Investor Presentation May 2015 www.icdrilling.com Forward Looking - - PowerPoint PPT Presentation

www.icdrilling.com

Investor Presentation

May 2015

Forward Looking Statements and Non-GAAP Financial Measures

Various statements contained in this presentation, including those that express a belief, expectation or intention, as well as those that are not statements of historical fact, are forward-looking statements. These forward-looking statements may include projections and estimates concerning the timing and success of specific projects and our future revenues, income and capital spending. Our forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “plan,” “goal,” “will” or other words that convey the uncertainty of future events or outcomes. The forward-looking statements in this presentation speak only as of the date of this presentation; we disclaim any obligation to update these statements unless required by law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These and other important factors, including those discussed under “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in the Company’s filings with the Securities and Exchange Commission, including the Company’s Annual Report on Form 10-K, may cause our actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by these forward-looking statements. These risks, contingencies and uncertainties include, but are not limited to, the following:

• our inability to implement our business and growth strategy;
• a sustained decrease in domestic spending by the oil and natural gas exploration and production industry;
• decline in or substantial volatility of crude oil and natural gas commodity prices;
• fluctuation of our operating results and volatility of our industry;
• inability to maintain or increase pricing on our contract drilling services;
• delays in construction or deliveries of our new land drilling rigs;
• the loss of our customer, financial distress or management changes of potential customers or failure to obtain contract renewals and additional customer contracts for our drilling services;
• an increase in interest rates and deterioration in the credit markets;
• our inability to raise sufficient funds through debt financing and equity issuances needed to fund our planned rig construction projects;
• our inability to comply with the financial and other covenants in debt agreements that we may enter into as a result of reduced revenues and financial performance;
• a substantial reduction in borrowing base under our revolving credit facility as a result of a decline in the appraised value of our drilling rigs;
• overcapacity and competition in our industry;
• unanticipated costs, delays and other difficulties in executing our long-term growth strategy;
• the loss of key management personnel;
• new technology that may cause our drilling methods or equipment to become less competitive;
• labor costs or shortages of skilled workers;
• the loss of or interruption in operations of one or more key vendors;
• the effect of operating hazards and severe weather on our rigs, facilities, business, operations and financial results, and limitations on our insurance coverage;
• increased regulation of drilling in unconventional formations;
• the incurrence of significant costs and liabilities in the future resulting from our failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment;
• the potential failure by us to establish and maintain effective internal control over financial reporting;
• lack of operating history as a contract drilling company; and
• uncertainties associated with any registration statement, including financial statements, we may be required to file with the SEC.

All forward-looking statements are necessarily only estimates of future results, and there can be no assurance that actual results will not differ materially from expectations, and, therefore, you are cautioned not to place undue reliance on such statements. Any forward-looking statements are qualified in their entirety by reference to the factors discussed throughout this presentation. Further, any forward-looking statement speaks only as of the date on which it is made, and we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which the statement is made or to reflect the occurrence of unanticipated events. Each of EBITDA and Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define “EBITDA” as earnings (or loss) before interest, taxes, depreciation, and amortization, and we define “Adjusted EBITDA” as EBITDA before stock-based compensation, gain/loss on warrant derivative liability and non-cash asset impairments. Adjusted EBITDA is not a measure of net income as determined by U.S. generally accepted accounting principles (“GAAP”). Management believes each of EBITDA and Adjusted EBITDA is useful because it allows us and our stockholders to more effectively evaluate our operating performance and compare the results of our

• perations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in calculating EBITDA and

Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. EBITDA and Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss), the most closely comparable financial measure calculated in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from EBITDA and Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as stock-based compensation and the historic costs of depreciable assets, none of which are components of EBITDA or Adjusted EBITDA. Our presentation of EBITDA and Adjusted EBITDA should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Our computations of EBITDA and Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.

U.S. Land-Based Contract Driller Providing Premium Services

• Successfully Completed IPO in August 2014 (NYSE: ICD).
• 14 Rig Fleet Composition:

‒ Sector’s most modern and technologically advanced fleet. ‒ 100% of fleet composed of 1,500-hp AC rigs. ‒ Bi-fuel capable, pad optimized with omnidirectional walking capabilities. ‒ All operating rigs currently in the Permian Basin. One newbuild scheduled for delivery Q3’15 for

• perations in the Eaglebine.
• Established reputation for operational excellence and safety:

‒ TRIR below IADC average. ‒ Fleet wide uptime of 98%. ‒ Longest lateral ever drilled in Permian Basin: ~14,000 ft. ‒ Walking between well groups 300 ft. and between pads 600 ft.

• Well-known customers who pay for quality equipment, execution.
• Well positioned to navigate current market conditions:

‒ Strong backlog of business. ‒ Modular manufacturing.

Independence Contract Drilling, Inc.

4

• Seasoned management team with over 200 years of industry leading

land and offshore drilling and HSE performance– focused on

• perational excellence and best in class safety performance.
• Nimble organization capable of responding to customer requirements

quickly and efficiently.

• Growth company offers significant advancement opportunities for

highly motivated individuals.

• Excellent crews sourced primarily from the Southeastern United

States (Texas, Oklahoma, Louisiana and Mississippi and Alabama).

Right People….

5

• ShaleDriller TM rigs are custom designed to reduce cycle times and drill

more wells per year:

• Integrated multi-directional walking system designed to optimize pad drilling.
• Move in any direction and quickly adjust to misaligned wellbores.
• NO skid beams or rail systems– only latest technology.
• Single load substructure allows for automated rapid rig up and down with the use of

remote control– NO cranes required.

• Standardized Rig Fleet:
• Entire fleet consists of all NEW 1500 HP AC programmable land drilling rigs.
• 1500 HP rig fleet enables us to work in any major US shale play.
• Standardization offers “plug and play” benefits such as cost savings, reduces spares.
• Minimizes potential downtime for our customers.
• Rig Assembly and Support:
• Rigs are assembled and fully commissioned in the yard prior to delivery–

eliminate the days of “breaking in a new rig”.

• Excellent maintenance personnel in the field to support the rig while
• perating.

Right Equipment….

6

• US land drilling will be the accelerator for increased shale oil and

natural gas production while the US strives to become energy independent.

• Continued shift to “manufacturing” well bores through multi-well

pad drilling will increase the efficiencies gained and reduce

• verall drilling and completion costs.
• Advanced drilling equipment and technologies lead to more

efficient well bores which are capable of producing oil and gas

• ver a longer period of time.
• Major rig replacement cycle in the US Land Drilling sector will be

required to meet the demand for highly advanced drilling equipment.

• Increased demand for drilling rigs capable of drilling long

horizontal wells in excess of 23-24,000’.

Right Time….

7

www.icdrilling.com

ICD Operational Footprint

New Construction

Q3’2015

Target Areas of Growth

Texas, Louisiana, Oklahoma and New Mexico

May 1, 2015

8

Rig Count History (1990-Present)

392 (APR 1999) 1,136 (JUL 2001) 1961 (AUG 2008) 829 (JUN 2009) 1992 (OCT 2011)

Source: BHI U.S. Land Rig Count, RigData May 1, 2015

1876 (SEP 2014)

871 (MAY 1, 2015)

876 (DEC 1992) 907 (SEP 1997) 1,080 (DEC 1990) 537 (APR 1993) 628 (APR 2002)

RigData

November 2014 to Present

11/28/14: 2099 5/1/15: 935

• 1164

(1,132) (1,005)

9

Current Market Conditions

• Operators remain focused on

unconventional assets.

• Operators focused on differentiating

technology that reduces overall costs to develop reserves.

• Operators focused on horizontal

development rather than vertical programs.

• Multi-well pad development is

becoming standard operating procedure with increasing wells per pad.

• Pad optimal rigs accompanied by

highly efficient operations are in highest demand compared to less efficient rigs and operations.

10

Modular Manufacturing Strong Backlog Operational Excellence Premium Customer Base Pad-Optimal Fleet Safety Excellence Expanding Cash Flows

Source: Baker Hughes

• In 2008, only 9% of US land

drilling fleet was AC drive. Today, over 50% of the fleet is AC drive.

• Due to shortage of pad-optimal

equipment, ~39% of horizontal wells are still being drilled by legacy mechanical and SCR equipment.

• Pad optimal equipment remains

a small subsector of the total AC drive rig universe.

Source: RigData,

Rig Replacement Cycle

Rigs Drilling Horizontal Wells: U.S. Land : April 2015.

Legacy Rigs: 49% AC Rigs: 51% AC Rigs: 61% Legacy Rigs: 39%

11

• Eliminate Errors and Increase Accuracy With Digital and Analog Displays:
• pump strokes
• weight on bit
• RPM and torque
• pressures (drilling or well control)
• Direct Control of the Drill String, Bit and Motor: Longer bit life, fewer bit trips.
• Accurate Lateral Sections: Trouble free casing run, increased well productivity.
• Reduces “Open Hole” Time: Can lead to well bore collapse or potential well control issues.
• Real-time Data Analysis: Helps Operator hit their target, development of future wells.
• Improved Equipment Maintenance Programs: Reduces non-productive time.
• Remote Operated Equipment: Hands free operation are safe and more efficient.

Advantages of AC

=

Increased Rate of Penetration (ROP)

12

Pad Optimal Rigs

As Defined by Operators

• 1,500 hp.
• Four day conventional move capability – SAFE By Design.
• Dual Fuel.
• 7,500 psi mud systems.
• Omni – Directional Walking System – Ability to walk over raised

wellheads and adjust to misaligned wellbores.

• AC VFD Drive – At this time in land rig technology evolution, this

goes without saying.

• PAD OPTIMAL

– Best suited for wellbore manufacturing model. – More wells per rig year. – Accelerate/ Optimize operator production profile/ cash flow.

13

ICD ShaleDriller “200 Series” PAD OPTIMAL

• Hook load: 750,000
• Vertical Depth Rating: 20,000’
• Horse Power Rating: 1,500
• Mud Pumps: 1600 HP, 5,000/7500 psi
• Omni-Directional Walking System
• Ability to Walk Over Well Heads
• AC Drive and Joy Stick Controls
• Single-Load Floor and Substructure
• Move Conventionally in 4 Days
• Bi-Fuel Capability

ShaleDriller 205 Concho Resources

Rig walked 100 feet with 19,400 feet of 5 inch drill pipe in less than 4 hours Eddy County New Mexico

14

Shaledriller = Enabling Technology

BOPCo, L.P. Drilling Island Project Eddy County New Mexico

• Potential for +40 wells on single pad.
• Bifuel drilling operation (~$1,500/day savings).
• Concrete coffin cellars for multi-wells.
• SEMS II Compliant, SimOps.
• Federal Land Regulations (BLM).
• Recent addition of second ICD rig for additional

drilling island.

• Longest lateral section in the Permian Basin.
• Demand for standardized 7,500 psi equipment.

15

ICD Operating Utilization

Total Hours Operating, Moving, Downtime April 2014 to April 2015

Source: NOV Drill Well

• Culture dedicated to safety and
• perational excellence drives ICD

value proposition to E&P operators.

• ICD newbuilds operate at highest

industry standards on their very first wells: ‒

Modular manufacturing.

‒

Systematic processes and procedures.

‒

SEMS II safety management system.

• Fast moving designs:

‒

Walk in less than 45 minutes between wells.

‒

Release to spud of next well in less than 3 hours.

‒

Regularly move between drilling locations in 4 days or less.

16

www.icdrilling.com

Target: 15 Days based on existing wells in the field. Saved 10 days ~$250,000

Days Equal Value

17

HSE Culture Evolution

ICD Total Recordable Incident Rates Year End 2014 - 1.14 Rolling 12 Month @ April ‘15 – 1.04

18

Quality Customer Base

• ICD customers are well capitalized

with established, long-term drilling plans.

• Demand the highest quality and

safest operations.

• Utilize pad drilling to maximize cash

flows and drilling efficiencies. During 2014, over 75% of wells drilled by ICD 200 Series ShaleDrillers were from multi-well pads.

• ~95% of ICD’s 2014 revenues

represent repeat business where customer contracted a second rig or renewed the contract.

ICD has Contracts in-place with some of the Most Active Players in the High Growth Permian Basin

Company 2015E Total Capex ($MM) Devon Energy 4,250 Apache Corporation 2,200 Concho Resources 2,000 Pioneer Natural Resources 1,850 Cimarex Energy 1,000 Energen Energy 1,000 SM Energy 1000 QEP Resources 975 Rosetta Resources 750 Laredo Petroleum 525 Diamondback Energy 425 RSP Permian 425 Parsley Energy 238 Approach Resources 160

Source: Public company filings and press releases.

19

Term Contract Coverage

• 2015 Contract Backlog

‒ Greater than 2014 revenues. ‒ Greater operating days than 2014. ‒ At higher average day rate than 2014. ‒ Drives increase in operating cash flows even in face of declining market conditions.

• Term contract coverage:

‒ Early termination payment provisions. ‒ Leading Permian operators.

(1) Represents average term contract coverage in 2015 divided by estimated ending rig count at 12/31/15. (2) Represents ICD average term contracts divided by expected ending rig count at 12/31/15. (3) Represents ICD estimate from public filings of three largest competitors for which data available . Represents average term contract coverage divided by expected ending rig count at 12/31/15. Excludes rigs and backlog associated with international or offshore operations only if backlog and rig data available for U.S.-only operations.

(2) (3) (3) (3)

20

Rig Equipment / Tools/Tubulars

Control Over Cost Chain

21

• Modular manufacturing drives
• perational efficiencies and

eliminates fixed costs.

‒ Rig crews assemble rigs, driving

safety and uptime.

‒ Subassemblies manufactured by

select vendors with ICD quality control supervision.

• ICD’s “all-in” capital costs for a

fully-equipped pad optimal ShaleDrillerTM rig delivered to the well site has been ~$20 million:

‒ Omni- directional walking system. ‒ 7500psi. ‒ Bi-Fuel. ‒ Automated handling systems.

Modular Manufacturing ShaleDrillerTM “All-in” Capital Cost Components Direct Materials / Labor Commissioning & Overhead Allocations Taxes

Land Drilling’s Only Pure-Play, Pad Optimal, Growth Story

Large Operators are Leading Unconventional Resource Capture Major Secular Shift in Unconventional Development is Underway Ongoing Resource Play Development Driving a Rig Replacement Cycle Pad Optimal AC Drilling Rigs are in Short Supply Major Barriers to Entry Exist for New Contract Drillers Vertically Integrated Model Provides a Compounding Capital Advantage ShaleDrillerTM Offers a Compelling Value Proposition to E&P Customers

Delivering Value to Stakeholders

22

Financial Strategy and Capitalization

• Maintain conservative balance sheet:
• Debt/EBITDA ratio of less than 3.0x

throughout completion of 2015 rig build.

• Interest coverage greater than 12x

throughout 2015.

• Expect to exit 2015 with net debt of less

than $60 million (~20% net debt/total cap).

• Stable, high quality cash flows:
• 2015 backlog exceeds 2014 revenues.
• Sizable NOL balance. Not a cash taxpayer.
• New rig fleet with low maintenance capital

requirements.

• Favorable cost structure:
• Modular manufacturing reduces fixed

costs.

• Standardized fleet allows for minimal

replacement cost.

23

Financial Flexibility and Liquidity

$ millions

Financial Strategy Cash @ 12/31/14 $10.8 Plus: Revolving Credit Facility Commitments 155.0 Less: Outstanding Borrowings @ 12/31/14 ($22.5) Less: 2015 Capex (54.0) Subtotal $89.3

ICD maintains significant liquidity even prior to application of 2015

• perating cash flows

Improving Financial & Operating Statistics

• Revenue growth.
• Margin growth.
• EBITDA growth.
• Overall revenue days.
• 2015 backlog greater than

2014 revenues.

24

34% 17% 100% 100% 39% 27% 100%

2015 Capex Budget Provides Flexibility

25

• Completion of 3 new builds

pursuant to multi-year term contracts.

• Completion of critical spare

inventory.

• Maintenance capex.
• Allocation for growth capex:
• Upgrade 100 Series rigs or

additional 200 Series rig.

• Determination to be made in

2H’15 based upon market conditions.

APPENDICES

Income Statement

27 December 31, 2015 2014 2014 Revenues 22,306 $ 13,549 $ 23,014 $ Costs and expenses Operating costs 13,106 8,777 12,685 Selling, general and administrative 3,827 2,094 4,437 Depreciation and amortization 4,289 3,416 4,648 Goodwill impairment and other charges

• 30,627

(Insurance recoveries) asset impairment, net (841) 4,650 (901) Loss (gain) on disposition of assets 393 (189) 158 Total cost and expenses 20,774 18,748 51,654 Operating income (loss) 1,532 (5,199) (28,640) Interest expense, net (312) (394) (174) Gain on warrant derivative

• 3

2,420 Income (loss) before income taxes 1,220 (5,590) (26,394) Income tax benefit (155) (1,885) (1,788) Net income (loss) 1,375 $ (3,705) $ (24,606) $ Loss per share: Basic 0.06 $ (0.30) $ (1.00) $ Diluted 0.06 $ (0.30) $ (1.00) $ Weighted average number of common shares outstanding: Basic and diluted 24,629 12,251 24,622 Three Months Ended March 31,

Balance Sheet

28

March 31, 2015 December 31, 2014 Assets Cash and cash equivalents 11,043 $ 10,757 $ Accounts receivable, net 17,999 19,127 Inventory 2,191 2,124 Deferred taxes 364 323 Prepaid expenses and other current assets 3,535 3,969 Total current assets 35,132 36,300 Property, plant and equipment, net 273,924 250,498 Other long-term assets, net 2,580 2,749 Total assets 311,636 $ 289,547 $ Liabilities and Stockholders’ Equity Liabilities Current portion of long-term debt (1)

• $

22,519 $ Accounts payable 30,013 21,993 Accrued liabilities 5,386 6,970 Income taxes payable 253 408 Total current liabilities (1) 35,652 51,890 Long-term debt (1) 35,940

• Other long-term liabilities

415 598 Deferred taxes 364 323 Total liabilities 72,371 52,811 Commitments and contingencies Stockholders’ equity Common stock, $0.01 par value, 100,000,000 shares authorized; 24,705,254 and 24,714,344 issued, respectively; 24,620,243 and 24,629,333 outstanding, respectively 246 246 Additional paid-in capital 273,904 272,750 Accumulated deficit (33,914) (35,289) Treasury shares, at cost, 85,011 shares (971) (971) Total stockholders’ equity 239,265 236,736 Total liabilities and stockholders’ equity 311,636 $ 289,547 $

Although borrowings under our credit facility do not mature until 2018, we revised the classification of long-term debt in our balance sheet as of December 31, 2014 from long-term debt to current portion of long-term debt due to

• ur credit facility at the time including both a required lock box payment method and a subjective acceleration clause permitting the lenders to declare an event of default in the event of a material adverse change. We

subsequently amended our credit facility to provide for a springing lock box arrangement to permit the long-term classification of the debt, subject to the credit facility’s ultimate maturity and our compliance with its terms and

• conditions. The reclassification did not affect previously reported net income, total assets, total liabilities or stockholders equity or cash flows as of and for the years ended December 31, 2014 or 2013.

Operating Data

March 31, 2015 March 31, 2014 December 31, 2014 Number of completed rigs end of period (1) 13 6 11 Rig operating days (2) 951.2 607.3 921.4 Average number of operating rigs (3) 10.6 6.7 10.0 Rig utilization (4) 92.1% 100.0% 99.2% Average revenue per operating day (5) $ 22,782 $ 20,918 $ 23,944 Average cost per operating day (6) $ 13,035 $ 12,697 $ 12,454 Average margin per day $ 9,747 $ 8,221 $ 11,490 Three Months Ended

(1) Number of completed rigs as of March 31, 2015, increased by seven compared to the number of completed rigs as of March 31, 2014, reflecting the addition of six newly constructed rigs and the completion of an upgrade of one of the Company’s drilling rigs. Number of completed rigs as of March 31, 2015, increased by two sequentially compared to the number of completed rigs as of December 31, 2014, reflecting the addition of two newly constructed rigs. (2) Rig operating days represent the number of days that our rigs are earning revenue under a contract, including days that standby revenues are earned. During the first quarter of 2015, there were 183.6 operating days in which ICD earned revenue on a standby basis, including 43.0 standby-without-crew days. (3) Average number of operating rigs is calculated by dividing the total number of rig operating days in the period by the total number of calendar days in the period. (4) Rig utilization percentage is calculated as rig operating days divided by the total number of days our drilling rigs are available during the applicable period. (5) Average revenue per operating day represents total contract drilling revenues earned during the period divided by rig operating days in the period. The following revenues are excluded in calculating average revenue per operating day: (i) revenues associated with reimbursement of out-of-pocket costs paid by customers

• f $0.6 million, $0.7 million and $0.9 million during the three months ended March 31, 2015 and 2014, and December 31, 2014, respectively, and (ii) direct revenues

associated with repair and service and other revenues from third-party drilling contractors of $0.0 million, $0.2 million and $0.0 million during the three months ended March 31, 2015 and 2014, and December 31, 2014, respectively. (6) Average cost per operating day represents total direct operating costs incurred during the period divided by rig operating days in the period. The following costs are excluded in calculating average cost per operating day: (i) costs relating to out-of-pocket costs reimbursed by customers of $0.6 million, $0.7 million and $0.9 million during the three months ended March 31, 2015 and 2014, and December 31, 2014, respectively, (ii) new crew training costs of $0.1 million, $0.3 million and $0.3 million during the three months ended March 31, 2015 and 2014, and December 31, 2014, respectively, and (iii) direct operating costs associated with repair and service and

• ther revenues from third-party drilling contractors of $0.0 million, $0.1 million and $0.0 million during the three months ended March 31, 2015 and 2014, and December

31, 2014, respectively.

Non-GAAP Financial Measures

March 31, 2015 March 31, 2014 December 31, 2014 Net income (loss) $ 1,375 $ (3,705) $ (24,606) Add back: Income tax benefit (155) (1,885) (1,788) Interest expense 312 394 174 Depreciation and amortization 4,289 3,416 4,648 EBITDA 5,821 (1,780) (21,572) Stock-based compensation 933 448 1,143 Goodwill impairment and other charges

• 30,627

(Insurance recoveries) asset impairment, net (841) 4,650 (901) Gain on warrant derivative liability

• (3)

(2,420) Loss (gain) on disposition of assets 393 (189) 158 Adjusted EBITDA $ 6,306 $ 3,126 $ 7,035 Three Months Ended

Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define “EBITDA” as earnings (or loss) before interest, taxes, depreciation, and amortization, and we define “Adjusted EBITDA” as EBITDA before stock-based compensation, gain/loss on warrant derivative liability and non-cash asset impairments and other one-time non-operating items. Adjusted EBITDA is not a measure

• f net income as determined by U.S. generally accepted accounting principles (“GAAP”).

Management believes Adjusted EBITDA is useful because it allows our stockholders to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in calculating Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss), the most closely comparable financial measure calculated in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as stock-based compensation and the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our presentation of Adjusted EBITDA should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. The following table presents a reconciliation of Adjusted EBITDA to the GAAP financial measure of net income for each of the periods indicated.

31

32

33