Organization and Summary of Significant Accounting Policies

Business

Pioneer Energy Services Corp. 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 to a diverse group of oil and gas exploration and production companies through our six drilling divisions in the US and internationally in Colombia. 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 or turnkey 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.

Since October 2014, domestic and international oil prices have declined significantly to historically low price levels resulting in a downturn in our industry. As a result, we performed an impairment evaluation of all our long-lived assets, in accordance with ASC Topic 360, Property, Plant and Equipment, which resulted in $71.0 million of impairment charges to reduce the carrying value of our 31 mechanical and lower horsepower electric drilling rigs to their estimated fair value.

Mechanical and lower horsepower drilling rigs are the most impacted by the industry downturn and are typically the first rigs to become idle. As of December 31, 2014, we owned a total of 31 mechanical and lower horsepower electric drilling rigs, which includes the nine rigs that were idle and classified as held for sale as of year-end and 15 rigs that we expect to place as held for sale during the first quarter of 2015, after their current contracts are completed. In January and February 2015, we sold six of these drilling rigs. (See Note 14, Subsequent Events.)

The following is a summary of our drilling rig counts as of December 31, 2014 and February 1, 2015.



	Drilling Rigs Owned	Drilling Rigs Held for Sale		Drilling Rig Fleet Count
As of December 31, 2014	62	(9	)	53
As of February 1, 2015	59	(12	)	47

As of February 1, 2015, the drilling rigs in our fleet are assigned to the following divisions:



Drilling Division	Rig Count
South Texas	13
West Texas	10
North Dakota	9
Utah	4
Appalachia	3
Colombia	8
	47

We are currently constructing five new-build 1,500 horsepower AC drilling rigs which we expect to deliver and begin operating under long-term drilling contracts in 2015, with the first two rigs to be deployed during the second quarter, two rigs in the third quarter, and the final rig by the end of the year. Excluding the rigs which we expect to sell in the near-term and considering the five new-build drilling rigs under construction, we expect to end 2015 with a drilling fleet of 43 rigs.

As of February 1, 2015, 40 of our 47 drilling rigs are earning revenues under drilling contracts, 29 of which are earning under term contracts. Four of our drilling rigs in Colombia are currently working under term contracts that extend through mid-2015 and we are actively marketing our other four rigs to multiple clients to diversify our client base in Colombia.

In response to the dramatic decline in oil prices during recent months, we have received early termination notices for 12 of our 29 drilling rigs that are earning revenues under term contracts. These 12 drilling rigs will be released upon completion of their current wells, all of which are expected to be completed by the end of the first quarter 2015, resulting in approximately $43.5 million of early termination payments which will be recognized as revenue over the remaining term of the contracts, $0.3 million of which was recognized in 2014.

Our Production Services Segment provides a range of services to exploration and production companies, including well servicing, wireline services and coiled tubing 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 February 1, 2015, we have a fleet of 117 well servicing rigs consisting of 107 rigs with 550 horsepower and 10 rigs with 600 horsepower, all of which are currently operating or are being actively marketed. We currently provide wireline services and coiled tubing services with a fleet of 128 wireline units and 17 coiled tubing units. On September 17, 2014, we completed the disposition of our fishing and rental services operations.

Basis of Presentation

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 expenses, 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, 2014, through the filing of this Form 10-K, for inclusion as necessary.

Drilling Contracts

Our drilling contracts generally provide for compensation on either a daywork or turnkey 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. Spot market contracts generally provide for the drilling of a single well and typically permit the client to terminate on short notice. We enter into longer-term drilling contracts for our newly constructed rigs and/or during periods of high rig demand. Currently, we have contracts with original terms of six months to four years in duration.

As of February 1, 2015, we have 29 drilling rigs earning under term contracts, which if not renewed prior to the end of their terms, will expire 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
United States	25	13	6	4	2
Colombia	4	4	—	—	—
	29	17	6	4	2

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 or turnkey 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 contracts on the percentage-of-completion method based on our estimate of the number of days to complete each contract. All of our revenues are recognized net of applicable sales taxes.

Our management has determined that it is appropriate to use the percentage-of-completion method to recognize revenue on our turnkey contracts. Although our turnkey 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 contract, we would need to rely on applicable law to enforce our lien rights, because our turnkey 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 contract.

The risks to us under a turnkey contract 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 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 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.

With most long-term drilling contracts, we are entitled to receive a full or reduced rate of revenue from our clients if they choose to place a rig on standby or to early terminate the contract before its original expiration term. Generally, these revenues are billed and collected over the remaining term of the contract, as the rig is placed on standby rather than fully released from the contract, and thus may go back to work at the client's decision any time before the end of the contract. Some of our drilling contracts contain "make-whole" provisions whereby if we are able to secure additional work for the rig with another client, then each party is entitled to a make-whole payment. If the dayrates under the new contract are less than the dayrates in the original contract, we would be entitled to a reduced revenue dayrate from the terminating client, and likewise, the terminating client may be entitled to a payment from us if the new contract dayrates exceed those of the original contract. A client may also choose to early terminate the contract and make an upfront early termination payment based on a per day rate for the remaining term of the contract. Revenues derived from rigs placed on standby or from the early termination of long-term drilling contracts are deferred and recognized as the amounts become fixed or determinable, over the remainder of the original term or when the rig is sold.

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, including amounts collected for early terminations of long-term drilling contracts. As of December 31, 2014 we had $3.3 million and $1.2 million of current deferred revenues and costs, respectively. Our deferred mobilization costs and revenues primarily relate to prepayments of long-term drilling contracts in the US. Amortization of deferred mobilization revenues was $4.6 million, $5.3 million and $6.3 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Production Services—Our Production Services Segment earns revenues for well servicing, wireline services and coiled tubing services pursuant to master services agreements based on purchase orders, contracts or other arrangements with the client that include fixed or determinable prices. Production services jobs are generally short-term and are charged at current market rates. Production service revenue is recognized when the service has been rendered and collectability is reasonably assured.

Concentration of Clients—We derive a significant portion of our revenue from a limited number of major clients. For the years ended December 31, 2014, 2013 and 2012, our drilling and production services to our top three clients accounted for approximately 28%, 29%, and 25%, respectively, of our revenue, and in 2014, 2013 and 2012, one client, Whiting Petroleum Company, accounted for 12%, 13% and 10%, respectively, of our revenue.

Cash and Cash Equivalents

For purposes of the consolidated statements of cash flows, we consider all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. We had cash equivalents of $2.6 million and $0.7 million at December 31, 2014 and 2013, respectively, which consisted of investments in corporate and government money market accounts.

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,
	2014			2013			2012
Balance at beginning of year	$	1,356		$	1,044		$	994
Increase in allowance charged to expense	1,445			801			76
Accounts charged against the allowance	(254		)	(489		)	(26		)
Balance at end of year	$	2,547		$	1,356		$	1,044

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 drilling contracts are invoiced upon completion of the contract.

Our unbilled receivables totaled $38.0 million at December 31, 2014, of which $0.8 million related to turnkey drilling contract revenues, $32.8 million represented revenue recognized but not yet billed on daywork drilling contracts in progress at December 31, 2014 and $4.4 million related to unbilled receivables for our Production Services Segment. At December 31, 2013, our unbilled receivables totaled $49.5 million, of which $45.4 million represented revenue recognized but not yet billed on daywork drilling contracts in progress at December 31, 2013 and $4.1 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 current portion of prepaid taxes in Colombia which are creditable against future income taxes and the current portion of deferred mobilization costs for certain drilling contracts that are recognized on a straight-line basis over the contract term.

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 capitalize expenditures for renewals and betterments to the appropriate property and equipment accounts.

Intangible Assets

Our intangible assets consist of the following components as of December 31, 2014 and 2013 (amounts in thousands):



	December 31,
	2014			2013
Cost:
Client relationships	$	63,168		$	63,168
Non-compete agreements	1,355			1,355
Accumulated amortization:
Client relationships	(39,256		)	(31,584		)
Non-compete agreements	(1,044		)	(745		)
	$	24,223		$	32,194

Substantially all of our intangible assets were recorded in connection with the acquisitions of production services businesses and are subject to amortization. The cost of our client relationships are amortized using the straight-line method over their respective estimated economic useful lives which range from three 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 three to seven years. Amortization expense was $8.0 million, $8.5 million and $8.7 million for the years ended December 31, 2014, 2013 and 2012, respectively. Amortization expense is estimated to be approximately $7.9 million, $5.1 million, $3.8 million, $3.8 million and $3.6 million for the years ending December 31, 2015, 2016, 2017, 2018 and 2019, respectively. Actual amortization amounts may be different due to future acquisitions, impairments, changes in amortization periods, or other factors.

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. 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 and coiled tubing). 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.

Due to several significant adverse factors affecting our coiled tubing services reporting unit, including increased competition in certain coiled tubing markets, turnover of key personnel and lower than anticipated utilization, all of which contributed to a decline in our projected cash flows for the coiled tubing reporting unit, we performed an impairment analysis of our long-lived tangible and intangible assets as of June 30, 2013. Our analysis resulted in a non-cash impairment charge of $3.1 million which we recognized during 2013 to reduce our intangible asset carrying value of client relationships. This impairment charge did not have an impact on our liquidity or debt covenants; however, it was a reflection of the increased competition in certain coiled tubing markets where we operate and a decline in our projected cash flows for the coiled tubing reporting unit. Due to continued increases in competition in certain coiled tubing markets and lower than anticipated operating results, we performed another impairment analysis of our long-lived tangible and intangible assets as of December 31, 2013, at which time we determined that the sum of the estimated future undiscounted net cash flows for our coiled tubing services reporting unit was in excess of the carrying amount and concluded that no impairment existed.

The most significant inputs used in our impairment analyses include the projected utilization and pricing of our coiled tubing services, which are classified as Level 3 inputs as defined by ASC Topic 820, Fair Value Measurements and Disclosures. Although we believe the assumptions and estimates used in our analysis are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. If we fail to meet the projected increases in utilization and pricing for our coiled tubing services, or in the event of significant unfavorable changes in the forecasted cash flows or key assumptions used in our analysis, the most significant of these being the projected utilization and pricing of our coiled tubing services, then we may incur a future impairment. Our coiled tubing services' operating results for the year ended December 31, 2014 exceeded our projections.

Our impairment analyses did not result in any impairment charges to our coiled tubing tangible long-lived assets, substantially all of which relates to our coiled tubing units and equipment. As discussed further below, we also recorded a non-cash impairment charge during 2013 to reduce the carrying value of goodwill to zero.

Goodwill

In connection with the acquisition of the production services business from Go-Coil, we recorded $41.7 million of goodwill at December 31, 2011. Due to several significant adverse factors affecting our coiled tubing services reporting unit, including increased competition in certain coiled tubing markets, turnover of key personnel and lower than anticipated utilization, all of which contributed to a decline in our projected cash flows for the coiled tubing reporting unit, we performed an impairment analysis of our goodwill as of June 30, 2013. We used an income approach to estimate the fair value of our coiled tubing services reporting unit and determined that there was no remaining implied fair value attributable to goodwill. Accordingly, we recorded a non-cash impairment charge of $41.7 million during 2013 to reduce the carrying value of our goodwill to zero. This impairment charge did not have an impact on our liquidity or debt covenants; however, it was a reflection of the increased competition in certain coiled tubing markets where we operate and a decline in our projected cash flows for the coiled tubing reporting unit.

The most significant inputs used in our impairment analysis included the projected utilization and pricing of our coiled tubing services and the weighted average cost of capital (discount rate) used in order to calculate the discounted cash flows for the reporting unit. These inputs are classified as Level 3 inputs as defined by ASC Topic 820, Fair Value Measurements and Disclosures. We assumed a 13% discount rate to estimate the fair value of the coiled tubing services reporting unit. A decrease in this assumption of 5% would have resulted in a decrease to our goodwill impairment charge of approximately $3.5 million. An increase of 1% in either the utilization or pricing assumptions would have resulted in a decrease to our goodwill impairment charge of approximately $2 million or $3 million, respectively. Although we believe the assumptions and estimates used in our analysis are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. The assumptions used in estimating fair values of reporting units and performing the goodwill impairment test are inherently uncertain and require management judgment.

Other Long-Term Assets

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

Other Current Liabilities

Our other accrued expenses include accruals for items such as property tax, sales tax, professional and other fees. We routinely expense these items in the normal course of business over the periods these expenses benefit.

Other Long-Term Liabilities

Our other long-term liabilities consist of the noncurrent portion of liabilities associated with our long-term compensation plans, deferred mobilization revenues, and other deferred liabilities.

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 estimated in accordance with ASC Topic 718, Compensation—Stock Compensation. 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 fair market value of our stock on the date of exercise over the exercise price of the options. In accordance with ASC Topic 718, we reported 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 6, Income Taxes.

Recently Issued Accounting Standards

Discontinued Operations. In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-08, Discontinued Operations (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. This update, among other things, raises the threshold for a disposal to qualify for discontinued operations accounting and requires additional disclosures about disposals. We chose early adoption of this guidance beginning July 1, 2014.

Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, a comprehensive new revenue recognition standard that will supersede nearly all existing revenue recognition guidance. The standard outlines a single comprehensive model for revenue recognition based on the core principle that a company will recognize revenue when promised goods or services are transferred to clients, in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. We are required to apply this new standard beginning with our first quarterly filing in 2017. We are currently evaluating the potential impact of this guidance, but at this time, do not expect that the adoption of this new standard will have a material effect on our financial position or results of operations.

Reclassifications

Certain amounts in the financial statements for the prior years have been reclassified to conform to the current year’s presentation.