10-K 1 d282774d10k.htm FORM 10-K FORM 10-K
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

 

 

FORM 10-K

 

 

(Mark one)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2011

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 000-51630

 

 

UNION DRILLING, INC.

(Exact name of registrant as specified in its charter)

 

 

 

DELAWARE   16-1537048
(State or other jurisdiction of
incorporation or organization)
  (I.R.S. Employer
Identification Number)

4055 International Plaza

Suite 610

Fort Worth, Texas

  76109
(Address of principal executive offices)   (Zip Code)

Registrant’s telephone number, including area code: 817-735-8793

Registrant’s website: www.uniondrilling.com

 

 

Securities registered pursuant to Section 12(b) of the Act:

 

Common Stock, $0.01 Par Value   NASDAQ Global Select Market
(Title of each class)   (Name of each exchange on which registered)

Securities registered pursuant to Section 12(g) of the Act: None

 

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.    Yes  ¨    No  x

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).    Yes  ¨    No  x

The aggregate market value of the registrant’s voting and nonvoting common equity held by non-affiliates of the registrant as of June 30, 2011, the last business day of the registrant’s most recently completed second fiscal quarter, was $155,685,858 based on the last sales price of the registrant’s common stock on June 30, 2011 as reported on the NASDAQ Global Select Market. The determination of affiliate status for the purposes of this calculation is not necessarily a conclusive determination for other purposes. The calculation excludes shares held by directors and officers and by each stockholder whose ownership exceeded 10% of the Registrant’s outstanding Common Stock. Exclusion of these shares should not be construed to indicate that any such person controls, is controlled by or is under common control with the Registrant.

As of March 8, 2012, there were 25,228,816 shares of common stock, par value $0.01 per share, of the registrant issued and 23,148,116 shares outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement related to the registrant’s 2012 Annual Meeting of Stockholders to be held on June 7, 2012, to be filed subsequently with the Securities and Exchange Commission, are incorporated by reference into Part III of this Annual Report on Form 10-K.

 

 

 


Table of Contents

TABLE OF CONTENTS

 

PART I      1   

Item 1.

  Business      1   

Item 1A.

  Risk Factors      4   

Item 1B.

  Unresolved Staff Comments      10   

Item 2.

  Properties      10   

Item 3.

  Legal Proceedings      10   

Item 4.

  Mine Safety Disclosures      10   
PART II      10   

Item 5.

  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities      10   

Item 6.

  Selected Financial Data      14   

Item 7.

  Management’s Discussion and Analysis of Financial Condition and Results of Operations      15   

Item 7A.

  Quantitative and Qualitative Disclosures About Market Risk      24   

Item 8.

  Financial Statements and Supplementary Data      25   

Item 9.

  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure      48   

Item 9A.

  Controls and Procedures      48   

Item 9B.

  Other Information      48   
PART III      48   

Item 10.

  Directors, Executive Officers and Corporate Governance      49   

Item 11.

  Executive Compensation      49   

Item 12.

  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters      49   

Item 13.

  Certain Relationships and Related Transactions, and Director Independence      49   

Item 14.

  Principal Accountant Fees and Services      49   
PART IV      49   

Item 15.

  Exhibits and Financial Statement Schedules      49   

SIGNATURES

     50   

 

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PART I

 

Item 1. Business

We provide contract land drilling services and equipment to oil and natural gas producers in the United States, having commenced operations in 1997 with 12 drilling rigs and related equipment acquired from an entity providing contract drilling services under the name “Union Drilling.” Through a combination of acquisitions and new rig construction, we increased the size of our fleet to 71 marketed land drilling rigs. In 2011, in an effort to better align our rig fleet with the growing part of the market (deep horizontal shale drilling), we added three new large rigs, decommissioned two of our older, smaller rigs, sold a small, marketed rig in a private transaction and auctioned 31 of our older, smaller rigs that have had minimal utilization over the past several years. Of those 31 rigs, 20 were marketed rigs, while 11 had been previously decommissioned. Accordingly, our marketed rig fleet at December 31, 2011 contained 51 land drilling rigs. In January 2012, we sold another small rig in a private transaction.

We specialize in shallow to deep horizontal drilling in select oil and gas producing basins of the United States. The emergence of shale plays, the application of new technologies to traditional basins, and the influx of investments in plays in the United States from the major and large independent E&P companies have all resulted in more complex drilling and customers who demand superior safety and efficiency. We have met these demands through investments in equipment designed for horizontal drilling, as well as invested in our people and processes to improve drilling productivity and safety, and reduce total well costs for our customers.

Our strategy is to focus on areas that have high growth potential, adequate takeaway capacity and low finding and development costs in order to maximize utilization and return on capital throughout the commodity price cycle. Since the global economic crisis in 2008, oil prices have rebounded while natural gas has not. Due to the divergence of oil and natural gas prices, many of our customers have shifted their investments to oil and liquids-rich plays; accordingly, many of the rigs in our fleet have been repositioned and are now concentrated in those areas. Our principal operations are in the Appalachian Basin, extending from New York to Tennessee including the Marcellus, Huron, and Utica shales; the Arkoma Basin in eastern Oklahoma and Arkansas, including the Fayetteville, Caney, and Woodford shales; the Fort Worth Basin in North Texas, including the Barnett Shale and in West Texas extending to southeastern New Mexico, the Permian and Delaware Basins. We believe we are well positioned to expand into the Mississippian oil plays in central Oklahoma and southern Kansas.

We market our rigs to a number of customers, who are principally major or large independent E&P companies. Repeat business from customers accounts for a substantial portion of our business. We do not invest in oil or natural gas properties and therefore, do not drill for our own account. In 2011, 2010 and 2009, we performed services for 90, 78, and 64 customers, respectively. In 2011, 2010 and 2009, our top 20 customers provided 83%, 80% and 89%, respectively, of our total revenue. The following table shows our three largest customers as a percentage of our total contract drilling revenue for each of the last three years.

 

Year

  

Customer

   Total Contract Drilling
Revenue Percentage
 
2011    Exxon Mobil Corp (formerly XTO)      24.2
   Chief Oil & Gas LLC      13.0
   Apache Corp.      6.6
     

 

 

 
   Total      43.8
     

 

 

 
2010    Exxon Mobil Corp (formerly XTO)      26.9
   Chief Oil & Gas LLC      14.0
   Broad Oak Energy      5.6
     

 

 

 
   Total      46.5
     

 

 

 
2009    Exxon Mobil Corp (formerly XTO)      27.9
   Quicksilver Resources Inc.      15.9
   Chief Oil & Gas LLC      10.9
     

 

 

 
   Total      54.7
     

 

 

 

 

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Drilling contracts

We enter into written contracts with our customers for all rig deployments. The length of contracts has ranged from a one-well project to multi-year term for major exploration programs. Our contracts are obtained either through competitive bidding or through direct negotiations with customers. Our oil and natural gas drilling contracts provide for compensation on a daywork (fixed rate per day is charged) or footage (fixed rate per foot of hole drilled to a stated depth) basis. Contracts performed on a footage basis involve greater financial risk to us. In 2011 and 2010, approximately 98% and 96% of our revenues were derived from daywork contracts. The contract terms we offer generally depend on the location, depth and complexity of the well to be drilled; the on-site drilling conditions; the type of equipment used; the duration of the work to be performed; and the competitive forces of the market. In most instances, our contracts provide for additional payments related to rig mobilization and demobilization, as well as reimbursement of certain out-of-pocket costs.

As of December 31, 2011, we had 24 rigs under term contracts, which we define as a contract for drilling services with an original term in excess of six months. In some cases, a contract may be extended beyond the original term at prices mutually agreeable to us and the customer. Further, under term contracts, our customer may elect to terminate the contract, but generally, there are early termination payments if a contract is terminated prior to the expiration of the stated term. Under certain limited circumstances such as destruction of a drilling rig, bankruptcy, sustained unacceptable performance by us, or delivery of a rig beyond the stated delivery date, no early termination payment would be paid to us.

Our rig fleet

A land drilling rig consists of a derrick, a substructure, a hoisting system, a rotating system, pumps and holding tanks to circulate and clean drilling fluid, blowout preventers and other related equipment. Diesel engines are typically the main power sources for a drilling rig. The intended well depth and drill site conditions determine the size and type of rig most suitable for a particular drilling job, and we often customize and upgrade our rigs to meet customer specifications. Since 2006, we have placed 27 new rigs into service and have an additional four new rigs scheduled to be delivered and deployed in 2012. Moreover, to better focus on safety and operational efficiency, we have upgraded many of our rigs with automation and other modern features designed for horizontal drilling, including adding top drives, pad drilling and skidding systems, larger circulating systems and pipe handling systems.

We believe that our drilling rigs and other related equipment are in good operating condition as our employees perform continuous maintenance on our drilling rigs. We also utilize various oilfield service companies for major repair work and upgrades of our drilling equipment. We own a fleet of trucks that are used to move our rigs as well as bulldozers, forklifts, various vehicles and other equipment that is used to support the operation of our rigs.

The materials and supplies we use in our drilling operations include fuels, drill pipe and drill collars to operate drilling equipment, oil and lubricants to maintain equipment, paint and coating to protect equipment, as well as miscellaneous hardware, including hoses, belts, nuts and fasteners. We do not rely on a single source of supply for any of these items.

Including the four new-builds to be delivered in 2012, as well as several upgrades that are in progress, our rig fleet at February 29, 2012, is composed of 34 large rigs, 12 medium rigs, and 8 small rigs (we utilize drawworks horsepower to categorize our rigs into three sizes including large (>1,000 hp), medium (750-999 hp) and small (less than 750 hp). At December 31, 2011, all of our large rigs, 10 of our medium rigs, and 5 of our small rigs were under contract.

 

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The following table sets forth certain information regarding each of our marketed rigs as of February 29, 2012 (excluding the four new builds under construction):

 

        Rig #        

 

    Division    

 

      Drawworks      
(HP)

 

      Pumps
       (HP)

 

      Hook Load      
(LBS)

Rig 058

  Appalachia   1,600   1,600   750,000

Rig 054

  Appalachia   1,000   1,600   441,000

Rig 059

  Appalachia   1,000   1,600   400,000

Rig 060

  Appalachia   1,000   1,000   760,000

Rig 061

  Appalachia   1,000   1,600   600,000

Rig 062

  Appalachia   1,000   1,600   550,000

Rig 121

  Appalachia   1,000   1,600   500,000

Rig 207

  Appalachia   1,000   1,600   550,000

Rig 209

  Appalachia   1,000   1,600   550,000

Rig 021

  Appalachia   900   1,600   365,000

Rig 048

  Appalachia   900   1,000   410,000

Rig 052

  Appalachia   900   1,600   365,000

Rig 124

  Appalachia   900   1,300   400,000

Rig 053

  Appalachia   515   350   185,000

Rig 055

  Appalachia   515   n/a   185,000

Rig 044

  Appalachia   500   800   275,000

Rig 045

  Appalachia   500   n/a   300,000

Rig 046

  Appalachia   500   1,000   300,000

Rig 025

  Appalachia   450   600   300,000

Rig 219

  Arkoma   1,500   1,600   750,000

Rig 122

  Arkoma   1,200   1,600   500,000

Rig 110

  Arkoma   1,000   1,000   500,000

Rig 125

  Arkoma   1,000   1,600   500,000

Rig 126

  Arkoma   1,000   1,600   500,000

Rig 112

  Arkoma   800   800   375,000

Rig 114

  Arkoma   800   800   250,000

Rig 116

  Arkoma   800   800   250,000

Rig 123

  Arkoma   800   1,000   390,000

Rig 211

  Arkoma   800   1,000   390,000

Rig 032

  Arkoma   500   900   310,000

Rig 220

  Texas   1,500   1,600   750,000

Rig 221

  Texas   1,500   1,600   750,000

Rig 222

  Texas   1,500   1,600   750,000

Rig 223

  Texas   1,500   1,600   750,000

Rig 224

  Texas   1,500   1,600   750,000

Rig 212

  Texas   1,400   1,300   420,000

Rig 216

  Texas   1,200   1,300   520,000

Rig 214

  Texas   1,000   1000   390,000

Rig 217

  Texas   1,000   1,300   550,000

Rig 225

  Texas   1,000   1,300   550,000

Rig 227

  Texas   1,000   1,600   550,000

Rig 228

  Texas   1,000   1,300   550,000

Rig 229

  Texas   1,000   1,000   550,000

Rig 230

  Texas   1,000   800   650,000

Rig 215

  Texas   1,000   1,000   420,000

Rig 206

  Texas   900   900   350,000

Rig 226

  Texas   900   900   420,000

Rig 205

  Texas   750   800   350,000

Rig 210

  Texas   750   650   280,000

Rig 201

  Texas   650   500   300,000

 

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Employees

As of February 29, 2012, we had approximately 1,300 employees. The number of employees fluctuates depending on the number of drilling projects we are engaged in at any particular time. Our employees are not subject to collective bargaining arrangements.

Available Information

We were incorporated in the State of Delaware in 1997. Our principal executive offices are located at 4055 International Plaza, Suite 610, Fort Worth, Texas 76109. Our telephone number is 817-735-8793.

We file annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission, or SEC. You may read and copy our reports, proxy statements and other information at the SEC’s public reference room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549-0213. You can request copies of these documents at prescribed rates by writing to the SEC at Public Reference Section, SEC, 100 F Street, N.E., Washington, D.C. 20549-0213. Please call the SEC at 1 800-SEC-0330 for more information about the operation of the public reference room. Our SEC filings are also available at the SEC’s website at www.sec.gov. Because our common stock is listed on the NASDAQ Global Select Market, you may also inspect reports, proxy statements and other financial information about us at the offices of the NASDAQ Global Select Market, One Liberty Plaza, 165 Broadway, New York, New York 10006.

You may obtain a free copy of our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after such reports have been filed with or furnished to the SEC on our website at www.uniondrilling.com or by contacting our Investor Relations Department at 817-735-8793. In addition, our Code of Ethics is available on our website.

 

Item 1A. Risk Factors

Risks Relating to Our Business

We operate in a highly competitive industry which can adversely affect our results of operations.

The contract land drilling services industry in which we operate is very competitive. Further, drilling rigs are mobile and can be moved from one region to another in response to market conditions, which heightens the competition in the industry. Over the last few years, there has been a substantial increase in the supply of land drilling rigs, whether through new construction or refurbishment. We face competition from new entrants as well as significantly larger domestic and international drilling contractors, many with greater resources. Further, new technology may cause our drilling equipment to become less competitive. Although we take measures to ensure that we use advanced oil and natural gas drilling technology, changes in technology or improvements in competitors’ equipment could make our equipment, less competitive or require significant capital investments to keep our equipment competitive. As a result, additional competition in our markets, price competition and obsolete equipment can negatively impact our revenue rates, utilization and profitability, as well as the value of our rig equipment, which could result in write-downs of our asset carrying values.

Our business and operations are substantially dependent upon, and affected by, the level of U.S. land-based oil and natural gas exploration and development activity, which has experienced significant volatility. If the level of that activity is depressed, our business and results of operations could be adversely affected.

Our business and operations are substantially dependent upon, and affected by, the level of U.S. land-based oil and natural gas exploration and development activity. Exploration and development activity determines the demand for contract land drilling and related services. We have no control over the factors driving the level of U.S. oil and natural gas exploration and development activity. If the level of that activity is depressed, our business and results of operations could be adversely affected. Other factors include, among others, the following:

 

   

the market prices of oil and natural gas;

 

   

market expectations about future prices of oil and natural gas;

 

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the cost of producing and delivering oil and natural gas;

 

   

the capacity of the oil and natural gas pipeline network;

 

   

government regulations and trade restrictions;

 

   

the presence or absence of tax incentives;

 

   

national and international political and economic conditions;

 

   

levels of production by, and other activities of, the Organization of Petroleum Exporting Countries and other oil and natural gas producers;

 

   

the levels of imports of natural gas, whether by pipelines from Canada or Mexico or by tankers in the form of LNG; and

 

   

the development of alternate energy sources and the long-term effects of worldwide energy conservation measures.

We cannot accurately predict the future level of demand for, or pricing of oil and natural gas, for our contract drilling services or overall future conditions in the land-based contract drilling industry.

Our operations are subject to hazards inherent in the land drilling business beyond our control. If those risks are not adequately insured or indemnified against, our results of operations could be adversely affected.

Our operations are subject to many hazards inherent in the land drilling business, including, but not limited to:

 

   

blowouts;

 

   

craterings;

 

   

fires;

 

   

explosions;

 

   

equipment failures;

 

   

poisonous gas emissions;

 

   

loss of well control;

 

   

loss of hole;

 

   

damaged or lost equipment; and

 

   

damage or loss from inclement weather or natural disasters.

These hazards are to some extent beyond our control and could cause, among other things:

 

   

personal injury or death;

 

   

serious damage to or destruction of property and equipment;

 

   

suspension of drilling operations; and

 

   

damage to the environment, including damage to producing formations and surrounding areas.

Our insurance policies for public liability and property damage to others and injury or death to persons are in some cases subject to large deductibles and may not be sufficient to protect us against liability for all consequences of well disasters, personal injury, extensive fire damage or damage to the environment. We may not be able to maintain adequate insurance in the future at rates we consider reasonable, or particular types of coverage may not be available. The occurrence of events, including any of the above-mentioned risks and hazards, that are not fully insured against or the failure of a customer that has agreed to indemnify us against certain liabilities to meet its indemnification obligations could subject us to significant liability and could have a material adverse effect on our financial condition and results of operations.

A weak global economy may affect the Company’s business.

As a result of volatility in oil and natural gas prices and a continuing weak global economic environment, the Company is unable to accurately predict the extent to which its customers will spend on exploration and development drilling or whether customers and/or vendors and suppliers will be able to access financing necessary to sustain or increase their current level of operations, fulfill their commitments and/or fund future operations and obligations. Furthermore, the Company is unable to predict the extent its existing customers will have continuing

 

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viability and capability to pay amounts owed to the Company. The overall weak economic environment may impact industry fundamentals and result in reduced demand for drilling rigs. These conditions could have a material adverse effect on the Company’s business, including limiting the growth of our revenues and margins as well as the potential impairments of our rig fleet.

In the year ended December 31, 2011, we derived approximately 44% of our total revenues from our top three customers. The loss of any of our principal customers and the failure to remarket the rigs employed by those customers could have a material adverse effect on our financial condition and results of operations.

In the year ended December 31, 2011, our three largest customers accounted for approximately 24%, 13% and 7% of our total revenues. Our principal customers may not continue to employ our services and we may not be able to successfully remarket the rigs. The loss of any of our principal customers and the failure to remarket the rigs utilized by those customers could have a material adverse effect on our financial condition and results of operations.

If we cannot keep our rigs utilized at profitable rates, our operating results could be adversely affected.

Our business has high fixed costs, and if we cannot keep our rigs utilized at profitable rates, our operating results could be adversely affected.

Term contracts may in certain instances be terminated without an early termination payment.

Term drilling contracts customarily provide for termination at the election of the customer, with an “early termination payment” to be paid to the Company if a contract is terminated prior to the expiration of the term. However, under certain limited circumstances, such as destruction of a drilling rig, limited capital resources of the customer or bankruptcy of the customer, no early termination payment may be paid to the Company or, if paid, not paid in full or in a timely manner. Even if an early termination payment is owed to the Company, the customer may not have the ability to timely pay (or pay at all) the early termination payment.

Shortages of drilling equipment and supplies could adversely affect our operations.

The contract drilling business is highly cyclical. During periods of increased demand for contract drilling services, delays in delivery and shortages of equipment and supplies can occur. These risks are intensified during periods when the industry experiences significant new drilling rig construction or refurbishment. Any such delays or shortages could have a material adverse effect on our business, financial conditions and results of operations.

To the extent we acquire additional rigs in the future, we may experience difficulty integrating those acquisitions. Additionally, we may incur leverage to effect those acquisitions, which adds additional financial risk to our business. To the extent we incur additional leverage in financing acquisitions, it may adversely affect our financial position.

The process of integrating acquired rigs or newly constructed rigs may involve unforeseen difficulties and may require a disproportionate amount of management’s attention and other resources. We may not be able to successfully manage and integrate new rigs into our existing operations or successfully maintain the market share attributable to drilling rigs that we purchase. We also may encounter cost overruns related to newly constructed rigs or unexpected costs related to acquired rigs. To the extent we experience some or all of these difficulties with regard to our four new builds under construction at February 29, 2012, our financial condition could be adversely affected. Expanding our fleet by building new rigs or acquiring rigs from third parties may cause us to incur additional financial leverage, increasing our financial risk, and debt service requirements, which could adversely affect our operating results and financial position.

 

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We may decide to purchase or internally build additional drilling rigs and upgrade or refurbish some of our marketed drilling rigs. Any delay could result in a loss of revenue, and/or loss of a contract.

We may purchase or internally build additional drilling rigs and upgrade or refurbish some of our current drilling rigs. All of these projects are subject to risks of delay or cost overruns inherent in large construction projects. Among those risks are:

 

   

shortages of equipment, materials or skilled labor;

 

   

long lead times or delays in the delivery of ordered materials and equipment;

 

   

engineering problems;

 

   

work stoppages;

 

   

weather interference;

 

   

availability of specialized services; and

 

   

cost increases.

These factors may contribute to delays in the delivery, upgrade or completion of the refurbishment of the drilling rigs, which could result in a loss of revenue. Additionally, these factors may delay the delivery of a rig beyond the stated delivery date, which could cause a contract to be terminated, which could result in a loss of revenue. Finally, we may incur higher costs than expected, which would adversely affect the economics of the investment in such rigs.

We may not be able to raise additional funds through public or private financings or additional borrowings, which could have a material adverse effect on our financial condition.

The contract drilling industry is capital intensive. Our cash flow from operations and the continued availability of credit are subject to a number of variables, including general economic conditions, and more specifically, our rig utilization rates, operating margins and ability to control costs and obtain contracts in a competitive industry. Our cash flow from operations and present borrowing capacity may not be sufficient to fund our anticipated capital expenditures and working capital requirements. We may from time to time seek additional financing, either in the form of bank borrowings, sales of debt or equity securities or otherwise. To the extent our capital resources and cash flow from operations are at any time insufficient to fund our activities or repay our indebtedness as it becomes due, we will need to raise additional funds through public or private financings or additional borrowings. We may not be able to obtain any such capital resources in the amount or at the time when needed. If we are at any time not able to obtain the necessary capital resources, our financial condition and results of operations could be materially adversely affected.

We could be adversely affected if we lost the services of certain of our senior officers and key employees.

The success of our business is highly dependent upon the services, efforts and abilities of certain key employees, such as our regional managers and of Christopher D. Strong, our President and Chief Executive Officer, Tina L. Castillo, our Senior Vice President and Chief Financial Officer, and David S. Goldberg, our Senior Vice President and General Counsel. Our business could be materially and adversely affected by the loss of any of these individuals. We have limited employment agreements with some key employees. We do not maintain key man life insurance on the lives of any of our executive officers or regional managers.

Competition for experienced technical personnel may negatively impact our operations or financial results.

We utilize highly skilled personnel in operating and supporting our business. In times of high utilization, it can be difficult to retain, and in some cases, find qualified individuals. Although to date our operations have not been materially affected by competition for personnel, an inability to obtain or find a sufficient number of qualified personnel could materially impact our business, financial condition and results of operations.

 

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Our operations could be adversely affected by abnormally poor weather conditions.

Our operations are conducted in areas subject to poor weather conditions, and often in difficult terrain. Primarily in the winter and spring, our operations are often curtailed because of cold, snow or muddy conditions. Unusually severe weather conditions could further curtail our operations and could have a material adverse effect on our financial condition and results of operations.

We have limited control over the timing of payment of our deferred tax liabilities.

We currently have deferred tax liabilities and have limited control over the timing of the payment of these deferrals. These deferred liabilities could come due at a time when our revenues are reduced. This could cause tax payments to be due at a time when our cash flow from operations is reduced. Such a situation could have a material adverse effect on our financial condition.

Our operations are subject to environmental, health and safety laws and regulations that may expose us to liabilities for noncompliance, which could adversely affect us.

The U.S. oil and natural gas industry is affected from time to time in varying degrees by political developments and federal, state and local environmental, health and safety laws and regulations applicable to our business. Our operations are vulnerable to certain risks arising from the numerous environmental health and safety laws and regulations. These laws and regulations may restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling activities, require reporting of the storage, use or release of certain chemicals and hazardous substances, require removal or cleanup of contamination under certain circumstances, and impose substantial civil liabilities or possible criminal penalties for violations. Environmental laws and regulations may impose strict liability, rendering a company liable for environmental damage without regard to negligence or fault, and could expose us to liability for the conduct of, or conditions caused by, others, or for our acts that were in compliance with all applicable laws at the time such acts were performed. Moreover, there has been a trend in recent years toward stricter standards in environmental, health and safety legislation and regulation, which may continue. While the scientific debate concerning the impact of human activities on world climate change continues, we recognize the need to minimize in a commercially reasonable manner our impact on the environment, including the release of greenhouse gases.

Although we believe that our operations are in material compliance with applicable laws and to date, we have not incurred any significant compliance costs, we may incur material liability related to our operations under governmental regulations, including environmental, health and safety requirements. We cannot predict how existing laws and regulations may be interpreted by enforcement agencies or court rulings, whether additional laws and regulations will be adopted, or the effect such changes may have on our business, financial condition or results of operations. Because the requirements imposed by such laws and regulations are subject to change, we are unable to forecast the ultimate cost of compliance with such requirements. The modification of existing laws and regulations or the adoption of new laws or regulations, both in the U.S. and globally, which directly or indirectly curtail exploratory or development drilling for oil and natural gas for economic, political, environmental or other reasons could have a material adverse effect on us by limiting drilling opportunities.

New legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

The EPA has commenced a study of the potential environmental impacts of hydraulic fracturing including the impact on drinking water sources and public health, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. Legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states have, and others are considering, adopting regulations that could restrict hydraulic fracturing in certain circumstances. Any new laws, regulations or permitting requirements regarding hydraulic fracturing could lead to operational delays, increased costs, or third party or governmental claims. This could result in additional burdens that could serve to delay or limit the drilling services we provide to third parties. Drilling operations could be impacted by these regulations or increase our costs of compliance and doing business as well as delay the development of unconventional gas resources from shale formations which are not commercial without the use of hydraulic fracturing.

 

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

Our revolving credit facility contains various provisions that limit our ability to engage in specified types of transactions. These provisions limit our ability to, among other things:

 

   

incur additional indebtedness;

 

   

issue certain preferred shares;

 

   

unless certain conditions are satisfied, pay dividends on or make distributions in respect of our capital stock or make other restricted payments;

 

   

make certain investments, including capital expenditures;

 

   

sell certain assets;

 

   

create liens; and

 

   

consolidate, merge, sell or otherwise dispose of all or substantially all of our assets.

Risks Related to Our Common Stock

Our principal stockholder has significant ownership.

As of February 29, 2012, Union Drilling Company LLC, our principal stockholder, owned approximately 34% of our outstanding common stock. As a result, Union Drilling Company LLC and its affiliates may substantially influence the outcome of stockholder votes, including votes concerning the election of directors, the adoption or amendment of provisions in our certificate of incorporation or bylaws and the approval of mergers and other significant corporate transactions. The existence of this level of ownership concentration makes it less likely that any small holder of our common stock will be able to affect the management or direction of Union Drilling. These factors may also have the effect of delaying or preventing a change in the management or voting control of Union Drilling.

Trading volume of our common stock may contribute to its price volatility.

Our common stock is traded on the NASDAQ Global Select Market. During the period from January 1, 2011 through February 29, 2012, the average daily trading volume of our common stock as reported by the NASDAQ Global Select Market was 127,958 shares. There can be no assurance that a more or less active trading market in our common stock will develop. As a result, even relatively small trades may have a disproportionate impact on the price of our common stock and, therefore, may contribute to the price volatility of our common stock. As a result, our common stock may be subject to greater price volatility than the stock market when taken as a whole, or comparable securities of other contract drilling service providers, who may or may not have greater volumes.

The market price of our common stock has been, and may continue to be, volatile. During the period from January 1, 2011 through February 29, 2012, the trading price of our common stock ranged from $4.24 to $13.86 per share. Because of the limited trading market of our common stock and the price volatility of our common stock, you may be unable to fully sell shares of our common stock when you desire or at a price you desire.

We do not intend to pay cash dividends on our common stock in the foreseeable future, and therefore only appreciation of the price of our common stock, which may not occur, will provide a return to our stockholders.

We currently anticipate that we will retain all future earnings, if any, to finance growth and development of our business. We do not intend to pay cash dividends in the foreseeable future. Any payment of cash dividends will depend upon our financial condition, capital requirements, earnings and other factors deemed relevant by our board of directors. In addition, the terms of our revolving credit facility restrict us from paying dividends and making other distributions unless certain conditions are satisfied. As a result, for the foreseeable future, only appreciation of the price of our common stock, which may not occur, will provide a return to our stockholders.

 

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Provisions in our certificate of incorporation and bylaws as well as Delaware corporate law may make a takeover difficult.

Provisions in our certificate of incorporation and bylaws, as well as Delaware corporate law, may make it difficult and expensive for a third party to pursue a tender offer, change in control or takeover attempt that is opposed by our board of directors. These anti-takeover provisions could substantially impede the ability of public stockholders to benefit from a change in control or in a change to our management and board of directors.

 

Item 1B. Unresolved Staff Comments

None.

 

Item 2. Properties

Our principal executive offices are located in Fort Worth, Texas and include approximately 12,600 square feet of leased office space. Our contract drilling operations are conducted from eight field offices (three offices serving the Appalachian basin, three offices serving the Barnett and Permian basins, and two offices serving the Arkoma basin) which contain office, shop and yard space to support day-to-day operations, including the repair and maintenance of equipment, as well as the storage of equipment, inventory and supplies, and to facilitate administrative responsibilities and sales. We own five of our eight field office locations, while the rest are leased. We believe that none of the leased facilities is individually material to our operations and that our existing facilities are suitable and adequate to meet our needs.

 

Item 3. Legal Proceedings

See Note 12 of the financial statements, included in “Item 8. Financial Statements and Supplementary Data” for a summary of our legal proceedings, such information being incorporated herein by reference.

 

Item 4. Mine Safety Disclosures

Not applicable.

PART II

 

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

As of February 29, 2012, 23,148,116 shares of our common stock were outstanding. As of February 29, 2012, the number of holders of record of our common stock was ten.

 

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Our common stock trades on the NASDAQ Global Select Market under the symbol “UDRL.” The following table sets forth, for each of the periods indicated, the high and low trading price per share for our common stock on the NASDAQ Global Select Market:

 

     Low      High  

Fiscal Year 2011

     

Fourth quarter

   $ 4.24       $ 8.14   

Third quarter

   $ 4.70       $ 11.98   

Second quarter

   $ 8.54       $ 13.86   

First quarter

   $ 7.07       $ 10.47   

Fiscal Year 2010

     

Fourth quarter

   $ 4.28       $ 8.00   

Third quarter

   $ 4.40       $ 6.49   

Second quarter

   $ 4.81       $ 7.08   

First quarter

   $ 5.79       $ 8.39   

The last reported sales price for our common stock on the NASDAQ Global Select Market on February 29, 2012 was $6.74 per share.

We have not paid or declared any cash dividends on our common stock and currently intend to retain earnings to fund our working capital needs and growth opportunities. Any future dividends will be at the discretion of our board of directors after taking into account various factors deemed relevant, including our financial condition and performance, cash needs, income tax consequences and the restrictions Delaware and other applicable laws and our credit facilities then impose. Our debt arrangements include provisions that generally place certain limits on payment of cash dividends and share repurchases.

Purchases of Equity Securities

In September 2011, the Company’s Board approved the 2011 Union Drilling, Inc. Share Repurchase Program (the “Program”). Under the Program, the Board authorized the Company to repurchase up to three million shares of the Company’s outstanding common stock. The authorization under the Program does not have a stated expiration date and the pace of repurchase activity is dependent on Company’s stock price, among other factors. The table below sets forth share repurchase information for the time periods indicated.

 

      Total Number
of Shares
Purchased
     Average Price
Paid
Per Share
     Total Number of
Shares Purchased
As Part of Publicly
Announced Plans
or Programs
     Maximum Number
of Shares that May
Yet be Purchased
Under the Plans or
Programs
 

October 1-31, 2011

     80,700       $ 5.29         80,700         2,919,300   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

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Equity Compensation Plan Information

The following table provides information as of December 31, 2011 about our common stock that may be issued upon the exercise of options, warrants and rights granted to employees, consultants or members of the board of directors under all of our existing equity compensation plans:

 

     Number of shares
of common stock
to be issued upon
exercise of
outstanding
options, warrants
and rights
     Weighted average
exercise price per share
of outstanding options
warrants and rights
     Number of shares of
common stock remaining
available for future
issuance under equity
compensation plans
(excluding shares
reflected in column (a) )
 
     ( a )                

Equity compensation plans approved by security holders

     1,417,039(1)       $ 9.80         224,705(2)   
  

 

 

    

 

 

    

 

 

 

 

(1) Includes 176,545 shares of common stock issuable upon the exercise of options that were outstanding under our Amended and Restated 2000 Stock Option Plan and 1,240,494 shares of common stock issuable upon the exercise of options that were outstanding under our Amended and Restated 2005 Stock Incentive Plan, in each case, as of December 31, 2011.
(2) These are available for future issuance under our Amended and Restated 2005 Stock Incentive Plan as of December 31, 2011.

PERFORMANCE GRAPH

The following graph shows a comparison of the total cumulative returns over the past five year period of an investment of $100 in cash on December 31, 2006, in (i) our common stock, (ii) the NASDAQ Composite Index, U.S. Companies, and (iii) a group of peer issuers that the Company selected that includes 4 public companies within our industry. The companies that comprise the peer group index are Helmerich & Payne, Inc., Patterson-UTI Energy, Inc., Pioneer Drilling Company and Nabors Industries, Inc. The historical comparisons in the graph are required by the SEC and are not intended to forecast or be indicative of the possible future performance of our common stock. The graph assumes that all dividends have been reinvested (although the Company has not declared any cash dividends).

 

     2006      2007      2008      2009      2010      2011  

Union Drilling, Inc

   $ 100.00       $ 112.00       $ 36.86       $ 44.39       $ 51.70       $ 44.32   

NASDAQ Composite

     100.00         110.26         65.65         95.19         112.1         110.81   

Peer Group

     100.00         102.06         51.78         87.37         103.41         97.85   

 

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LOGO

The foregoing shall not be deemed to be “soliciting material” or to be “filed” with the Securities and Exchange Commission or subject to Regulation 14A or 14C under the Securities Exchange Act of 1934 and shall not be deemed incorporated by reference into any filing made by the Company under the Securities Act of 1933 or the Securities Exchange Act of 1934, notwithstanding any general statement contained in any such filing incorporating this Annual Report by reference, except to the extent the Company incorporates such graph by specific reference.

 

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Item 6. Selected Financial Data

The following information derives from our audited financial statements. You should review this information in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this report and the historical financial statements and related notes this report contains.

 

     Year Ended December 31,  
     2011     2010     2009     2008      2007  
     (In thousands, except per share data)  

Revenues

   $ 250,891      $ 192,539      $ 168,922      $ 302,780       $ 289,035   

(Loss) income from operations

     (9,282     (25,330     (15,641     20,389         53,291   

(Loss) income before income taxes

     (6,938     (24,982     (16,426     20,361         52,852   

Net (loss) income

     (5,351     (16,068     (12,033     7,750         30,832   

(Loss) earnings per common share-basic

     (0.23     (0.69     (0.55     0.35         1.41   

(Loss) earnings per common share-diluted

     (0.23     (0.69     (0.55     0.35         1.41   

Long-term debt, including current portion and line of credit

     68,003        30,227        9,767        47,745         17,309   

Stockholders’ equity

     197,655        201,756        216,323        204,713         203,409   

Total assets

     342,011        300,989        293,010        336,605         277,308   

Calculation of EBITDA:

           

Net (loss) income

   $ (5,351   $ (16,068   $ (12,033   $ 7,750       $ 30,832   

Interest expense

     1,488        1,005        794        845         1,824   

Income tax (benefit) expense

     (1,587     (8,914     (4,393     12,611         22,020   

Depreciation and amortization

     50,846        49,932        47,719        44,298         39,072   

Impairment charge

     808        —          4,069        7,909         —     
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

EBITDA

   $ 46,204      $ 25,955      $ 36,156      $ 73,413       $ 93,748   
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

EBITDA is earnings before net interest, income taxes, depreciation and amortization and non-cash impairment. The Company believes EBITDA is a useful measure of evaluating its financial performance because it is used by external users, such as investors, commercial banks, research analysts and others, to assess: (1) the financial performance of Union Drilling’s assets without regard to financing methods, capital structure or historical cost basis, (2) the ability of Union Drilling’s assets to generate cash sufficient to pay interest costs and support its indebtedness, and (3) Union Drilling’s operating performance and return on capital as compared to those of other entities in our industry, without regard to financing or capital structure. EBITDA is not a measure of financial performance under generally accepted accounting principles. However, EBITDA is a common alternative measure of operating performance used by investors, financial analysts and rating agencies. A reconciliation of EBITDA to net (loss) income is included above. EBITDA as presented may not be comparable to other similarly titled measures reported by other companies.

 

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

This management’s discussion and analysis of financial condition and results of operations (“MD&A”) section of our Annual Report on Form 10-K discusses our results of operations, liquidity and capital resources, and certain factors that may affect our future results, including economic and industry-wide factors. You should read this MD&A in conjunction with our financial statements and accompanying notes included under Part II, Item 8, of this Annual Report.

Statements we make in the following MD&A discussion and in other parts of this report that express a belief, expectation or intention, as well as those which are not historical fact, are forward-looking statements within the meaning of the federal securities laws and are subject to risks, uncertainties and assumptions. These forward-looking statements may be identified by the use of words such as “expect,” “anticipate,” “believe,” “estimate,” “potential” or similar words. These matters include statements concerning management’s plans and objectives relating to our operations or economic performance and related assumptions, including general economic and business conditions and industry trends, the continued strength or weakness of the contract land drilling industry in the geographic areas in which we operate, decisions about onshore exploration and development projects to be made by oil and gas companies, the highly competitive nature of our business, our future financial performance, including availability, terms and deployment of capital, the continued availability of qualified personnel, and changes in, or our failure or inability to comply with, government regulations, including those relating to workplace safety and the environment. Although we believe that the expectations reflected in these forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Further, we specifically disclaim any duty to update any of the information set forth in this report, including any forward-looking statements. Forward-looking statements are made based on management’s current expectations and beliefs concerning future events and, therefore, involve a number of assumptions, risks and uncertainties, including the risk factors described in Item 1A, “Risk Factors,” above. Management cautions that forward-looking statements are not guarantees, and our actual results could differ materially from those expressed or implied in the forward-looking statements.

Company Overview

Union Drilling, Inc. (“Union Drilling,” “Company” or “we”) provides contract land drilling services and equipment, primarily to oil and natural gas producers in the United States. In addition to drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs.

We provide drilling services to customers engaged in developing oil and natural gas bearing formations in selected areas of the United States. Our strategy is to focus on areas that have high growth potential, adequate takeaway capacity and low finding and development costs in order to maximize utilization and return on capital throughout the commodity price cycle. Since the global economic crisis in 2008, oil prices have rebounded while natural gas has not. Due to the divergence of oil and natural gas prices, many of our customers have shifted their investments to oil and liquids-rich plays; accordingly, many of the rigs in our fleet have been repositioned and are now concentrated in those areas. Our principal operations are in the Appalachian Basin, extending from New York to Tennessee including the Marcellus, Huron, and Utica shales; the Arkoma Basin in eastern Oklahoma and Arkansas, including the Fayetteville, Caney, and Woodford shales; the Fort Worth Basin in North Texas, including the Barnett Shale and in West Texas extending to southeastern New Mexico, the Permian and Delaware Basins. We believe we are well positioned to expand into the Mississippian oil plays in central Oklahoma and southern Kansas.

We commenced operations in 1997 with 12 drilling rigs and related equipment acquired from an entity providing contract drilling services under the name “Union Drilling.” Through a combination of acquisitions and new rig construction, we increased the size of our fleet to 71 marketed land drilling rigs. In 2011, in an effort to better align our rig fleet with the growing part of the market (deep horizontal shale drilling), we added three new large rigs, decommissioned two of our older, smaller rigs, sold a small, marketed rig in a private transaction and auctioned 31 of our older, smaller rigs that have had minimal utilization over the past several years. Of those 31 rigs, 20 were marketed rigs, while 11 had been previously decommissioned. Accordingly, our marketed rig fleet at December 31, 2011, contains 51 land drilling rigs, demonstrating our commitment to provide premium, modern rigs and experienced, knowledgeable crews to the major and large independent E&P companies.

 

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Key Indicators of Financial Performance for Management

Key performance measurements in our industry are rig utilization, revenue per revenue day and operating expenses per revenue day. Revenue days for each rig are days when the rig is earning revenues under a contract, which is usually a period from the date the rig begins moving to the drilling location until the rig is released from the contract. We compute rig utilization rates by dividing revenue days by total available days during a period. Total available days are the number of calendar days during the period that we have owned and marketed the drilling rig.

The following table summarizes management’s key indicators of financial performance for each of the three years in the period ended December 31, 2011:

 

     Year Ended December 31,  
     2011     2010     2009  

Revenue days

     14,772        12,735        9,700   

Average number of marketed rigs

     65.9        71.0        71.0   

Marketed rig utilization rates

     61.5     49.1     37.4

Revenue per revenue day

   $ 16,984      $ 15,119      $ 17,415   

Operating expenses per revenue day

   $ 12,122      $ 11,256      $ 11,129   

Our business is substantially dependent on and affected by the level of U.S. land-based oil and natural gas exploration and development activity. Since the global economic crisis in 2008, oil prices have rebounded while natural gas has not. Since that time, we experienced improvement in our marketed rig utilization rates as well as improvement in our revenue per revenue day due to upgrades in our drilling fleet, shift to oil drilling, and relatively stable demand for natural gas drilling in shale plays. Our operating expenses per revenue day have also increased due to more complex drilling required for unconventional and shale plays, higher wages and headcount across certain of our markets, as well as an enhanced focus on retention and safety initiatives. During 2011, we enhanced our pre-employment screening processes, hired additional safety and training personnel, and upgraded technology associated with certain field personnel. Revenue per revenue day declined in 2010 compared to 2009 as term contracts with higher rates expired and re-priced during the year.

We devote substantial resources to maintaining and upgrading our rig fleet. On a regular basis, we remove certain rigs from service to perform upgrades. In the short term, these actions result in fewer revenue days and lower utilization; however, in the long term, we believe the upgrades will help the marketability of the rigs and improve their operating performance.

Average number of marketed rigs represents the average number of rigs we owned and marketed during the period. During 2011, we added three new large rigs, decommissioned two of our older, smaller rigs, sold a small, marketed rig in a private transaction and auctioned 31 of our older, smaller rigs that have had minimal utilization over the past several years. Of those 31 rigs, 20 were marketed rigs, while 11 were decommissioned. Accordingly, our marketed rig fleet at December 31, 2011, contained 51 land drilling rigs, while our average marketed rig fleet for the year ended December 31, 2011, was 65.9 land drilling rigs.

Critical Accounting Policies and Estimates

Revenue and cost recognition. We generate revenue principally by drilling wells for oil and natural gas producers primarily under daywork contracts, and to a lesser extent footage contracts, which provide for the drilling of single or multiple well projects. Revenues on daywork contracts are recognized based on the days worked at the dayrate each contract specifies. Mobilization fees are recognized as the related drilling services are provided. We recognize revenues on footage contracts based on the footage drilled for the applicable accounting period. Expenses are recognized based on the costs incurred during that same accounting period. Reimbursements received for out-of-pocket expenses are recorded as revenues.

 

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Accounts receivable. We evaluate the creditworthiness of our customers based on their financial condition using information obtained from their bank, as well as their major vendors, and our past experiences, if any, with the customer. In some instances, we require new customers to make prepayments. We typically invoice our customers semi-monthly during the performance of the contracts and upon completion of the contract, with payment due within 30 days. We established an allowance for doubtful accounts of $1.4 million and $153,000 at December 31, 2011 and 2010, respectively. The increase in allowance for doubtful accounts at December 31, 2011, compared to December 31, 2010, is due to certain disputed invoices and an increase in revenues. Any allowance established is subject to judgment and estimates made by management. We determine our allowance by considering a number of factors, including the length of time trade accounts receivable are past due, our previous loss history, our assessment of our customers’ current abilities to pay obligations to us and the condition of the general economy and the oil and natural gas industry as a whole. Our bad debt expense was $1.5 million, $97,000 and $1.1 million for 2011, 2010 and 2009, respectively. We write off specific accounts receivable when we determine they are uncollectible. In 2011, 2010 and 2009, we wrote off $219,000, $1.3 million and $1.2 million, of accounts receivable, respectively.

At December 31, 2011 and 2010, our unbilled receivables totaled $1.7 million and $1.4 million, respectively, all of which relates to the revenue recognized, but not yet billed, on contracts in progress at December 31, 2011 and 2010, respectively. The $300,000 increase at December 31, 2011, compared to December 31, 2010, is primarily due to the improvement in our revenues and utilization.

Asset impairments. We assess the impairment of long-lived assets whenever events or circumstances indicate that the asset’s carrying value may not be recoverable. For purposes of performing our impairment analysis, we group long-lived assets at the lowest level for which there are identifiable cash flows. Factors that could trigger an impairment review would be any significant negative trends in the industry or the general economy, our contract revenue rates, our rig utilization rates, cash flows generated from operating our drilling rigs, existence of term drilling contracts, current and future oil and natural gas prices, our customers’ access to capital and the trends in the price of used drilling equipment observed by our management. If a review of our long-lived assets indicates that our carrying value exceeds the estimated undiscounted future cash flows, an impairment charge is made to adjust the carrying value to the estimated fair value. Cash flows are estimated by management considering factors such as expectations of future industry trends and the impact on dayrates, utilization and operating expenses; historical performance of the asset; the remaining expected life of the asset; any cash investment required to make the asset more marketable; suitability, specification and size of the rig; terminal value, as well as overall competitive dynamics. Use of different assumptions could result in an impairment charge different from that reported.

Depreciation. We provide for depreciation of our drilling rigs, transportation and other equipment on a straight line method over useful lives that we have estimated, ranging from two to 12 years. Unlike depreciation based on units-of-production, our approach to depreciation does not change when equipment becomes idle or when utilization changes. We continue to depreciate idled equipment on a straight-line basis despite the fact that our revenues and operating costs may vary with changes in utilization levels. Equipment that is classified as held for sale is no longer depreciated. Our estimates of the useful lives of our drilling, transportation and other equipment are based on our experience in the drilling industry with similar equipment.

Deferred taxes. We record deferred taxes for the basis difference in our property and equipment between financial reporting and tax reporting purposes and other costs such as compensation, employee benefits and other accrued liabilities which are deductible in different periods for financial reporting and tax reporting purposes. For property and equipment, basis differences arise from differences in depreciation periods and methods and the value of assets acquired in a business acquisition where we acquire the stock of an entity rather than its assets. For financial reporting purposes, we depreciate the various components of our drilling rigs and refurbishments over two to 12 years, while federal income tax rules require that we depreciate drilling rigs and refurbishments over five years. In 2009, tax depreciation also included bonus depreciation allowed as a result of the American Recovery and Reinvestment Act of 2009. In 2011 and in 2010, bonus depreciation did not create any current tax benefit and is not included in our tax depreciation calculations. In the earlier years of our ownership of a drilling rig, our tax depreciation may often exceed our financial reporting depreciation, resulting in our recording deferred tax liabilities on this depreciation difference. In later years, financial reporting depreciation exceeds tax depreciation, and the deferred tax liability begins to reverse.

 

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Accrued workers’ compensation. The Company accrues for costs under our workers’ compensation insurance program in accrued expenses and other liabilities. We have a deductible of $100,000 per covered accident under our workers’ compensation insurance. Our insurance policies require us to maintain letters of credit to cover our deductible payments. As of December 31, 2011 and 2010, we satisfied this requirement with letters of credit totaling $4.2 million and $4.3 million, respectively. We accrue for these costs as claims are incurred considering cost estimates established for each claim by the insurance companies providing the administrative services for processing the claims, including estimates for incurred but not reported claims, claims paid directly by us, administrative costs associated with these claims, and our historical experience with these types of claims. In addition, as needed, we accrue the estimated workers compensation premium payable to Ohio, a monopolistic state, when our rigs work in that state.

Stock-based compensation. Compensation cost resulting from share-based payment awards are measured at fair value and recognized in general and administrative expense on a straight line basis over the requisite service period. The amount of compensation cost recognized at any date is at least equal to the portion of the grant-date fair value of the award that is vested at that date. For the years ended December 31, 2011, 2010 and 2009, the Company recorded stock-based compensation expense of $1.6 million ($1.1 million net of tax), $1.3 million ($0.8 million net of tax), and $1.8 million ($1.1 million net of tax), respectively. Total unamortized stock-based compensation was approximately $3.4 million at December 31, 2011, and will be recognized over a weighted average service period of 3.7 years. Any tax benefit realized from stock options exercised is included as a cash inflow from financing activities on the statement of cash flows in the period the benefit is realized.

Estimating the fair value of stock options granted requires us to utilize valuation models and to establish several underlying assumptions. The fair value of stock option grants was estimated using the Black-Scholes valuation model based on the following weighted average assumptions, (no stock options were issued in 2011):

 

     2010    2009

Risk-free interest rate

   1.4% - 1.6%    2.1% - 2.6%

Expected life

   5 years    5 years

Dividend yield

   0%    0%

Expected volatility

   77% - 78%    74% - 75%

The risk-free interest rate is the implied yield available for zero-coupon U.S. government issues with a remaining term equal to the expected life of the stock options.

The expected lives of the options are determined based on the Company’s expectations of individual stock option holders’ anticipated behavior and the term of the stock option.

The Company has not paid out dividends historically; thus, the dividend yield is estimated at zero percent.

Volatility is based upon price performance of the Company and prior to November 2010 included a peer company, as the Company did not have a sufficient historical price base to determine potential volatility over the term of the issued stock options.

The fair value of restricted stock or restricted stock units is the closing market price of the Company’s stock on the award grant date. During the period ended December 31, 2011, 2010, and 2009, 172,912, 50,000 and 38,545 restricted stock units were granted, respectively.

Results of Operations

Our operations primarily consist of drilling oil or natural gas wells for our customers under either daywork contracts and, to a lesser extent, footage contracts. The contract terms we offer generally depend on the location, depth and complexity of the well to be drilled; the on-site drilling conditions; the type of equipment used; the duration of the work to be performed; and the competitive forces of the market. In most instances, our contracts provide for additional payments related to rig mobilization and demobilization, as well as reimbursement of certain out-of-pocket costs.

 

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Statements of Operations Analysis

The following table provides selected information about our operations for the years ended December 31, 2011, 2010 and 2009 (in thousands).

 

     Year Ended December 31,  
     2011     2010     2009  

Revenues

   $ 250,891      $ 192,539      $ 168,922   

Operating expenses

     179,066        143,348        107,956   

Depreciation and amortization

     50,846        49,932        47,719   

Impairment charge

     808        —          4,069   

General and administrative expense

     29,453        24,589        24,819   

Interest expense

     1,488        1,005        794   

Other income and gain on disposal of assets

     3,832        1,353        9   

Effective income tax rate

     22.9     35.7     26.7

Revenues. The $58.4 million, or 30% increase in revenues in 2011 compared to 2010 was due to the increase in our marketed rig utilization and average dayrates. Average dayrates increased to $16,984 in 2011 from $15,119 in 2010, primarily due to rig mix and an increase in pricing in Texas. Utilization increased to 61.5% in 2011 from 49.1% in 2010, primarily due to the contributions from six new rigs, of which three were added in 2011, and three were added in 2010, as well as the disposition of certain smaller rigs in an auction held in December 2011.

The $23.6 million or 14% increase in revenues in 2010 compared to 2009 was primarily due to the increase in our marketed rig utilization from 37.4% in 2009 to 49.1% in 2010, as a result of the improvement in the level of U.S. land-based drilling that began in the second half of 2009 particularly directed for oil drilling, and partially offset by lower dayrates.

Operating expenses. Our operating expenses increased $35.7 million, or 25%, in 2011 compared to 2010, primarily due to the increase in marketed rig utilization as well as an increase in operating costs due to increased employment costs and increased rig maintenance costs. Further, operating costs also increased due to increased safety initiatives, retention efforts and training costs.

The $35.4 million, or 33% increase in operating expenses in 2010 compared to 2009 was primarily due to the increase in marketed rig utilization, additional costs incurred to prepare certain idled rigs to return to operation during 2010 and increased safety training and supplies costs. In addition, employment costs increased beginning in the first half of 2010 as the Company restored wage reductions that were implemented in 2009 in response to the deteriorating market conditions.

Depreciation and amortization. The $914,000, or 2% increase in depreciation and amortization expense in 2011 compared to 2010 was due to the increase in depreciable assets, resulting from rig acquisitions and capital equipment upgrades that enhanced our fleet capabilities, partially offset by a decrease in depreciation expense related to the disposition of assets in an auction held in December 2011. Capital expenditures were $83.5 million in 2011.

 

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The $2.2 million, or 5%, increase in depreciation and amortization expense in 2010 compared to 2009 was due to the increase in depreciable assets, resulting from three rig purchases and various other capital equipment upgrades in 2010 that enhanced our fleet capabilities. Capital expenditures were $60.3 million in 2010.

Impairment charge.

For the year ended December 31, 2011, we recorded $808,000 of impairment related to the auction of certain of our older, smaller rigs. For the year ended December 31, 2010, no impairment charges were required. For the year ended December 31, 2009, $4.1 million of impairment charges were recognized as a result of the global economic crisis that began in 2008.

General and administrative expenses. Our general and administrative expenses increased $4.9 million or 20%, in 2011 compared to 2010. This increase was primarily attributable to higher employment costs due to increased headcount, costs associated with hosting and administrative support for our new information system and an increase in our allowance for doubtful accounts on higher revenues.

General and administrative expenses decreased slightly, or $230,000, in 2010 compared to 2009. This decrease was primarily due to a $1.0 million decrease in the provision for doubtful accounts, as well as lower corporate insurance rates and property taxes in 2010 compared to 2009. These decreases were partially offset by higher employment costs due to increased headcount as well as consulting fees related to a new information system conversion and implementation.

Interest expense. The $483,000 increase in interest expense in 2011 compared to 2010 was primarily attributable to the increase in the average balance of our credit facility, proceeds of which were used to partially fund our 2011 capital spending program.

The $211,000 increase in interest expense in 2010 compared to 2009 was primarily attributable to the increase in the average balance of our credit facility, proceeds of which were used to partially fund our 2010 capital spending program.

Other income and gain on disposal of assets. The $2.5 million increase in other income and gain (loss) on disposal of assets in 2011 compared to 2010 is due to the auction of 31 of our older, smaller rigs in December 2011 and the sale of an older, smaller rig in a private transaction during the third quarter.

The $1.3 million increase in other income and gain (loss) on disposal of assets in 2010 compared to 2009 was due to a gain on the settlement of a rig physical insurance claim as well as gains from the disposal of non-core assets.

Taxes. Our effective income tax rates of 22.9%, 35.7%, and 26.7% for 2011, 2010 and 2009, respectively, differ from the federal statutory rate of 35%, primarily due to state income taxes and permanent book/tax differences such as those associated with the 50% deduction limitation on per diem meals expense, the domestic manufacturing deduction and stock-based compensation. See Note 6 to our Financial Statements for further information on our income taxes.

The decrease in income tax benefit in 2011 compared to 2010 was primarily due to the decrease in pre-tax loss and the effective income tax rate.

 

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The Company had federal net operating loss carryforwards of approximately $25.1 million and $23.3 million at December 31, 2011, and 2010, respectively. These losses may be carried forward for 20 years and will begin to expire in 2023. State net operating losses at December 31, 2011, and 2010, were $44.9 million and $43.6 million, respectively. State losses vary as to carryforward period and will begin to expire in 2014, depending upon the jurisdiction where applied. In 2011 and 2010, a valuation allowance of $391,000 and $70,000, respectively, was established for state net operating loss carryforwards in states where utilization is uncertain due to lack of forecasted future operations or the remaining carryforward period is limited. Based upon 2011 results and forecasted future operations, we believe it is more likely than not that the remaining amounts will be realized.

The Company files U.S. federal income tax returns and income tax returns in various state jurisdictions. The tax years 2006 through 2011 remain open to examination by the major taxing jurisdictions to which we are subject. In addition, tax years 1999, 2000, 2002 and 2003 remain open due to utilized losses in some jurisdictions.

Liquidity and Capital Resources

Our operations have historically generated sufficient cash flow to meet our requirements for debt service and equipment expenditures. Cash flow provided by operating activities was $34.0 million, $34.9 million and $58.5 million during 2011, 2010 and 2009, respectively. The decrease in cash flows provided by operating activities in 2011 compared to 2010 was primarily attributable to the increase in accounts receivable offset by a decrease in net loss. The increase in accounts receivable is due to an increase in revenues as well as in increase in the timing of collections. The decrease in cash flows provided by operating activities in 2010 compared to 2009 was due to an increase in accounts receivable. The increase in accounts receivable was due to an increase in revenues, and an increase in the timing of collections.

Our cash flow from operations primarily was used to invest in new machinery and equipment as well as for capitalized upgrades to our fleet. During 2011, 2010 and 2009, cash used in investing activities totaled $71.2 million, $55.6 million and $43.9 million, respectively. In 2011, we recorded $12.4 million of proceeds from the sales of machinery and equipment, of which $10.4 million related to the auction of certain of our older smaller rigs.

For the year ended December 31, 2011, our cash flow from financing activities was $37.2 million, consisting primarily of the $37.8 million increase in our net borrowings on our credit facility and other debt. In addition, in October 2011, we purchased 80,700 shares of common stock for $427,000 under a share repurchase program. In 2010 cash flow used in financing activities was $20.7 million, which consisted primarily of the $21.1 million increase in net borrowing from 2009 on our credit facility

We believe cash generated by our operations and our ability to borrow the currently unused portion of our revolving credit facility of approximately $78.0 million, after reductions for approximately $4.2 million outstanding letters of credit as of December 31, 2011, should allow us to meet our routine financial obligations for the foreseeable future.

Sources of Capital Resources

Our rig fleet has grown from 12 rigs in 1997 to 51 marketed land drilling rigs. We have financed this growth with a combination of debt and equity financing, as well as operating cash flows. At December 31, 2011, our ratio of total debt to total capital was 26%.

See Note 8 of the financial statements, included in “Item 8. Financial Statements and Supplementary Data” for a summary of our capital resources, such information being incorporated herein by reference.

 

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Uses of Capital Resources

For the years ended December 31, 2011 and 2010, the additions to our property and equipment consisted of the following (in thousands):

 

     Year Ended December 31,  
     2011     2010  

Land and buildings

   $ 2,237      $ —     

Drilling rigs and related equipment

     81,847        57,191   

Vehicles

     2,307        210   

Information systems

     529        2,908   

Furniture and fixtures

     12        —     
  

 

 

   

 

 

 

Property and equipment additions

   $ 86,932      $ 60,309   

Plus adjustments for non-cash transactions:

    

Cash paid in current period for prior period accruals

     2,616        810   

Current period accruals

     (6,006     (2,616
  

 

 

   

 

 

 

Cash used for purchases of machinery and equipment

   $ 83,542      $ 58,503   
  

 

 

   

 

 

 

During 2011, additions to drilling equipment included $81.8 million, which included the purchase of three new rigs and progress payments for three new rigs that will be completed in the first half of 2012. We upgraded and enhanced several of the existing rigs and related equipment in our fleet with pad drilling systems, top drives, larger drawworks and higher horsepower mud pumps. We also purchased office buildings, rig yards and surrounding land in West Texas and Arkansas.

Our capital expenditures program in 2010 included the purchase of three rigs and partial payments associated with a fourth rig. In addition, we upgraded and enhanced several of the existing rigs and related equipment in our fleet with pad drilling systems, top drives, larger drawworks and higher horsepower mud pumps. In 2010, we began a process of implementing a new information system that we put into production in January 2011.

 

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Working Capital

Our working capital increased by $5.7 million at December 31, 2011, compared to December 31, 2010. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 1.5 for the years ended December 31, 2011 and 2010. The changes in the components of our working capital were as follows (in thousands):

 

     December 31,  
     2011      2010      Change  

Cash and cash equivalents

   $ 7       $ 4       $ 3   

Accounts receivable

     45,387         30,880         14,507   

Inventories

     832         1,252         (420

Income tax recoverable

     368         1,023         (655

Prepaid expenses, deposits and other receivables

     3,027         2,112         915   

Deferred taxes

     1,239         1,186         53   
  

 

 

    

 

 

    

 

 

 

Current assets

     50,860         36,457         14,403   

Accounts payable

     21,513         13,076         8,437   

Current portion of notes payable for equipment

     120         173         (53

Financed insurance premiums

     1,057         909         148   

Accrued expenses and other liabilities

     10,811         10,675         136   
  

 

 

    

 

 

    

 

 

 

Current liabilities

     33,501         24,833         8,668   
  

 

 

    

 

 

    

 

 

 

Working capital

   $ 17,359       $ 11,624       $ 5,735   
  

 

 

    

 

 

    

 

 

 

The $14.5 million increase in accounts receivable at December 31, 2011, compared to December 31, 2010, was primarily due to the increase in revenue in 2011 compared to 2010, as well as an increase in timing of collections.

The $915,000 increase in prepaid expenses, deposits and other receivables at December 31, 2011, compared to December 31, 2010, was primarily due to an increase in miscellaneous receivables related to auction receipts and an increase in vendor rebates.

The $8.4 million increase in accounts payable at December 31, 2011, compared to December 31, 2010, was primarily due to increased operating and general and administrative expenses, as well as an increase in capital expenditures.

Long-term Debt

Our long-term debt at December 31, 2011 and 2010 consisted of the following (in thousands):

 

     December 31,  
     2011      2010  

Revolving credit facility

   $ 67,813       $ 30,054   

Long-term notes payable for equipment

     70         —     
  

 

 

    

 

 

 
   $ 67,883       $ 30,054   
  

 

 

    

 

 

 

 

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Contractual Obligations

The following table includes all of our contractual obligations of the type specified below at December 31, 2011, (in thousands):

 

Contractual Obligations

   Total      Less than 1
year
     1-3 years      4 - 5
years
     More than 5
years
 

Revolving credit facility (a)

   $ 67,813       $ —         $ —         $ 67,813       $ —     

Notes payable for equipment

     190         120         70         —           —     

Operating lease obligations

     3,334         1,621         1,711         2         —     

Purchase obligations for fleet upgrades

     33,384         33,384         —           —           —     
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 104,721       $ 35,125       $ 1,781       $ 67,815       $ —     
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(a) The amount included in the table above represents principal maturities only. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for information regarding estimated future interest payment obligations under long-term debt obligations and Note 8 of Notes to Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”

On April 27, 2011, the Company entered into an Amended and Restated Revolving Credit and Security Agreement with PNC Bank, National Association, acting as lender and as agent to the other lenders as specified in the agreement, and PNC Capital Markets LLC, as lead arranger. See Note 8 “Debt Obligations” of the financial statements for information on this agreement, such information being incorporated herein by reference.

Inflation

Inflation did not have a significant effect on our results of operations in any of the periods reported.

Off Balance Sheet Arrangements

We do not currently have any off balance sheet arrangements.

Recently Issued Accounting Standards

See Note 2 of the financial statements, included in “Item 8. Financial Statements and Supplementary Data” for recently issued accounting standards, such information being incorporated herein by reference.

 

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

We are subject to market risk exposure related to changes in interest rates on our revolving credit facility, which provides for interest on borrowings under the facility at a floating rate. At December 31, 2011, we had $67.8 million outstanding debt on our revolving credit facility. An increase or decrease of 1% in the interest rate would have a corresponding decrease or increase in our interest expense of approximately $678,000 annually.

 

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Item 8. Financial Statements and Supplementary Data

UNION DRILLING, INC.

INDEX TO FINANCIAL STATEMENTS

 

     Page  

Report of Independent Registered Public Accounting Firm

     26   

Report of Independent Registered Public Accounting Firm

     27   

Balance Sheets as of December 31, 2011 and 2010

     28   

Statements of Operations for the Years Ended December 31, 2011, 2010 and 2009

     29   

Statements of Stockholders’ Equity for the Years Ended December 31, 2011, 2010 and 2009

     30   

Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009

     31   

Notes to Financial Statements

     32   

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC

ACCOUNTING FIRM

The Board of Directors and Stockholders of

Union Drilling, Inc.

We have audited Union Drilling, Inc.’s (the “Company”) internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Union Drilling, Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

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

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

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

In our opinion, Union Drilling, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the balance sheets of Union Drilling, Inc. as of December 31, 2011 and 2010 and the related statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2011 and our report dated March 8, 2012 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Fort Worth, Texas

March 8, 2012

 

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Table of Contents

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

of Union Drilling, Inc.

We have audited the accompanying balance sheets of Union Drilling, Inc. (the “Company”) as of December 31, 2011 and 2010, and the related statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Union Drilling, Inc. at December 31, 2011 and 2010, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Union Drilling, Inc.’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 8, 2012 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Fort Worth, Texas

March 8, 2012

 

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Table of Contents

Union Drilling, Inc.

Balance Sheets

(in thousands, except share and per share data)

 

     December 31,  
     2011     2010  

Assets:

    

Current assets:

    

Cash and cash equivalents

   $ 7      $ 4   

Accounts receivable (net of allowance for doubtful accounts of $1,409 and $153 at December 31, 2011 and 2010, respectively)

     45,387        30,880   

Inventories

     832        1,252   

Income tax recoverable

     368        1,023   

Prepaid expenses, deposits and other receivables

     3,027        2,112   

Deferred taxes

     1,239        1,186   
  

 

 

   

 

 

 

Total current assets

     50,860        36,457   

Intangible assets (net of accumulated amortization of $1,221 and $920 at December 31, 2011 and 2010, respectively)

     979        1,280   

Property, buildings and equipment (net of accumulated depreciation of $212,173 and $239,362 at December 31, 2011 and 2010, respectively)

     289,429        263,210   

Other assets

     743        42   
  

 

 

   

 

 

 

Total assets

   $ 342,011      $ 300,989   
  

 

 

   

 

 

 

Liabilities and Stockholders’ Equity:

    

Current liabilities:

    

Accounts payable

   $ 21,513      $ 13,076   

Current portion of notes payable for equipment

     120        173   

Financed insurance premiums

     1,057        909   

Accrued expense and other liabilities

     10,811        10,675   
  

 

 

   

 

 

 

Total current liabilities

     33,501        24,833   

Revolving credit facility

     67,813        30,054   

Long-term notes payable for equipment

     70        —     

Deferred taxes

     42,972        44,089   

Customer advances and other long-term liabilities

     —          257   
  

 

 

   

 

 

 

Total liabilities

     144,356        99,233   

Stockholders’ equity:

    

Common stock, par value $.01 per share; 75,000,000 shares authorized; 25,228,816 shares and 25,182,345 shares issued at December 31, 2011 and 2010, respectively

     252        252   

Additional paid-in capital

     172,465        170,788   

Retained earnings

     35,828        41,179   

Treasury stock; 2,080,700 and 2,000,000 shares December 31, 2011 and 2010, respectively

     (10,890     (10,463
  

 

 

   

 

 

 

Total stockholders’ equity

     197,655        201,756   
  

 

 

   

 

 

 

Total liabilities and stockholders’ equity

   $ 342,011      $ 300,989   
  

 

 

   

 

 

 

See accompanying notes to financial statements.

 

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Union Drilling, Inc.

Statements of Operations

(in thousands, except share and per share data)

 

     Years Ended December 31  
     2011     2010     2009  

Revenues

   $ 250,891      $ 192,539      $ 168,922   

Cost and expenses

      

Operating expenses

     179,066        143,348        107,956   

Depreciation and amortization

     50,846        49,932        47,719   

Impairment charge

     808        —          4,069   

General and administrative

     29,453        24,589        24,819   
  

 

 

   

 

 

   

 

 

 

Total cost and expenses

     260,173        217,869        184,563   
  

 

 

   

 

 

   

 

 

 

Operating loss

     (9,282     (25,330     (15,641

Interest expense

     (1,488     (1,005     (794

Gain (loss) on disposal of assets

     3,774        1,351        (112

Other income

     58        2        121   
  

 

 

   

 

 

   

 

 

 

Loss before income taxes

     (6,938     (24,982     (16,426

Income tax benefit

     (1,587     (8,914     (4,393
  

 

 

   

 

 

   

 

 

 

Net loss

   $ (5,351   $ (16,068   $ (12,033
  

 

 

   

 

 

   

 

 

 

Loss per common share:

      

Basic

   $ (0.23   $ (0.69   $ (0.55
  

 

 

   

 

 

   

 

 

 

Diluted

   $ (0.23   $ (0.69   $ (0.55
  

 

 

   

 

 

   

 

 

 

Weighted-average common shares outstanding:

      

Basic

     23,172,709        23,167,131        21,796,868   
  

 

 

   

 

 

   

 

 

 

Diluted

     23,172,709        23,167,131        21,796,868   
  

 

 

   

 

 

   

 

 

 

See accompanying notes to financial statements.

 

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Union Drilling, Inc.

Statements of Stockholders' Equity

(in thousands, except share data)

 

     Common Stock      Additional
Paid-In

Capital
     Retained
Earnings
    Treasury
Stock
    Total  
     Shares     $                            

Balance at January 1, 2009

     20,309,563      $ 220       $ 144,113       $ 69,280      $ (8,900     204,713   

Share-based compensation

     —          —           1,774         —          —          1,774   

Exercise of stock options

     98,722        1         247         —          —          248   

Purchase of treasury stock

     (285,182     —           —           —          (1,563     (1,563

Issuance of common shares,net of $1,566 issue costs

     3,000,000        30         23,154             23,184   

Net loss

     —          —           —           (12,033     —          (12,033
  

 

 

   

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Balance at December 31, 2009

     23,123,103        251         169,288         57,247        (10,463     216,323   

Share-based compensation

     —          —           1,275         —          —          1,275   

Exercise of stock options

     59,242        1         225         —          —          226   

Net loss

     —          —           —           (16,068     —          (16,068
  

 

 

   

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Balance at December 31, 2010

     23,182,345        252         170,788         41,179        (10,463     201,756   

Share-based compensation

     —          —           1,620         —          —          1,620   

Exercise of stock options

     9,000        —           57         —          —          57   

Vested Restricted Stock Units

     37,471        —           —           —          —          —     

Purchase of treasury stock

     (80,700     —           —           —          (427     (427

Net loss

     —          —           —           (5,351     —          (5,351
  

 

 

   

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Balance at December 31, 2011

     23,148,116      $ 252       $ 172,465       $ 35,828      $ (10,890   $ 197,655   
  

 

 

   

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

See accompanying notes to financial statements.

 

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Union Drilling, Inc.

Statements of Cash Flows

(in thousands)

 

     Year Ended December 31,  
     2011     2010     2009  

Operating activities:

      

Net loss

   $ (5,351   $ (16,068   $ (12,033

Adjustments to reconcile net loss to net cash provided by operating activities:

      

Depreciation and amortization

     50,846        49,932        47,719   

Impairment charge

     808        —          4,069   

Amortization of stock-based compensation expense

     1,620        1,275        1,774   

Provision for doubtful accounts

     1,475        97        1,072   

(Gain) loss on disposal of assets

     (3,774     (1,351     112   

Provision for deferred taxes

     (1,172     (9,085     3,680   

Changes in operating assets and liabilities:

      

Accounts receivable

     (15,982     (7,815     20,612   

Inventories

     420        692        495   

Income tax recoverable, prepaid expenses, deposits and other receivables

     (2,064     8,337        734   

Accounts payable

     6,145        3,090        (4,690

Accrued expenses and other liabilities

     981        5,774        (5,048
  

 

 

   

 

 

   

 

 

 

Cash flow provided by operating activities

     33,952        34,878        58,496   

Investing activities:

      

Purchases of machinery and equipment

     (83,542     (58,503     (44,516

Proceeds from sale of machinery and equipment

     12,379        2,883        598   
  

 

 

   

 

 

   

 

 

 

Cash flow used in investing activities

     (71,163     (55,620     (43,918

Financing activities:

      

Borrowings on line of credit

     287,846        218,661        189,178   

Repayments on line of credit

     (250,087     (197,603     (222,827

Cash overdrafts

     (341     —          276   

Borrowings - other debt

     1,396        992        1,149   

Repayments - other debt

     (1,230     (1,536     (4,623

Proceeds from stock offering, net of issue costs

     —          —          23,184   

Purchases of treasury stock

     (427     —          (1,563

Exercise of stock options

     57        226        248   
  

 

 

   

 

 

   

 

 

 

Cash flow provided by (used in) financing activities

     37,214        20,740        (14,978
  

 

 

   

 

 

   

 

 

 

Net increase (decrease) in cash

     3        (2     (400

Cash and cash equivalents at beginning of period

     4        6        406   
  

 

 

   

 

 

   

 

 

 

Cash and cash equivalents at end of period

   $ 7      $ 4      $ 6   
  

 

 

   

 

 

   

 

 

 

See accompanying notes to financial statements.

 

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UNION DRILLING, INC.

NOTES TO FINANCIAL STATEMENTS

1. Organization and Description of Business

Union Drilling, Inc. (“Union Drilling”, “Company” or “we”), incorporated in Delaware in 1997, provides contract land drilling services and equipment, primarily to oil and natural gas producers in the United States. In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. We commenced operations with 12 drilling rigs and related equipment acquired from an entity providing contract drilling services under the name “Union Drilling.” Through a combination of acquisitions and new rig construction, we increased the size of our fleet to 71 marketed land drilling rigs. In 2011, in an effort to better align our rig fleet with the growing part of the market (deep horizontal shale drilling), we added three new large rigs, decommissioned two of our older, smaller rigs, sold a small, marketed rig in a private transaction and auctioned 31 of our older, smaller rigs that have had minimal utilization over the past several years. Of those 31 rigs, 20 were marketed rigs, while 11 had been previously decommissioned. Accordingly, our marketed rig fleet at December 31, 2011 contains 51 land drilling rigs, demonstrating our commitment to provide premium, modern rigs and experienced, knowledgeable crews to the major and large independent E&P companies. We presently focus our operations in selected U.S. shale formations, with high growth potential, low finding and development costs and adequate take away capacity. Our principal operations are in the Appalachian Basin, extending from New York to Tennessee including the Marcellus, Huron, and Utica shales; the Arkoma Basin in eastern Oklahoma and Arkansas, including the Fayetteville, Caney, and Woodford shales; the Fort Worth Basin in North Texas, including the Barnett Shale and in West Texas extending to southeastern New Mexico, the Permian and Delaware Basins.

We market our rigs to a number of customers, primarily the major and large independent E&P companies. Revenues from the top ten customers for the year ended December 31, 2011, represented 69% of total revenues with two customers’ revenue totaling 24% and 13%. Revenues from the top ten customers for the year ended December 31, 2010, represented approximately 68% of total revenues with two customers’ revenue totaling 27% and 14%. Revenues from the top ten customers for the year ended December 31, 2009, represented approximately 76% of total revenues with three customers’ revenue totaling 28%, 16%, and 11%.

2. Summary of Significant Accounting Policies

Basis of Presentation

The financial statements relate solely to the accounts of Union Drilling, Inc. The Company has no controlling financial interests in any entity which would require consolidation. To conform to the presentation of the December 31, 2011 financial statements and accompanying notes, certain balances have been reclassified on the December 31, 2010 financial statements.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results may differ from those estimates.

Accounts Receivable

We evaluate the creditworthiness of our customers based on their financial condition using information obtained from their bank, as well as their major vendors, and our past experiences, if any, with the customer. In some instances, we require new customers to make prepayments. We typically invoice our customers semi-monthly during the performance of the contracts and upon completion of the contract, with payment due within 30 days. We established an allowance for doubtful accounts of $1.4 million and $153,000 at December 31, 2011 and 2010, respectively. Any allowance established is subject to judgment and estimates made by management. We determine

 

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our allowance by considering a number of factors, including the length of time trade accounts receivable are past due, our previous loss history, our assessment of our customers’ current abilities to pay obligations to us and the condition of the general economy and the oil and natural gas industry as a whole. At December 31, 2011, approximately $4.0 million of invoices were under dispute; we believe that our current reserve adequately provides for such disputes, as well as any other potential write-offs related to outstanding amounts at December 31, 2011. We write off specific accounts receivable when we determine they are uncollectible. See Note 4 for additional information on the allowance for doubtful accounts.

Our contract drilling work in progress relates to the revenue recognized, but not yet billed, on contracts in progress at the balance sheet date.

Inventories

Inventories maintained by the Company are primarily engines and consumable replacement parts. Inventories are maintained on a first-in, first-out basis, and recorded at the lower of cost or net realizable value.

Prepaid Expenses, Deposits and Other Receivables

Prepaid expenses, deposits and other receivables include items such as insurance, taxes, utility deposits, fees and insurance claim receivables. We routinely expense our prepaid expenses in the normal course of business over the periods these expenses benefit. A detail of prepaid expenses, deposits and other receivables is as follows:

 

     December 31,  
     2011      2010  

Prepaid insurance

   $ 1,477       $ 1,404   

Deposits

     502         496   

Unamortized loan costs

     227         168   

Other

     821         44   
  

 

 

    

 

 

 
   $ 3,027       $ 2,112   
  

 

 

    

 

 

 

Goodwill and Intangible Assets

Our customer list is amortized over the estimated benefit period which was initially determined to be 20 years, but in 2009, was revised to 10 years based on actual historical customer turnover. Depreciation and amortization includes amortization of intangibles of $301,000, $302,000 and $206,000 for the years ended December 31, 2011, 2010 and 2009, respectively. The remaining life at December 31, 2011 is 3.3 years.

The total cost and accumulated amortization of intangible assets are as follows (in thousands):

 

     December 31,  
     2011     2010  

Customer list

   $ 2,200      $ 2,200   

Accumulated amortization

     (1,221     (920
  

 

 

   

 

 

 

Intangible assets, net

   $ 979      $ 1,280   
  

 

 

   

 

 

 

 

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Property, Buildings and Equipment

Property, buildings and equipment is stated at cost, net of accumulated depreciation. The Company capitalizes costs of replacements or renewals that improve or extend the lives of existing property, buildings and equipment. Maintenance and repairs are expensed as incurred. Depreciation is calculated on the straight-line method over the estimated remaining useful lives of the assets. Depreciation on acquired or constructed rigs and other components commences when the assets are ready for use. Once placed in service, depreciation continues when assets are being repaired, refurbished or between periods of deployment. As a result, our depreciation charges will not vary with changes in utilization levels, unlike our revenue. Our estimates of the useful lives of our drilling, transportation and other equipment are based on our experience in the drilling industry with similar equipment. For the years ended December 31, 2011, 2010 and 2009, depreciation expense was $50.5 million, $49.6 million and $47.5 million, respectively.

The estimated lives of the assets are as follows:

 

Buildings

     30 - 40 years   

Drilling rigs and related equipment

     2 - 12 years   

Vehicles

     5 - 7 years   

Impairment of Long-Lived Assets

We assess the impairment of long-lived assets whenever events or circumstances indicate that the asset’s carrying value may not be recoverable. For purposes of performing our impairment analysis, we group long-lived assets at the lowest level for which there are identifiable cash flows. Factors that could trigger an impairment review would be any significant negative trends in the industry or the general economy, our contract revenue rates, our rig utilization rates, cash flows generated from operating our drilling rigs, existence of term drilling contracts, current and future oil and natural gas prices, our customers’ access to capital and the trends in the price of used drilling equipment observed by our management. If a review of our long-lived assets indicates that our carrying value exceeds the estimated undiscounted future cash flows, an impairment charge is made to adjust the carrying value to the estimated fair value. Cash flows are estimated by management considering factors such as expectations of future industry trends and the impact on dayrates, utilization and operating expenses; historical performance of the asset; the remaining expected life of the asset; any cash investment required to make the asset more marketable; suitability, specification and size of the rig; terminal value; as well as overall competitive dynamics. Use of different assumptions could result in an impairment charge different from that reported.

For the year ended December 31, 2011, we recorded $808,000 of impairment related to the auction of certain of our older, smaller rigs. For the year ended December 31, 2010, no impairment charges were required. For the year ended December 31, 2009, $4.1 million of impairment charges were recognized as a result of the global economic crisis that began in 2008.

Accrued Workers’ Compensation

The Company accrues for costs under our workers’ compensation insurance program in accrued expenses and other liabilities. We have a deductible of $100,000 per covered accident under our workers’ compensation insurance. Our insurance policies require us to maintain letters of credit to cover our deductible payments. As of December 31, 2011 and 2010, we satisfied this requirement with letters of credit totaling $4.2 million and $4.3 million, respectively. We accrue for these costs as claims are incurred considering cost estimates established for each claim by the insurance companies providing the administrative services for processing the claims, including an estimate for incurred but not reported claims, claims paid directly by us, administrative costs associated with these claims and our historical experience with these types of claims. In addition, as needed, we accrue the estimated workers’ compensation premium payable to Ohio, a monopolistic state, when our rigs work in that state.

 

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Stock-Based Compensation

Compensation cost resulting from share-based payment awards are measured at fair value and recognized in general and administrative expense on a straight line basis over the requisite service period. The amount of compensation cost recognized at any date is at least equal to the portion of the grant-date fair value of the award that is vested at that date. For the years ended December 31, 2011, 2010 and 2009, the Company recorded stock-based compensation expense of $1.6 million ($1.1 million net of tax), $1.3 million ($0.8 million net of tax) and $1.8 million ($1.1 million net of tax), respectively. Total unamortized stock-based compensation was approximately $3.4 million at December 31, 2011, and will be recognized over a weighted average service period of 3.7 years.

Estimating the fair value of stock options granted requires us to utilize valuation models and to establish several underlying assumptions. The fair value of stock option grants was estimated using the Black-Scholes valuation model based on the following weighted average assumptions (no stock options were issued in 2011):

 

     2010   2009

Risk-free interest rate

   1.4% - 1.6%   2.1% - 2.6%

Expected life

   5 years   5 years

Dividend yield

   0%   0%

Expected volatility

   77% - 78%   74% - 75%

The risk-free interest rate is the implied yield available for zero-coupon U.S. government issues with a remaining term equal to the expected life of the stock options.

The expected lives of the stock options are determined based on the Company’s expectations of individual stock option holders’ anticipated behavior and the term of the stock option.

The Company has not paid out dividends historically; thus, the dividend yield is estimated at zero percent.

Volatility is based upon price performance of the Company and prior to November 2010 included a peer company, as the Company did not have a sufficient historical price base to determine potential volatility over the term of the issued stock options.

The fair value of restricted stock or restricted stock units is the closing market price of the Company’s stock on the award grant date. During the period ended December 31, 2011, 2010, and 2009 172,912, 50,000, and 38,545 restricted stock units were granted, respectively.

Revenue Recognition

We generate revenue principally by drilling wells for oil and natural gas producers primarily under daywork contracts, and to a lesser extent footage contracts, which provide for the drilling of single or multiple well projects. Revenues on daywork contracts are recognized based on the days worked at the dayrate each contract specifies. Mobilization fees are recognized as the related drilling services are provided. We recognize revenues on footage contracts based on the footage drilled for the applicable accounting period. Expenses are recognized based on the costs incurred during that same accounting period. Reimbursements received for out-of-pocket expenses are recorded as revenues.

Concentration of Credit Risk

A majority of the Company’s operations relate to drilling services performed for major and large independent E&P companies in the United States. The Company utilizes a fleet of land drilling rigs to provide these contract drilling services. These operations are aggregated into one reportable segment based on the similarity of economic characteristics among all markets and the similarity of the nature of the services provided and the type of customers served.

 

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Income Taxes

We record deferred taxes for the basis difference in our property and equipment between financial reporting and tax reporting purposes and other costs such as compensation, employee benefits and other accrued liabilities which are deductible in different periods for financial reporting and tax reporting purposes. For property and equipment, basis differences arise from differences in depreciation periods and methods and the value of assets acquired in a business acquisition where we acquire the stock of an entity rather than its assets. For financial reporting purposes, we depreciate the various components of our drilling rigs and refurbishments over two to 12 years, while federal income tax rules require that we depreciate drilling rigs and refurbishments over five years. In 2009 tax depreciation also included bonus depreciation allowed as a result of the American Recovery and Reinvestment Act of 2009. In 2011 and 2010, bonus depreciation did not create any current tax benefit and is not included in our tax depreciation calculations. In the earlier years of our ownership of a drilling rig, our tax depreciation may often exceed our financial reporting depreciation, resulting in our recording deferred tax liabilities on this depreciation difference. In later years, financial reporting depreciation exceeds tax depreciation, and the deferred tax liability begins to reverse.

Earnings Per Share

Basic earnings per common share is computed by dividing net (loss) income by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is computed by dividing net (loss) income by the weighted average number of common shares outstanding during the period and the effect of all dilutive common stock equivalents, such as stock options and restricted stock units. The treasury stock method is used to compute the assumed incremental shares related to our outstanding stock options and restricted stock units. The average common stock market prices for the periods are used to determine the number of incremental shares.

In periods where there is a net loss, diluted earnings per common share is equal to basic earnings per common share since the effect of including any dilutive common stock equivalents would be antidilutive.

Other Comprehensive Income

For all years presented, other comprehensive income (loss) equals net income (loss).

Recent Accounting Pronouncements

In October 2009, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2009-13, amending Subtopic 605-25 Revenue Recognition – Multiple-Element Arrangements, which establishes the accounting and reporting guidance for arrangements under which a vendor will perform multiple revenue-generating activities. This ASU amends the criteria for separating consideration in multiple-deliverable arrangements and expands the related disclosures. This ASU is effective prospectively for revenue arrangements entered into or materially modified in fiscal years beginning on or after June 15, 2010, with early adoption permitted. The adoption of ASU No. 2009-13 on January 1, 2011 did not have a material effect on the financial condition or results of operations of the Company.

In January 2010, the FASB issued ASU No. 2010-06, amending Topic 820 Fair Value Measurements and Disclosures. This ASU updates Subtopic 820-10 and requires the following new disclosures: 1) disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers; and 2) present separately in the reconciliation for fair value measurements using significant unobservable inputs (Level 3), information about purchases, sales, issuances and settlements (on a gross basis rather than one net number). In addition, this ASU clarifies existing disclosures as follows: 1) provide fair value measurement disclosures for each class of assets and liabilities (often a subset within a line item in the statement of financial position); and 2) provide disclosures about the valuation techniques and inputs used to measure both recurring and nonrecurring Level 2 or Level 3 fair value measurements. These new disclosures and clarifications of

 

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existing disclosures are effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances and settlements in the Level 3 reconciliation of fair value measurements, which are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. The adoption of ASU No. 2010-06 did not have a material impact on our financial condition or results of operations.

3. Fair Value Measurement

The Fair Value Measurements and Disclosures Topic of the FASB Codification utilizes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three broad levels. The following is a brief description of those three levels:

 

Level 1:    Observable inputs such as quoted prices for identical assets or liabilities in active markets;
Level 2:    Other inputs that are observable directly or indirectly, such as quoted prices for similar assets or liabilities or market-corroborated inputs;
Level 3:    Unobservable inputs for which there is little or no market data and which require us to develop our own assumptions about how market participants would price the assets or liabilities.

We use the following methods and assumptions in estimating our fair value disclosures for financial instruments. The carrying amount of cash and cash equivalents approximates fair value due to the short-term maturity of these instruments. For accounts and other receivables, accounts payable, financed insurance premiums and accrued liabilities, we believe that recorded amounts approximate fair value due to the relatively short maturity period. Further, the pricing mechanisms in the Company’s debt agreements combined with the short-term nature of the equipment financing arrangements result in the carrying values of these obligations approximating their respective fair values.

We do not have any financial instruments for which estimates of fair value disclosures utilize Level 3 inputs.

During 2011, we recorded $808,000 of impairment charges related to certain long-lived assets with a carrying amount of $1.6 million and an estimated fair value of $811,000. No impairments were recorded in 2010. During 2009, we recorded $4.1 million of impairment charges related to certain long-lived assets with a carrying amount of $23.0 million and an estimated fair value of $18.9 million. Estimated fair value was determined using significant unobservable inputs (Level 3) based on both an income approach and a market approach. The income approach was calculated as the estimated discounted future net cash flows assumed to be received from the operation of the asset over its useful life and a terminal value, while market was based on external industry data for similar equipment.

The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of nonfinancial assets and liabilities and their placement within the fair value hierarchy levels.

 

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4. Accounts Receivable

Accounts receivable consist of the following (in thousands):

 

     December 31,  
     2011     2010  

Billed receivables

   $ 45,320      $ 29,882   

Unbilled receivables

     1,743        1,361   

Reserve for sales credits

     (267     (210
  

 

 

   

 

 

 

Total receivables

     46,796        31,033   

Allowance for doubtful accounts

     (1,409     (153
  

 

 

   

 

 

 

Net receivables

   $ 45,387      $ 30,880   
  

 

 

   

 

 

 

Unbilled receivables represent recorded revenue for contract drilling services performed that is billable by the Company at future dates based on contractual payment terms, and is anticipated to be billed and collected in the quarter following the balance sheet date.

Activity in the allowance for doubtful accounts was as follows (in thousands):

 

Balance, January 1, 2009

   $ 1,495   

Net charge to expense

     1,072   

Amounts written off

     (1,188
  

 

 

 

Balance, December 31, 2009

     1,379   

Net charge to expense

     97   

Amounts written off

     (1,323
  

 

 

 

Balance, December 31, 2010

     153   

Net charge to expense

     1,475   

Amounts written off

     (219
  

 

 

 

Balance, December 31, 2011

   $ 1,409   
  

 

 

 

 

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5. Property, Buildings and Equipment

Major classes of property, buildings and equipment are as follows (in thousands):

 

     December 31,  
     2011     2010  

Land

   $ 1,935      $ 988   

Buildings

     2,921        1,641   

Drilling and well service equipment

     448,715        475,994   

Vehicles

     12,484        12,419   

Furniture and fixtures

     190        168   

Information systems

     3,786        688   

Leasehold improvements

     126        126   

Construction in progress

     31,445        10,548   
  

 

 

   

 

 

 
     501,602        502,572   

Accumulated depreciation

     (212,173     (239,362
  

 

 

   

 

 

 
   $ 289,429      $ 263,210   
  

 

 

   

 

 

 

During 2011, 2010 and 2009, we capitalized $664,000, $481,000 and $636,000, respectively, of interest costs incurred during the construction periods of certain drilling equipment.

At December 31, 2011, and 2010, we had $6.0 million and $2.6 million, respectively, of capital expenditures accrued but not yet paid.

During 2011, the Company purchased three new rigs and made progress payments for the initial construction costs of three new builds, which are expected to be completed in the first half of 2012. These increases to Drilling and well service equipment were partially offset as we auctioned 31 of our older, smaller rigs and sold an older, smaller rig in a private transaction. The Company also purchased office buildings, rig yards and surrounding land in West Texas and Arkansas.

During the year ended December 31, 2011, we recorded $2.7 million of gain as a result of the auction discussed in Notes 1 and 2. This gain has been classified as “Gain (loss) on disposal of assets” in the accompanying financial statements. Proceeds were $10.0 million (net of $1.4 million in commission and other direct expenses) while the carrying value of the underlying assets were $7.3 million.

In 2010, we began a process of implementing a new information system that was put into production in January 2011. Capitalized costs associated with this project were $2.9 million and were classified as construction in progress at December 31, 2010. During 2011, the Company amortized $595,000 related to this information system.

 

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6. Income Taxes

The current and deferred components of income tax (benefit) expense are as follows (in thousands):

 

     Year Ended December 31,  
     2011     2010     2009  

Current tax (benefit) expense:

      

Federal

   $ (527   $ 202      $ (8,060

State

     112        (31     (13
  

 

 

   

 

 

   

 

 

 
     (415     171        (8,073

Deferred tax (benefit) expense:

      

Federal

     (1,132     (8,120     4,033   

State

     (40     (965     (353
  

 

 

   

 

 

   

 

 

 
     (1,172     (9,085     3,680   
  

 

 

   

 

 

   

 

 

 

Income tax benefit

   $ (1,587   $ (8,914   $ (4,393
  

 

 

   

 

 

   

 

 

 

Total income tax benefit differed from the amounts computed by applying the U.S. statutory federal income tax rate to loss before income taxes as a result of the following (in thousands) at December 31:

 

     2011     2010     2009  

U.S. statutory federal income tax rate

     35     35     35
  

 

 

   

 

 

   

 

 

 

Income tax benefit at the statutory federal tax rate

   $ (2,428   $ (8,743   $ (5,749

State and local income taxes, net of federal tax benefits

     (118     (859     (613

Meal allowances

     1,157        956        851   

Non-cash compensation

     44        57        39   

Domestic production deduction

     —          (97     745   

Decrease in unrecognized tax benefits

     —          (2     (45

Deferred tax rate adjustment

     (277     (218     60   

Valuation allowance

     320        9        61   

Prior year meal allowance adjustment

     (366     —          —     

Other

     81        (17     258   
  

 

 

   

 

 

   

 

 

 

Income tax benefit

   $ (1,587   $ (8,914   $ (4,393
  

 

 

   

 

 

   

 

 

 

During 2011, 2010, and 2009, the Company received tax refunds, net of payments made, of approximately $166,000, $7.7 million, and $6.4 million, respectively.

 

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The components of the net deferred income tax assets and liabilities are as follows (in thousands):

 

     December 31,  
     2011     2010  

Current deferred tax assets:

    

Bad debt expense

   $ 542      $ 59   

Workers compensation and other insurance reserves

     1,055        1,305   

Sales returns

     103        81   

Other

     126        203   
  

 

 

   

 

 

 
     1,826        1,648   

Long-term deferred tax assets:

    

Stock compensation

     2,441        1,965   

Tax credit carry forwards

     3,625        3,349   

Net operating loss carry forwards

     11,168        10,418   

Other

     19        101   
  

 

 

   

 

 

 
     17,253        15,833   
  

 

 

   

 

 

 

Total deferred tax assets

     19,079        17,481   

Less valuation allowance

     (391     (70
  

 

 

   

 

 

 

Net deferred tax asset

     18,688        17,411   

Current deferred tax liabilities:

    

Prepaid expenses

     587        462   

Long-term deferred tax liabilities:

    

Intangible assets

     374        495   

Other

     55        —     

Property, building and equipment, principally due to differences in depreciation

     59,405        59,357   
  

 

 

   

 

 

 
     59,834        59,852   
  

 

 

   

 

 

 

Total deferred tax liabilities

     60,421        60,314   
  

 

 

   

 

 

 

Net deferred tax liability

   $ 41,733      $ 42,903   
  

 

 

   

 

 

 

Deferred tax assets and liabilities are presented net in the balance sheet according to their current or long-term classification.

The Company had federal net operating loss carryforwards of approximately $25.1 million and $23.3 million at December 31, 2011 and 2010, respectively. These losses may be carried forward for 20 years and will begin to expire in 2023. State net operating losses at December 31, 2011 and 2010, were $44.9 million and $43.6 million, respectively. State losses vary as to carryforward period and will begin to expire in 2014, depending upon the jurisdiction where applied. In 2011 and 2010, a valuation allowance of $391,000 and $70,000, respectively, was established for state net operating loss carryforwards in states where utilization is uncertain due to lack of forecasted future operations or the remaining carryforward period is limited. Based upon 2011 results and forecasted future operations, we believe it is more likely than not that the remaining amounts will be realized.

At December 31, 2011 we had no unrecognized tax benefits. At December 31, 2010, we had approximately $239,000 of unrecognized tax benefits, of which approximately $155,000 would affect our effective tax rate if recognized. Such amounts were carried as other long-term liabilities.

 

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A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (in thousands) at December 31:

 

     2011     2010  

Balance at beginning of year

   $ 239      $ 208   

Reductions for tax positions of prior years

     —          (17

Additions for tax positions taken during current period

     —          41   

Additions for tax positions of prior years

     —          7   

Settlements with taxing authorities

     (239     —     
  

 

 

   

 

 

 

Balance at end of year

   $ —        $ 239   
  

 

 

   

 

 

 

Interest and penalties related to uncertain tax positions are classified as interest expense and general and administrative costs, respectively. During 2011, the Company did not recognize interest expense related to unrecognized tax benefits. During 2010 and 2009, the Company recognized $9,000 and $96,000, in interest expense related to unrecognized tax benefits, respectively. No accrual was necessary in relation to uncertain tax positions at December 31, 2011, and $17,000 of interest expense was accrued in relation to uncertain tax positions at December 31, 2010.

The Company reclassified its uncertain tax positions during 2011, from “Other long term liabilities” to “Accrued expenses and other liabilities”. The adjustment was the result of settlement negotiations with the State of Texas regarding certain disputed deductions related to the state franchise tax calculation. The Company paid the amount that had been previously accrued, in the fourth quarter of 2011. An adjustment to reverse previously accrued interest, which was waived, was also recorded.

The Company files U.S. federal income tax returns and income tax returns in various state jurisdictions. The tax years 2006 through 2011 remain open to examination by the major taxing jurisdictions to which we are subject. In addition, tax years 1999, 2000, 2002 and 2003 remain open due to utilized losses in some jurisdictions.

7. Accrued Expenses and Other Liabilities

A detail of accrued expenses and other liabilities is as follows (in thousands):

 

     December 31,  
     2011      2010  

Payroll

   $ 3,900       $ 3,269   

Workers compensation

     2,373         3,078   

Medical claims

     1,099         1,639   

Deferred revenue

     1,925         979   

Other taxes

     483         495   

Other

     1,031         1,215   
  

 

 

    

 

 

 
   $ 10,811       $ 10,675   
  

 

 

    

 

 

 

Other taxes include sales, franchise and property taxes.

8. Debt Obligations

On April 27, 2011, the Company entered into an Amended and Restated Revolving Credit and Security Agreement with PNC Bank, for itself and as agent for a group of lenders (Credit Facility). This Credit Facility replaced an existing facility that had a $97.5 million borrowing base and which matured on March 30, 2012 (Prior Facility). The Credit Facility, which matures April 27, 2016, provides for a borrowing base equal to $125 million, with a permitted

 

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increase of up to an additional $25 million for a maximum borrowing base of $150 million. On August 1, 2011, the accordion feature of the Credit Facility was exercised to add a new lender which increased the maximum capacity to $150 million. On September 29, 2011, we executed a First Amendment to the Credit Facility which permitted the auction of certain of our older, smaller rigs.

Amounts outstanding under the Credit Facility bear interest, depending upon facility usage, at either (i) the higher of the Federal Funds Open Rate plus 50 to 100 basis points or PNC Bank’s base commercial lending rate (4.0% at December 31, 2011) or (ii) LIBOR plus 225 to 275 basis points (2.8% at December 31, 2011). Interest on outstanding loans is due monthly for domestic rate loans and at the end of the relevant interest period for LIBOR loans. Depending upon our facility usage, we are assessed an unused line fee of 25 to 50 basis points on the available borrowing capacity. The available borrowing capacity was $78.0 million at December 31, 2011. There is a $10.0 million sublimit for letters of credit issued under the Credit Facility. We will incur a prepayment penalty if the Credit Facility is terminated prior to April 2014. As of December 31, 2011, we had a loan balance of $67.8 million under the Credit Facility, and an additional $4.2 million of the total capacity was utilized to support our letter of credit requirements.

In general, the Credit Facility is secured by substantially all of our assets. The forced liquidation value of our assets serving as collateral is determined at least annually by an independent appraisal, with adjustments for acquisitions and dispositions between appraisals. The Credit Facility contains affirmative and negative covenants and also provides for events of default typical for such an agreement. Among the affirmative covenants are requirements to maintain a specified tangible net worth. As of December 31, 2011, our actual tangible net worth was $196.7 million compared to the required minimum tangible net worth of $158.4 million. Among the negative covenants are restrictions on major corporate transactions, incurrence of indebtedness and amendments to our organizational documents. Events of default would include a change in control and any change in our operations or condition which has a material adverse effect. As of December 31, 2011, we were in compliance with all of our covenants.

The Prior Facility’s outstanding amounts bore interest, depending upon facility usage, at either (i) the higher of the Federal Funds Open Rate plus 75 to 125 basis points or PNC Bank’s base commercial lending or (ii) LIBOR plus 250 to 300 basis points. At December 31, 2010, we had a loan balance of $30.0 million of which $4.3 million of the total capacity had been utilized to support our letter of credit requirement; further, the available borrowing capacity was $63.2 million at December 31, 2010. The Prior Facility was also secured, in general, by substantially all of our assets and contained normal and customary representations and warranties similar to the Credit Facility, although the Prior Facility required a minimum fixed charge coverage ratio in addition to the tangible net worth. As of December 31, 2010, our actual tangible net worth was $200.5 million compared to the required minimum tangible net worth of $66.8 million, and our actual fixed charge coverage ratio of 13.2 exceeded the required 1.1 fixed charge coverage ratio. Among the negative covenants were restrictions on major corporate transactions, incurrence of indebtedness and amendments to our organizational documents. At December 31, 2010, we were in compliance with all of our covenants.

Our credit facilities primarily have been used to pay for rig acquisitions and for working capital requirements. The Credit Facility may also be used by the Company, subject to certain conditions, to repurchase its common stock and/or pay a cash dividend.

In addition, the Company has entered into various equipment-specific financing agreements with various third-party financing institutions. The terms of these agreements range from 24 to 48 months. As of December 31, 2011 and December 31, 2010, the total outstanding balance under these arrangements was approximately $190,000 and $173,000, respectively, and is classified, according to payment date, in current portion of notes payable for equipment and long-term notes payable for equipment in the accompanying balance sheets. At December 31, 2011, the stated interest rate on these borrowings are zero percent.

The Company paid approximately $2.0 million in interest for December 31, 2011, and $1.5 million for each of the years ended December 31, 2010 and 2009.

 

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9. Stockholders’ Equity

At December 31, 2011, the number of authorized shares of common stock was 75,000,000 shares, of which 23,148,116 shares were outstanding, and 1,641,744 shares were reserved for future issuance through the Company’s equity based plans. The number of authorized shares of preferred stock was 100,000 shares at December 31, 2011. No shares of preferred stock were outstanding or reserved for future issuance.

In September 2011, the Company’s Board of Directors approved the 2011 Union Drilling, Inc. Share Repurchase Program under which up to three million shares of the Company’s outstanding common stock may be repurchased. For the year ended December 31, 2011, 80,700 shares were purchased at an average price, including commission, of $5.29.

In June 2009, the Company completed a public offering consisting of three million shares of newly issued common stock at a price of $8.25 per share. Proceeds to the Company, net of underwriting discounts and other fees and expenses, were $23.2 million and were used to repay indebtedness outstanding under the Company’s revolving credit facility.

10. Management Compensation

Equity Based Compensation Plans

The Company has two equity based compensation plans, the Amended and Restated 2005 Stock Incentive Plan and the Amended and Restated 2000 Stock Option Plan. Under each plan, 1,579,552 shares of the Company’s common stock have been authorized for awards of stock options. Under both plans, incentive and non-qualified stock options may be awarded to directors and employees. Restricted stock units may be granted under the Amended and Restated 2005 Stock Incentive Plan. As of December 31, 2011, 1,195,734 stock options and 526,231 restricted stock units have been granted under the Amended and Restated 2005 Stock Incentive Plan and 1,548,124 stock options have been granted under the Amended and Restated 2000 Stock Option Plan (433,018 of such grants have since expired or forfeited). Stock options are granted with an exercise price equal to the fair market value of our stock on the grant date, which is determined by the closing trading price of our common stock on the NASDAQ Global Select Market. Prior to the Company’s initial public offering in November 2005, the exercise price of stock options were based on the Board of Directors’ assessment of the fair market value of the stock at the time the stock options were granted.

Stock options. Stock options typically vest over a three or four year period and, unless earlier exercised or forfeited, expire on the tenth anniversary of the grant date. A summary of stock option activity was as follows:

 

     2011      2010      2009  
     Shares     Weighted
Average
Exercise
Price
     Shares     Weighted
Average
Exercise
Price
     Shares     Weighted
Average
Exercise
Price
 

Outstanding at beginning of year

     929,091      $ 9.66         894,333      $ 9.64         879,890      $ 10.40   

Granted

     —          —           100,000        6.19         243,088        6.69   

Exercised

     (9,000     6.32         (59,242     3.80         (98,722     2.51   

Forfeited/expired

     (25,000     5.68         (6,000     6.32         (129,923     14.68   
  

 

 

   

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

Outstanding at end of year

     895,091      $ 9.80         929,091      $ 9.66         894,333      $ 9.64   
  

 

 

   

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

Options exercisable at end of year

     726,235      $ 10.57         590,194      $ 11.05         506,493      $ 10.72   
  

 

 

   

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

Weighted average fair value of options granted during the year

     $ —           $ 3.89         $ 4.16   
    

 

 

      

 

 

      

 

 

 

New shares of common stock are issued to satisfy stock options exercised. Cash received from the exercise of stock options for the years ended December 31, 2011, 2010 and 2009, was $57,000, $226,000 and $248,000, respectively. The total intrinsic value of stock options exercised during 2011, 2010 and 2009 was $29,000, $168,000 and $37,000, respectively.

 

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A summary of stock options outstanding as of December 31, 2011, was as follows:

 

     Options Outstanding      Options Exercisable  

Range of Exercise Prices

   Number
Outstanding
     Weighted
Average
Years of
Remaining
Contractual
Life
     Weighted
Average
Exercise
Price
     Number
Outstanding
     Weighted
Average
Exercise
Price
 

$3.80 to $9.89

     437,436         7.1       $ 5.94         268,580       $ 5.57   

$12.75 to $14.62

     457,655         4.8       $ 13.50         457,655       $ 13.50   
  

 

 

          

 

 

    
     895,091               726,235      
  

 

 

          

 

 

    

The aggregate intrinsic value of stock options outstanding and stock options exercisable as of December 31, 2011, was $251,000 and $239,000, respectively. The weighted average remaining contractual life of stock options exercisable as of December 31, 2011 was 5.4 years.

The total fair value of stock options vested during the years ended December 31, 2011, 2010 and 2009, was $492,000, $662,000 and $1.1 million, respectively.

The following table summarizes additional information as of December 31, 2011, for fully vested stock options and stock options expected to vest:

 

Number of shares outstanding

     848,790   

Weighted average exercise price

   $ 9.98   

Aggregate intrinsic value (in thousands)

   $ 247   

Weighted average remaining contractual term

     5.8   

Restricted stock awards. During 2011, 172,912 restricted stock units were awarded at a weighted average grant date fair value of $8.03 per unit and vesting period from three to four years. During 2010, 50,000 restricted stock units were awarded at a weighted average grant date fair value of $7.41 per unit and vesting periods ranging from four to six years. During 2009, 38,545 restricted stock units were awarded at a weighted average grant date fair value of $6.32 per unit and vesting periods ranging from three to four years.

Of the outstanding restricted stock unit awards, 200,000 restricted stock units are subject to both performance and service criteria, of which the performance criteria for 50,000 restricted stock units vested as of December 31, 2011.

A summary of restricted stock unit activity for the years ended December 31 follows:

 

     2011     2010  

Nonvested at beginning of year

     349,036        299,036   

Granted

     172,912        50,000   

Vested

     (37,471     —     
  

 

 

   

 

 

 

Nonvested at end of year

     484,477        349,036   
  

 

 

   

 

 

 

 

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Employee Benefit Plan

The Company has a defined contribution employee benefit plan covering substantially all of its employees. Company contributions to the plan are discretionary. The Company made contributions of approximately $379,000, $305,000 and $275,000 during the years ended December 31, 2011, 2010 and 2009, respectively.

11. (Loss) Earnings Per Common Share

Because we incurred a net loss for the years ended December 31, 2011, 2010 and 2009, basic and diluted loss per share were calculated as our net loss divided by the weighted average shares outstanding. Excluded from the computation of diluted loss per share for the year ended December 31, 2011, 2010 and 2009 were 768,000, 300,080 and 579,732 respectively, weighted average stock options and restricted stock units because the effect of including them would have been antidilutive.

12. Commitments and Contingencies

Operating Leases

The Company leases certain buildings, automobiles, office equipment and phone services under noncancelable operating agreements. Lease expense was approximately $3.3 million, $2.7 million and $2.2 million for the years ended December 31, 2011, 2010 and 2009, respectively. As of December 31, 2011, future minimum lease payments under noncancelable operating leases consist of the following (in thousands):

 

2012

   $ 1,621   

2013

     1,240   

2014

     464   

2015

     7   

2016

     2   
  

 

 

 

Total

   $ 3,334   
  

 

 

 

Litigation and Other Contingencies

From time to time, we are a party to claims, litigation or other legal or administrative proceedings that we consider to arise in the ordinary course of our business. While no assurances can be given regarding the outcome of these or any other pending proceedings, or the ultimate effect such outcomes may have, we do not believe we are a party to any legal or administrative proceedings which, if determined adversely to us, individually or in the aggregate, would have a material effect on our financial position, results of operations or cash flows. Management believes that the Company maintains adequate levels of insurance necessary to cover its business risk.

 

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13. Quarterly Financial Data (Unaudited)

The following table sets forth unaudited financial results on a quarterly basis for each of the last two years (in thousands, except per share amounts):

 

     First
Quarter
    Second
Quarter
    Third
Quarter
    Fourth
Quarter
    Total  

2011

          

Revenues

   $ 55,995      $ 59,924      $ 66,744      $ 68,228      $ 250,891   

Operating income (loss)

     (6,441     (4,045     122        1,082        (9,282

Net income (loss)

     (4,597     (3,433     617        2,062        (5,351

Net income (loss) per common share:

          

Basic

   $ (0.20   $ (0.15   $ 0.03      $ 0.09      $ (0.23

Diluted

   $ (0.20   $ (0.15   $ 0.03      $ 0.09      $ (0.23

2010

          

Revenues

   $ 38,660      $ 43,678      $ 52,028      $ 58,173      $ 192,539   

Operating loss

     (9,607     (8,260     (6,421     (1,042     (25,330

Net loss

     (5,968     (5,344     (4,443     (313     (16,068

Net loss per common share:

          

Basic

   $ (0.26   $ (0.23   $ (0.19   $ (0.01   $ (0.69

Diluted

   $ (0.26   $ (0.23   $ (0.19   $ (0.01   $ (0.69

 

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

None

 

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures.

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures (as defined in 13a-15(e) of the Securities Exchange Act of 1934, or the Exchange Act). Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures are effective.

Management’s Report on Internal Control over Financial Reporting.

Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). Our internal control over financial reporting is designed to provide reasonable assurance to management and the Board of Directors regarding the preparation and fair presentation of published financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2011. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework. Based on our assessment, we believe that, as of December 31, 2011, our internal control over financial reporting is effective based on those criteria.

Attestation Report of Independent Registered Public Accounting Firm.

The attestation report of our independent registered public accounting firm regarding internal control over financial reporting is set forth in Item 8 of this Annual Report on Form 10-K under the caption “Report of Independent Registered Public Accounting Firm” and is incorporated herein by reference.

Changes in Internal Control over Financial Reporting.

No change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the fiscal quarter ended December 31, 2011, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

Item 9B. Other Information

None.

PART III

In Items 10, 11, 12, 13 and 14 below, we are incorporating by reference the information we refer to in those Items from the definitive proxy statement for our 2012 Annual Meeting of Stockholders. We intend to file our definitive proxy statement with the SEC by April 30, 2012.

 

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Item 10. Directors, Executive Officers and Corporate Governance

We have a Code of Ethics that applies to our directors and all employees including our principal executive officer, principal financial officer, principal accounting officer and persons performing similar functions. Our Code of Ethics is posted in the “Investor Relations” section on our website at http://www.uniondrilling.com.

The other information required in response to this Item will be set forth in our definitive proxy statement for our 2012 Annual Meeting of Stockholders and is incorporated herein by reference.

 

Item 11. Executive Compensation

The information required in response to this Item will be set forth in our definitive proxy statement for our 2012 Annual Meeting of Stockholders and is incorporated herein by reference.

 

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

The information required in response to this Item will be set forth in our definitive proxy statement for our 2012 Annual Meeting of Stockholders and is incorporated herein by reference.

 

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

The information required in response to this Item will be set forth in our definitive proxy statement for our 2012 Annual Meeting of Stockholders and is incorporated herein by reference.

 

Item 14. Principal Accountant Fees and Services

The information required in response to this Item will be set forth in our definitive proxy statement for our 2012 Annual Meeting of Stockholders and is incorporated herein by reference.

PART IV

 

Item 15. Exhibits and Financial Statement Schedules

 

(a) The following documents are filed as a part of this report:

1. Financial Statements.

See Index to Financial Statements on page 28.

2. Financial Statement Schedules:

All financial statement schedules have been omitted because they are not applicable or the required information is presented in the financial statements or the notes to the financial statements.

 

(b) Exhibits. A list of exhibits required by Item 601 of Regulation S-K and to be filed as part of this report is set forth in the Index to Exhibits beginning on page 54, which immediately precedes such exhibits.

 

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SIGNATURES

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

 

    UNION DRILLING, INC.
  March 8, 2012     By:   /s/ Tina L. Castillo
        Tina L. Castillo
        Senior Vice President, Chief Financial Officer and Treasurer

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

 

Signature

  

Title

 

Date

/s/ Christopher D. Strong     
Christopher D. Strong    President, Chief Executive Officer and Director   March 8, 2012
/s/ Tina L. Castillo     
Tina L. Castillo    Senior Vice President, Chief Financial Officer and Treasurer   March 8, 2012
/s/ Thomas H. O’Neill, Jr.     

Thomas H. O’Neill Jr.

   Director   March 8, 2012
/s/ Howard I. Hoffen     

Howard I. Hoffen

   Director   March 8, 2012
/s/ Gregory D. Myers     

Gregory D. Myers

   Director   March 8, 2012
/s/ M. Joseph McHugh     

M. Joseph McHugh

   Director   March 8, 2012
/s/ T.J. Glauthier     

T.J. Glauthier

   Director   March 8, 2012
/s/ Ronald Harrell     

Ronald Harrell

   Director   March 8, 2012
/s/ Robert M. Wohleber     

Robert M. Wohleber

   Director   March 8, 2012

 

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Table of Contents

UNION DRILLING, INC.

INDEX TO EXHIBITS

 

Exhibit
Number

      

Description

  3.1

     Form of Amended and Restated Certificate of Incorporation of Union Drilling (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).

  3.2

     Form of Amended and Restated Bylaws of Union Drilling (incorporated by reference to Exhibit 3.1 to our Form 8-K filed on August 9, 2007).

  4.1

     Specimen Stock Certificate for the common stock, par value $0.01 per share, of Union Drilling (incorporated by reference to Exhibit 4.1 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).

10.1†

     First Amendment to Union Drilling’s Amended and Restated 2000 Stock Option Plan and Its Accompanying Form of Stock Option Agreement (incorporated by reference to Exhibit 10.1 to our Form 8-K filed on November 30, 2007).

10.2†

     Form of Stock Option Agreement under First Amendment to Union Drilling’s Amended and Restated 2000 Stock Option Plan (incorporated by reference to Exhibit 10.1 to our Form 8-K filed on November 30, 2007).

10.3†

     Stock Option Plan and Agreement, dated May 13, 1999, by and between Union Drilling and Christopher Strong (incorporated by reference to Exhibit 10.3 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).

10.4†

     First Amendment to Union Drilling’s 2005 Stock Option Plan and Its Accompanying Form of Stock Option Agreement (incorporated by reference to Exhibit 10.2 to our Form 8-K filed on November 30, 2007).

10.5†

     Form of Stock Option Agreement under Union Drilling’s Amended and Restated 2005 Stock Option Plan (incorporated by reference to Exhibit 10.2 to our Form 8-K filed on November 30, 2007).

10.5.1†

     Amended and Restated 2005 Stock Incentive Plan and the accompanying forms of award agreements (incorporated by reference to Exhibit 10.1 to our Form 8-K filed on June 11, 2008).

10.5.2†

     Restricted Stock Unit Agreement, dated June 10, 2008, between Union Drilling and Christopher D. Strong (incorporated by reference to Exhibit 10.2 to our Form 8-K filed on June 11, 2008).

10.6

     Form of Stockholders Agreement by and among Union Drilling and certain of its direct and indirect stockholders (incorporated by reference to Exhibit 10.6 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-127525) filed on October 18, 2005).

10.7

     Revolving Credit and Security Agreement, dated March 31, 2005, between Union Drilling the lenders signatory thereto and PNC Bank, as agent for the lenders, together with the First Amendment dated April 19, 2005 (incorporated by reference to Exhibit 10.7 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).

10.8

     Stock Purchase Agreement, dated as of March 31, 2005, by and between Union Drilling and Richard Thornton, the sole stockholder of Thornton Drilling Company (incorporated by reference to Exhibit 10.8 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).

10.9

     Registration Rights Agreement, dated as of March 31, 2005, between Union Drilling and Richard Thornton (incorporated by reference to Exhibit 10.9 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).

10.10†

     Employment Agreement, dated as of March 31, 2005, between Union Drilling and Richard Thornton (incorporated by reference to Exhibit 10.10 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).

10.11

     Stock Purchase Agreement, dated as of March 31, 2005, by and between Union Drilling, Steven A. Webster, Wolf Marine S.A. and William R. Ziegler (incorporated by reference to Exhibit 10.11 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).

 

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Table of Contents

10.12

     Option and Asset Purchase and Sale Agreement dated as of February 28, 2005 between Thornton Drilling Company and SPA Drilling, LP; Amendment No. 1 to Purchase and Sale Agreement between Thornton Drilling Company and SPA Drilling, LP; and Assignment and Assumption Agreement between Thornton Drilling Company and Union Drilling Texas, LP. (incorporated by reference to Exhibit 10.12 to Amendment No. 4 to our Registration Statement on Form S-1 (File No. 333-127525) filed on November 7, 2005).

10.13

     Asset Purchase Agreement, dated May 31, 2005, between C and L Services, LP and Union Drilling Texas, LP. (incorporated by reference to Exhibit 10.13 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).

10.14

     Forms of Indemnification Agreement with Union Drilling directors and certain of its officers (incorporated by reference to Exhibit 10.14 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-127525) filed on October 18, 2005).

10.15

     Second Amendment, dated August 15, 2005, to the Revolving Credit and Security Agreement between Union Drilling, the lenders signatory thereto and PNC Bank, as agent for the lenders (incorporated by reference to Exhibit 10.15 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-127525) filed on September 28, 2005).

10.16

     Asset Purchase Agreement, dated August 12, 2005, between C and L Services, LP and Union Drilling Texas, LP. (incorporated by reference to Exhibit 10.16 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-127525) filed on September 28, 2005).

10.17

     Third Amendment, dated October 5, 2005, to the Revolving Credit and Security Agreement between Union Drilling, the lenders signatory thereto and PNC Bank, as agent for the lenders (incorporated by reference to Exhibit 10.17 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-127525) filed on October 18, 2005).

10.18

     Option to purchase drilling rigs from National Oilwell Varco (incorporated by reference to Exhibit 10.18 to Amendment No. 4 to our Registration Statement on Form S-1 (File No. 333-127525) filed on November 7, 2005).

10.19

     Purchase and Sale Agreement, dated December 8, 2005, between Union Drilling and National-Oilwell, L.P., relating to the purchase of three drilling rigs (incorporated by reference to Exhibit 10.1 to our Form 8-K filed on December 13, 2005).

10.20

     Option Agreement, dated December 8, 2005, between Union Drilling and National-Oilwell, L.P., relating to the purchase of three drilling rigs (incorporated by reference to Exhibit 10.2 to our Form 8-K filed on December 13, 2005).

10.21

     Assets Purchase Agreement, dated December 19, 2005, between Permian Drilling Corporation and Maverick Oil and Gas, Inc., (incorporated by reference to Exhibit 10.1 to our Form 8-K filed on February 3, 2006).

10.22

     Agreement Regarding Assignment and Assumption of Rights and Obligations under Assets Purchase Agreement, dated January 30, 2006, between Maverick Oil and Gas, Inc. and Thornton Drilling Company; (incorporated by reference to Exhibit 10.1 to our Form 8-K filed on February 3, 2006).

10.23

     Addendum to Assets Purchase Agreement and Letter Agreement, dated January 30, 2006, between Permian Drilling Corporation, Maverick Oil and Gas, Inc. and Thornton Drilling Company, (incorporated by reference to Exhibit 10.1 to our Form 8-K filed on February 3, 2006).

10.24

     Purchase and Sale Agreement dated April 21, 2006 between Union Drilling and National-Oilwell, L.P., relating to the purchase price of three drilling rigs (incorporated by reference to Exhibit 10.2 to our Form 8-K filed on May 2, 2006).

10.25

     Fourth Amendment to Revolving Credit and Security Agreement, dated September 27, 2006, between Union Drilling, Inc., Thornton Drilling Company, Union Drilling Texas L.P., and PNC Bank, National Association, for itself and for other lenders (incorporated by reference to Exhibit 10.1 to our Form 8-K filed on September 28, 2006).

10.26

     Fifth Amendment to Revolving Credit and Security Agreement, dated December 5, 2006, between Union Drilling, Inc., Thornton Drilling Company, Union Drilling Texas L.P., and PNC Bank, National Association, for itself and for other lenders (incorporated by reference to Exhibit 10.1 to our Form 8-K/A filed on December 7, 2006).

 

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Table of Contents

10.27

     Purchase and Sale Agreement dated January 4, 2008 between Union Drilling and IDM Equipment, LLC (incorporated by reference to Exhibit 10.1 to our Form 8-K filed on January 8, 2008).

10.28

     Sixth Amendment to Revolving Credit and Security Agreement dated July 29, 2008 between Union Drilling and PNC Bank, National Association, for itself and for the other lenders (incorporated by reference to Exhibit 10.1 to our Form 8-K filed on July 31, 2008).

10.29

     Seventh Amendment to Revolving Credit and Security Agreement dated September 30, 2008 between Union Drilling and PNC Bank, National Association, for itself and for the other lenders (incorporated by reference to Exhibit 10.1 to our Form 8-K filed on October 6, 2008).

10.30

     Separation Agreement dated August 10, 2009 between Union Drilling, Inc. and A.J. Verdecchia (incorporated by reference to Exhibit 10.1 to our Form 8-K filed on August 11, 2009).

10.31†

     Form of Termination Protection Agreement between Union Drilling and certain designated senior executive officers (incorporated by reference to Exhibit 10.1 to our Form 8-K filed on March 31, 2011).

10.32†

     Form of Change of Control provision for inclusion of Union Drilling’s officer stock option award agreements (incorporated by reference to Exhibit 10.2 to our Form 8-K filed on March 31, 2011).

10.33†

     Form of Change of Control provision for inclusion in Union Drilling’s officer restricted stock unit award agreements (incorporated by reference to Exhibit 10.3 to our Form 8-K filed on March 31, 2011).

10.34

     Amended and Restated Revolving Credit and Security Agreement dated April 27, 2011 by and among Union Drilling, PNC Bank, National Association, for itself and for the other lenders, and PNC Capital Markets LLC (incorporated by reference to Exhibit 10.1 to our Form 8-K filed on April 28, 2011).

10.35

     Form of Rig and Equipment Sale Agreement dated July 5, 2011 between Union Drilling and Integrated Drilling Equipment Company Holdings, Inc. (incorporated by reference to Exhibit 10.1 to our Form 8-K filed on July 6, 2011).

23.1*

     Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm

31.1*

     Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.

31.2*

     Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.

32.1*

     Section 1350 Certification of Chief Executive Officer.**

32.2*

     Section 1350 Certification of Chief Financial Officer.**

101

     The following financial statements from Union Drilling, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2011, filed on March 8, 2012, formatted in XBRL (Extensible Business Reporting Language); (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Equity, (iv) Consolidated Statements of Cashflows and (v) the Notes to Consolidated Financial Statements.

 

Management contract or compensatory plan or arrangement.
* Filed with this Report.
** This Certification shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section. This Certification shall not be deemed to be incorporated by reference into any filing of the Company under the Securities Act of 1933 or the Securities Exchange Act of 1934, each as amended, whether made before or after the date hereof, except to the extent that the Company specifically incorporates it by reference.
*** In accordance with Rule 406T of Regulations S-T, the XBRL related information in Exhibit 101 to this Annual Report on Form 10-K shall not be deemed to be “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, and shall not be part of any registration or other document filed under the Securities Act or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.

 

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