Organization and Summary of Significant Accounting Policies

Business and Principles of Consolidation

On July 30, 2012, we changed our company name from "Pioneer Drilling Company" to "Pioneer Energy Services Corp." Our common stock trades on the New York Stock Exchange under the ticker symbol "PES." Our new name reflects our strategy to expand our service offerings beyond drilling services, which has been our core, legacy business. Pioneer Energy Services provides drilling services and production services to a diverse group of independent and large oil and gas exploration and production companies throughout much of the onshore oil and gas producing regions of the United States and internationally in Colombia. We also provide coiled tubing and wireline services offshore in the Gulf of Mexico.

Our Drilling Services Segment provides contract land drilling services with its fleet of 70 drilling rigs which are currently assigned to the following divisions:



Drilling Division		Rig Count
South Texas		14
East Texas		4
West Texas		23
North Dakota		12
Utah		5
Appalachia		4
Colombia		8
		70

Since late 2009, increased demand for drilling services in domestic shale plays and oil or liquid rich regions resulted in increased rig utilization and drilling revenues in these regions. We capitalized on this trend by moving drilling rigs in our fleet to these higher demand regions from lower demand regions. As a result, we closed our Oklahoma and North Texas drilling divisions and established our West Texas drilling division in 2011.

In early 2011, we began construction, based on term contracts, of ten new-build AC drilling rigs that are fit for purpose for domestic shale plays. Construction has been completed for eight of these new-build drilling rigs which are currently operating in the shale plays, and we expect the remaining two to be completed and working under term contracts by the end of the first quarter of 2013.

As of January 31, 2013, 57 drilling rigs are operating under drilling contracts, 43 of which are under term contracts. Included in the 43 drilling rigs currently operating under term contracts are three rigs which our client early released due to the recent decrease in demand for vertical conventional drilling in West Texas. These three drilling rigs are under term contracts and therefore we are receiving a standby dayrate for the remainder of the contract term. All our drilling rigs in Colombia are currently working, six of which are working under term contracts that were extended through the first quarter of 2013. We are actively marketing all our idle drilling rigs.

In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. We obtain our contracts for drilling oil and natural gas wells either through competitive bidding or through direct negotiations with existing or potential clients. Our drilling contracts generally provide for compensation on either a daywork, turnkey or footage basis. Contract terms generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used, and the anticipated duration of the work to be performed.

Our Production Services Segment provides a range of services to exploration and production companies, including well servicing, wireline services, coiled tubing services, and fishing and rental services. Our production services operations are concentrated in the major United States onshore oil and gas producing regions in the Mid-Continent and Rocky Mountain states and in the Gulf Coast, both onshore and offshore. As of January 31, 2013, we have a fleet of 108 well servicing rigs consisting of ninety-eight 550 horsepower rigs and ten 600 horsepower rigs, all of which are currently operating or are being actively marketed. We currently provide wireline services and coiled tubing services with a fleet of 120 wireline units and 13 coiled tubing units, and we provide rental services with approximately $16.1 million of fishing and rental tools.

The accompanying consolidated financial statements include the accounts of Pioneer Energy Services Corp. and our wholly owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. In preparing the accompanying consolidated financial statements, we make various estimates and assumptions that affect the amounts of assets and liabilities we report as of the dates of the balance sheets and income and expenses we report for the periods shown in the income statements and statements of cash flows. Our actual results could differ significantly from those estimates. Material estimates that are particularly susceptible to significant changes in the near term relate to our recognition of revenues and costs for turnkey contracts, our estimate of the allowance for doubtful accounts, our determination of depreciation and amortization expense, our estimates of fair value for impairment evaluations, our estimate of deferred taxes, our estimate of the liability relating to the self-insurance portion of our health and workers’ compensation insurance, and our estimate of compensation related accruals.

In preparing the accompanying consolidated financial statements, we have reviewed events that have occurred after December 31, 2012, through the filing of this Form 10-K, for inclusion as necessary.

Recently Issued Accounting Standards

Fair Value Measurement. In May 2011, the FASB issued ASU No. 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs. This update clarifies existing guidance about how fair value should be applied where it already is required or permitted and provides wording changes that align this standard with International Financial Reporting Standards (IFRS). We are required to apply this guidance prospectively beginning with our first quarterly filing in 2012. The adoption of this new guidance has not had an impact on our financial position or results of operations.

Comprehensive Income. In June 2011, the FASB issued ASU No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. This update increases the prominence of other comprehensive income in financial statements, eliminating the option of presenting other comprehensive income in the statement of changes in equity, and instead, requiring the components of net income and comprehensive income to be presented in either one or two consecutive financial statements. We are required to comply with this guidance prospectively beginning with our first quarterly filing in 2012. The adoption of this new guidance has not had an impact on our financial position or results of operations.

In December 2011, the FASB issued ASU No. 2011-12, Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05. This update delays the effective date of the requirement to present reclassification adjustments for each component of accumulated other comprehensive income in both net income and other comprehensive income on the face of the financial statements.

In February 2012, the FASB issued ASU No. 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. This update adds new disclosure requirements for items reclassified out of accumulated other comprehensive income. We are required to apply this guidance prospectively beginning with our first quarterly filing in 2013. The adoption of this new guidance will not impact our financial position or statement of operations, other than changes in presentation.

Intangibles–Goodwill and Other. In September 2011, the FASB issued ASU No. 2011-08, Intangibles–Goodwill and Other (Topic 350): Testing Goodwill for Impairment. This update allows entities testing goodwill for impairment the option of performing a qualitative assessment before calculating the fair value of the reporting unit (i.e., step one of the two-step goodwill impairment test). If entities determine, on the basis of qualitative factors, that the fair value of the reporting unit is more likely than not less than the carrying amount, the two-step impairment test would be required. The amendments are effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. The adoption of this new guidance has not had an impact on our financial position or results of operations.

Drilling Contracts

Our drilling contracts generally provide for compensation on either a daywork, turnkey or footage basis. Contract terms generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used, and the anticipated duration of the work to be performed. Generally, our contracts provide for the drilling of a single well and typically permit the client to terminate on short notice. During periods of high rig demand, or for our newly constructed rigs, we enter into longer-term drilling contracts. Currently, we have contracts with terms of six months to four years in duration. As of January 31, 2013, we have 43 drilling rigs operating under term contracts, as well as term contracts for another two new-build AC drilling rigs which we expect to begin working by the end of the first quarter of 2013. As of January 31, 2013, if not renewed at the end of their terms, the expiration of the 43 term contracts under which we are currently operating is as follows:



		Term Contract Expiration by Period
	Total Term Contracts	Within 6 Months	6 Months to 1 Year	1 Year to 18 Months	18 Months to 2 Years	2 to 4 Years
United States	37	23	6	2	1	5
Colombia	6	6	—	—	—	—
	43	29	6	2	1	5

Foreign Currencies

Our functional currency for our foreign subsidiary in Colombia is the U.S. dollar. Nonmonetary assets and liabilities are translated at historical rates and monetary assets and liabilities are translated at exchange rates in effect at the end of the period. Income statement accounts are translated at average rates for the period. Gains and losses from remeasurement of foreign currency financial statements into U.S. dollars and from foreign currency transactions are included in other income or expense.

Revenue and Cost Recognition

Drilling Services—Our Drilling Services Segment earns revenues by drilling oil and gas wells for our clients under daywork, turnkey or footage contracts, which usually provide for the drilling of a single well. Drilling contracts for individual wells are usually completed in less than 60 days. We recognize revenues on daywork contracts for the days completed based on the dayrate each contract specifies. We recognize revenues from our turnkey and footage contracts on the percentage-of-completion method based on our estimate of the number of days to complete each contract.

Our management has determined that it is appropriate to use the percentage-of-completion method to recognize revenue on our turnkey and footage contracts. Although our turnkey and footage contracts do not have express terms that provide us with rights to receive payment for the work that we perform prior to drilling wells to the agreed-on depth, we use this method because, as provided in applicable accounting literature, we believe we achieve a continuous sale for our work-in-progress and believe, under applicable state law, we ultimately could recover the fair value of our work-in-progress even in the event we were unable to drill to the agreed-on depth in breach of the applicable contract. However, in the event we were unable to drill to the agreed-on depth in breach of the contract, ultimate recovery of that value would be subject to negotiations with the client and the possibility of litigation.

If a client defaults on its payment obligation to us under a turnkey or footage contract, we would need to rely on applicable law to enforce our lien rights, because our turnkey and footage contracts do not expressly grant to us a security interest in the work we have completed under the contract and we have no ownership rights in the work-in-progress or completed drilling work, except any rights arising under the applicable lien statute on foreclosure. If we were unable to drill to the agreed-on depth in breach of the contract, we also would need to rely on equitable remedies outside of the contract available in applicable courts to recover the fair value of our work-in-progress under a turnkey or footage contract.

The risks to us under a turnkey contract and, to a lesser extent, under footage contracts, are substantially greater than on a contract drilled on a daywork basis. Under a turnkey contract, we assume most of the risks associated with drilling operations that are generally assumed by the operator in a daywork contract, including the risks of blowout, loss of hole, stuck drill pipe, machinery breakdowns and abnormal drilling conditions, as well as risks associated with subcontractors’ services, supplies, cost escalations and personnel operations.

We accrue estimated contract costs on turnkey and footage contracts for each day of work completed based on our estimate of the total costs to complete the contract divided by our estimate of the number of days to complete the contract. Contract costs include labor, materials, supplies, repairs and maintenance, operating overhead allocations and allocations of depreciation and amortization expense. In addition, the occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey and footage contracts could have a material adverse effect on our financial position and results of operations. Therefore, our actual results for a contract could differ significantly if our cost estimates for that contract are later revised from our original cost estimates for a contract in progress at the end of a reporting period which was not completed prior to the release of our financial statements.

With most drilling contracts, we receive payments contractually designated for the mobilization of rigs and other equipment. Payments received, and costs incurred for the mobilization services are deferred and recognized on a straight line basis over the related contract term. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. Reimbursements that we receive for out-of-pocket expenses are recorded as revenue and the out-of-pocket expenses for which they relate are recorded as operating costs.

The assets “prepaid expenses and other current assets” and “other long-term assets” include the current and long-term portions of deferred mobilization costs for certain drilling contracts. The liabilities “deferred revenues” and “other long-term liabilities” include the current and long-term portions of deferred mobilization revenues for certain drilling contracts and amounts collected on contracts in excess of revenues recognized. As of December 31, 2012 we had $3.9 million and $5.2 million of current deferred mobilization revenues and costs, respectively, and $0.6 million and $0.9 million of long-term deferred mobilization revenues and costs, respectively. Our deferred mobilization costs and revenues primarily related to long-term contracts for our new-build drilling rigs and long-term contracts for drilling rigs which we moved between drilling divisions. Amortization of deferred mobilization revenues was $6.3 million, $5.1 million and $3.0 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Production Services—Our Production Services Segment earns revenues for well servicing, wireline services, coiled tubing services and fishing and rental services pursuant to master services agreements based on purchase orders, contracts or other arrangements with the client that include fixed or determinable prices. Production service revenue is recognized when the service has been rendered and collectability is reasonably assured.

Cash and Cash Equivalents

For purposes of the statements of cash flows, we consider all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. Cash equivalents consist of investments in corporate and government money market accounts. Cash equivalents at December 31, 2012 and 2011 were $3.1 million and $5.7 million, respectively.

Restricted Cash

As of December 31, 2012, we had restricted cash in the amount of $0.7 million held in an escrow account to be used for a future payment due March 2013 to a former shareholder of a previously acquired production services business. Restricted cash of $0.7 million is recorded in other current assets and the associated obligation of $0.7 million is recorded in accrued expenses.

Trade Accounts Receivable

We record trade accounts receivable at the amount we invoice our clients. These accounts do not bear interest. The allowance for doubtful accounts is our best estimate of the amount of probable credit losses in our accounts receivable as of the balance sheet date. We determine the allowance based on the credit worthiness of our clients and general economic conditions. Consequently, an adverse change in those factors could affect our estimate of our allowance for doubtful accounts.

We review our allowance for doubtful accounts on a monthly basis. Our typical drilling contract provides for payment of invoices in 30 days. We generally do not extend payment terms beyond 30 days and have not extended payment terms beyond 90 days for any of our contracts in the last three fiscal years. Our production services terms generally provide for payment of invoices in 30 days. Balances more than 90 days past due are reviewed individually for collectability. We charge off account balances against the allowance after we have exhausted all reasonable means of collection and determined that the potential for recovery is remote. We do not have any off-balance sheet credit exposure related to our clients.

The changes in our allowance for doubtful accounts consist of the following (amounts in thousands):



	Year ended December 31,
	2012			2011			2010
Balance at beginning of year	$	994		$	712		$	286
Increase in allowance charged to expense	76			787			521
Accounts charged against the allowance, net of recoveries	(26		)	(505		)	(95		)
Balance at end of year	$	1,044		$	994		$	712

Unbilled Accounts Receivable

The asset “unbilled receivables” represents revenues we have recognized in excess of amounts billed on drilling contracts and production services completed but not yet invoiced. We typically invoice our clients at 15-day intervals during the performance of daywork drilling contracts and upon completion of the daywork contract. Turnkey and footage drilling contracts are invoiced upon completion of the contract.

Our unbilled receivables totaled $35.1 million at December 31, 2012, of which $0.6 million related to turnkey drilling contract revenues, $31.8 million represented revenue recognized but not yet billed on daywork drilling contracts in progress at December 31, 2012 and $2.7 million related to unbilled receivables for our Production Services Segment.

Inventories

Inventories primarily consist of drilling rig replacement parts and supplies held for use by our Drilling Services Segment’s operations in Colombia and supplies held for use by our Production Services Segment’s operations. Inventories are valued at the lower of cost (first in, first out or actual) or market value.

Prepaid Expenses and Other Current Assets

Prepaid expenses and other current assets include items such as insurance, rent deposits and fees. We routinely expense these items in the normal course of business over the periods these expenses benefit. Prepaid expenses and other current assets also include the short-term portion of deferred mobilization costs for certain drilling contracts that are recognized on a straight-line basis over the contract term.

Investments

At December 31, 2010, we held $15.9 million (par value) of auction rate preferred securities (“ARPSs”), which were variable-rate preferred securities with a long-term maturity that were classified as held for sale. On January 19, 2011, we entered into an agreement with a financial institution to sell the ARPSs for $12.6 million, which represented 79% of the par value, plus accrued interest. The $3.3 million difference between the ARPSs’ par value of $15.9 million and the sales price of $12.6 million represented an other-than-temporary impairment of the ARPSs investment which was reflected as an impairment of investments in our consolidated statement of operations for the year ended December 31, 2010.

Under the ARPSs sales agreement, we retained the unilateral right for a period ending January 7, 2013 to: (a) repurchase all the ARPSs that were sold at the $12.6 million price at which they were initially sold to the financial institution; and (b) if not repurchased, receive additional proceeds from the financial institution upon redemption of the ARPSs by the original issuer of these securities (collectively, the “ARPSs Call Option”). Upon origination, the fair value of the ARPSs Call Option was estimated to be $0.6 million and was recognized as other income in our consolidated statement of operations for 2011. The ARPSs Call Option was subsequently carried at fair value on our consolidated balance sheets with changes in fair value recognized as "other income (loss)" in our consolidated statement of operations.

On October 1, 2012, we received proceeds of $0.6 million from the redemption of certain ARPSs by the original issuer of the securities, which we recognized as other income in our consolidated statement of operations.

The ARPSs Call Option had a fair value of zero as of December 31, 2012 and expired on January 7, 2013.

Property and Equipment

Property and equipment are carried at cost less accumulated depreciation. Depreciation is provided for our assets over the estimated useful lives of the assets using the straight-line method. We record the same depreciation expense whether a rig is idle or working. We charge our expenses for maintenance and repairs to operating costs. We charge our expenses for renewals and betterments to the appropriate property and equipment accounts.

As of December 31, 2012, the estimated useful lives and costs of our asset classes are as follows:



	Lives	Cost
		(amounts in thousands)
Drilling rigs and equipment	3 - 25	$	1,229,574
Well servicing rigs and equipment	3 - 20	197,130
Wireline units and equipment	2 - 10	124,471
Coiled tubing units and equipment	2 - 7	46,333
Fishing and rental tools and equipment	5 - 10	16,104
Vehicles	3 - 10	59,100
Office equipment	3 - 5	7,676
Buildings and improvements	3 - 40	15,705
Land	—	2,424
		$	1,698,517

We recorded gains on disposition of our property and equipment of $1.2 million, losses of $0.2 million and gains of $1.6 million, for the years ended December 31, 2012, 2011 and 2010, respectively, in our drilling services costs and expenses.

As of December 31, 2012 and 2011, we had incurred $134.9 million and $141.5 million, respectively, in construction costs for ongoing projects, primarily for our new-build drilling rigs and additions to our production services fleets. During the years ended December 31, 2012, 2011 and 2010, we capitalized $10.2 million, $2.3 million and $0.5 million, respectively, of interest costs incurred during the construction periods of new-build drilling rigs and other drilling equipment.

We evaluate for potential impairment of long-lived tangible and intangible assets subject to amortization when indicators of impairment are present. Circumstances that could indicate a potential impairment include significant adverse changes in industry trends, economic climate, legal factors, and an adverse action or assessment by a regulator. More specifically, significant adverse changes in industry trends include significant declines in revenue rates, utilization rates, oil and natural gas market prices and industry rig counts for drilling rigs and well servicing rigs. In performing an impairment evaluation, we estimate the future undiscounted net cash flows from the use and eventual disposition of long-lived tangible and intangible assets grouped at the lowest level that cash flows can be identified. For our Production Services Segment, we perform an impairment evaluation and estimate future undiscounted cash flows for the individual reporting units (well servicing, wireline, coiled tubing and fishing and rental services). For our Drilling Services Segment, we perform an impairment evaluation and estimate future undiscounted cash flows for individual drilling rig assets. If the sum of the estimated future undiscounted net cash flows is less than the carrying amount of the asset group, then we would determine the fair value of the asset group. The amount of an impairment charge would be measured as the difference between the carrying amount and the fair value of these assets. The assumptions used in the impairment evaluation for long-lived assets are inherently uncertain and require management judgment.

In March 2012, we decided to retire two mechanical drilling rigs, with most of their components to be used for spare equipment, and recognized an associated impairment charge of $0.6 million. Also during 2012, we decided to dispose of two older wireline units and certain wireline equipment resulting in an impairment charge of approximately $0.5 million.

In September 2011, we evaluated the drilling rigs in our fleet that had remained idle and decided to place six mechanical drilling rigs as held for sale and to retire another drilling rig from our fleet, with most of its components to be used as spare equipment. Sales of all six mechanical drilling rigs were completed by mid November 2011 and we recognized an impairment charge of $0.5 million in September 2011 in association with our decision to dispose of these seven drilling rigs.

Goodwill

Goodwill results from business acquisitions and represents the excess of acquisition costs over the fair value of the net assets acquired. We perform a qualitative assessment of goodwill annually as of December 31 or more frequently if events or changes in circumstances indicate that the asset might be impaired. Circumstances that could indicate a potential impairment include a significant adverse change in the economic or business climate, a significant adverse change in legal factors, an adverse action or assessment by a regulator, unanticipated competition, loss of key personnel and the likelihood that a reporting unit or significant portion of a reporting unit will be sold or otherwise disposed of. These circumstances could lead to our net book value exceeding our market capitalization which is another indicator of a potential impairment of goodwill.

If our qualitative assessment of goodwill indicates a possible impairment, we test for goodwill impairment using a two-step process. First, the fair value of each reporting unit with goodwill is compared to its carrying value to determine whether an indication of impairment exists. Second, if impairment is indicated, then the fair value of the reporting unit's goodwill is determined by allocating the unit's fair value to its assets and liabilities (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination on the impairment test date. The amount of impairment for goodwill is measured as the excess of the carrying value of the reporting unit over its fair value. The assumptions used in estimating fair values of reporting units and performing the goodwill impairment test are inherently uncertain and require management judgment.

When estimating fair values of a reporting unit for our goodwill impairment test, we use an income approach which provides an estimated fair value based on the reporting unit’s anticipated cash flows that are discounted using a weighted average cost of capital rate. The primary assumptions used in the income approach are estimated cash flows and weighted average cost of capital. Estimated cash flows are primarily based on projected revenues, operating costs and capital expenditures and are discounted at a rate that is based on our weighted average cost of capital and estimated industry average rates for cost of capital. To ensure the reasonableness of the estimated fair value of our reporting units, we consider current industry market multiples and we perform a reconciliation of our total market capitalization to the total estimated fair value of all our reporting units. The assumptions used in estimating fair values of reporting units and performing the goodwill impairment test are inherently uncertain and require management judgment.

We have goodwill of $41.7 million as of December 31, 2012. All of this goodwill was recorded in connection with the acquisition of the production services business from Go-Coil on December 31, 2011, as described in Note 2, Acquisitions. As a result, the goodwill has been allocated to the coiled tubing services reporting unit within our Production Services Segment. As of December 31, 2012, we performed the first step of the two-step process to evaluate our goodwill for potential impairment. As a result of this test, we have concluded that the fair value of our coiled tubing services reporting unit is substantially in excess of its carrying value, including goodwill, and therefore no impairment loss on goodwill exists as of December 31, 2012.

Intangible Assets

Substantially all of our intangible assets were recorded in connection with the acquisitions of the production services businesses and are subject to amortization. Intangible assets consist of the following components (amounts in thousands):



	December 31, 2012			December 31, 2011
Cost:
Client relationships	$	66,273		$	66,273
Non-compete agreements	1,355			3,133
Trademarks / trade names	568			671
Accumulated amortization:
Client relationships	(23,667		)	(15,512		)
Non-compete agreements	(436		)	(1,885		)
Trademarks / trade names	(250		)	—
	$	43,843		$	52,680

The cost of our client relationships, trademarks and trade names are amortized using the straight-line method over their respective estimated economic useful lives which range from two to nine years. Amortization expense for our non-compete agreements is calculated using the straight-line method over the period of the agreements which range from two to seven years. Amortization expense was $8.7 million, $4.3 million and $4.6 million for the years ended December 31, 2012, 2011 and 2010, respectively. Amortization expense is estimated to be approximately $8.7 million, $8.4 million, $8.4 million, $5.6 million and $4.2 million for the years ending December 31, 2013, 2014, 2015, 2016 and 2017, respectively. Actual amortization amounts may be different due to future acquisitions, impairments, changes in amortization periods, or other factors.

Other Long-Term Assets

Other long-term assets consist of cash deposits related to the deductibles on our workers’ compensation insurance policies, the long-term portion of deferred mobilization costs, debt issuance costs, net of amortization, and noncurrent prepaid taxes in Colombia which are creditable against future income taxes. Debt issuance costs are described in more detail in Note 3, Long-term Debt.

Other Long-Term Liabilities

Our other long-term liabilities consist of the noncurrent portion of deferred mobilization revenues, liabilities associated with our long-term compensation plans, the noncurrent portion of the Colombia net equity tax and other deferred liabilities. In previous years, our other long-term liabilities also included the noncurrent portion of our obligation to a former shareholder of a previously acquired production services business, for which the cash is held in escrow.

Treasury Stock

Treasury stock purchases are accounted for under the cost method whereby the cost of the acquired common stock is recorded as treasury stock. Gains and losses on the subsequent reissuance of treasury stock shares are credited or charged to additional paid in capital using the average cost method.

Stock-based Compensation

We recognize compensation cost for stock option, restricted stock and restricted stock unit awards based on the fair value of the awards. For our awards with graded vesting, we recognize compensation expense on a straight-line basis over the service period for each separately vesting portion of the award as if the award was, in substance, multiple awards.

We receive a tax deduction for certain stock option exercises during the period the options are exercised, generally for the excess of the market price of our common stock on the exercise date over the exercise price of the stock options. We report all excess tax benefits resulting from the exercise of stock options as financing cash flows in our consolidated statement of cash flows.

Income Taxes

We follow the asset and liability method of accounting for income taxes, under which we recognize deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. We measure our deferred tax assets and liabilities by using the enacted tax rates we expect to apply to taxable income in the years in which we expect to recover or settle those temporary differences. The effect of a change in tax rates on deferred tax assets and liabilities is reflected in income in the period during which the change occurs. A recent change in Colombia tax rates is described in more detail in Note 5, Income Taxes.

Other Comprehensive Income (Loss)

During the year ended December 31, 2010, we recognized a $3.3 million other-than-temporary impairment of the ARPSs in earnings, and therefore reclassified to net loss $2.7 million of previously unrealized losses on ARPSs which had been recorded in other comprehensive income.