Business

Pioneer Energy Services Corp. provides land-based drilling services and production services to a diverse group of independent and large oil and gas exploration and production companies in the United States and internationally in Colombia. We also provide two of our services (coiled tubing and wireline services) offshore in the Gulf of Mexico.

We have a current fleet of 31 drilling rigs, 94% of which are pad-capable, and 15 of which are AC walking rigs built within the last five years and engineered to optimize pad drilling. In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. The drilling rigs in our fleet are currently assigned to the following divisions:



Drilling Division	Rig Count
South Texas	7
West Texas	6
North Dakota	6
Appalachia	4
Colombia	8
	31

Since late 2014, oil prices have declined significantly resulting in a downturn in our industry, affecting both drilling and production services. In drilling, all rig classes have been severely impacted by the industry downturn. However, AC drilling rigs equipped with either a walking or skidding system are the best suited for horizontal pad drilling. We completed construction of five new-build 1,500 horsepower AC drilling rigs during 2015. We sold 32 of our mechanical and lower horsepower electric drilling rigs during 2015, which were the most negatively impacted by the industry downturn, and placed an additional four rigs as held for sale as of year-end.

Our Production Services Segment provides a range of services to a diverse group of exploration and production companies, with our operations 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 December 31, 2015, our production services fleets are as follows:



Production Services Fleets
	550 HP	600 HP	Total
Well servicing rigs, by horsepower (HP) rating	114	11	125

	Offshore	Onshore	Total
Wireline units	6	119	125
Coiled tubing units	5	12	17

Drilling Contracts

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. 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.

With most 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 often 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 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.

In response to the significant decline in oil prices over the last year, term contracts for 19 of our drilling rigs have been terminated early, including three which were terminated in early 2016, resulting in a total of $62.8 million of early termination payments. We recognized $49.2 million and $0.3 million of revenue for early termination payments during the years ended December 31, 2015 and 2014, respectively, and we will recognize the remaining $13.3 million in 2016.

Currently, 14 of our 23 domestic drilling rigs are earning revenues, 12 of which are under term contracts. Of the eight rigs in Colombia, three are under term contracts, but have been put on standby by our client and are not earning revenue. The term contracts in Colombia are cancelable without penalty, by our client if 30 days' notice is provided, and by us if rig operations are suspended without an associated dayrate. We are actively marketing our idle drilling rigs in Colombia to various operators to diversify our client base, and evaluating other options, including the possibility of the sale of some or all of our assets in Colombia.

Including these three contracts in Colombia, 17 of our drilling rigs are currently under contract, which if not canceled or renewed prior to the end of their terms, will expire as follows:



	Spot Market Contracts	Term Contracts and Term Contract Expiration by Period
	Spot Market Contracts	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
Domestic Rigs:
Earning under contract	2	8	1	2	—	1	4
Earning but not working	—	4	3	1	—	—	—

Colombia Rigs (on standby)	—	3	—	1	—	—	2
	2	15	4	4	—	1	6

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 projected cash flows and fair values for impairment evaluations, our estimate of the valuation allowance for deferred tax assets, 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, 2015, through the filing of this Form 10-K, for inclusion as necessary.

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.

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, including amounts collected for early terminations of long-term drilling contracts. As of December 31, 2015, we had $6.2 million and $1.5 million of current deferred revenues and costs, respectively. Our deferred costs and revenues primarily relate to prepayments of long-term contracts for our domestic drilling rigs. Amortization of deferred mobilization revenues was $1.1 million, $4.6 million and $5.3 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Turnkey Drilling Contracts—Our management has determined that it is appropriate to use the proportional performance basis 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 operations personnel.

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.

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, 2015, 2014 and 2013, our drilling and production services to our top three clients accounted for approximately 29%, 28%, and 29%, respectively, of our revenue, and in 2015, 2014 and 2013, our largest client, Whiting Petroleum Corporation, accounted for 18%, 12% and 13%, respectively, of our revenue.

Cash and Cash Equivalents

For purposes of the statements of cash flows, we consider all highly liquid instruments purchased with a maturity of three months or less to be cash equivalents. Cash equivalents consist of investments in money market accounts. Cash equivalents at December 31, 2015 and 2014 were $1.3 million and $2.6 million, respectively.

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,
	2015			2014			2013
Balance at beginning of year	$	2,547		$	1,356		$	1,044
Increase in allowance charged to expense	472			1,445			801
Accounts charged against the allowance	(765		)	(254		)	(489		)
Balance at end of year	$	2,254		$	2,547		$	1,356

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 $13.6 million at December 31, 2015, of which $11.9 million represented revenue recognized but not yet billed on daywork drilling contracts in progress, $1.1 million related to unbilled receivables for our Production Services Segment and $0.6 million related to one turnkey contract in progress, which was completed prior to the issuance of these consolidated financial statements. At December 31, 2014, our unbilled receivables totaled $38.0 million, of which $32.8 million represented revenue recognized but not yet billed on daywork drilling contracts in progress, $4.4 million related to unbilled receivables for our Production Services Segment, and $0.8 million related to turnkey drilling contract revenues.

Inventories

Inventories primarily consist of drilling rig replacement parts, 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 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 were recorded in connection with the acquisitions of production services businesses and are subject to amortization. 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).

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, and a non-cash impairment charge of $41.7 million to reduce the carrying value of goodwill to zero.

As a result of the downturn which began in late 2014 and worsened through the first half of 2015, we performed impairment testing on our coiled tubing operations as of June 30, 2015 which indicated that the carrying value of our coiled tubing reporting unit was recoverable and thus there was no impairment present at June 30, 2015. However, as the downturn persisted through 2015, our projected cash flows declined further as compared to our projections made earlier in the year and we performed another impairment analysis of our long-lived tangible and intangible assets as of December 31, 2015, which resulted in an impairment charge of $14.3 million which we recognized during the fourth quarter of 2015. As a result of this impairment, the carrying value of our coiled tubing intangible assets was reduced to zero. This impairment charge did not have an impact on our liquidity or debt covenants; however, it was a reflection of the overall downturn in our industry and a decline in our projected cash flows for the coiled tubing reporting unit. Our impairment analysis performed in the fourth quarter of 2015 also resulted in an impairment to our coiled tubing tangible long-lived assets, which is discussed in more detail in Note 3, Property and Equipment.

We used an income approach to estimate the fair value of our coiled tubing services reporting unit. The most significant inputs used in our impairment analysis of our coiled tubing operations 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. 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 impairment charge of approximately $2 million. An increase of 1% in either the utilization or pricing assumptions would have resulted in a decrease to our impairment charge of approximately $1 million or $2 million, respectively.

As of December 31, 2015 and 2014, the estimated useful lives and components of our intangible asset classes are as follows:



		December 31,
		2015			2014
	Lives	(amounts in thousands)
Client relationships:	5 - 9
Cost		$	13,592		$	55,282
Accumulated amortization		(11,682		)	(31,370		)
Non-compete agreements:	4 - 7
Cost		675			1,355
Accumulated amortization		(641		)	(1,044		)
		$	1,944		$	24,223

The cost of our client relationships are amortized using the straight-line method over their respective estimated economic useful lives and amortization expense for our non-compete agreements is calculated using the straight-line method over the period of the agreements. Amortization expense was $7.9 million, $8.0 million and $8.5 million for the years ended December 31, 2015, 2014 and 2013, respectively. Amortization expense is estimated to be approximately $1.5 million, $0.2 million, and $0.2 million for the years ending December 31, 2016, 2017, and 2018, 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 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, Colombian net wealth tax, and 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, the long-term portion of deferred 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, when we have excess tax benefits resulting from the exercise of stock options, we report them as financing cash flows in our consolidated statement of cash flows, unless otherwise disallowed under ASC Topic 740, Income Taxes.

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.

Related-Party Transactions

During the years ended December 31, 2015 and 2014, the Company paid approximately $0.2 million and $0.4 million, respectively, for trucking and equipment rental services, which represented arms-length transactions, to Gulf Coast Lease Service. Joe Freeman, our Senior Vice President of Well Servicing, serves as the President of Gulf Coast Lease Service, which is owned and operated by Mr. Freeman's two sons. Mr. Freeman does not receive compensation from Gulf Coast Lease Service, and he serves primarily in an advisory role to his sons.

Comprehensive Income

We have not reported comprehensive income due to the absence of items of other comprehensive income in the years presented.

Recently Issued Accounting Standards

Revenue Recognition. In May 2014, the FASB issued Accounting Standards Update (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 2018. 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.

Debt Issuance Costs. On April 7, 2015, the FASB issued ASU No. 2015-03, Simplifying the Presentation of Debt Issuance Costs, which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts, and that amortization of debt issuance costs be reported as interest expense. In August 2015, these provisions were further amended with guidance from the Securities and Exchange Commission Staff that they would not object to an entity deferring and presenting debt issuance costs related to line-of-credit arrangements as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this ASU. This ASU requires retrospective adoption and will be effective for us beginning with our first quarterly filing in 2016. Early adoption is permitted. We do not expect the adoption of this new standard to have a material impact on our financial position or results of operations.

Deferred Income Tax Classification. In November 2015, the FASB issued ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes, which requires that the net of deferred tax assets and liabilities be classified as noncurrent on the balance sheet by jurisdiction rather than being separately presented as current and noncurrent portions. We are required to adopt the new standard beginning with our first quarterly filing in 2017; however, early adoption is permitted and the standard may be applied either retrospectively or on a prospective basis to all deferred tax assets and liabilities. On December 31, 2015, we elected to early adopt ASU No. 2015-17 prospectively, thus reclassifying $6.8 million of current deferred tax assets to noncurrent on the accompanying consolidated balance sheet. The prior reporting period was not retrospectively adjusted.

Reclassifications

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