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 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.

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, 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.

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.

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.

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.

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		$	—	$	—