Indenture, dated as of December 31, 2013, among Laredo Petroleum Holdings, Inc., Laredo Petroleum, Inc., Laredo Midstream Services, LLC, and Wells Fargo Bank, National Association, as trustee under the 2012 Indenture (incorporated by reference to Exhibit 4.2 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on January 6, 2014).
4.10			Indenture, dated as of January 23, 2014, among Laredo Petroleum, Inc., Laredo Midstream Services, LLC and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on January 24, 2014).
10.1			Third Amended and Restated Credit Agreement, dated as of July 1, 2011, among Laredo Petroleum, Inc., Wells Fargo Bank, N.A., as Administrative Agent, Bank of America, N.A. and JPMorgan Chase Bank, N.A., as Co-Syndication Agents, Societe Generale, Union Bank, N.A. and BMO Harris Financing, Inc., as Co-Documentation Agents, Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated and J.P. Morgan Securities LLC, as Joint Lead Arrangers and the financial institutions listed on Schedule I thereto (incorporated by reference to Exhibit 10.1 of Laredo's Registration Statement on Form S-1 (File No. 333-176439) filed on August 24, 2011).
10.2			First Amendment to Third Amended and Restated Credit Agreement, dated as of October 11, 2011, among Laredo Petroleum, Inc., each of the guarantors thereto, each of the banks signatories thereto, and Wells Fargo Bank, N.A., as administrative agent (incorporated by reference to Exhibit 10.4 of Laredo's Registration Statement on Form S-1A (File No. 333-176439) filed on November 14, 2011).
10.3			Limited Consent and Second Amendment to Third Amended and Restated Credit Agreement, dated as of November 23, 2011, among Laredo Petroleum, Inc., Wells Fargo Bank, N.A., as administrative agent, the guarantors signatories thereto and the banks signatories thereto (incorporated by reference to Exhibit 10.3 of Laredo's Registration Statement on From S-4/A (File No. 333-173984-05) filed on December 12, 2011).
10.4			Third Amendment to Third Amended and Restated Credit Agreement, dated as of April 24, 2012, among Laredo Petroleum, Inc., each of the guarantors thereto, each of the banks signatories thereto, and Wells Fargo Bank, N.A., as administrative agent (incorporated by reference to Exhibit 10.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on April 25, 2012).
10.5			Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of April 27, 2012, among Laredo Petroleum, Inc., each of the guarantors thereto, each of the banks signatories thereto, and Wells Fargo Bank, N.A., as administrative agent (incorporated by reference to Exhibit 10.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on April 30, 2012).
10.6			Fifth Amendment to Third Amended and Restated Credit Facility, dated as of November 7, 2012, among Laredo Petroleum, Inc., Wells Fargo Bank, N.A., as administrative agent, the guarantors signatory thereto and the banks signatory thereto (incorporated by reference to Exhibit 10.1 of Laredo's Quartlery Report on Form 10-Q (File No. 001-35380) filed on November 9, 2012).
10.7			Sixth Amendment to Third Amended and Restated Credit Agreement, dated as of May 29, 2013, among Laredo Petroleum, Inc., Wells Fargo Bank, N.A., as administrative agent, the guarantors signatory thereto and the banks signatory thereto (incorporated by reference to Exhibit 10.1 of Laredo’s Current Report on Form 8-K (File No. 001-35380) filed on May 30, 2013).
10.8			Seventh Amendment to Third Amended and Restated Credit Agreement, dated as of November 4, 2013, among Laredo Petroleum, Inc., Wells Fargo Bank, N.A., as administrative agent, the guarantors signatory thereto and the banks signatory thereto (incorporated by reference to Exhibit 10.1 of Laredo’s Quarterly Report on Form 10-Q (File No. 001-35380) filed on November 7, 2013).
10.9			Fourth Amended and Restated Credit Agreement, dated as of December 31, 2013, among Laredo Petroleum, Inc., as borrower, Wells Fargo Bank, National Association as administrative agent, and the other financial institutions signatory thereto (incorporated by reference to Exhibit 10.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on January 6, 2014).
10.10			First Amendment to Fourth Amended and Restated Credit Agreement, dated as of January 31, 2014, among Laredo Petroleum, Inc., Wells Fargo Bank, N.A., as administrative agent, Laredo Midstream Services, LLC and the banks signatory thereto (incorporated by reference to Exhibit 10.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on February 4, 2014).

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Exhibit Number			Description
10.11			Purchase and Sale Agreement, dated May 20, 2013, by and between Laredo Petroleum, Inc., Laredo Petroleum Texas, LLC, Laredo Gas Services, LLC and EnerVest Energy Institutional Fund XII-WIB, L.P., EnerVest Energy Institutional Fund XII-WIC, L.P., EnerVest Energy Institutional Fund XII-A, L.P., EnerVest Energy Institutional Fund XIII-A, L.P., EnerVest Energy Institutional Fund XIII-WIB, L.P., EnerVest Energy Institutional Fund XIII-WIC, L.P. and EnerVest Operating, L.L.C. (incorporated by reference to Exhibit 10.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on August 1, 2013).
10.12			Contribution Agreement, dated as of June 15, 2011, by and among Broad Oak Energy, Inc., Warburg Pincus Private Equity IX, L.P., the other persons listed as Contributors on the signature pages thereto and Laredo Petroleum, LLC (incorporated by reference to Exhibit 10.2 of Laredo's Registration Statement on Form S-1 (File No. 333-176439) filed on August 24, 2011).
10.13			Stock Purchase and Sale Agreement, dated as of June 15, 2011, by and among Laredo Petroleum, Inc. and the individuals listed as Sellers on the signature pages thereto (incorporated by reference to Exhibit 10.3 of Laredo's Registration Statement on Form S-1 (File No. 333-176439) filed on August 24, 2011).
10.14			Form of Registration Rights Agreement dated December 20, 2011 among Laredo Petroleum Holdings, Inc. and the signatories thereto (incorporated by reference to Exhibit 10.5 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on December 22, 2011).
10.15#			Form of Indemnification Agreement between Laredo Petroleum Holdings, Inc. and each of the officers and directors thereof (incorporated by reference to Exhibit 10.6 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on December 22, 2011).
10.16#			Laredo Petroleum Holdings, Inc. 2011 Omnibus Equity Incentive Plan (incorporated by reference to Exhibit 10.4 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on December 22, 2011).
10.17#			Form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on February 9, 2012).
10.18#			Form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.3 of Laredo's Quarterly Report on Form 10-Q (File No. 001-35380) filed on August 9, 2012).
10.19#			Form of Stock Option Agreement (incorporated by reference to Exhibit 10.2 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on February 9, 2012).
10.20#			Form of Performance Compensation Award Agreement (incorporated by reference to Exhibit 10.3 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on February 9, 2012).
10.21			Laredo Petroleum Holdings, Inc. Change in Control Executive Severance Plan Certificate (incorporated by reference to Exhibit 10.7 of Laredo's Registration Statement on Form S-1/A (File No. 333-176439) filed on November 14, 2011).
10.22#*			Form of 2013 Performance Compensation Award Agreement (incorporated by reference to Exhibit 10.16 of Laredo's Annual Report on Form 10-K (File No. 001-35380) filed on March 12, 2013.
10.23*			Non-Exclusive Aircraft Lease Agreement, dated January 1, 2013 between Lariat Ranch, LLC and Laredo Petroleum, Inc (incorporated by reference to Exhibit 10.17 of Laredo's Annual Report on Form 10-K (file No. 001-35380) filed on March 12, 2013.
10.24			Registration Rights Agreement, dated as of January 23, 2014, among Laredo Petroleum, Inc., Laredo Midstream Services, LLC and the initial purchasers (incorporated by reference to Exhibit 10.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on January 24, 2014).
21.1*			List of Subsidiaries of Laredo Petroleum, Inc.
23.1*			Consent of Grant Thornton LLP.
23.2*			Consent of Ryder Scott Company, L.P.
31.1*			Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
31.2*			Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.

82

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Exhibit Number		Description
32.1**		Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1*		Summary Report of Ryder Scott Company, L.P.
101.INS*		XBRL Instance Document.
101.CAL*		XBRL Schema Document.
101.SCH*		XBRL Calculation Linkbase Document.
101.DEF*		XBRL Definition Linkbase Document.
101.LAB*		XBRL Labels Linkbase Document.
101.PRE*		XBRL Presentation Linkbase Document.

___________________________________________________________________________

* Filed herewith.

** Furnished herewith.

# Management contract or compensatory plan or arrangement.

83

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		LAREDO PETROLEUM, INC.
Date: February 27, 2014		By:		/s/ Randy A. Foutch
				Randy A. Foutch  Chief Executive Officer

KNOWN ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Randy A. Foutch, Richard C. Buterbaugh and Kenneth E. Dornblaser, each of whom may act without joinder of the other, as their true and lawful attorneys-in-fact and agents, each with full power of substitution and resubstitution, for such person and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signatures		Title		Date
/s/ Randy A. Foutch		Chairman and Chief Executive Officer (principal executive officer)		2/27/2014
Randy A. Foutch
/s/ Richard C. Buterbaugh		Executive Vice President and Chief Financial Officer (principal financial and accounting officer)		2/27/2014
Richard C. Buterbaugh
/s/ Jay P. Still		Director, President and Chief Operating Officer		2/27/2014
Jay P. Still
/s/ Peter R. Kagan		Director		2/27/2014
Peter R. Kagan
/s/ James R. Levy		Director		2/27/2014
James R. Levy
/s/ B.Z. (Bill) Parker		Director		2/27/2014
B.Z. (Bill) Parker
/s/ Pamela S. Pierce		Director		2/27/2014
Pamela S. Pierce
/s/ Ambassador Francis Rooney		Director		2/27/2014
Ambassador Francis Rooney
/s/ Dr. Myles W. Soggins		Director		2/27/2014
Dr. Myles W. Scoggins
/s/ Edmund P. Segner, III		Director		2/27/2014
Edmund P. Segner, III
/s/ Donald D. Wolf		Director		2/27/2014
Donald D. Wolf

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Consolidated Financial Statements of Laredo Petroleum, Inc.:
Report of Independent Registered Public Accounting Firm	F-2
Consolidated balance sheets as of December 31, 2013 and 2012	F-3
Consolidated statements of operations for the years ended December 31, 2013, 2012 and 2011	F-4
Consolidated statements of stockholders' equity for the years ended December 31, 2013, 2012 and 2011	F-5
Consolidated statements of cash flows for the years ended December 31, 2013, 2012 and 2011	F-6
Notes to the consolidated financial statements	F-7
Supplemental oil and natural gas disclosures (Unaudited)	F-43
Supplemental quarterly financial data (Unaudited)	F-47

F-1

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

Laredo Petroleum, Inc.

We have audited the accompanying consolidated balance sheets of Laredo Petroleum, Inc. (formerly known as Laredo Petroleum Holdings, Inc.) (a Delaware corporation) and subsidiary (formerly subsidiaries) (the “Company”) as of December 31, 2013 and 2012, and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Laredo Petroleum, Inc. (formerly known as Laredo Petroleum Holdings, Inc.) and subsidiary (formerly subsidiaries) as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2013, based on criteria established in the 1992 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 27, 2014, expressed an unqualified opinion thereon.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

February 27, 2014

F-2

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Laredo Petroleum, Inc.

Consolidated balance sheets

(in thousands, except share data)

	December 31,
	2013				2012
Assets
Current assets:
Cash and cash equivalents	$	198,153			$	33,224
Accounts receivable, net	77,318				83,840
Derivatives	15,806				4,644
Deferred income taxes	3,634				12,713
Other current assets	12,698				3,016
Total current assets	307,609				137,437
Property and equipment:
Oil and natural gas properties, full cost method:
Proved properties	3,276,578				2,993,266
Unproved properties not being amortized	208,085				159,946
Pipeline and gathering assets	44,255				74,877
Other fixed assets	40,281				25,599
Total property and equipment	3,569,199				3,253,688
Less accumulated depletion, depreciation, amortization and impairment	(1,364,875		)		(1,139,797		)
Net property and equipment	2,204,324				2,113,891
Deferred income taxes	—				49,916
Derivatives	79,726				2,058
Deferred loan costs, net	25,933				29,444
Investment in equity method investee	5,913				—
Other assets, net	255				5,558
Total assets	$	2,623,760			$	2,338,304
Liabilities and stockholders' equity
Current liabilities:
Accounts payable	$	16,002			$	48,672
Accrued payable - affiliates	3,489				—
Undistributed revenue and royalties	35,124				36,065
Accrued capital expenditures	116,328				121,612
Accrued compensation and benefits	16,711				10,318
Derivatives	10,795				1,325
Other current liabilities	55,520				44,076
Total current liabilities	253,969				262,068
Long-term debt	1,051,538				1,216,760
Derivatives	2,680				3,260
Deferred income taxes	16,293				—
Asset retirement obligations	21,478				21,120
Other noncurrent liabilities	5,546				3,373
Total liabilities	1,351,504				1,506,581
Commitments and contingencies
Stockholders' equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued at December 31, 2013 and 2012	—				—
Common stock, $0.01 par value, 450,000,000 shares authorized, and 142,671,436 and 128,298,559 issued, net of treasury, at December 31, 2013 and 2012, respectively	1,427				1,283
Additional paid-in capital	1,283,809				961,424
Accumulated deficit	(12,980		)		(130,980		)
Treasury stock, at cost, zero and 7,609 common shares at December 31, 2013 and 2012, respectively	—				(4		)
Total stockholders' equity	1,272,256				831,723
Total liabilities and stockholders' equity	$	2,623,760			$	2,338,304

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

F-3

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Laredo Petroleum, Inc.

Consolidated statements of operations

(in thousands, except per share data)

	For the years ended December 31,
	2013				2012				2011
Revenues:
Oil and natural gas sales	$	664,844			$	583,569			$	506,255
Transportation and treating	413				325				92
Total revenues	665,257				583,894				506,347
Costs and expenses:
Lease operating expenses	79,136				67,325				43,306
Production and ad valorem taxes	42,396				37,637				31,982
Transportation and treating	680				162				65
Transportation and treating - affiliates	891				—				—
Drilling and production	2,688				2,452				2,675
General and administrative (including non-cash stock-based compensation of $21,433, $10,056 and $6,111 for the years ended December 31, 2013, 2012 and 2011, respectively)	89,696				62,106				51,064
Accretion of asset retirement obligations	1,475				1,200				616
Depletion, depreciation and amortization	233,944				241,072				174,119
Total costs and expenses	450,906				411,954				303,827
Operating income	214,351				171,940				202,520
Non-operating income (expense):
Gain (loss) on derivatives:
Commodity derivatives, net	79,902				8,800				21,047
Interest rate derivatives, net	(24		)		(412		)		(1,311		)
Income from equity method investee	29				—				—
Interest expense	(100,327		)		(85,572		)		(50,580		)
Interest and other income	163				59				108
Write-off of deferred loan costs	(1,502		)		—				(6,195		)
Loss on disposal of assets, net	(1,508		)		(51		)		(1		)
Non-operating expense, net	(23,267		)		(77,176		)		(36,932		)
Income from continuing operations before income taxes	191,084				94,764				165,588
Income tax expense:
Deferred	(74,507		)		(33,003		)		(59,612		)
Total income tax expense	(74,507		)		(33,003		)		(59,612		)
Income from continuing operations	116,577				61,761				105,976
Income (loss) from discontinued operations, net of tax	1,423				(107		)		(422		)
Net income	$	118,000			$	61,654			$	105,554
Net income per common share:
Basic:
Income from continuing operations	$	0.88			$	0.49			$	0.99
Income (loss) from discontinued operations, net of tax	0.01				—				(0.01		)
Net income per share	$	0.89			$	0.49			$	0.98
Diluted:
Income from continuing operations	$	0.87			$	0.48			$	0.98
Income (loss) from discontinued operations, net of tax	0.01				—				—
Net income per share	$	0.88			$	0.48			$	0.98
Weighted average common shares outstanding:
Basic	132,490				126,957				107,187
Diluted	134,378				128,171				108,099

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

F-4

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Laredo Petroleum, Inc.

Consolidated statements of stockholders' equity

(in thousands)

	Series A							BOE Preferred							Restricted Units							Treasury Units			Common Stock							Additional paid-in capital				Treasury Stock (at cost)							Other equity interests				Accumulated deficit				Total
	Units			Amount				Units			Amount				Units			Amount							Shares			Amount								Shares			Amount
Balance, December 31, 2010	99,870			$	549,187			—			$	—			31,432			$	4,504			—			—			$	—			$	—			—			$	—			$	155,596			$	(298,188	)		$	411,099
Purchase of equity interests	—			—				—			—				—			—				(125	)		—			—				—				—			—				—				—				(125		)
Cancellation of Series A Units	(20	)		(125		)		—			—				—			—				125			—			—				—				—			—				—				—				—
Stock-based compensation	—			—				—			—				9,859			5,829				—			—			—				—				—			—				132				—				5,961
Purchase of restricted units	—			—				—			—				—			—				(38	)		—			—				—				—			—				—				—				(38		)
Cancellation of restricted units	—			—				—			—				(1,389	)		(37		)		38			—			—				—				—			—				—				—				1
Broad Oak Transaction	—			—				88,986			73,765				—			—				—			—			—				—				—			—				(155,728		)		—				(81,963		)
Common shares issued upon Corporate Reorganization	(99,850	)		(549,062		)		(88,986	)		(73,765		)		(39,902	)		(10,296		)		—			107,500			1,075				632,048				—			—				—				—				—
Common shares issued at initial public offering, net of offering costs	—			—				—			—				—			—				—			20,125			201				319,177				—			—				—				—				319,378
Stock-based compensation	—			—				—			—				—			—				—			—			—				150				—			—				—				—				150
Shares repurchased	—			—				—			—				—			—				—			(8	)		—				—				8			(4		)		—				—				(4		)
Net income	—			—				—			—				—			—				—			—			—				—				—			—				—				105,554				105,554
Balance, December 31, 2011	—			—				—			—				—			—				—			127,617			1,276				951,375				8			(4		)		—				(192,634		)		760,013
Restricted stock awards	—			—				—			—				—			—				—			932			9				(9		)		—			—				—				—				—
Restricted stock forfeitures	—			—				—			—				—			—				—			(251	)		(2		)		2				—			—				—				—				—
Stock-based compensation	—			—				—			—				—			—				—			—			—				10,056				—			—				—				—				10,056
Net income	—			—				—			—				—			—				—			—			—				—				—			—				—				61,654				61,654
Balance, December 31, 2012	—			—				—			—				—			—				—			128,298			1,283				961,424				8			(4		)		—				(130,980		)		831,723
Restricted stock awards	—			—				—			—				—			—				—			1,469			15				(15		)		—			—				—				—				—
Restricted stock forfeitures	—			—				—			—				—			—				—			(229	)		(2		)		2				—			—				—				—				—
Vested restricted stock exchanged for tax withholding	—			—				—			—				—			—				—			—			—				—				95			(2,083		)		—				—				(2,083		)
Retirement of treasury stock	—			—				—			—				—			—				—			(95	)		(1		)		(2,086		)		(103	)		2,087				—				—				—
Exercise of employee stock options	—			—				—			—				—			—				—			104			1				2,049				—			—				—				—				2,050
Equity issuance, net of offering costs	—			—				—			—				—			—				—			13,000			130				297,974				—			—				—				—				298,104
Equity issued for acquisition, net of offering costs	—			—				—			—				—			—				—			124			1				3,028				—			—				—				—				3,029
Stock-based compensation	—			—				—			—				—			—				—			—			—				21,433				—			—				—				—				21,433
Net income	—			—				—			—				—			—				—			—			—				—				—			—				—				118,000				118,000
Balance, December 31, 2013	—			$	—			—			$	—			—			$	—			—			142,671			$	1,427			$	1,283,809			—			$	—			$	—			$	(12,980	)		$	1,272,256

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

F-5

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Laredo Petroleum, Inc.

Consolidated statements of cash flows

(in thousands)

	For the years ended December 31,
	2013				2012				2011
Cash flows from operating activities:
Net income	$	118,000			$	61,654			$	105,554
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income tax expense	75,288				32,949				59,374
Depletion, depreciation and amortization	234,571				243,649				176,366
Bad debt expense	653				—				—
Impairment expense	—				—				243
Non-cash stock-based compensation	21,433				10,056				6,111
Accretion of asset retirement obligations	1,475				1,200				616
Mark-to-market on derivatives:
Gain on derivatives, net	(79,878		)		(8,388		)		(19,736		)
Cash settlements received (paid) for matured derivatives, net	3,745				24,910				(1,154		)
Cash settlements received for early terminations and modifications of derivatives, net	6,008				—				—
Change in net present value of deferred premiums paid for derivatives	462				668				471
Cash premiums paid for derivatives	(10,277		)		(6,118		)		(555		)
Amortization of deferred loan costs	5,023				4,816				3,871
Write-off of deferred loan costs	1,502				—				6,195
Amortization of October 2011 Notes premium	(222		)		(202		)		(39		)
Amortization of other assets	(8		)		19				19
Loss on disposal of assets, net	1,508				52				40
Equity method investee income	(29		)		—				—
Cash settlement of performance unit awards	(2,080		)		—				—
(Increase) decrease in accounts receivable	6,825				(9,705		)		(30,196		)
(Increase) decrease in other assets	(7,438		)		(414		)		(833		)
Increase (decrease) in accounts payable	(32,581		)		2,665				(3,825		)
Increase (decrease) in undistributed revenues and royalties	(941		)		9,221				16,180
Increase (decrease) in accrued compensation and benefits	6,393				(952		)		2,492
Increase (decrease) in other accrued liabilities	10,065				8,801				23,031
Increase (decrease) in other noncurrent liabilities	499				98				(149		)
Increase (decrease) in fair value of performance unit awards	4,733				1,797				—
Net cash provided by operating activities	364,729				376,776				344,076
Cash flows from investing activities:
Capital expenditures:
Acquisitions of oil and natural gas properties	(33,710		)		(20,496		)		—
Investment in equity method investee	(3,287		)		—				—
Oil and natural gas properties	(702,349		)		(895,312		)		(687,062		)
Pipeline and gathering assets	(24,409		)		(16,241		)		(13,368		)
Other fixed assets	(16,257		)		(8,755		)		(6,413		)
Proceeds from dispositions of capital assets, net of costs	450,128				53				56
Net cash used in investing activities	(329,884		)		(940,751		)		(706,787		)
Cash flows from financing activities:
Broad Oak transaction	—				—				(81,963		)
Borrowings on revolving credit facilities	230,000				360,000				790,100
Payments on revolving credit facilities	(395,000		)		(280,000		)		(1,096,700		)
Payments on term loan	—				—				(100,000		)
Issuance of 2019 Notes	—				—				552,000
Issuance of 2022 Notes	—				500,000				—
Proceeds from issuance of common stock, net of offering costs	298,104				—				319,378
Purchase of equity interests and units, net	—				—				(164		)
Proceeds from exercise of employee stock options	2,050				—				—
Purchase of treasury stock	(2,083		)		—				(3		)
Payments for loan costs	(2,987		)		(10,803		)		(23,170		)
Net cash provided by financing activities	130,084				569,197				359,478
Net increase (decrease) in cash and cash equivalents	164,929				5,222				(3,233		)
Cash and cash equivalents, beginning of period	33,224				28,002				31,235
Cash and cash equivalents, end of period	$	198,153			$	33,224			$	28,002

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

F-6

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

A—Organization

The Company (defined below) is an independent energy company focused on the exploration, development and acquisition of oil and natural gas properties primarily in the Permian Basin in West Texas. On August 1, 2013, the Company sold its properties in the Mid-Continent region of the United States (as further described below).

Laredo Petroleum, Inc. (“Laredo”), formerly known as Laredo Petroleum Holdings, Inc., was formed pursuant to the laws of the State of Delaware on August 12, 2011 for purposes of a Corporate Reorganization (defined below) and initial public offering of its common stock (the "IPO"). On December 19, 2011, Laredo Petroleum, LLC ("Laredo LLC"), a Delaware limited liability company, was merged with and into Laredo, with Laredo surviving the merger (the "Corporate Reorganization"). As a holding company, Laredo's management operations were conducted through its wholly-owned subsidiary, Laredo Petroleum, Inc. ("Laredo Inc"), a Delaware corporation, and Laredo Inc’s subsidiaries, Laredo Petroleum Texas, LLC (“Laredo Texas”), a Texas limited liability company, Laredo Gas Services, LLC (“Laredo Gas”), a Delaware limited liability company, and Laredo Petroleum—Dallas, Inc. (“Laredo Dallas”), a Delaware corporation.

Effective December 31, 2013, an internal corporate reorganization was completed, which simplified the corporate structure. Two of Laredo Inc's subsidiaries, Laredo Texas and Laredo Dallas, were merged with and into Laredo Inc. The sole remaining wholly-owned subsidiary of Laredo Inc, Laredo Gas, changed its name to Laredo Midstream Services, LLC ("Laredo Midstream" or "Guarantor"). Laredo Inc merged with and into Laredo with Laredo surviving and changing its name to ‘‘Laredo Petroleum, Inc.’’(the events described in this paragraph collectively, the "Internal Consolidation").

On July 1, 2011, Laredo LLC and Laredo Inc completed the acquisition of Broad Oak Energy, Inc. ("Broad Oak"), a Delaware corporation, for a combination of equity and cash. Prior to the acquisition, Broad Oak was owned by its management and Warburg Pincus Private Equity IX, L.P. ("Warburg Pincus IX"). On July 19, 2011, Broad Oak's name was changed to Laredo Petroleum—Dallas, Inc.

On December 19, 2011, immediately prior to the IPO, Laredo LLC merged with and into Laredo, with Laredo being the surviving entity. Warburg Pincus IX and other affiliates of Warburg Pincus LLC ("Warburg Pincus") were majority owners of Laredo LLC and until November 25, 2013 were of Laredo. The preferred units and certain series of restricted units of Laredo LLC were exchanged into shares of common stock of Laredo based on the pre-offering equity value of such units in the Corporate Reorganization. The common stock has one vote per share and a par value of $0.01 per share.

In these notes, the "Company," (i) when used in the present tense, prospectively or as of December 31, 2013, refers to Laredo and Laredo Midstream collectively; (ii) when used for historical periods from December 19, 2011 to December 30, 2013, refers to Laredo and its subsidiaries, collectively; and (iii) when used for historical periods prior to December 19, 2011 refers to Laredo LLC, Laredo Inc and its subsidiaries, collectively, unless the context indicates otherwise. All amounts, dollars and percentages presented in these consolidated financial statements and the related notes are rounded and therefore approximate.

On August 19, 2013, Laredo, together with certain affiliates of Warburg Pincus and members of the Company's management (together with Warburg Pincus, the "Selling Stockholders") completed the sale of (i) 13,000,000 shares of Laredo's common stock by Laredo and (ii) 3,000,000 shares of Laredo's common stock by the Selling Stockholders, at a price to the public of $23.75 per share ($22.9781 per share, net of underwriting discounts) (the "Follow-on Offering"). On August 27, 2013, certain of the Selling Stockholders sold an additional 1,577,583 shares of Laredo's common stock pursuant to the option to purchase additional shares of Laredo's common stock granted to the associated underwriters. The Company received net proceeds of $298.1 million, after underwriting discounts, commissions, and offering expenses as a result of the Follow-on Offering. The Company did not receive any proceeds from either of the sales of shares of Laredo's common stock by the Selling Stockholders.

B—Basis of presentation and significant accounting policies

1.    Basis of presentation

The accompanying consolidated financial statements were derived from the historical accounting records of the Company and reflect the historical financial position, results of operations and cash flows for the periods described herein. The Broad Oak acquisition discussed in Note A was accounted for in a manner similar to a pooling of interests. The historical financial statements present the assets and liabilities of Laredo and its subsidiaries and Broad Oak at historical carrying values and their operations as if they were consolidated for all periods presented. All material intercompany transactions and account balances have been eliminated in the consolidation of accounts. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). The

F-7

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

Company operates oil and natural gas properties as one business segment, which explores, develops and produces oil and natural gas. Unless otherwise indicated, the information in these notes relate to the Company’s continuing operations.

2.    Use of estimates in the preparation of consolidated financial statements

The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ from these estimates.

Significant estimates include, but are not limited to, (i) estimates of the Company’s reserves of oil and natural gas, (ii) future cash flows from oil and natural gas properties, (iii) depletion, depreciation and amortization, (iv) asset retirement obligations, (v) stock-based compensation, (vi) deferred income taxes, (vii) fair value of assets acquired and liabilities assumed in an acquisition and (viii) fair values of commodity derivatives, interest rate derivatives, commodity deferred premiums and performance unit awards. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment. Such estimates and assumptions are adjusted when facts and circumstances dictate. Illiquid credit markets and volatile equity and energy markets have combined to increase the uncertainty inherent in such estimates and assumptions. Management believes its estimates and assumptions to be reasonable under the circumstances. As future events and their effects cannot be determined with precision, actual values and results could differ from these estimates. Any changes in estimates resulting from future changes in the economic environment will be reflected in the financial statements in future periods.

3.    Reclassifications

Certain amounts in the accompanying consolidated financial statements have been reclassified to conform to the 2013 presentation. These reclassifications had no impact to previously reported net income or losses, total stockholders' equity or cash flows. See Note C for a discussion regarding discontinued operations.

4.    Cash and cash equivalents

The Company maintains cash and cash equivalents in bank deposit accounts and money market funds that may not be federally insured. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on such accounts. The Company defines cash and cash equivalents to include cash on hand, cash in bank accounts and highly liquid investments with original maturities of three months or less.

5.    Accounts receivable

The Company sells oil and natural gas to various customers and participates with other parties in the drilling, completion and operation of oil and natural gas wells. Joint interest and oil and natural gas sales receivables related to these operations are generally unsecured. Accounts receivable for joint interest billings are recorded as amounts billed to customers less an allowance for doubtful accounts.

Amounts are considered past due after 30 days. The Company determines joint interest operations accounts receivable allowances based on management's assessment of the creditworthiness of the joint interest owners and, as the operator in the majority of its wells, the ability to realize the receivables through netting of anticipated future production revenues. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging, and existing industry and economic data. The Company reviews its allowance for doubtful accounts quarterly. Past due balances greater than 90 days and over a specified amount are reviewed individually for collectability. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is remote.

    

F-8

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

Accounts receivable consist of the following components as of December 31:

(in thousands)		2013				2012
Oil and natural gas sales		$	57,647			$	48,445
Joint operations, net(1)		16,629				30,925
Other		3,042				4,470
Total		$	77,318			$	83,840

______________________________________________________________________________

(1)	Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.7 million and $0.1 million as of December 31, 2013 and 2012, respectively.

6.    Derivatives

The Company uses derivatives to reduce exposure to fluctuations in the prices of oil and natural gas. By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flows from operations due to fluctuations in commodity prices. These transactions are primarily in the form of collars, swaps, puts and basis swaps. In addition, the Company enters into derivative contracts in the form of interest rate derivatives to minimize the effects of fluctuations in interest rates.

Derivatives are recorded at fair value and are included on the consolidated balance sheets as assets or liabilities. The Company netted the fair value of derivatives by counterparty in the accompanying consolidated balance sheets where the right of offset exists. The Company determines the fair value of its derivatives utilizing pricing models for substantially similar instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. 

The Company’s derivatives were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities (see Note G).

7.    Other current liabilities

Other current liabilities consist of the following components as of December 31:

(in thousands)		2013				2012
Accrued interest payable		$	25,885			$	26,106
Lease operating expense payable		10,637				9,766
Prepaid drilling liability		1,393				2,916
Production taxes payable		1,303				2,121
Current portion of asset retirement obligations		265				385
Other accrued liabilities		16,037				2,782
Total other current liabilities		$	55,520			$	44,076

8.    Oil and natural gas properties

The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain related employee costs, incurred for the purpose of finding oil and natural gas are capitalized and amortized on a composite units of production method based on proved oil and natural gas reserves. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Costs, including related employee costs, associated with production and general corporate activities are expensed in the period incurred. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas.

The Company computes the provision for depletion of oil and natural gas properties using the units of production method based upon production and estimates of proved reserve quantities. Unevaluated costs and related carrying costs are excluded from the amortization base until the properties associated with these costs are evaluated. Approximately $208.1 million and $159.9 million of such costs were excluded from the amortization base as of December 31, 2013 and 2012,

F-9

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

respectively. The amortization base includes estimated future development costs and dismantlement, restoration and abandonment costs, net of estimated salvage values. Total accumulated depletion for oil and natural gas properties was $1.3 billion and $1.1 billion for the years ended December 31, 2013 and 2012, respectively. Depletion expense for oil and natural gas properties was $228.0 million, $237.1 million and $171.5 million for the years ended December 31, 2013, 2012 and 2011, respectively. There were no impairments recorded for the years ended December 31, 2013, 2012 and 2011. Depletion per barrel of oil equivalent for the Company's oil and natural gas properties was $20.34, $20.98 and $19.82 for the years ended December 31, 2013, 2012 and 2011, respectively.

The Company excludes the costs directly associated with acquisition and evaluation of unproved properties from the depletion calculation until it is determined whether or not proved reserves can be assigned to the properties. All items classified as unevaluated property are assessed on a quarterly basis for possible impairment or reduction in value. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.

The full cost ceiling is based principally on the estimated future net cash flows from oil and natural gas properties discounted at 10%. Full cost companies are required 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, unless prices were defined by contractual arrangements, to calculate the discounted future revenues. In the event the unamortized cost of oil and natural gas properties being amortized exceeds the full cost ceiling, as defined by the Securities and Exchange Commission ("SEC"), the excess is charged to expense in the period such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible.

As of December 31, 2013, the full cost ceiling value of the Company's reserves was calculated based on the unweighted arithmetic average first-day-of-the-month price for the 12-months ended December 31, 2013 of $3.57 per MMBtu for natural gas, adjusted by area for energy content, transportation fees, and regional price differentials, and the unweighted arithmetic average first-day-of-the-month price for the 12-months ended December 31, 2013 of $93.52 per barrel for oil, adjusted by area for energy content, transportation fees, and regional price differentials. Using these prices, the Company's net book value of oil and natural gas properties did not exceed the full cost ceiling amount as of December 31, 2013. Changes in production rates, levels of reserves, future development costs, and other factors will determine the Company's actual full cost ceiling test calculation and impairment analysis in future periods.

As of December 31, 2012, the full cost ceiling value of the Company's reserves was calculated based on the unweighted arithmetic average first-day-of-the-month price for the 12-months ended December 31, 2012 of $2.63 per MMBtu for natural gas, adjusted by area for energy content, transportation fees, and regional price differentials, and the unweighted arithmetic average first-day-of-the-month price for the 12-months ended December 31, 2012 of $91.21 per barrel for oil, adjusted by area for energy content, transportation fees, and regional price differentials. Using these prices, the Company's net book value of oil and natural gas properties did not exceed the full cost ceiling amount as of December 31, 2012.

As of December 31, 2011, the full cost ceiling value of the Company's reserves was calculated based on the unweighted arithmetic average first-day-of-the-month price for the 12-months ended December 31, 2011 of $3.99 per MMBtu for natural gas, adjusted by area for energy content, transportation fees, and regional price differentials, and the unweighted arithmetic average first-day-of-the-month price for the 12-months ended December 31, 2011 of $92.71 per barrel for oil, adjusted by area for energy content, transportation fees, and regional price differentials. Using these prices, the Company's net book value of oil and natural gas properties did not exceed the full cost ceiling amount as of December 31, 2011.

9.    Pipeline and gathering assets

Pipeline and gathering assets are recorded at cost, net of accumulated depreciation, and consist of gathering assets and related equipment. Depreciation of assets is provided using the shorter of the lease term or the straight-line method based on estimated useful lives of 20 years, as applicable. Expenditures for major renewals or betterments, which extend the useful lives of existing fixed assets, are capitalized and depreciated. Upon retirement or disposition, the cost and related accumulated depreciation and amortization are removed from the accounts and any gain or loss is recognized in "Non-operating income (expense)" in the consolidated statements of operations. Depreciation expense from continuing operations for pipeline and gathering assets was $1.5 million, $0.8 million and $0.4 million for the years ended December 31, 2013, 2012 and 2011, respectively.

F-10

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

Pipeline and gathering assets consist of the following as of December 31:

(in thousands)		2013				2012
Pipeline and gathering assets		$	44,255			$	74,877
Less accumulated depreciation		2,757				9,585
Total, net		$	41,498			$	65,292

10.    Other fixed assets

Other fixed assets are recorded at cost net of accumulated depreciation and amortization. Land is recorded at cost and is not subject to depreciation. Depreciation and amortization of other fixed assets is provided using the shorter of the lease term or the straight-line method based on estimated useful lives of three to ten years, as applicable. Leasehold improvements are capitalized and amortized over the shorter of the estimated useful lives of the assets or the terms of the related leases. Expenditures for major renewals or betterments, which extend the useful lives of existing fixed assets, are capitalized and depreciated. Upon retirement or disposition, the cost and related accumulated depreciation and amortization are removed from the accounts and any gain or loss is recognized in "Non-operating income (expense)" in the consolidated statements of operations. Depreciation and amortization expense from continuing operations for other fixed assets was $4.4 million, $3.1 million and $2.2 million for the years ended December 31, 2013, 2012 and 2011, respectively.

Other fixed assets consist of the following as of December 31:

(in thousands)		2013				2012
Computer hardware and software		$	11,370			$	7,774
Drilling service assets		7,269				7,223
Aircraft		4,952				—
Vehicles		4,741				3,396
Leasehold improvements		3,520				3,121
Furniture and fixtures		1,342				1,057
Production equipment		403				262
Other		2,546				675
Depreciable total		36,143				23,508
Less accumulated depreciation and amortization		12,803				8,938
Depreciable total, net		23,340				14,570
Land		4,138				2,091
Total, net		$	27,478			$	16,661

11.    Environmental

The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed in the period incurred. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed in the period incurred. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. Management believes no materially significant liabilities of this nature existed as of December 31, 2013 or 2012.

12.    Deferred loan costs

Loan origination fees, which are stated at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods. The Company capitalized $3.0 million and $10.8 million of deferred loan costs during the year ended December 31, 2013 and 2012, respectively. The Company had total deferred loan costs of $25.9 million and $29.4 million, net of accumulated amortization of $14.2 million and $9.2 million, as of December 31, 2013 and 2012, respectively.

F-11

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

During the years ended December 31, 2013 and 2011, the Company wrote-off $1.5 million and $6.2 million, respectively, in deferred loan costs as a result of the retirement of debt and changes in the borrowing base under the Senior Secured Credit Facility (as defined in Note D). No deferred loan costs were written off in the year ended December 31, 2012.

Future amortization expense of deferred loan costs as of December 31, 2013 is as follows:

(in thousands)
2014		$	4,258
2015		4,320
2016		4,386
2017		4,457
2018		4,252
Thereafter		4,260
Total		$	25,933

13.    Asset retirement obligations

Asset retirement obligations associated with the retirement of tangible long-lived assets, are recognized as a liability in the period in which they are incurred and become determinable. The associated asset retirement costs are part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related long-lived asset is charged to expense through the depletion of the asset. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as corresponding accretion expense.

The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, which converts future cash flows into a single discounted amount. Significant inputs to the valuation include: (i) estimated plug and abandonment cost per well based on Company experience; (ii) estimated remaining life per well based on the reserve life per well; (iii) future inflation factors; and (iv) the Company's average credit adjusted risk free rate. Inherent in the fair value calculation of asset retirement obligations are numerous assumptions and judgments including, in addition to those noted above, the ultimate settlement of these amounts, the ultimate timing of such settlement, and changes in legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing asset retirement obligation liability, a corresponding adjustment will be made to the asset balance.

The Company is obligated by contractual and regulatory requirements to remove certain pipeline and gas gathering assets and perform other remediation of the sites where such pipeline and gas gathering assets are located upon the retirement of those assets. However, the fair value of the asset retirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminate. The Company will record an asset retirement obligation for pipeline and gas gathering assets in the periods in which settlement dates are reasonably determinable.

The following reconciles the Company's asset retirement obligations liability for continuing and discontinued operations as of December 31:

(in thousands)		2013				2012
Liability at beginning of year		$	21,505			$	13,074
Liabilities added due to acquisitions, drilling, and other		2,709				4,233
Accretion expense		1,475				1,200
Liabilities settled upon plugging and abandonment		(226		)		(148		)
Liabilities removed due to the Anadarko Basin Sale		(7,801		)		—
Revision of estimates		4,081				3,146
Liability at end of year		$	21,743			$	21,505

14.    Fair value measurements

The carrying amounts reported in the consolidated balance sheets for cash and cash equivalents, accounts receivable, prepaid expenses, accounts payable, undistributed revenue and royalties and other accrued liabilities approximate their fair values. See Note D for fair value disclosures related to the Company’s debt obligations. The Company carries its derivatives at fair value. See Note G and Note H for details regarding the fair value of the Company’s derivatives.

F-12

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

15.    Treasury stock

The Company acquires treasury stock, which is recorded at cost, to satisfy tax withholding obligations for Laredo's employees that arise upon the lapse of restrictions on restricted stock or for other reasons. Upon acquisition, this treasury stock is retired.

16.    Revenue recognition

Oil and natural gas revenues are recorded using the sales method. Under this method, the Company recognizes revenues based on actual volumes of oil and natural gas sold to purchasers. The Company and other joint interest owners may sell more or less than their entitlement share of the volumes produced. Under the sales method, when a working interest owner has overproduced in excess of its share of remaining estimated reserves, the overproduced party recognizes the excessive gas imbalance as a liability. If the underproduced working interest owner determines that an overproduced owner's share of remaining net reserves is insufficient to settle the imbalance, the underproduced owner recognizes a receivable, net of any allowance from the overproduced working interest owner. During the year ended December 31, 2013, the majority of the Company's natural gas imbalance positions were transferred to a buyer in connection with the Anadarko Basin Sale (defined below). Prior to their disposition, the value of net overproduced positions arising during the year ended December 31, 2013, which increased oil and natural gas sales, was $0.03 million.

17.    General and administrative expense

The Company receives fees for the operation of jointly-owned oil and natural gas properties and records such reimbursements as a reduction of general and administrative expenses.

The following amounts have been recorded for the periods presented:

		For the years ended December 31,
(in thousands)		2013				2012				2011
Fees received for the operation of jointly-owned oil and natural gas properties		$	3,398			$	2,335			$	2,241

18.    Compensation awards

For stock-based compensation awards, compensation expense is recognized in "General and administrative" in the Company's consolidated statements of operations over the awards' vesting periods based on their grant date fair value. The Company utilizes the closing stock price on the date of grant to determine the fair value of service vesting restricted stock awards and a Black-Scholes pricing model to determine the fair values of service vesting restricted stock option awards. The Company utilizes a Monte Carlo simulation prepared by an independent third party to determine the fair value of the performance unit awards. See Note E for further discussion of the restricted stock awards, restricted stock option awards and performance unit awards.

19.    Income taxes

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating losses and tax credit carry-forwards. Under this method, deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is determined it is more likely than not that the related tax benefit will not be realized. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary. See Note F for detail of amounts recorded in the consolidated financial statements.

The Company evaluates uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more-likely-than-not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. The Company has no unrecognized tax benefits related to uncertain tax positions in the consolidated financial statements at December 31, 2013, 2012 or 2011.

F-13

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

20.    Impairment of long-lived assets

Impairment losses are recorded on property and equipment used in operations and other long-lived assets when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets' carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset. The Company determined a lower of cost or market adjustment was not necessary for materials and supplies as of December 31, 2013 and 2012. During the year ended December 31, 2011, the Company reduced materials and supplies by $0.2 million in order to reflect the balance at the lower of cost or market. This reduction is recorded in "Income (loss) from discontinued operations, net of tax" in the Company's consolidated statements of operations. For the years ended December 31, 2013, 2012 and 2011, the Company did not record any additional impairment to property and equipment used in operations or other long-lived assets.

21.    Supplemental cash flow disclosure information and non-cash investing and financing information

The following table summarizes the supplemental disclosure of cash flow information for the periods presented:

		For the years ended December 31,
(in thousands)		2013				2012				2011
Cash paid for interest, net of $255, $627 and zero of capitalized interest, respectively		$	95,622			$	74,638			$	31,157

The following presents the supplemental disclosure of non-cash investing and financing information for the periods presented:

		For the years ended December 31,
(in thousands)		2013				2012				2011
Change in accrued capital expenditures		$	(5,284	)		$	30,590			$	25,122
Capitalized asset retirement cost		$	6,790			$	7,379			$	4,520
Equity issued in connection with acquisition		$	3,029			$	—			$	—

 C—Acquisitions and divestitures

The Company accounts for business combinations under the acquisition method of accounting. Accordingly, the Company conducts assessments of net assets acquired and recognizes amounts for identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values, while transaction and integration costs associated with the acquisitions are expensed as incurred.

The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. The most significant assumptions relate to the estimated fair values of proved and unproved oil and natural gas properties. The fair value of these properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risk factors. To compensate for the inherent risk of estimating the value of the unproved properties, the discounted future net revenues of probable and possible reserves are reduced by additional risk-weighting factors.

1.    2013 acquisition

On September 6, 2013, the Company completed the acquisition of proved and unproved oil and natural gas properties located in Glasscock County, Texas, from private parties for $36.7 million consisting of cash and Laredo's restricted common stock, subject to customary closing adjustments. The results of operations prior to September 2013 do not include results from this acquisition.

  

F-14

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

The following table reflects the final estimate of the fair value of the acquired assets and liabilities associated with this acquisition as of September 6, 2013:

(in thousands)
Fair value of net assets:
Proved oil and natural gas properties(1)		$	9,652
Unproved oil and natural gas properties(1)		27,087
Other assets		200
Total assets acquired		36,939
Liabilities assumed		(200		)
Net assets acquired		$	36,739
Fair value of consideration paid for net assets:
Cash consideration, net of closing adjustments		$	33,710
Common stock issued(2)		3,029
Total consideration paid for net assets		$	36,739

_____________________________________________________________________________

(1) The fair value of the oil and natural gas properties acquired was determined using a discounted cash flow model, with future cash flows estimated based upon market assumptions of oil and natural gas prices, projections of estimated oil and natural gas reserve quantities, expectations for timing of future development and operating costs, and projections of future rates of production. The commodity prices utilized were based upon commodity strip prices as of September 6, 2013, and were adjusted for transportation fees and regional price differentials. Future cash flows were discounted using a peer group weighted average cost of capital rate. These assumptions represent Level 3 inputs under the fair value hierarchy, as described in Note H.

(2) In accordance with the acquisition agreement, on September 6, 2013, Laredo issued 123,803 restricted shares of its common stock to the sellers (the "Acquisition Shares"). Subject to federal securities laws, the Acquisition Shares are restricted from trading on public markets for six months from the acquisition date. For accounting purposes, the fair value of the Acquisition Shares was determined in accordance with GAAP by adjusting the closing price of $26.21 per share of Laredo's common stock on September 6, 2013 for a discount for lack of marketability. The discount of 6.64% was determined utilizing an Asian put option model, which includes an assumption of the estimated volatility of Laredo's common stock. This assumption represents a Level 3 input under the fair value hierarchy, as described in Note H.

2.    2013 divestiture of Dalhart Basin acreage

On December 20, 2013, the Company completed the sale of 37,000 net acres and one producing property in the Dalhart Basin for $20.4 million, subject to customary closing adjustments.

3.    2013 divestiture of Anadarko assets

On August 1, 2013, the Company completed the sale of its oil and natural gas properties, associated pipeline assets and various other associated property and equipment in the Anadarko Granite Wash, Central Texas Panhandle and the Eastern Anadarko Basin (the "Anadarko Basin Sale") to certain affiliates of EnerVest, Ltd. (collectively, "EnerVest") and certain other third parties in connection with the exercise of such third parties' preferential rights associated with the oil and gas assets. The purchase price consisted of $400.0 million from EnerVest and $38.0 million from the third parties. Approximately $388.0 million of the purchase price, excluding closing adjustments, was allocated to oil and natural gas properties pursuant to to the rules governing full cost accounting. After transaction costs and adjustments at closing reflecting an economic effective date of April 1, 2013, the net proceeds were $428.3 million, net of working capital adjustments.

Effective at closing, the operations and cash flows of these properties were eliminated from the ongoing operations of the Company and the Company does not have continuing involvement in the operations of these properties. The results of operations of the oil and natural gas properties that are a component of the Anadarko Basin Sale are not presented as discontinued operations pursuant to the rules governing full cost accounting for oil and natural gas properties.

    

F-15

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

The following table presents revenues and expenses of the oil and natural gas properties that are a component of the Anadarko Basin Sale included in the accompanying consolidated statements of operations for the periods presented:

		For the years ended December 31,
(in thousands)		2013				2012				2011
Revenues		$	59,631			$	84,616			$	103,746
Expenses(1)		46,357				89,602				80,308

_____________________________________________________________________________

(1) Expenses include lease operating expense, production and ad valorem tax expense, accretion expense and depletion, depreciation and amortization expense.

The results of operations of the associated pipeline assets and various other associated property and equipment ("Pipeline Assets") are presented as results of discontinued operations, net of tax in these consolidated financial statements. Accordingly, the Company has reclassified the financial results and the related notes for all prior periods presented to reflect these operations as discontinued. As a result of the sale of the Pipeline Assets, a gain of $3.2 million was recognized in the consolidated statements of operations in the line item "Loss on disposal of assets, net."

The following represents operating results from discontinued operations for the periods presented:

		For the years ended December 31,
(in thousands)		2013				2012				2011
Revenues:
Transportation and treating		$	4,020			$	4,186			$	3,923
Total revenues from discontinued operations		4,020				4,186				3,923
Cost and expenses:
Transportation and treating		1,207				1,306				912
Drilling and production		(18		)		463				1,142
Depletion, depreciation and amortization		627				2,577				2,247
Impairment expense		—				—				243
Total costs and expenses from discontinued operations		1,816				4,346				4,544
Non-operating expense, net		—				(1		)		(39		)
Income (loss) from discontinued operations before income tax		2,204				(161		)		(660		)
Income tax (expense) benefit		(781		)		54				238
Income (loss) from discontinued operations		$	1,423			$	(107	)		$	(422	)

4.    2012 acquisition

On July 12, 2012, the Company completed the acquisition of additional working interest in certain oil and natural gas properties located in Glasscock County, Texas, for a contract price of $20.5 million from a private company, net of closing purchase price adjustments. The results of operations prior to July 2012 do not include results from this acquisition.

    

    

F-16

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

The following table reflects the estimated fair value of the acquired assets and liabilities associated with this acquisition at July 12, 2012:

(in thousands)
Fair value of net assets:
Proved oil and natural gas properties(1)		$	16,925
Unproved oil and natural gas properties(1)		3,693
Total assets acquired		20,618
Liabilities assumed		(122		)
Net assets acquired		$	20,496
Fair value of consideration paid for net assets:
Cash consideration		$	20,496

_____________________________________________________________________________

(1) The fair value of the oil and natural gas properties acquired was determined using a discounted cash flow model, with future cash flows estimated based upon market assumptions of oil and natural gas prices, projections of estimated oil and natural gas reserve quantities, expectations for timing of future development and operating costs, and projections of future rates of production. The commodity prices utilized were based upon commodity strip prices as of July 12, 2012, and were adjusted for transportation fees and regional price differentials. Future cash flows were discounted using a peer group weighted average cost of capital rate. These assumptions represent Level 3 inputs under the fair value hierarchy, as described in Note H.

D—Debt

1.    Interest expense

The following amounts have been incurred and charged to interest expense for the periods presented:

		For the years ended December 31,
(in thousands)		2013				2012				2011
Cash payments for interest		$	95,877			$	75,265			$	31,157
Amortization of deferred loan costs and other adjustments		4,926				4,940				4,231
Accrued interest related to the October 2011 Notes(1)		—				—				(3,378		)
Change in accrued interest		(221		)		5,994				18,570
Interest charges incurred		100,582				86,199				50,580
Less capitalized interest		(255		)		(627		)		—
Total interest expense		$	100,327			$	85,572			$	50,580

___________________________________________________________________

(1)

As part of the October 19, 2011 offering of $200.0 million additional senior unsecured notes (further explained below), the Company received $3.4 million in interest from the initial notes purchasers, which represents the interest on such notes that accrued from August 15, 2011 to October 19, 2011, the date of the issuance of the notes. This accrued interest was paid to the holders of such notes by Laredo on February 15, 2012.

2.    2022 Notes

On April 27, 2012, the Company completed an offering of $500.0 million in aggregate principal amount of 7 3/8% senior unsecured notes due 2022 (the “2022 Notes”). The 2022 Notes will mature on May 1, 2022 and bear an interest rate of 7 3/8% per annum, payable semi-annually, in cash in arrears on May 1 and November 1 of each year. The 2022 Notes are fully and unconditionally guaranteed, jointly and severally on a senior unsecured basis by Laredo Midstream (the “Guarantor”).

The 2022 Notes were issued under, and are governed by, an indenture and supplement thereto, each dated April 27, 2012 (collectively, and as further supplemented, the “2012 Indenture”), among Laredo Inc, Wells Fargo Bank, National Association, as trustee, and the guarantors named therein. The 2012 Indenture contains customary terms, events of default and covenants relating to, among other things, the incurrence of debt, the payment of dividends or similar restricted payments, entering into transactions with affiliates and limitations on asset sales. Indebtedness under the 2022 Notes may be accelerated in certain circumstances upon an event of default as set forth in the 2012 Indenture.

F-17

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

Laredo will have the option to redeem the 2022 Notes, in whole or in part, at any time on or after May 1, 2017, at the redemption prices (expressed as percentages of principal amount) of 103.688% for the 12-month period beginning on May 1, 2017, 102.458% for the 12-month period beginning on May 1, 2018, 101.229% for the 12-month period beginning on May 1, 2019 and 100.000% beginning on May 1, 2020 and at any time thereafter, together with any accrued and unpaid interest, if any, to the date of redemption. In addition, before May 1, 2017, Laredo may redeem all or any part of the 2022 Notes at a redemption price equal to the sum of the principal amount thereof, plus a make-whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. Furthermore, before May 1, 2015, Laredo may, at any time or from time to time, redeem up to 35% of the aggregate principal amount of the 2022 Notes with the net proceeds of a public or private equity offering at a redemption price of 107.375% of the principal amount of the 2022 Notes, plus any accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the 2022 Notes issued under the 2012 Indenture remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. Laredo may also be required to make an offer to purchase the 2022 Notes upon a change of control triggering event.

3.    2019 Notes

On January 20, 2011, the Company completed an offering of $350.0 million 9 1/2% senior unsecured notes due 2019 (the “January Notes”) and on October 19, 2011, Laredo completed an offering of an additional $200.0 million 9 1/2% senior unsecured notes due 2019 (the “October 2011 Notes” and together with the January Notes, the “2019 Notes”). The 2019 Notes will mature on February 15, 2019 and bear an interest rate of 9 1/2% per annum, payable semi-annually, in cash in arrears on February 15 and August 15 of each year. The 2019 Notes are fully and unconditionally guaranteed, jointly and severally on a senior unsecured basis by the Guarantor.

The 2019 Notes were issued under and are governed by an indenture dated January 20, 2011 (as supplemented, the “2011 Indenture”) among Laredo Inc, Wells Fargo Bank, National Association, as trustee, and guarantors named therein. The Indenture contains customary terms, events of default and covenants relating to, among other things, the incurrence of debt, the payment of dividends or similar restricted payments, the undertaking of transactions with Laredo's unrestricted affiliates and limitations on asset sales. Indebtedness under the 2019 Notes may be accelerated in certain circumstances upon an event of default as set forth in the Indenture.

Laredo will have the option to redeem the 2019 Notes, in whole or in part, at any time on or after February 15, 2015, at the redemption prices (expressed as percentages of principal amount) of 104.750% for the 12-month period beginning on February 15, 2015, 102.375% for the 12-month period beginning on February 15, 2016 and 100.000% for the 12-month period beginning on February 15, 2017 and at any time thereafter, together with accrued and unpaid interest, if any, to the date of redemption. In addition, before February 15, 2015, Laredo may redeem all or any part of the 2019 Notes at a redemption price equal to the sum of the principal amount thereof, plus a make-whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. Laredo may also be required to make an offer to purchase the 2019 Notes upon a change of control triggering event.

4.    Senior secured credit facility

As of December 31, 2013, the Fourth Amended and Restated Credit Agreement (as amended, the "Senior Secured Credit Facility"), which matures November 4, 2018, had a capacity of $2.0 billion, with a borrowing base of $925.0 million with an aggregate elected commitment of $825.0 million and no amounts outstanding. The borrowing base is subject to a semi-annual redetermination based on the financial institutions' evaluation of the Company's oil and natural gas reserves. As defined in the Senior Secured Credit Facility, (i) the Adjusted Base Rate advances under the facility bear interest payable quarterly at an Adjusted Base Rate plus applicable margin and (ii) the Eurodollar advances under the facility bear interest, at the Company's election, at the end of one-month, two-month, three-month, six-month or, to the extent available, 12-month interest periods (and in the case of six-month and 12-month interest periods, every three months prior to the end of such interest period) at an Adjusted London Interbank Offered Rate plus an applicable margin, based on the ratio of outstanding revolving credit to the total commitment under the Senior Secured Credit Facility. Laredo is also required to pay an annual commitment fee on the unused portion of the financial institutions' commitment of 0.375% to 0.5%, based on the ratio of outstanding revolving credit to the total commitment under the Senior Secured Credit Facility. Subsequent to December 31, 2013, as a result of the issuance by the Company of $450.0 million in aggregate principal amount of 5 5/8% senior unsecured notes due 2022, the amount available for borrowings and the aggregate elected commitment under the Senior Secured Credit Facility was decreased to $812.5 million. See Note O.1 for additional information regarding this subsequent event.

The Senior Secured Credit Facility is secured by a first priority lien on Laredo and the Guarantor's assets and stock, including oil and natural gas properties, constituting at least 80% of the present value of the Company's proved reserves.

F-18

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

Further, the Company is subject to various financial and non-financial ratios on a consolidated basis, including a current ratio at the end of each calendar quarter, of not less than 1.00 to 1.00. As defined by the Senior Secured Credit Facility, the current ratio represents the ratio of current assets to current liabilities, inclusive of available capacity and exclusive of current balances associated with derivative positions. Additionally, at the end of each calendar quarter, the Company must maintain a ratio of (I) its consolidated net income (a) plus each of the following; (i) any provision for (or less any benefit from) income or franchise taxes; (ii) consolidated net interest expense; (iii) depletion, depreciation and amortization expense; (iv) exploration expenses; and (v) other non-cash charges, and (b) minus all non-cash income ("EBITDAX"), as defined in the Senior Secured Credit Facility, to (II) the sum of net interest expense plus letter of credit fees of not less than 2.50 to 1.00, in each case for the four quarters then ending. The Senior Secured Credit Facility contains both financial and non-financial covenants and the Company was in compliance with these covenants as of December 31, 2013 and 2012.

Additionally, the Senior Secured Credit Facility provides for the issuance of letters of credit, limited to the lesser of total capacity or $20.0 million. No letters of credit were outstanding as of December 31, 2013.

5.    Fair value of debt

The following table presents the carrying amount and fair value of the Company's debt instruments for the periods presented:

		December 31, 2013								December 31, 2012
(in thousands)		Carrying value				Fair value				Carrying value				Fair value
2019 Notes(1)		$	551,538			$	615,313			$	551,760			$	616,000
2022 Notes		500,000				549,375				500,000				541,250
Senior Secured Credit Facility		—				—				165,000				165,098
Total value of debt		$	1,051,538			$	1,164,688			$	1,216,760			$	1,322,348

________________________________________________________________________

(1)	The carrying value of the 2019 Notes includes the October 2011 Notes unamortized bond premium of $1.5 million and $1.8 million as of December 31, 2013 and 2012, respectively.

As of December 31, 2013 and 2012, the fair value of the debt outstanding on the 2019 Notes and the 2022 Notes was determined using the December 31, 2013 and 2012 quoted market price (Level 1), respectively, and the fair value of the outstanding debt as of December 31, 2012 on the Senior Secured Credit Facility was estimated utilizing pricing models for similar instruments (Level 2). See Note H for information about fair value hierarchy levels.

E—Employee compensation

In November 2011, Laredo's Board of Directors approved a Long-Term Incentive Plan (the "LTIP"), which provides for the granting of incentive awards in the form of restricted stock awards, restricted stock option awards and other awards. The LTIP provides for the issuance of 10.0 million shares.

The Company recognizes the fair value of stock-based payments to employees and directors as a charge against earnings. The Company recognizes stock-based payment expense over the requisite service period. Laredo's stock-based compensation awards are accounted for as equity instruments. Stock-based compensation is included in "General and administrative" in the consolidated statements of operations.

1.    Restricted stock awards

All restricted stock awards are non-participating securities and are treated as issued and outstanding in the accompanying consolidated financial statements. If an employee terminates employment prior to the restriction lapse date, the awarded shares are forfeited, canceled and are no longer considered issued and outstanding. Restricted stock awards converted in the Corporate Reorganization vested 20% at the grant date and then vest 20% annually thereafter. The restricted stock awards granted under the LTIP to employees generally vest 33%, 33% and 34% per year beginning on the first anniversary date of the grant. Restricted stock awards granted to non-employee directors vest fully on the anniversary date of the grant.

    

F-19

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

The following table reflects the outstanding restricted stock awards for the years ended December 31, 2013 and 2012 and from the Corporate Reorganization until December 31, 2011:

(in thousands, except for grant date fair values)		Restricted stock awards			Weighted average grant date fair value
Outstanding as of December 19, 2011		—			$	—
Exchanged		912			$	1.14
Vested		(1	)		$	1.11
Outstanding as of December 31, 2011		911			$	1.14
Granted		932			$	22.90
Forfeited		(251	)		$	15.61
Vested(1)		(397	)		$	1.03
Outstanding as of December 31, 2012		1,195			$	15.06
Granted		1,469			$	18.17
Forfeited		(229	)		$	18.47
Vested(2)		(636	)		$	18.69
Outstanding as of December 31, 2013		1,799			$	19.17

______________________________________________________________________________

(1) Vestings in the year ended December 31, 2012 related to restricted stock awards converted in the Corporate Reorganization. Such shares have a tax basis of zero to the grantee and therefore result in no tax benefit to the Company.

(2) The vesting of certain restricted stock grants could result in federal and state income tax expense or benefits related to the difference between the market price of the common stock at the date of vesting and the date of grant. The total fair value of restricted stock vested during the year ended December 31, 2013 was $8.9 million. The Company recognized excess income tax expense of $0.4 million during the year ended December 31, 2013 related to restricted stock, which was recorded as an adjustment to deferred income taxes. There were no comparative amounts recorded in the years ended December 31, 2012 or 2011.

The Company utilizes the closing stock price on the date of grant to determine the fair value of service vesting restricted stock awards. As of December 31, 2013, unrecognized stock-based compensation expense related to restricted stock awards was $23.3 million. Such cost is expected to be recognized over a weighted average period of 1.83 years.

F-20

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

2.    Restricted stock option awards

Restricted stock options awards granted under the LTIP vest and are exercisable in four equal installments on each of the first four anniversaries of the date of the grant. The following table reflects the stock option award activity for the years ended December 31, 2013 and 2012:

(in thousands, except for weighted average exercise price and contractual term)		Restricted stock option awards			Weighted average exercise price (per option)				Weighted average contractual term (years)
Outstanding as of December 31, 2011		—			$	—			—
Granted		603			$	24.11			10
Forfeited		(144	)		$	24.11			10
Outstanding as of December 31, 2012		459			$	24.11			10
Granted		1,019			$	17.34			9.13
Exercised(1)		(104	)		$	20.79			8.75
Expired or canceled		(12	)		$	24.11			—
Forfeited		(133	)		$	19.88			—
Outstanding as of December 31, 2013		1,229			$	19.32			8.82
Vested and exercisable at end of period(2)		158			$	22.12			8.40
Vested, exercisable, and expected to vest at end of period(3)		1,197			$	19.33			8.82

_____________________________________________________________________________

(1) The exercise of stock options could result in federal and state income tax expense or benefits related to the difference between the fair value of the stock option at the date of grant and the intrinsic value of the stock option when exercised. The intrinsic value of a stock option is the amount by which the market value upon exercise of the underlying stock exceeds the exercise price of the option. The total intrinsic value of options exercised during the year ended December 31, 2013 was $0.9 million. The Company recognized excess income tax expense of $0.1 million during the year ended December 31, 2013, related to stock options, which was recorded as an adjustment to deferred income taxes. There were no comparative amounts recorded in years ended December 31, 2012 or 2011.

(2) The aggregate intrinsic value of vested and exercisable options at December 31, 2013 was $0.9 million.

(3) The aggregate intrinsic value of vested, exercisable and expected to vest options at December 31, 2013 was $10.0 million.

The Company used the Black-Scholes option pricing model to determine the fair value of restricted stock options and is recognizing the associated expense on a straight-line basis over the four-year requisite service period of the awards. Determining the fair value of stock-based awards requires judgment, including estimating the expected term that stock options will be outstanding prior to exercise, and the associated volatility. As of December 31, 2013 unrecognized stock-based compensation expense related to restricted option awards was $8.3 million. Such cost is expected to be recognized over a weighted average period of 2.89 years.

    

F-21

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

The assumptions used to estimate the fair value of restricted stock options granted are as follows:

		February 15, 2013				February 3, 2012
Risk-free interest rate(1)		1.19		%		1.14		%
Expected option life(2)		6.25 years				6.25 years
Expected volatility(3)		58.89		%		59.98		%
Fair value per option		$	9.67			$	13.52

_______________________________________________________________________________

(1)	U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, matching the treasury yield terms to the expected life of the option.

(2)	As the Company had no historical exercise history at the time of the grant, expected option life assumptions were developed using the simplified method in accordance with GAAP.

(3)	The Company utilized a peer historical look-back, weighted with the Company's own volatility since the IPO, to develop the expected volatility.

In accordance with the LTIP and stock option agreement, the options granted will become exercisable in accordance with the following schedule based upon the number of full years of the optionee's continuous employment or service with the Company, following the date of grant:

Full years of continuous employment		Incremental percentage of option exercisable			Cumulative percentage of option exercisable
Less than one		—	%		—	%
One		25	%		25	%
Two		25	%		50	%
Three		25	%		75	%
Four		25	%		100	%

No shares of common stock may be purchased unless the optionee has remained in the continuous employment of the Company through a year from the grant date. Unless terminated sooner, the option will expire if and to the extent it is not exercised within 10 years from the grant date. The unvested portion of an option will expire upon termination of employment of the optionee, and the vested portion of such option will remain exercisable for (A) one year following termination of employment by death, but not later than the expiration of the option period or (B) 90 days following termination of employment or service without cause, but not later than the expiration of the option period. The unvested and the unexercised vested portion of the option will expire upon termination of employment for cause.

3.    Stock-based compensation award expense

The following has been recorded to stock-based compensation expense for the periods presented:

		For the years ended December 31,
(in thousands)		2013				2012				2011
Restricted stock award compensation expense		$	17,084			$	8,496			$	6,111
Restricted stock option award compensation expense		4,349				1,560				—
Total stock-based compensation expense		$	21,433			$	10,056			$	6,111

During the year ended December 31, 2013, two officers' and 20 employees' restricted stock awards and restricted option awards were modified to vest upon the officers' or the employees' retirement or in connection with the employees' termination of employment as a result of the Anadarko Basin Sale. The incremental compensation cost resulting from these modifications recognized during the year ended December 31, 2013 was $4.7 million.

4. Performance unit awards

The performance unit awards issued to management are subject to a combination of market and service vesting criteria. A Monte Carlo simulation prepared by an independent third party is utilized in order to determine the fair value of the awards at the date of grant and to re-measure the fair value at the end of each reporting period until settlement in accordance with GAAP. The volatility criteria utilized in the Monte Carlo simulation is based on the volatility of the Company and the volatilities of a

F-22

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

group of peer companies that have been determined to be most representative of the Company. These awards are accounted for as liability awards as they will be settled in cash at the end of the requisite service period based on the achievement of certain performance criteria. The liability and related compensation expense for each period for these awards is recognized by dividing the fair value of the total liability by the requisite service period and recording the pro rata share for the period for which service has already been provided. The Company issued performance unit awards on February 15, 2013 ("2013 performance unit awards") and on February 3, 2012 ("2012 performance unit awards").

The 2013 performance unit awards have a performance period of January 1, 2013 to December 31, 2015 and are expected to be paid in 2016 if the performance criteria is met. The 2012 performance unit awards have a performance period of January 1, 2012 to December 31, 2014 and are expected to be paid in 2015 if the performance criteria is met. There were no performance unit awards issued or outstanding during the year ended December 31, 2011.

The following table reflects the outstanding performance unit awards for the periods presented:

(in thousands)		2013 performance unit awards			2012 performance unit awards
Outstanding at December 31, 2011		—			—
Granted		—			49
Forfeited		—			(2	)
Outstanding at December 31, 2012		—			47
Granted		58			—
Forfeited		(4	)		(9	)
Vested (1)		(10	)		(11	)
Outstanding at December 31, 2013		44			27

_______________________________________________________________________________

(1)	During the year ended December 31, 2013, certain officers' performance unit awards were modified to vest upon the officers' retirement in 2013. The cash payments for these performance unit awards were paid at $100.00 per unit.

The assumptions used to estimate the fair value of the respective performance unit awards as of December 31, 2013 are as follows:

		2013 performance unit awards				2012 performance unit awards
Risk-free rate(1)		0.38		%		0.13		%
Dividend yield		—		%		—		%
Expected volatility(2)		37.34		%		37.42		%
Laredo closing price as of December 31, 2013		$	27.69			$	27.69

_______________________________________________________________________________

(1)	The risk-free rate was derived using a zero-coupon yield calculated from the Treasury Constant Maturities yield curve.

(2)	The Company utilized a peer historical look-back, weighted with the Company's own volatility since the IPO, to develop the expected volatility.

The fair value of the 2013 performance unit awards and 2012 performance unit awards as of December 31, 2013 were $5.7 million and $3.8 million, respectively. The fair value of the 2012 performance unit awards as of December 31, 2012 was $5.4 million.

    

F-23

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

The following has been recorded to performance unit award compensation expense for the periods presented:

		For the years ended December 31,
(in thousands)		2013				2012
2013 Performance unit award compensation expense		$	2,863			$	—
2012 Performance unit award compensation expense		1,870				1,797
Total performance unit award compensation expense		$	4,733			$	1,797

Compensation expense for these awards is recognized in "General and administrative" in the Company's consolidated statements of operations and the corresponding liability is included in "Other noncurrent liabilities" in the consolidated balance sheets. As there are inherent uncertainties related to the factors and the Company's judgment in applying them to the fair value determinations, there is risk that the recorded performance unit compensation may not accurately reflect the amount ultimately earned by the members of management.

5.    Defined contribution plan

The Company sponsors a 401(k) defined contribution plan for the benefit of substantially all employees at the date of hire. The plan allows eligible employees to make pre-tax and after-tax contributions up to 100% of their annual compensation, not to exceed annual limits established by the federal government. The Company makes matching contributions of up to 6% of an employee’s compensation and may make additional discretionary contributions for eligible employees. Employees are 100% vested in the employer contributions upon receipt.

The following table presents total employer contributions to the plans for the periods presented:

		For the years ended December 31,
(in thousands)		2013				2012				2011
Contributions		$	1,886			$	1,293			$	1,651

F-24

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

F—Income taxes

The Company uses an asset and liability approach for financial accounting and for reporting income tax. Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.

The Company is subject to corporate income taxes and the Texas franchise tax. Income tax expense attributable to income from continuing operations for the periods presented consisted of the following:

		For the years ended December 31,
(in thousands)		2013				2012				2011
Current taxes:
Federal		$	—			$	—			$	—
State		—				—				—
Deferred taxes:
Federal		(64,034		)		(31,390		)		(58,965		)
State		(10,473		)		(1,613		)		(647		)
Income tax expense		$	(74,507	)		$	(33,003	)		$	(59,612	)

The following presents the comprehensive provision for income taxes for the periods presented:

		For the years ended December 31,
(in thousands)		2013				2012				2011
Comprehensive provision for income taxes allocable to:
Continuing operations		$	(74,507	)		$	(33,003	)		$	(59,612	)
Discontinued operations		(781		)		54				238
Comprehensive provision for income taxes		$	(75,288	)		$	(32,949	)		$	(59,374	)

Income tax expense attributable to income from continuing operations before income taxes differed from amounts computed by applying the applicable federal income tax rate of 34% to pre-tax earnings as a result of the following:

		For the years ended December 31,
(in thousands)		2013				2012				2011
Income tax expense computed by applying the statutory rate		$	(64,969	)		$	(32,219	)		$	(56,300	)
State income tax, net of federal tax benefit and increase in valuation allowance		(7,532		)		(102		)		(2,530		)
Non-deductible stock-based compensation		(1,070		)		(1,177		)		(2,078		)
Stock-based compensation tax deficiency		(559		)		—				—
Change in deferred tax valuation allowance		(63		)		583				660
Income from nontaxable entity		—				—				30
Other items		(314		)		(88		)		606
Income tax expense		$	(74,507	)		$	(33,003	)		$	(59,612	)

The effective tax rate for the Company's continuing operations was 39%, 35% and 36% for the years ended December 31, 2013, 2012 and 2011, respectively. The Company's effective tax rate is affected by recurring permanent differences and by discrete items that may occur in any given year, but are not consistent from year to year.

During the year ended December 31, 2013, certain shares related to restricted stock awards vested at times when the Company's stock price was lower than the fair value of those shares at the time of grant. As a result, the income tax deduction related to such shares is less than the expense previously recognized for book purposes. During the year ended December 31, 2013, certain restricted stock options were exercised. The income tax deduction related to the options intrinsic value was less than the expense previously recognized for book purposes. In accordance with GAAP, such shortfalls reduce additional paid-in capital to the extent windfall tax benefits have been previously recognized. However, the Company has not previously recognized any windfall tax benefits. Therefore, the tax impact of these shortfalls totaling $0.6 million for the year ended

F-25

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

December 31, 2013 is included in income tax expense attributable to continuing operations for the period. There were no comparative amounts for the years ended December 31, 2012 or 2011.

The Company filed its 2012 federal and Oklahoma income tax returns during the year ended December 31, 2013. As a result, the Company recognized an aggregate expense from tax related items, primarily the result of Oklahoma income allocation updates. The Oklahoma income allocation expense reflects a change to the applicable methodology for allocating income between certain states in the fiscal 2012 and prior-year returns. The tax impact of these items of $2.4 million for the year ended December 31, 2013 is included in income tax expense attributable to continuing operations for the period. There were no comparative amounts for the years ended December 31, 2012 or 2011.

Significant components of the Company's deferred tax (liabilities) assets as of December 31 are as follows:

(in thousands)		2013				2012
Net operating loss carry-forward		$	284,890			$	222,017
Oil and natural gas properties and equipment		(278,735		)		(175,823		)
Derivatives		(30,859		)		7,108
Stock-based compensation		6,578				2,928
Accrued bonus		3,740				3,502
Capitalized interest		2,099				1,850
Other		(240		)		1,113
Gross deferred tax (liability) asset		(12,527		)		62,695
Valuation allowance		(132)				(66		)
Net deferred tax (liability) asset		$	(12,659	)		$	62,629

Net deferred tax assets and liabilities were classified in the consolidated balance sheets as of December 31 as follows:

(in thousands)		2013				2012
Deferred tax asset		$	3,634			$	62,629
Deferred tax liability		(16,293		)		—
Net deferred tax (liability) assets		$	(12,659	)		$	62,629

The following presents the Company's federal net operating loss carry-forwards and their applicable expiration dates as of December 31, 2013:

(in thousands)
2026		$	2,741
2027		38,651
2028		228,661
2029		101,932
2030		82,948
2031		74,151
2032		135,390
2033		154,538
Total		$	819,012

The Company had federal net operating loss carry-forwards totaling $819.0 million and state of Oklahoma net operating loss carry-forwards totaling $180.1 million as of December 31, 2013. These carry-forwards begin expiring in 2026. As of December 31, 2013, the Company believes the federal and state of Oklahoma net operating loss carry-forwards are fully realizable. The Company considered all available evidence, both positive and negative, in determining whether, based on the weight of that evidence, a valuation allowance was needed on either the federal or Oklahoma net operating loss carry-forwards. Such consideration included estimated future projected earnings based on existing reserves and projected future cash flows from its oil and natural gas reserves (including the timing of those cash flows), the reversal of deferred tax liabilities recorded as of December 31, 2013, the Company’s ability to capitalize intangible drilling costs, rather than expensing these costs in order to prevent an operating loss carry-forward from expiring unused, and future projections of Oklahoma sourced income.

F-26

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

The Company's federal and state operating loss carry-forwards include windfall tax deductions from vestings of certain restricted stock awards and stock option exercises that were not recorded in the Company's income tax provision. The amount of windfall tax benefit recognized in additional paid-in capital is limited to the amount of benefit realized currently in income taxes payable. As of December 31, 2013, the Company had suspended additional paid-in capital credits of $0.9 million related to windfall tax deductions. Upon realization of the net operating loss carry-forwards from such windfall tax deductions, the Company would record a benefit of up to $0.9 million in additional paid-in capital.

The Company maintains a valuation allowance to reduce certain deferred tax assets to amounts that are more likely than not to be realized. As of December 31, 2013, a full valuation allowance of $0.1 million was recorded against the deferred tax asset related to the Company’s charitable contribution carry-forward of $0.4 million.

In evaluating its current tax positions in order to identify any material uncertain tax positions, the Company developed a policy for identifying uncertain tax positions that considers support for each position, industry standard, tax return disclosure and schedule, and the significance of each position. The Company had no material adjustments to its unrecognized tax benefits during the year ended December 31, 2013.

Prior to the Internal Consolidation, the Company and its subsidiaries filed a federal corporate income tax return on a consolidated basis. Following the Internal Consolidation, the surviving entities will file a single return. The Company's income tax returns for the years 2010 through 2013 remain open and subject to examination by federal tax authorities and/or the tax authorities in Oklahoma, Texas and Louisiana which are the jurisdictions where the Company has or had operations. The Company's 2011 federal income tax return is currently under examination. Additionally, the statute of limitations for examination of federal net operating loss carry-forwards typically does not begin to run until the year the attribute is utilized in a tax return.

G—Derivatives

1.    Commodity derivatives

The Company engages in derivative transactions such as collars, swaps, puts and basis swaps to hedge price risks due to unfavorable changes in oil and natural gas prices related to its oil and natural gas production. As of December 31, 2013, the Company had 37 open derivative contracts with financial institutions which extend from January 2014 to June 2018, none of which were designated as hedges for accounting purposes. The contracts are recorded at fair value on the consolidated balance sheets and gains and losses are recognized in current period earnings.

Each collar transaction has an established price floor and ceiling. When the settlement price is below the price floor established by these collars, the Company receives an amount from its counterparty equal to the difference between the settlement price and the price floor multiplied by the hedged contract volume. When the settlement price is above the price ceiling established by these collars, the Company pays its counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the hedged contract volume.

Each swap transaction has an established fixed price. When the settlement price is above the fixed price, the Company pays its counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is below the fixed price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.

Each put transaction has an established floor price. The Company pays the counterparty a premium in order to enter into the put transaction. When the settlement price is below the floor price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires.

Each oil basis swap transaction has an established fixed basis differential. The Company's oil basis swap differentials are between the West Texas Intermediate Midland Argus ("Midland") index crude oil price and the West Texas Intermediate Argus Cushing ("WTI Argus") index crude oil price or the Light Louisiana Sweet Argus ("LLS Argus") index crude oil price and the Brent International Petroleum Exchange ("Brent") index crude oil price. When the WTI Argus price less the fixed basis differential is greater than the actual Midland price, the difference multiplied by the hedged contract volume is paid to the Company by the counterparty. When the WTI Argus price less the fixed basis differential is less than the actual Midland price, the difference multiplied by the hedged contract volume is paid by the Company to the counterparty. When the Brent price less the fixed basis differential is greater than the actual LLS Argus price, the difference multiplied by the hedged contract volume is paid to the Company by the counterparty. When the LLS Argus price less the fixed basis differential is less than the actual Brent price, the difference multiplied by the hedged contract volume is paid by the Company to the counterparty.

F-27

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

Gains and losses on derivatives are reported on the consolidated statements of operations in the respective “Gain (loss) on derivatives” amounts.

During the year ended December 31, 2013, the Company entered into additional commodity contracts to hedge a portion of its estimated future production. The following table summarizes information about these additional commodity derivative contracts:

		Aggregate volumes			Swap price				Floor price				Ceiling price				Contract period
Oil (volumes in Bbl):
Swap		1,377,000			$	98.10			$	—			$	—			March 2013 - December 2013
Basis swap(1)		4,026,000			$	(1.00	)		$	—			$	—			March 2013 - December 2014
Swap		80,000			$	101.20			$	—			$	—			August 2013 - December 2013
Swap		204,000			$	106.60			$	—			$	—			October 2013 - December 2013
Swap		912,500			$	93.65			$	—			$	—			January 2014 - December 2014
Swap		365,000			$	93.68			$	—			$	—			January 2014 - December 2014
Swap		399,996			$	93.30			$	—			$	—			January 2014 - December 2014
Swap		480,000			$	97.47			$	—			$	—			January 2014 - December 2014
Price collar		555,000			$	—			$	90.00			$	97.00			January 2014 - December 2014
Price collar		555,000			$	—			$	90.00			$	97.05			January 2014 - December 2014
Price collar		555,000			$	—			$	90.00			$	96.93			January 2014 - December 2014
Price collar		555,000			$	—			$	90.00			$	96.90			January 2014 - December 2014
Basis swap(2)		14,610,000			$	(2.85	)		$	—			$	—			July 2014 - June 2018
Price collar		1,277,500			$	—			$	80.00			$	98.50			January 2015 - December 2015
Price collar		690,000			$	—			$	80.00			$	95.87			January 2015 - December 2015
Price collar		1,928,760			$	—			$	80.00			$	92.00			January 2015 - December 2015
Price collar		364,380			$	—			$	80.00			$	92.05			January 2015 - December 2015
Price collar		1,084,380			$	—			$	80.00			$	92.16			January 2015 - December 2015
Price collar		600,000			$	—			$	80.00			$	92.30			January 2015 - December 2015
Price collar		360,000			$	—			$	80.00			$	92.35			January 2015 - December 2015
Price collar		1,281,000			$	—			$	80.00			$	93.00			January 2016 - December 2016
Price collar		579,000			$	—			$	80.00			$	87.75			January 2016 - December 2016
Natural gas (volumes in MMBtu):
Price collar		2,900,000			$	—			$	3.00			$	4.00			March 2013 - December 2013
Swap		3,338,400			$	4.31			$	—			$	—			June 2013 - December 2013
Swap		3,978,500			$	4.36			$	—			$	—			January 2014 - December 2014

______________________________________________________________________________

(1) The associated oil basis swap derivative is settled based on the differential between the WTI Argus index oil price and the Midland oil futures.

(2) The associated oil basis swap derivative is settled based on the differential between the LLS Argus index crude oil price and the Brent index crude oil price.

    

F-28

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

During the year ended December 31, 2013, the following commodity derivative contracts were transferred to a buyer in connection with the Anadarko Basin Sale:

		Aggregate volumes			Swap price				Contract period
Natural gas (volumes in MMBtu):
Swap		2,386,800			$	4.31			August 2013 - December 2013
Swap		3,978,500			$	4.36			January 2014 - December 2014

During the year ended December 31, 2013, the Company received $6.0 million, net of $2.2 million in deferred premiums, in settlements from early terminations and modifications of commodity derivative contracts. There were no comparable amounts recorded in the years ended December 31, 2012 or 2011. Gains and losses on early terminated derivatives are reported on the consolidated statements of operations in the respective “Gain (loss) on derivatives” amounts.

The following commodity derivative contracts were unwound in connection with the Anadarko Basin Sale during the year ended December 31, 2013:

		Aggregate volumes			Floor price				Ceiling price				Contract period
Natural gas (volumes in MMBtu):
Price collar		2,200,000			$	4.00			$	7.05			September 2013 - December 2013
Put		2,200,000			$	4.00			$	—			September 2013 - December 2013
Price collar		3,480,000			$	4.00			$	7.00			January 2014 - December 2014
Price collar		1,800,000			$	4.00			$	7.05			January 2014 - December 2014
Price collar		1,680,000			$	4.00			$	7.05			January 2014 - December 2014
Price collar		1,560,000			$	3.00			$	5.50			January 2014 - December 2014
Price collar		2,520,000			$	3.00			$	6.00			January 2015 - December 2015
Price collar		2,400,000			$	3.00			$	6.00			January 2015 - December 2015
Price collar		2,400,000			$	3.00			$	6.00			January 2015 - December 2015

    

F-29

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

The following table summarizes open positions as of December 31, 2013, and represents, as of such date, derivatives in place through June 2018, on annual production volumes:

		Year 2014				Year 2015				Year 2016				Year 2017				Year 2018
Oil positions:
Puts:
Hedged volume (Bbl)		540,000				456,000				—				—				—
Weighted average price ($/Bbl)		$	75.00			$	75.00			$	—			$	—			$	—
Swaps:
Hedged volume (Bbl)		2,157,496				—				—				—				—
Weighted average price ($/Bbl)		$	94.44			$	—			$	—			$	—			$	—
Collars:
Hedged volume (Bbl)		2,946,000				6,557,020				1,860,000				—				—
Weighted average floor price ($/Bbl)		$	86.42			$	79.81			$	80.00			$	—			$	—
Weighted average ceiling price ($/Bbl)		$	104.89			$	95.40			$	91.37			$	—			$	—
Basis swaps:
Hedged volume(1) (Bbl)		2,252,000				—				—				—				—
Weighted average price(1) ($/Bbl)		$	(1.04	)		$	—			$	—			$	—			$	—
Hedged volume(2) (Bbl)		1,840,000				3,650,000				3,660,000				3,650,000				1,810,000
Weighted average price(2) ($/Bbl)		$	(2.85	)		$	(2.85	)		$	(2.85	)		$	(2.85	)		$	(2.85	)
Natural gas positions:
Collars:
Hedged volume (MMBtu)		9,600,000				8,160,000				—				—				—
Weighted average floor price ($/MMBtu)		$	3.00			$	3.00			$	—			$	—			$	—
Weighted average ceiling price ($/MMBtu)		$	5.50			$	6.00			$	—			$	—			$	—

_______________________________________________________________________________

(1)	The associated oil basis swap derivatives are settled based on the differential between the WTI Argus index oil price and the Midland oil futures.

(2)	The associated oil basis swap derivative is settled based on the differential between the LLS Argus index oil price and the Brent oil price.

The following represents cash settlements received (paid) for matured derivatives for the periods presented:

		For the years ended December 31,
(in thousands)		2013				2012				2011
Commodity derivatives received		$	4,046			$	27,025			$	3,719
Interest rate derivatives paid		(301		)		(2,115		)		(4,873		)
Cash settlements received (paid) for matured derivatives, net		$	3,745			$	24,910			$	(1,154	)

2.    Interest rate derivatives

The Company is exposed to market risk for changes in interest rates related to any drawn amount on its Senior Secured Credit Facility. Interest rate derivative agreements are used to manage a portion of the exposure related to changing interest rates by converting floating-rate debt to fixed-rate debt. If the London Interbank Offered Rate ("LIBOR") is lower than the fixed rate in the contract, the Company is required to pay the counterparties the difference, and conversely, the counterparties are required to pay the Company if LIBOR is higher than the fixed rate in the contract. The Company did not designate the interest rate derivatives as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. The Company had one interest rate swap and one interest rate cap outstanding for a notional amount of $100.0 million with fixed pay rates of 1.11% and 3.00%, respectively, until their expiration in September 2013. No interest rate derivatives were in place as of December 31, 2013.

F-30

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

3.    Balance sheet presentation

The Company’s oil and natural gas commodity derivatives and interest rate derivatives are presented on a net basis as “Derivatives” in the consolidated balance sheets.

The following summarizes the fair value of derivatives outstanding on a gross basis as of:

(in thousands)		December 31, 2013				December 31, 2012
Assets:
Commodity derivatives:
Oil derivatives		$	140,496			$	16,219
Natural gas derivatives		657				17,896
Total assets		$	141,153			$	34,115
Liabilities:
Commodity derivatives:
Oil derivatives(1)		$	56,818			$	21,308
Natural gas derivatives(2)		2,278				10,413
Interest rate derivatives		—				277
Total liabilities		$	59,096			$	31,998
Net derivative position		$	82,057			$	2,117

______________________________________________________________________________

(1) The oil derivatives fair value includes a deferred premium liability of $11.1 million and $18.3 million as of December 31, 2013 and 2012, respectively.

(2) The natural gas derivatives fair value includes a deferred premium liability of $1.6 million and $6.4 million as of December 31, 2013 and 2012, respectively.

By using derivative instruments to hedge exposures to changes in commodity prices and interest rates, the Company exposes itself to credit risk and market risk. Market risk is the exposure to changes in the market price of oil and natural gas, which are subject to fluctuations from a variety of factors, including changes in supply and demand. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are participants in the Senior Secured Credit Facility which is secured by the Company’s oil and natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not require collateral from its counterparties. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that are also lenders in the Senior Secured Credit Facility and meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity and interest rate derivatives are subject to counterparty netting under agreements governing such derivatives and, therefore, the risk of such loss is somewhat mitigated as of December 31, 2013.

H—Fair value measurements

The Company accounts for its oil and natural gas commodity and interest rate derivatives at fair value. The fair value of the derivatives are determined utilizing pricing models for similar instruments. The models use a variety of techniques to arrive at fair value, including quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward curves generated from a compilation of data gathered from third parties.

The Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).

Assets and liabilities recorded at fair value on the consolidated balance sheets are categorized based on inputs to the valuation techniques as follows: 

Level 1—	Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2—	Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the assets or liabilities. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace.
Level 3—	Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Unobservable inputs are not corroborated by market data. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability.

When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company conducts a review of fair value hierarchy classifications on an annual basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. Transfers between fair value hierarchy levels are recognized and reported in the period in which the transfer occurred. No transfers between fair value hierarchy levels occurred during the years ended December 31, 2013 or 2012.

1. Fair value measurement on a recurring basis

The following presents the Company's fair value hierarchy for assets and liabilities measured at fair value on a recurring basis as of December 31, 2013 and 2012.

(in thousands)		Level 1				Level 2				Level 3				Total fair value
As of December 31, 2013:
Commodity derivatives		$	—			$	94,741			$	—			$	94,741
Deferred premiums		—				—				(12,684		)		(12,684		)
Total		$	—			$	94,741			$	(12,684	)		$	82,057

(in thousands)		Level 1				Level 2				Level 3				Total fair value
As of December 31, 2012:
Commodity derivatives		$	—			$	27,103			$	—			$	27,103
Deferred premiums		—				—				(24,709		)		(24,709		)
Interest rate derivatives		—				(277		)		—				(277		)
Total		$	—			$	26,826			$	(24,709	)		$	2,117

These items are included in "Derivatives" on the consolidated balance sheets. Significant Level 2 assumptions associated with the calculation of discounted cash flows used in the "mark-to-market" analysis of commodity derivatives include the NYMEX natural gas and crude oil prices, appropriate risk adjusted discount rates and other relevant data. Significant Level 2 assumptions associated with the calculation of discounted cash flows used in the "mark-to-market" analysis of interest rate swaps include the interest rate curves, appropriate risk adjusted discount rates and other relevant data.

The Company’s deferred premiums associated with its commodity derivative contracts are categorized as Level 3, as the Company utilizes a net present value calculation to determine the valuation. They are considered to be measured on a recurring basis as the derivative contracts they derive from are measured on a recurring basis. As commodity derivative contracts containing deferred premiums are entered into, the Company discounts the associated deferred premium to its net present value at the contract trade date, using the Senior Secured Credit Facility rate at the trade date (historical input rates range from 2.00% to 3.56%) and then records the change in net present value to interest expense over the period from trade until the final settlement date at the end of the contract. After this initial valuation, the net present value of each deferred premium is not adjusted; therefore, significant increases (decreases) in the Senior Secured Credit Facility rate would result in a significantly lower (higher) fair value measurement for each new deal containing a deferred premium entered into; however,

F-31

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

the valuation for the deals already recorded would remain unaffected. While the Company believes the sources utilized to arrive at the fair value estimates are reliable, different sources or methods could have yielded different fair value estimates; therefore, on a quarterly basis, the valuation is compared to counterparty valuations and third-party valuation of the deferred premiums for reasonableness.

The following table presents actual cash payments required for deferred premium contracts in place as of December 31, 2013, and for the calendar years following:

(in thousands)
2014		$	7,419
2015		5,166
2016		358
Total		$	12,943

A summary of the changes in assets classified as Level 3 measurements for the periods presented are as follows:

(in thousands)		For the year ended December 31, 2013
Balance of Level 3 at beginning of period		$	(24,709	)
Change in net present value of deferred premiums for derivatives		(462		)
Settlements(1)		12,487
Balance of Level 3 at end of period		$	(12,684	)

(in thousands)		For the year ended December 31, 2012
Balance of Level 3 at beginning of period		$	(18,868	)
Change in net present value of deferred premiums for derivatives		(668		)
Total purchases and settlements:
Purchases		(11,291		)
Settlements		6,118
Balance of Level 3 at end of period		$	(24,709	)

		For the year ended December 31, 2011
(in thousands)		Derivative option contracts				Deferred premiums
Balance of Level 3 at beginning of period		$	20,026			$	(12,495	)
Gains (losses) included in earnings		5,323				—
Change in net present value of deferred premiums for derivatives		—				(471		)
Total purchases and settlements:
Purchases		—				(5,988		)
Settlements		—				86
Transfers out of Level 3(2)(3)		(25,349		)		—
Balance of Level 3 at end of period		$	—			$	(18,868	)

___________________________________________________________________

(1)	The settlement amounts for the year ended December 31, 2013 include $2.2 million in deferred premiums which were settled net with the early terminated contracts from which they derive.

(2)

The Company transferred the commodity derivative option contracts out of Level 3 during the year ended December 31, 2011 due to the Company's ability to utilize transparent forward price curves and volatilities published and available through independent third party vendors. As a result, the Company transferred positions from Level 3 to Level 2 as the significant inputs used to calculate the fair value are all observable.

F-32

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

(3)	The Company's policy is to recognize transfers in and transfers out as of the actual date of the event or change in circumstances that caused the transfer.

2. Fair value measurement on a nonrecurring basis

The Company accounts for the impairment of long-lived assets (see Note B.20), if any, at fair value on a nonrecurring basis in accordance with GAAP. For purposes of fair value measurement, it was determined that the impairment of long-lived assets are classified as Level 3 based on the use of internally developed cash flow models. No impairments of long-lived assets were recorded in the years ended December 31, 2013, 2012 or 2011. See Note B.20 for discussion of the Company's impairment of materials and supplies in the year ended December 31, 2011.

The accounting policies for impairment of oil and natural gas properties are discussed in Note B.20. Significant inputs included in the calculation of discounted cash flows used in the impairment analysis include the Company's estimate of operating and development costs, anticipated production of proved reserves and other relevant data.

I—Credit risk

The Company's oil and natural gas sales are to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. The Company's joint operations accounts receivable are from a number of oil and natural gas companies, partnerships, individuals and others who own interests in the properties operated by the Company. Management believes that any credit risk imposed by a concentration in the oil and natural gas industry is offset by the creditworthiness of the Company's customer base and industry partners. The Company routinely assesses the recoverability of all material trade and other receivables to determine collectability.

The Company uses derivatives to hedge its exposure to oil and natural gas price volatility and its exposure to interest rate risk associated with the Senior Secured Credit Facility. These transactions expose the Company to potential credit risk from its counterparties. In accordance with the Company's standard practice, its derivatives are subject to counterparty netting under agreements governing such derivatives and therefore, the credit risk associated with its derivative counterparties is somewhat mitigated. See Note G for additional information regarding the Company's derivatives.

For the year ended December 31, 2013, the Company had three customers that accounted for 28.3%, 11.7% and 11.7% of total revenues, with two of the three customers accounting for 36.0% and 15.7% of oil and natural gas sales accounts receivable as of December 31, 2013. For the year ended December 31, 2012, the Company had three customers that accounted for 34.0%, 12.3% and 10.0% of total revenues, with the same three customers accounting for 25.7%, 13.0% and 10.7% and another customer accounting for 13.7% of oil and natural gas sales accounts receivable as of December 31, 2012. For the year ended December 31, 2011, the Company had three customers that accounted for 36.1%, 16.2% and 12.9% of total revenues, with the same three customers accounting for 31.6%, 13.9% and 15.9% and another customer accounting for 11.0% of oil and natural gas sales accounts receivable as of December 31, 2011.

As of December 31, 2013, the Company had four partners whose joint operations accounts receivable accounted for 16.0%, 14.1%, 13.1% and 10.9% of the Company's total joint operations accounts receivable. As of December 31, 2012, the Company had two partners whose joint operations accounts receivable accounted for 66.2% and 17.0% of the Company's total joint operations accounts receivable.

The Company's cash balances are insured by the FDIC up to $250,000 per bank. The Company had a cash balance on deposit with certain banks in the Senior Secured Credit Facility bank group as of December 31, 2013, which exceeded the balance insured by the FDIC in the amount of $240.5 million. Management believes that the risk of loss is mitigated by the bank's reputation and financial position.

F-33

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

Related-party transactions

The Company has a gathering and processing arrangement with affiliates of Targa Resources, Inc. ("Targa"). Warburg Pincus IX, a major stockholder of Laredo, and other affiliates of Warburg Pincus LLC, held material investment interests in Targa until May 2013. One of Laredo's directors is on the board of directors of affiliates of Targa. The following table summarizes the net oil and natural gas sales (oil and natural gas sales less production taxes) received from the Company's related party and included in the consolidated statements of operation for the periods presented:

		For the years ended December 31,
(in thousands)		2013				2012				2011
Net oil and natural gas sales		$	74,245			$	71,916			$	79,300

The following table summarizes the amounts included in oil and natural gas sales receivable from the Company's related party in the consolidated balance sheets for the periods presented:

		December 31,				December 31,
(in thousands)		2013				2012
Oil and natural gas sales receivable		$	9,064			$	6,244

J—Commitments and contingencies

1.    Lease commitments

The Company leases equipment and office space under operating leases expiring on various dates through 2022. Minimum annual lease commitments as of December 31, 2013, and for the calendar years following are:

(in thousands)
2014		1,994
2015		2,088
2016		1,923
2017		1,823
2018		1,738
Thereafter		1,367
Total		$	10,933

The following has been recorded to rent expense for the periods presented:

		For the years ended December 31,
(in thousands)		2013				2012				2011
Rent expense		$	1,923			$	1,339			$	1,175

The Company's office space lease agreements contain scheduled escalation in lease payments during the term of the lease. In accordance with GAAP, the Company records rent expense on a straight-line basis and a deferred lease liability for the difference between the straight-line amount and the actual amounts of the lease payments.

2.    Litigation

The Company may be involved in legal proceedings or is subject to industry rulings that could bring rise to claims in the ordinary course of business. The Company has concluded that the likelihood is remote that the ultimate resolution of any pending litigation or pending claims will be material or have a material adverse effect on the Company’s business, financial position, results of operations or liquidity.

F-34

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

3.    Drilling contracts

The Company has committed to several short-term drilling contracts with various third parties in order to complete its various drilling projects. The contracts contain an early termination clause that requires the Company to pay significant penalties to the third party should the Company cease drilling efforts. These penalties could significantly impact the Company’s financial statements upon contract termination. These commitments are not recorded in the accompanying consolidated balance sheets. Future commitments are $40.8 million as of December 31, 2013. Management does not anticipate canceling any drilling contracts or discontinuing drilling efforts in 2014.

4.    Federal and state regulations

Oil and natural gas exploration, production and related operations are subject to extensive federal and state laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases the cost of doing business and affects profitability. The Company believes that it is in compliance with currently applicable state and federal regulations related to oil and natural gas exploration and production, and that compliance with the current regulations will not have a material adverse impact on the financial position or results of operations of the Company. Because these rules and regulations are frequently amended or reinterpreted, the Company is unable to predict the future cost or impact of complying with these regulations.

K—Net income per share

Basic net income (loss) per share is computed by dividing net income (loss) by the weighted average number of shares outstanding for the period. Diluted net income (loss) per share reflects the potential dilution of non-vested restricted stock awards. The effect of the Company's outstanding options that were granted in February 2012 to purchase 359,002 shares of common stock at $24.11 per share were excluded from the calculation of diluted net income (loss) per share for each of the years ended December 31, 2013 and 2012, because the exercise price of those options was greater than the average market price during the period, and, therefore, the inclusion of these outstanding options would have been anti-dilutive. The effect of the Company's outstanding options that were granted in February 2013 to purchase 869,938 shares of common stock at $17.34 per share were excluded from the calculation of diluted net income (loss) per share for the year ended December 31, 2013, because, utilizing the treasury method, the sum of the assumed proceeds exceeds the average stock price during the period and, therefore, the inclusion of these outstanding options would have been anti-dilutive.

    

F-35

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

The following is the calculation of basic and diluted weighted average shares outstanding and net income per share for the periods presented:

		For the years ended December 31,
(in thousands, except for per share data)		2013				2012				2011
Net income (loss) (numerator):
Income from continuing operations—basic and diluted		$	116,577			$	61,761			$	105,976
Income (loss) from discontinued operations, net of tax—basic and diluted		1,423				(107		)		(422		)
Net income—basic and diluted		$	118,000			$	61,654			$	105,554
Weighted average shares (denominator):
Weighted average shares—basic(1)		132,490				126,957				107,187
Non-vested restricted stock(2)		1,888				1,214				912
Weighted average shares—diluted		134,378				128,171				108,099
Net income (loss) per share:
Basic:
Income from continuing operations		$	0.88			$	0.49			$	0.99
Income (loss) from discontinued operations, net of tax		0.01				—				(0.01		)
Net income per share		$	0.89			$	0.49			$	0.98
Diluted:
Income from continuing operations		$	0.87			$	0.48			$	0.98
Income (loss) from discontinued operations, net of tax		0.01				—				—
Net income per share		$	0.88			$	0.48			$	0.98

_______________________________________________________

(1)	For the year ended December 31, 2013, weighted average shares outstanding used in the computation of basic and diluted net income per share attributable to stockholders has been computed taking into account the Follow-on Offering.

(2)

For the year ended December 31, 2011, weighted average shares outstanding used in the computation of basic and diluted net income per share attributable to stockholders has been computed taking into account (i) restricted stock awards converted in the Corporate Reorganization as if the conversion occurred as of the beginning of the year and (ii) the 20,125,000 shares of common stock issued by the Company in the IPO.

L—Recently issued accounting standards

In July 2013, the Financial Accounting Standards Board ("FASB") issued guidance on the presentation of unrecognized tax benefits when a net operating loss carry-forward, a similar tax loss, or a tax credit carry-forward exists at the reporting date. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The Company does not expect the adoption to have an impact on the consolidated financial statements.

M—Variable interest entity

An entity is referred to as a variable interest entity ("VIE") pursuant to accounting guidance for consolidation if it possesses one of the following criteria: (i) it is thinly capitalized, (ii) the residual equity holders do not control the entity, (iii) the equity holders are shielded from the economic losses, (iv) the equity holders do not participate fully in the entity's residual economics, or (v) the entity was established with non-substantive voting interests. In order to determine if a VIE should be consolidated, an entity must determine if it is the primary beneficiary of the VIE. The primary beneficiary of a VIE is that variable interest holder possessing a controlling financial interest through: (i) its power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (ii) its obligation to absorb losses or its right to receive benefits from the VIE that could potentially be significant to the VIE. In order to determine whether the Company owns a variable interest in a VIE, a qualitative analysis is performed of the entity’s design, organizational structure, primary decision makers and relevant agreements. The Company continually monitors its VIE exposure to determine if any events have occurred that could cause the primary beneficiary to change.

F-36

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

On January 4, 2013 and April 22, 2013, Laredo Midstream contributed $0.9 million and $2.3 million, respectively, to Medallion Gathering & Processing, LLC (“Medallion”), a Texas limited liability company. Laredo Midstream holds 49% of Medallion ownership units. Medallion, which was formed on October 31, 2012 and its wholly owned subsidiary, Medallion Pipeline Company, LLC ("MPC"), a Texas limited liability company formed on September 9, 2013, were established for the purpose of developing midstream solutions and providing midstream infrastructure to bring discovered oil and natural gas to market. Laredo Midstream and the other 51% interest-holder have agreed that the voting rights of Medallion, the profit and loss sharing, and the additional capital contribution requirements shall be equal to the ownership unit percentage held. Additionally, Medallion requires a super-majority vote of 75% for all key operation and business decisions. The Company has determined that Medallion is a VIE. However, Laredo Midstream is not considered to be the primary beneficiary of the VIE because Laredo Midstream does not have the power to direct the activities that most significantly affect Medallion's economic performance. As such, Medallion is accounted for under the equity method of accounting with the Company's proportionate share of net income reflected in the consolidated statements of operations as "Income from equity method investee" and the carrying amount reflected in the consolidated balance sheet as "Investment in equity method investee."

Laredo Midstream has committed to contribute an additional $25.7 million to Medallion in 2014 towards the construction of a pipeline by MPC. The Company has recorded a capital contribution payable of $2.6 million related to the fourth quarter cash requirements of the project and a payable of $0.9 million related to its minimum volume commitment to Medallion, both of which are reported in the consolidated balance sheet as "Accrued payable - affiliates." The corresponding expense related to the minimum volume commitment is reported on the consolidated statements of operations in the "Transportation and treating - affiliates" line item.

N—Subsidiary guarantee

Laredo Midstream has fully and unconditionally guaranteed the 2019 Notes, the 2022 Notes and the Senior Secured Credit Facility. In accordance with practices accepted by the SEC, Laredo has prepared condensed consolidating financial statements in order to quantify the assets, results of operations and cash flows of Laredo Midstream as a subsidiary guarantor. The following condensed consolidating balance sheets as of December 31, 2013 and 2012, and condensed consolidating statements of operations and condensed consolidating statements of cash flows each for the years ended December 31, 2013, 2012 and 2011, present financial information for Laredo on a stand-alone basis (carrying any investment in subsidiaries under the equity method), financial information for the Laredo Midstream on a stand-alone basis (carrying any investment in subsidiaries under the equity method), and the consolidation and elimination entries necessary to arrive at the information for the Company on a condensed consolidated basis. Deferred income taxes for Laredo Midstream are recorded on Laredo's statements of financial position, statements of operations and statements of cash flow as a flow-through entity for income tax purposes. Laredo and Laredo Midstream are not restricted from making distributions.

F-37

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

Condensed consolidating balance sheet

December 31, 2013

(in thousands)		Laredo				Laredo Midstream				Intercompany eliminations				Consolidated company
Accounts receivable		$	77,318			$	—			$	—			$	77,318
Other current assets		230,291				—				—				230,291
Total oil and natural gas properties, net		2,135,348				—				—				2,135,348
Total pipeline and gathering assets, net		—				41,498				—				41,498
Total other fixed assets, net		27,478				—				—				27,478
Investment in subsidiaries and equity method investee		36,666				5,913				(36,666		)		5,913
Total other long-term assets		105,914				—								105,914
Total assets		$	2,613,015			$	47,411			$	(36,666	)		$	2,623,760
Accounts payable		$	12,216			$	3,786			$	—			$	16,002
Other current liabilities		231,008				6,959				—				237,967
Other long-term liabilities		45,997				—				—				45,997
Long-term debt		1,051,538				—				—				1,051,538
Stockholders' equity		1,272,256				36,666				(36,666		)		1,272,256
Total liabilities and stockholders' equity		$	2,613,015			$	47,411			$	(36,666	)		$	2,623,760

Condensed consolidating balance sheet

December 31, 2012

(in thousands)		Laredo				Laredo Midstream				Intercompany eliminations				Consolidated company
Accounts receivable		$	83,737			$	103			$	—			$	83,840
Other current assets		53,597				—				—				53,597
Total oil and natural gas properties, net		2,031,938				—				—				2,031,938
Total pipeline and gathering assets, net		—				65,292				—				65,292
Total other fixed assets, net		16,661				—				—				16,661
Investment in subsidiaries		60,652				—				(60,652		)		—
Total other long-term assets		86,976				—				—				86,976
Total assets		$	2,333,561			$	65,395			$	(60,652	)		$	2,338,304
Accounts payable		$	47,129			$	1,543			$	—			$	48,672
Other current liabilities		210,196				3,200				—				213,396
Other long-term liabilities		27,753				—				—				27,753
Long-term debt		1,216,760				—				—				1,216,760
Stockholders' equity		831,723				60,652				(60,652		)		831,723
Total liabilities and stockholders' equity		$	2,333,561			$	65,395			$	(60,652	)		$	2,338,304

F-38

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

Condensed consolidating statement of operations

For the year ended December 31, 2013

(in thousands)		Laredo				Laredo Midstream				Intercompany eliminations				Consolidated company
Total operating revenues		$	665,172			$	8,824			$	(8,739	)		$	665,257
Total operating costs and expenses		455,972				3,673				(8,739		)		450,906
Income from operations		209,200				5,151				—				214,351
Interest expense, net		(100,164		)		—				—				(100,164		)
Other, net		84,861				2,268				(10,232		)		76,897
Income from continuing operations before income tax		193,897				7,419				(10,232		)		191,084
Income tax (expense) benefit		(75,504		)		997				—				(74,507		)
Income from continuing operations		118,393				8,416				(10,232		)		116,577
Income (loss) from discontinued operations, net of tax		(393		)		1,816				—				1,423
Net income		$	118,000			$	10,232			$	(10,232	)		$	118,000

Condensed consolidating statement of operations

For the year ended December 31, 2012

(in thousands)		Laredo				Laredo Midstream				Intercompany eliminations				Consolidated company
Total operating revenues		$	583,759			$	10,285			$	(10,150	)		$	583,894
Total operating costs and expenses		418,745				3,359				(10,150		)		411,954
Income from operations		165,014				6,926				—				171,940
Interest expense, net		(85,513		)		—				—				(85,513		)
Other, net		18,143				—				(9,806		)		8,337
Income from continuing operations before income tax		97,644				6,926				(9,806		)		94,764
Income tax (expense) benefit		(33,969		)		966				—				(33,003		)
Income from continuing operations		63,675				7,892				(9,806		)		61,761
Income (loss) from discontinued operations, net of tax		(2,021		)		1,914				—				(107		)
Net income		$	61,654			$	9,806			$	(9,806	)		$	61,654

Condensed consolidating statement of operations

For the year ended December 31, 2011

(in thousands)		Laredo				Laredo Midstream				Intercompany eliminations				Consolidated company
Total operating revenues		$	506,430			$	7,189			$	(7,272	)		$	506,347
Total operating costs and expenses		308,541				2,558				(7,272		)		303,827
Income from operations		197,889				4,631				—				202,520
Interest expense, net		(50,472		)		—				—				(50,472		)
Other, net		21,182				—				(7,642		)		13,540
Income from continuing operations before income tax		168,599				4,631				(7,642		)		165,588
Income tax (expense) benefit		(60,698		)		1,086				—				(59,612		)
Income from continuing operations		107,901				5,717				(7,642		)		105,976
Income (loss) from discontinued operations, net of tax		(2,347		)		1,925				—				(422		)
Net income		$	105,554			$	7,642			$	(7,642	)		$	105,554

F-39

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

Condensed consolidating statement of cash flows

For the year ended December 31, 2013

(in thousands)		Laredo				Laredo Midstream				Intercompany eliminations				Consolidated company
Net cash flows provided by operating activities		$	359,198			$	15,763			$	(10,232	)		$	364,729
Net cash flows used in investing activities		(324,353		)		(15,763		)		10,232				(329,884		)
Net cash flows provided by financing activities		130,084				—				—				130,084
Net increase in cash and cash equivalents		164,929				—				—				164,929
Cash and cash equivalents at beginning of period		33,224				—				—				33,224
Cash and cash equivalents at end of period		$	198,153			$	—			$	—			$	198,153

Condensed consolidating statement of cash flows

For the year ended December 31, 2012

(in thousands)		Laredo				Laredo Midstream				Intercompany eliminations				Consolidated company
Net cash flows provided by operating activities		$	373,362			$	13,219			$	(9,805	)		$	376,776
Net cash flows used in investing activities		(937,337		)		(13,219		)		9,805				(940,751		)
Net cash flows provided by financing activities		569,197				—				—				569,197
Net increase in cash and cash equivalents		5,222				—				—				5,222
Cash and cash equivalents at beginning of period		28,002				—				—				28,002
Cash and cash equivalents at end of period		$	33,224			$	—			$	—			$	33,224

Condensed consolidating statement of cash flows

For the year ended December 31, 2011

(in thousands)		Laredo				Laredo Midstream				Intercompany eliminations				Consolidated company
Net cash flows provided by operating activities		$	341,607			$	10,111			$	(7,642	)		$	344,076
Net cash flows used in investing activities		(704,318		)		(10,111		)		7,642				(706,787		)
Net cash flows provided by financing activities		359,478				—				—				359,478
Net decrease in cash and cash equivalents		(3,233		)		—				—				(3,233		)
Cash and cash equivalents at beginning of period		31,235				—				—				31,235
Cash and cash equivalents at end of period		$	28,002			$	—			$	—			$	28,002

F-40

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

O—Subsequent events

1.   Note offering

On January 23, 2014, Laredo completed an offering of $450.0 million in aggregate principal amount of 5 5/8% senior unsecured notes due 2022 (the “Notes”), and entered into an Indenture (the “Indenture”) among Laredo, the Guarantor and Wells Fargo Bank, National Association, as trustee. The Notes will mature on January 15, 2022 with interest accruing at a rate of 5 5/8% per annum and payable semi-annually in cash in arrears on January 15 and July 15 of each year, commencing July 15, 2014. The Notes are guaranteed on a senior unsecured basis by the Guarantor and certain of the Company’s future restricted subsidiaries.

The Notes were issued pursuant to the Indenture in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended (the "Securities Act"). The Notes were offered and sold only to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. The Company received net proceeds of $442.2 million from the offering, after deducting the initial purchasers’ discount and the estimated outstanding offering expenses. The Company will use the net proceeds of the offering for general working capital purposes. As a result of the issuance of the Notes, the amount available for borrowings under the Senior Secured Credit Facility was reduced to $812.5 million.

Laredo may redeem, at its option, all or part of the Notes at any time on and after January 15, 2017, at the applicable redemption price plus accrued and unpaid interest to the date of redemption. In addition, Laredo may redeem, at its option, all or part of the Notes at any time prior to January 15, 2017 at a redemption price equal to 100% of the principal amount of the Notes redeemed plus the applicable premium and accrued and unpaid interest and additional interest, if any, to the date of redemption. Further, before January 15, 2017, Laredo may on one or more occasions redeem up to 35% of the aggregate principal amount of the Notes in an amount not exceeding the net proceeds from one or more private or public equity offerings at a redemption price of 105.625% of the principal amount of the Notes, plus accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the Notes remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of each such equity offering. If a change of control occurs prior to January 15, 2015, Laredo may redeem all, but not less than all, of the Notes at a redemption price equal to 110% of the principal amount of the Notes plus any accrued and unpaid interest to the date of redemption.

In connection with the closing of the offering of the Notes, Laredo and the Guarantor entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with the several initial purchasers named in the Registration Rights Agreement. Pursuant to the Registration Rights Agreement, Laredo and the Guarantor have agreed to use commercially reasonable efforts to file a registration statement with the SEC relating to an offer to exchange the Notes for substantially identical notes (other than with respect to restrictions on transfer or any increase in annual interest rate) that are registered under the Securities Act so as to permit the exchange offer to be consummated within 365 days after the issuance of the Notes. Under certain circumstances, Laredo and the Guarantor will be obligated to pay additional interest if they fail to comply with their obligations to register the Notes within the specified time periods.

2.    Additional contribution to Medallion

On February 5, 2014, Laredo Midstream contributed $11.3 million of its $25.7 million commitment to Medallion to fund the construction of a pipeline by MPC. As of December 31, 2013, the Company had recorded a capital contribution payable of $2.6 million related to this capital call.

3.    Early termination of derivative contract

In February 2014, the Company unwound a physical commodity contract and the associated oil basis swap financial derivative contract which hedged the differential between the Light Louisiana Sweet Argus and the Brent International Petroleum Exchange index oil prices. Prior to its unwind, the physical commodity contract qualified to be scoped out of mark-to-market accounting per the normal purchase normal sale exemption provided for under GAAP. Once modified to settle financially in the unwind agreement, the contract ceased to qualify for the normal purchase normal sale exemption, therefore requiring it to be marked-to-market. The Company received net proceeds of $76.7 million from the early termination of these contracts. The Company agreed to settle the contracts early due to the counterparty's decision to exit the physical commodity trading business.

F-41

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Laredo Petroleum, Inc.

Notes to the consolidated financial statements

December 31, 2013, 2012 and 2011

4.    New derivative contracts

Subsequent to December 31, 2013, the Company entered into the following new commodity contracts:

		Aggregate volumes			Swap price				Contract period
Natural gas (volumes in MMBtu):
Swap(1)		3,060,000			$	4.32			March 2014 - December 2014
Swap(1)		2,448,000			$	4.32			March 2014 - December 2014

_____________________________________________________________

(1)        These natural gas derivatives are settled based on the Inside FERC West Texas Waha index price for the calculation period.

    

F-42

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Laredo Petroleum, Inc.

Supplemental oil and natural gas disclosures

December 31, 2013, 2012 and 2011

P—Supplemental oil and natural gas disclosures

1.    Costs incurred in oil and natural gas property acquisition, exploration and development activities

Costs incurred in the acquisition and development of oil and natural gas assets are presented below for the periods presented:

		For the years ended December 31,
(in thousands)		2013				2012				2011
Property acquisition costs:
Proved		$	9,652			$	16,925			$	—
Unproved		27,087				3,693				—
Exploration		48,763				93,266				62,888
Development costs(1)		654,452				839,118				660,922
Total costs incurred		$	739,954			$	953,002			$	723,810

__________________________________________________________________________

(1)        The costs incurred for oil and natural gas development activities include $6.8 million, $7.4 million and $4.5 million, in asset retirement obligations for the years ended December 31, 2013, 2012 and 2011, respectively.

2.    Capitalized oil and natural gas costs

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depletion, depreciation and impairment are presented below for the periods presented:

		For the years ended December 31,
(in thousands)		2013				2012				2011
Capitalized costs:
Proved properties		$	3,276,578			$	2,993,266			$	2,083,015
Unproved properties		208,085				159,946				117,195
		3,484,663				3,153,212				2,200,210
Less accumulated depletion, depreciation and impairment		1,349,315				1,121,273				884,533
Net capitalized costs		$	2,135,348			$	2,031,939			$	1,315,677

The following table shows a summary of the oil and natural gas property costs not being amortized as of December 31, 2013, by year in which such costs were incurred:

(in thousands)		2013				2012				2011				2010 and prior				Total
Unproved properties		$	124,588			$	67,370			$	8,249			$	7,878			$	208,085

Unproved properties, which are not subject to amortization, are not individually significant and consist of costs for acquiring oil and natural gas leaseholds where no proved reserves have been identified, including costs of wells being evaluated. The evaluation process associated with these properties has not been completed and therefore, the Company is unable to estimate when these costs will be included in the amortization calculation.

F-43

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Laredo Petroleum, Inc.

Supplemental oil and natural gas disclosures

December 31, 2013, 2012 and 2011

3.    Results of oil and natural gas producing activities

The results of operations of oil and natural gas producing activities (excluding corporate overhead and interest costs) are presented below for the periods presented:

		For the years ended December 31,
(in thousands)		2013				2012				2011
Revenues:
Oil and natural gas sales		$	664,844			$	583,569			$	506,255
Production costs:
Lease operating expenses		79,136				67,325				43,306
Production and ad valorem taxes		42,396				37,637				31,982
		121,532				104,962				75,288
Other costs:
Depletion and depreciation		227,992				237,130				171,517
Accretion of asset retirement obligation		1,475				1,200				616
Income tax expense(1)		112,984				83,686				93,180
Results of operations		$	200,861			$	156,591			$	165,654

__________________________________________________________________________

(1)     Income tax expense above is computed utilizing the statutory rate.

4.    Net proved oil and natural gas reserves - (unaudited)

Ryder Scott Company, L.P. ("Ryder Scott"), the Company's independent reserve engineers, estimated 100% of the Company's proved reserves as of December 31, 2013, 2012 and 2011. In accordance with SEC regulations, reserves as of December 31, 2013, 2012 and 2011 were estimated using the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. The Company's reserves are reported in two streams; crude oil and natural gas. The economic value of the natural gas liquids in the Company's natural gas is included in the wellhead natural gas price. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and natural gas properties. Accordingly, the estimates may change as future information becomes available.

The following table provides an analysis of the change in estimated quantities of oil and natural gas reserves, all of which are located within the United States, for the periods presented.

		Year ended December 31, 2013
		Oil (MBbl)			Gas (MMcf)			MBOE
Proved developed and undeveloped reserves:
Beginning of year		98,141			542,946			188,632
Revisions of previous estimates		(17,956	)		15,710			(15,338	)
Extensions, discoveries and other additions		37,850			192,229			69,888
Purchases of reserves in place		170			1,454			412
Sales of reserves in place		(1,220	)		(165,289	)		(28,768	)
Production		(5,487	)		(34,348	)		(11,211	)
End of year		111,498			552,702			203,615
Proved developed reserves:
Beginning of year		33,316			289,045			81,490
End of year		37,878			203,082			71,725
Proved undeveloped reserves:
Beginning of year		64,825			253,901			107,142
End of year		73,620			349,620			131,890

F-44

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Laredo Petroleum, Inc.

Supplemental oil and natural gas disclosures

December 31, 2013, 2012 and 2011

		Year ended December 31, 2012
		Oil (MBbl)			Gas (MMcf)			MBOE
Proved developed and undeveloped reserves:
Beginning of year		56,267			601,117			156,453
Revisions of previous estimates		(12,396	)		(260,651	)		(55,837	)
Extensions, discoveries and other additions		57,391			232,418			96,127
Purchases of reserves in place		1,654			9,210			3,189
Production		(4,775	)		(39,148	)		(11,300	)
End of year		98,141			542,946			188,632
Proved developed reserves:
Beginning of year		21,762			248,598			63,195
End of year		33,316			289,045			81,490
Proved undeveloped reserves:
Beginning of year		34,505			352,519			93,258
End of year		64,825			253,901			107,142

		Year ended December 31, 2011
		Oil (MBbl)			Gas (MMcf)			MBOE
Proved developed and undeveloped reserves:
Beginning of year		44,847			550,278			136,560
Revisions of previous estimates		(1,124	)		(47,296	)		(9,006	)
Extensions, discoveries and other additions		15,912			129,846			37,553
Purchases of reserves in place		—			—			—
Production		(3,368	)		(31,711	)		(8,654	)
End of year		56,267			601,117			156,453
Proved developed reserves:
Beginning of year		12,420			194,481			44,833
End of year		21,762			248,598			63,195
Proved undeveloped reserves:
Beginning of year		32,427			355,797			91,727
End of year		34,505			352,519			93,258

For the year ended December 31, 2013, the Company's negative revision of 15,338 MBOE of previously estimated quantities is primarily attributable to the removal of 11,944 MBOE due to the combined effect of the removal of 174 proved undeveloped locations and the net effect of redetermining 501 undeveloped locations. The 174 locations that were removed were comprised of vertical Wolfberry and short horizontal laterals which were replaced with longer horizontal laterals to better align with future drilling plans. The remaining 3,394 MBOE of the negative revision is due to a combination of pricing, performance and other changes. Extensions, discoveries and other additions of 69,888 MBOE during the year ended December 31, 2013, consisted of 22,245 MBOE primarily from the drilling of new wells during the year and 47,643 MBOE from new proved undeveloped locations added during the year. The latter consists of 45,510 MBOE attributable to 85 horizontal locations in the Permian Basin. Purchases of minerals in place added 412 MBOE from acquisition of proved reserves in the Permian Basin. The oil and natural gas reference prices used in computing our reserves as of December 31, 2013 were $93.52 per barrel of oil and $3.57 per MMBtu of natural gas before price differentials.

For the year ended December 31, 2012, the Company's negative revision of 55,837 MBOE of previous estimated quantities is primarily attributable to the removal of 50,845 MBOE due to lower natural gas prices and increased development costs for vertical Granite Wash locations in the Anadarko Basin and shallow Wolfberry vertical locations in the Permian Basin. Due to these factors, these locations became economically unattractive to develop and were replaced by new horizontal and/or oil development opportunities. The balance of the negative revision of 4,993 MBOE is due to a combination of performance,

F-45

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Laredo Petroleum, Inc.

Supplemental oil and natural gas disclosures

December 31, 2013, 2012 and 2011

pricing and other changes. Extensions, discoveries and other additions of 96,127 MBOE during the year ended December 31, 2012, consist of 26,235 MBOE primarily from the drilling of new wells during the year and 69,892 MBOE from new proved undeveloped locations added during the year, which increased the Company's proved reserves. The latter consists of 67,200 MBOE attributable to 317 locations in our Permian Basin play and 2,692 MBOE attributable to six locations in our Anadarko Granite Wash play. Purchases of minerals in place added 3,189 MBOE from acquisition of proved reserves in the Permian Basin. The oil and natural gas reference prices used in computing our reserves as of December 31, 2012 were $91.21 per barrel of oil and $2.63 per MMBtu of natural gas before price differentials.

For the year ended December 31, 2011, the Company's negative revision of 9,006 MBOE of previous estimated quantities is primarily attributable to uneconomic proved undeveloped locations. Extensions, discoveries and other additions of 37,553 MBOE during the year ended December 31, 2011, consist of 14,709 MBOE primarily from the drilling of new wells during the year and 22,844 MBOE from new proved undeveloped locations added during the year, which increased the Company's proved reserves, the latter of which consists of 15,009 MBOE attributable to 155 vertical locations in our Permian Basin play, 7,835 MBOE attributable to 47 vertical locations in our Anadarko Granite Wash play. The oil and natural gas reference prices used in computing our reserves as of December 31, 2011 were $92.71 per barrel of oil and $3.99 per MMBtu of natural gas before price differentials.

5.    Standardized measure of discounted future net cash flows - (unaudited)

The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions.

The estimates of future cash flows and future production and development costs as of December 31, 2013, 2012 and 2011 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. Future income tax expenses are computed using the appropriate year-end statutory tax rates applied to the future pretax net cash flows from proved oil and natural gas reserves, less the tax basis of the Company's oil and natural gas properties. Reference prices used, before differentials were applied were $93.52, $91.21 and $92.71 per Bbl of oil and $3.57, $2.63 and $3.99 per MMBtu for December 31, 2013, 2012 and 2011, respectively. All wellhead prices are held flat over the forecast period for all reserve categories. The estimated future net cash flows are then discounted at a rate of 10%.

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows for the periods presented:

		For the years ended December 31,
(in thousands)		2013				2012				2011
Future cash inflows		$	13,337,798			$	11,636,926			$	8,856,906
Future production costs		(3,059,368		)		(3,163,371		)		(2,562,237		)
Future development costs		(2,250,950		)		(2,252,559		)		(1,959,818		)
Future income tax expenses		(2,150,983		)		(1,433,373		)		(999,185		)
Future net cash flows		5,876,497				4,787,623				3,335,666
10% discount for estimated timing of cash flows		(3,554,293		)		(2,910,167		)		(1,934,807		)
Standardized measure of discounted future net cash flows		$	2,322,204			$	1,877,456			$	1,400,859

In the foregoing determination of future cash inflows, sales prices used for oil and natural gas for December 31, 2013, 2012 and 2011 were estimated using the average price during the 12-month period, determined as the unweighted arithmetic average first-day-of-the-month price for each month. Prices were adjusted by lease for quality, transportation fees and regional price differentials. Future costs of developing and producing the proved oil and natural gas reserves reported at the end of each year shown were based on costs determined at each such year-end, assuming the continuation of existing economic conditions.

It is not intended that the FASB's standardized measure of discounted future net cash flows represent the fair market value of the Company's proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.

F-46

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Laredo Petroleum, Inc.

Supplemental oil and natural gas disclosures

December 31, 2013, 2012 and 2011

Changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows for the periods presented:

		For the years ended December 31,
(in thousands)		2013				2012				2011
Standardized measure of discounted future net cash flows, beginning of year		$	1,877,456			$	1,400,859			$	869,982
Changes in the year resulting from:
Sales, less production costs		(543,312		)		(478,607		)		(430,967		)
Revisions of previous quantity estimates		(190,961		)		(631,693		)		(70,021		)
Extensions, discoveries and other additions		1,166,481				1,287,952				529,041
Net change in prices and production costs		313,947				194,921				566,034
Changes in estimated future development costs		921				(3,917		)		(163,399		)
Previously estimated development costs incurred during the period		89,396				137,510				207,818
Purchases of reserves in place		7,604				25,041				—
Divestitures of reserves in place		(239,148		)		—				—
Accretion of discount		234,852				176,996				106,170
Net change in income taxes		(259,991		)		(101,955		)		(176,165		)
Timing differences and other		(135,041		)		(129,651		)		(37,634		)
Standardized measure of discounted future net cash flows, end of year		$	2,322,204			$	1,877,456			$	1,400,859

Estimates of economically recoverable oil and natural gas reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are, to some degree, subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities of oil and natural gas may differ materially from the amounts estimated.

Q—Supplemental quarterly financial data - (unaudited)

The Company's results from continuing operations by quarter for the periods presented are as follows:

		Year ended December 31, 2013
(in thousands, except per share data)		First Quarter				Second Quarter				Third Quarter				Fourth Quarter
Revenues		$	163,705			$	177,296			$	170,840			$	153,416
Operating income		44,505				57,414				57,420				55,012
Net income		1,409				35,812				12,543				68,236
Net income per common share:
Basic		$	0.01			$	0.28			$	0.09			$	0.48
Diluted		$	0.01			$	0.27			$	0.09			$	0.48

		Year ended December 31, 2012(1)
(in thousands, except per share data)		First Quarter				Second Quarter				Third Quarter				Fourth Quarter
Revenues		$	149,012			$	139,715			$	143,835			$	151,332
Operating income		55,145				41,689				37,206				37,900
Net income (loss)		26,235				30,975				(7,384		)		11,828
Net income (loss) per common share:
Basic		$	0.21			$	0.24			$	(0.06	)		$	0.09
Diluted		$	0.20			$	0.24			$	(0.06	)		$	0.09

______________________________________________________________________________

(1) The results of operations of the Pipeline Assets, which are a component of the Anadarko Basin Sale, are presented as results of discontinued operations, net of tax in these consolidated financial statements. Accordingly, the Company has reclassified the financial results and the related notes for all prior periods presented to reflect these operations as discontinued.

F-47