Independence Contract Drilling, Inc. - FORM 10-Q

Attached files

file	filename
EX-32.2 - EXHIBIT 32.2 - Independence Contract Drilling, Inc.	icd-20160630x10qexx322.htm
EX-32.1 - EXHIBIT 32.1 - Independence Contract Drilling, Inc.	icd-20160630x10qexx321.htm
EX-31.2 - EXHIBIT 31.2 - Independence Contract Drilling, Inc.	icd-20160630x10qexx312.htm
EX-31.1 - EXHIBIT 31.1 - Independence Contract Drilling, Inc.	icd-20160630x10qexx311.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q


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

For the quarterly period ended June 30, 2016


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

For the transition period from to

Commission File Number: 001-36590

Independence Contract Drilling, Inc.

(Exact name of registrant as specified in its charter)



Delaware	37-1653648
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

11601 North Galayda Street Houston, Texas	77086
(Address of principal executive offices)	(Zip code)

(281) 598-1230

(Registrant’s telephone number, including area code)

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 Exchange 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 (§ 232.405 of this chapter) 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 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.



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 Exchange Act). Yes ¨ No x

37,646,398 shares of the registrant’s Common Stock were outstanding as of July 27, 2016.

INDEPENDENCE CONTRACT DRILLING, INC.

Index to Form 10-Q



Part I. FINANCIAL INFORMATION

Item 1. Financial Statements

Balance Sheets as of June 30, 2016 and December 31, 2015 (Unaudited)		4

Statements of Operations for the three and six months ended June 30, 2016 and 2015 (Unaudited)		5

Statements of Stockholders’ Equity for the six months ended June 30, 2016 (Unaudited)		6

Statements of Cash Flows for the six months ended June 30, 2016 and 2015 (Unaudited)		7

Notes to the Financial Statements (Unaudited)		8

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		18

Item 3. Quantitative and Qualitative Disclosures About Market Risk		28

Item 4. Controls and Procedures		28

Part II. OTHER INFORMATION

Item 1. Legal Proceedings		29

Item 1A. Risk Factors		29

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		29

Item 3. Defaults Upon Senior Securities		29

Item 4. Mine Safety Disclosures		29

Item 5. Other Information		29

Item 6. Exhibits		30

Signatures		31

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in this Quarterly Report on Form 10-Q (this "Form 10-Q"), including those that express a belief, expectation or intention, as well as those that are not statements of historical fact, may constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. 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. 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 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:


•	a sustained decrease in domestic spending by the oil and natural gas exploration and production industry;


•	a decline in or substantial volatility of crude oil and natural gas commodity prices;


•	our inability to implement our business and growth strategy;


•	fluctuation of our operating results and volatility of our industry;


•	inability to maintain or increase pricing of our contract drilling services;


•	our backlog of term contracts declining rapidly;


•	the current severe market downturn impairing our ability to predict future rig utilization and spot dayrates due to customers delaying or changing their capital budget plans;


•	the loss of any of our customers, financial distress or management changes of potential customers or failure to obtain contract renewals and additional customer contracts for our drilling services;


•	overcapacity and competition in our industry;


•	an increase in interest rates and deterioration in the credit markets;


•	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 or reduction in the number of rigs operating;


•	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; and


•	the potential failure by us to establish and maintain effective internal control over financial reporting.

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 Form 10-Q and Part I, “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the fiscal year ended December 31, 2015. 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.

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Independence Contract Drilling, Inc.

Balance Sheets

(Unaudited)

(in thousands, except par value and share amounts)



	June 30, 2016			December 31, 2015
Assets
Cash and cash equivalents	$	7,086		$	5,344
Accounts receivable, net	6,872			18,240
Inventory	2,491			2,317
Prepaid expenses and other current assets	3,075			3,436
Total current assets	19,524			29,337
Property, plant and equipment, net	280,121			283,378
Other long-term assets, net	1,339			2,074
Total assets	$	300,984		$	314,789
Liabilities and Stockholders’ Equity
Liabilities
Current portion of long-term debt	$	373		$	—
Accounts payable	3,886			8,584
Accrued liabilities	6,461			10,206
Total current liabilities	10,720			18,790
Long-term debt	16,661			62,708
Deferred income taxes	229			193
Other long-term liabilities	149			361
Total liabilities	27,759			82,052
Commitments and contingencies (Note 10)
Stockholders’ equity
Common stock, $0.01 par value, 100,000,000 shares authorized; 37,816,424 and 24,539,937 shares issued, respectively; and 37,646,398 and 24,403,659 shares outstanding, respectively	376			244
Additional paid-in capital	322,092			276,948
Accumulated deficit	(47,774		)	(43,169		)
Treasury stock, at cost, 170,026 and 136,278 shares, respectively	(1,469		)	(1,286		)
Total stockholders’ equity	273,225			232,737
Total liabilities and stockholders’ equity	$	300,984		$	314,789

The accompanying notes are an integral part of these financial statements.

Independence Contract Drilling, Inc.

Statements of Operations

(Unaudited)

(in thousands, except per share amounts)



	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Revenues	$	15,155		$	21,082		$	37,610		$	43,388
Costs and expenses
Operating costs	7,398			12,057			19,965			25,163
Selling, general and administrative	5,005			3,755			8,626			7,582
Depreciation and amortization	5,816			5,169			11,641			9,458
(Insurance recoveries) asset impairment, net	—			—			—			(841		)
Loss (gain) on disposition of assets	37			(59		)	(88		)	334
Total costs and expenses	18,256			20,922			40,144			41,696
Operating (loss) income	(3,101		)	160			(2,534		)	1,692
Interest expense	(1,059		)	(717		)	(2,036		)	(1,029		)
(Loss) income before income taxes	(4,160		)	(557		)	(4,570		)	663
Income tax expense (benefit)	31			95			35			(60		)
Net (loss) income	$	(4,191	)	$	(652	)	$	(4,605	)	$	723
Net (loss) income per share:
Basic and diluted	$	(0.12	)	$	(0.03	)	$	(0.16	)	$	0.03
Weighted average number of common shares outstanding:
Basic and diluted	33,608			23,851			28,812			24,455

The accompanying notes are an integral part of these financial statements.

Independence Contract Drilling, Inc.

Statements of Stockholders’ Equity

(Unaudited)

(in thousands, except share amounts)



	Common Stock
	Shares		Amount		Additional Paid-in Capital		Accumulated Deficit			Treasury Stock			Total Stockholders’ Equity
Balances at December 31, 2015	24,403,659		$	244	$	276,948	$	(43,169	)	$	(1,286	)	$	232,737
Restricted stock units vested	51,487		—		—		—			—			—
Purchase of treasury stock	(33,748	)	—		—		—			(183		)	(183		)
Public offering, net of offering costs of $3,305	13,225,000		132		42,851		—			—			42,983
Stock-based compensation	—		—		2,293		—			—			2,293
Net loss	—		—		—		(4,605		)	—			(4,605		)
Balances at June 30, 2016	37,646,398		$	376	$	322,092	$	(47,774	)	$	(1,469	)	$	273,225

The accompanying notes are an integral part of these financial statements.

Independence Contract Drilling, Inc.

Statements of Cash Flows

(Unaudited)



	Six Months Ended June 30,
(in thousands)	2016			2015
Cash flows from operating activities
Net (loss) income	$	(4,605	)	$	723
Adjustments to reconcile net (loss) income to net cash provided by operating activities
Depreciation and amortization	11,641			9,458
(Insurance recoveries) asset impairment, net	—			(841		)
Stock-based compensation	2,360			1,734
Stock-based compensation - executive retirement	(67		)	—
(Gain) loss on disposition of assets	(88		)	334
Deferred income taxes	36			—
Amortization of deferred financing costs	283			315
Write-off of deferred financing costs	504			—
Bad debt expense	—			80
Changes in operating assets and liabilities
Accounts receivable	11,368			5,629
Inventory	(146		)	(253		)
Prepaid expenses and other current assets	176			(1,820		)
Accounts payable and accrued liabilities	(6,078		)	2,620
Income taxes payable	—			(195		)
Net cash provided by operating activities	15,384			17,784
Cash flows from investing activities
Purchases of property, plant and equipment	(10,521		)	(58,215		)
Proceeds from insurance claims	188			2,899
Proceeds from the sale of property, plant and equipment	747			351
Net cash used in investing activities	(9,586		)	(54,965		)
Cash flows from financing activities
Borrowings under credit facility	34,775			89,566
Repayments under credit facility	(81,129		)	(50,724		)
Public offering proceeds, net of offering costs of $3,305	42,983			—
Purchase of treasury stock	(183		)	—
Financing costs paid	(217		)	(164		)
Payments for capital lease obligations	(285		)	—
Net cash (used in) provided by financing activities	(4,056		)	38,678
Net increase in cash and cash equivalents	1,742			1,497
Cash and cash equivalents
Beginning of period	5,344			10,757
End of period	$	7,086		$	12,254
Supplemental disclosure of cash flow information
Cash paid during the period for interest	$	1,426		$	1,379
Cash paid during the period for income taxes	$	—		$	135
Supplemental disclosure of non-cash investing and financing activities
Stock-based compensation capitalized as property, plant and equipment	$	—		$	423
Change in property, plant and equipment purchases in accounts payable	$	(2,577	)	$	(15,776	)
Additions to property, plant and equipment through capital leases	$	965		$	—

The accompanying notes are an integral part of these financial statements.

INDEPENDENCE CONTRACT DRILLING, INC.

Notes to Financial Statements


1.	Nature of Operations

Independence Contract Drilling, Inc. (“we,” “us,” “our,” the “Company” or “ICD”) was incorporated in Delaware on November 4, 2011. We provide land-based contract drilling services for oil and natural gas producers targeting unconventional resource plays in the United States. We construct, own and operate a premium fleet comprised entirely of technologically advanced, custom designed ShaleDriller® rigs that are specifically engineered and designed to optimize the development of our customers’ most technically demanding oil and gas properties. We are focused on creating stockholder and customer value through our commitment to operational excellence and our focus on safety.

Our standardized fleet consists of fourteen premium ShaleDriller® rigs. Of these fourteen rigs, thirteen are 200 Series rigs equipped with our integrated omni-directional walking system that is specifically designed to optimize pad drilling for our customers. We have the ability to upgrade our remaining non-walking rig to 200 Series status when market conditions improve, but until such time this rig has been decommissioned, and we do not intend to market it. Every ShaleDriller® rig in our fleet is a 1500-hp, AC programmable rig (“AC rig”) designed to be fast-moving between drilling sites and is equipped with top drives, automated tubular handling systems and blowout preventer (“BOP”) handling systems. Twelve of our fourteen rigs are equipped with bi-fuel capabilities that enable the rig to operate on either diesel or a natural gas-diesel blend.

Our first rig began drilling in May 2012. We currently focus our operations on unconventional resource plays located in geographic regions that we can efficiently support from our Houston, Texas facilities in order to maximize economies of scale. Currently, our rigs are predominantly operating in the Permian Basin, however, our rigs have previously operated in the Mid-Continent and Eaglebine regions and the Eagle Ford Shale, as well. Two of our rigs are scheduled to mobilize for operations in Louisiana later in 2016.

Our business depends on the level of exploration and production activity by oil and gas companies operating in the U.S., and in particular, the regions where we actively market our contract drilling services. The oil and gas exploration and production industry is a historically cyclical industry characterized by significant changes in the levels of exploration and development activities. Oil and gas prices and market expectations of potential changes in those prices significantly affect the levels of those activities. Worldwide political, regulatory, economic, and military events, as well as natural disasters have contributed to oil and gas price volatility historically, and are likely to continue to do so in the future. Any prolonged reduction in the overall level of exploration and development activities in the U.S. and the regions where we market our contract drilling services, whether resulting from changes in oil and gas prices or otherwise, could materially and adversely affect our business.

Current Oil and Gas Prices and Drilling Activity

Oil prices began to decline in the second half of 2014 and declined further during 2015 and 2016. The closing price of oil was as high as $106.06 per barrel during the third quarter of 2014, was $37.13 per barrel on December 31, 2015, but improved to a high of $51.23 during the second quarter of 2016 (WTI spot price as reported by the United States Energy Information Administration). Despite the recent moderate upturn in oil prices, our industry is still experiencing an exceptional overall downturn, market conditions remain very dynamic and are changing quickly. Although the magnitude, as well as the duration, of this downturn are not yet known, we believe that the remainder of 2016 will continue to be an exceptionally challenging year for ICD and our industry.

We believe the vast majority of exploration and production ("E&P") companies, including our customers, have significantly reduced their 2016 capital spending plans compared to 2015 levels. The initial impact of these spending reductions is evidenced by the published rig counts which have declined more than 70% since their peak in October 2014, and we believe the rig count in the United States could decline further in 2016 if oil and gas prices fall below current levels.

As a result of this deterioration in market conditions, our customers are principally focused on their most economic wells, drilling to maintain leasehold positions and on maintaining their most cost efficient operations that deliver the overall lowest cost of producing their wells and minimize their capital expenditures. As a result, operators are focusing more of their capital spending on horizontal drilling programs compared to vertical drilling. They also are more focused on utilizing drilling equipment and techniques that optimize costs and efficiency. Thus, we believe this rapid market deterioration has significantly accelerated the pace of the ongoing land rig replacement cycle and continued shift to horizontal drilling from multi-well pads utilizing “pad optimal” rig technology.

Although we believe that the current market downturn is rapidly increasing the focus of our customers towards the use of premium drilling rigs such as our ShaleDriller®, and that premium operations such as ours have been less affected by the downturn relative to operations conducted by legacy fleets, the rapid pace and level of the market decline has negatively impacted pricing, utilization and contract tenors for premium rigs, including our ShaleDriller® rig. During the second quarter of 2016, our premium drilling fleet operated at 66% utilization, but we may not be able to maintain this level of utilization if commodity prices fall below current levels.

Retirement and Resignation of Edward S. Jacob, III

On June 10, 2016, ICD and Edward S. Jacob, III, our President and Chief Operating Officer, announced Mr. Jacob’s retirement as an officer of ICD effective June 30, 2016. ICD and Mr. Jacob also announced his resignation as director of ICD effective on June 30, 2016. In connection with Mr. Jacob’s retirement, ICD and Mr. Jacob entered into a Retirement Agreement on June 9, 2016 (the “Retirement Agreement”), setting out certain terms and conditions governing Mr. Jacob’s retirement. Under the terms of the Retirement Agreement, we agreed to make certain retirement benefits available to Mr. Jacob, including a cash retirement payment of approximately $1.5 million to be paid in one lump sum on January 2, 2017 and accelerated vesting of certain outstanding equity awards. The retirement payment and the impact from the accelerated vesting of equity awards are recorded as selling, general and administrative expense in our Statements of Operations for the quarter ended June 30, 2016.

Amendment to Revolving Credit Facility

On April 14, 2016, we entered into a Fourth Amendment (the “Fourth Amendment”) to the Amended and Restated Credit Agreement (the “Credit Agreement”) dated November 5, 2014.

Among other things, the Fourth Amendment (a) decreased the aggregate commitments under the Credit Agreement from $125.0 million to $85.0 million, but maintained the $25.0 million uncommitted accordion feature pursuant to which commitments may be increased in the future; (b) amended the Leverage Ratio, and Rig Utilization and Fixed Charge covenants; (c) amended the advance rate on Eligible Equipment for purposes of calculating the borrowing base; and (d) added a springing covenant associated with capital expenditures consistent with our previously announced capital plans.

In addition, in connection with the execution of the Fourth Amendment, the Administrative Agent agreed to include certain capital spare equipment in the calculation of our borrowing base through December 31, 2016.

Public Offering of Common Stock

On April 26, 2016, we completed an underwritten public offering of 13,225,000 shares of common stock at a price to the public of $3.50 per share. We received net proceeds of approximately $43.0 million, after deducting underwriting discounts and commissions and offering expenses.

We used the net proceeds from this offering to repay a portion of the outstanding borrowings under our revolving credit facility and for general corporate purposes.


2.	Interim Financial Information

These unaudited financial statements include the accounts of ICD, and have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). These financial statements should be read along with our audited financial statements for the year ended December 31, 2015, included in our Annual Report on Form 10-K for the year ended December 31, 2015. In management’s opinion, these financial statements contain all adjustments necessary to fairly present our financial position, results of operations, cash flows and changes in stockholders' equity for all periods presented.

As we had no items of other comprehensive income in any period presented, no other components of comprehensive income or comprehensive income is presented.

Interim results for the three and six months ended June 30, 2016 may not be indicative of results that will be realized for the full year ending December 31, 2016.

Segment and Geographical Information

Our operations consist of one reportable segment because all of our drilling operations are located in the United States and have similar economic characteristics. Corporate management administers all properties as a whole rather than as discrete operating segments. Operational data is tracked by rig; however, financial performance is measured as a single

enterprise and not on a rig-by-rig basis. Further, the allocation of capital resources is employed on a project-by-project basis across our entire asset base to maximize profitability without regard to individual geographic areas.

Other Matters

We have not elected to avail ourselves of the extended transition period available to emerging growth companies("EGCs") as provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended, for complying with new or revised accounting standards, therefore, we will be subject to new or revised accounting standards at the same time as other public companies that are not EGCs.

Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (the "FASB") issued an accounting standards update to provide guidance on the recognition of revenue from customers. Under this guidance, an entity will recognize revenue when it transfers promised goods or services to customers in an amount that reflects what it expects in exchange for the goods or services. This guidance also requires more detailed disclosures to enable users of the financial statements to understand the nature, amount, timing and uncertainty, if any, of revenue and cash flows arising from contracts with customers. This guidance, as updated, is effective for interim and annual periods beginning after December 15, 2017. We are currently evaluating the impact this guidance will have on our financial statements.

In August 2014, the FASB issued guidance requiring management to perform interim and annual assessments of an entity’s ability to continue as a going-concern within one year of the date the financial statements are issued. The standard also provides guidance on determining when and how to disclose going-concern uncertainties in the financial statements. An entity must provide certain disclosures if there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going-concern. Management’s evaluation should be based on relevant conditions and events that are known and reasonably knowable at the date that the financial statements are issued. The new guidance applies to all entities and is effective for annual periods ending after December 15, 2016, and interim periods thereafter, with early adoption permitted. We will begin performing the assessments and making the required disclosures, if applicable, beginning at the end of fiscal year 2016.

In July 2015, the FASB issued an accounting standards update requiring an entity to measure inventory at the lower of cost or market. Market could be replacement cost, net realizable value, or net realizable value less an approximately normal profit margin. The amendments do not apply to inventory that is measured using last-in, first-out ("LIFO") or the retail inventory method. The amendments apply to all other inventory, which includes inventory that is measured using first-in, first-out ("FIFO") or average cost. Management should measure in scope inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. Subsequent measurement is unchanged for inventory measured using LIFO or the retail inventory method. This guidance is effective for public companies for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. The amendments should be applied prospectively with earlier application permitted as of the beginning of an interim or annual reporting period. Adoption of this pronouncement is not expected to have a material impact on our financial statements.

In February 2016, the FASB issued an accounting standards update to establish the principles that lessees and lessors shall apply to report useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. Under the new guidance, lessees will be required to recognize (with the exception of short-term leases) at the commencement date, a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. This guidance is effective for public companies for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application is permitted for all public business entities upon issuance. We are currently evaluating the impact this guidance will have on our financial statements.

In March 2016, the FASB issued an accounting standards update intended to improve the accounting for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. Several aspects of the accounting for share-based payment award transactions are simplified, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. For public companies, the amendments are effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted for any organization in any interim or annual period. We are currently evaluating the impact this guidance will have on our financial statements.

In May 2016, the FASB issued an accounting standards update to clarify certain narrow aspects of Topic 606 such as assessing the collectability criterion, presentation of sales taxes and other similar taxes collected from customers, non-cash consideration, contract modifications at transition, completed contracts at transition, and technical correction. The guidance is effective for public companies for annual reporting periods beginning after December 15, 2017. We are currently evaluating the impact this guidance will have on our financial statements.


3.	Financial Instruments and Fair Value

Fair value is a market-based measurement that should be determined based on assumptions that market participants would use in pricing an asset or liability. As a basis for considering such assumptions, there exists a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows:


Level 1	Unadjusted quoted market prices for identical assets or liabilities in an active market;


Level 2	Quoted market prices for identical assets or liabilities in an active market that have been adjusted for items such as effects of restrictions for transferability and those that are not quoted but are observable through corroboration with observable market data, including quoted market prices for similar assets; and


Level 3	Unobservable inputs for the asset or liability only used when there is little, if any, market activity for the asset or liability at the measurement date.

This hierarchy requires us to use observable market data, when available, and to minimize the use of unobservable inputs when determining fair value.

The carrying value of certain of our assets and liabilities, consisting primarily of cash and cash equivalents, accounts receivable and accounts payable, approximates their fair value due to the short-term nature of such instruments.

The fair value of our revolving debt is determined by Level 3 measurements based on the amount of future cash flows associated with the debt, discounted using our current borrowing rate for comparable debt instruments (the Income Method). Based on our evaluation of the risk free rate, the market yield and credit spreads on comparable company publicly traded debt issues, we used an annualized discount rate, including a credit valuation allowance, of 6.5%. The fair value of our lease obligations is determined using level 3 measurements using our current incremental borrowing rate. The estimated fair value of our long-term debt totaled $16.4 million and $59.7 million as of June 30, 2016 and December 31, 2015, respectively, compared to a carrying amount of $16.7 million and $62.7 million as of June 30, 2016 and December 31, 2015, respectively.

Fair value measurements are applied with respect to our non-financial assets and liabilities measured on a non-recurring basis, which would consist of measurements primarily of long-lived assets.


4.	Inventory

All of our inventory as of June 30, 2016 and December 31, 2015 consisted of rig components and supplies.


5.	Accrued Liabilities

Accrued liabilities consisted of the following:



(in thousands)	June 30, 2016		December 31, 2015
Accrued salaries and other compensation	$	2,421	$	2,050
Insurance	779		600
Deferred revenues	1,398		4,591
Property, sales and other taxes	1,705		2,585
Other	158		380
	$	6,461	$	10,206


6.	Long-term Debt

Our Long-term Debt consisted of the following:



	June 30, 2016			December 31, 2015

Credit facility due November 5, 2018	$	16,354		$	62,708
Capital lease obligations	680			—
	17,034			62,708
Less: current portion	(373		)	—
Long-term debt	$	16,661		$	62,708

Credit Facility

In November 2014, we entered into an amended and restated credit agreement (the “Credit Facility”) with a syndicate of financial institutions led by CIT Finance, LLC, that provided for a committed $155.0 million revolving credit facility and an additional uncommitted $25.0 million accordion feature that allowed for future increases in the facility. On April 23, 2015, we amended the Credit Facility to provide for a springing lock-box arrangement. On October 20, 2015, in light of market conditions and our reduced capital plans, we entered into an amendment to the Credit Facility to reduce aggregate commitments to $125.0 million and modified certain maintenance covenants. On April 14, 2016, we again amended the Credit Facility to reduce aggregate commitments to $85.0 million and further modify certain maintenance covenants. In connection with this amendment, we expensed certain previously deferred debt issuance costs totaling $0.5 million reflecting the reduction in borrowing capacity. The obligations under the Credit Facility are secured by all of our assets and are unconditionally guaranteed by all of our current and future direct and indirect subsidiaries.

Borrowings under the Credit Facility are subject to a borrowing base formula that allows for borrowings of up to 85% of eligible trade accounts receivable not more than 90 days outstanding, plus up to 72.5% of the appraised forced liquidation value of our eligible, completed and owned drilling rigs. This advance rate declines 1.25% per quarter beginning in 2017. Rigs that remain idle for 90 consecutive days or longer are removed from the borrowing base until they are contracted. In addition, rigs are appraised three times a year and are subject to upward or downward revisions as a result of market conditions as well as the age of the rig. The Credit Facility matures on November 5, 2018.

At our election, interest under the Credit Facility is determined by reference at our option to either (i) the London Interbank Offered Rate (“LIBOR”), plus 4.5% or (ii) a “base rate” equal to the higher of the prime rate published by JP Morgan Chase Bank or three-month LIBOR plus 1%, plus in each case, 3.5%, the federal funds effective rate plus 0.05%. We also pay, on a quarterly basis, a commitment fee of 0.50% per annum on the unused portion of the Credit Facility commitment. As of June 30, 2016, the weighted average interest rate on our borrowings was 5.18%.

The amended Credit Facility contains various financial covenants including a leverage covenant, springing fixed charge coverage ratio and rig utilization ratio. Additionally, there are restrictive covenants that limit our ability to, among other things: incur or guarantee additional indebtedness or issue disqualified capital stock; transfer or sell assets; pay dividends or distributions; redeem subordinated indebtedness; make certain types of investments or make other restricted payments; create or incur liens; consummate a merger; consolidation or sale of all or substantially all assets; and engage in business other than a business that is the same or similar to the current business and reasonably related businesses. The Credit Facility does, however, permit us to incur up to $20.0 million of additional indebtedness for the purchase of additional rigs or rig equipment.

Under the Credit Agreement, as amended, for purposes of calculating EBITDA, non-cash stock-based compensation is added back to EBITDA as well as up to $2.0 million per year of previously capitalized construction costs that may be incurred in 2016 and 2017. At June 30, 2016, our calculated leverage ratio under this covenant was approximately 0.4x.

The Credit Facility provides that an event of default may occur if a material adverse change to the Company occurs, which is considered a subjective acceleration clause under applicable accounting rules. Under ASC 470-10-45, because of the existence of this clause, borrowings under the Credit Facility will be required to be classified as current in the event the springing lock-box event occurs, regardless of the actual maturity of the borrowings. The Fourth Amendment reduces the requirement for a mandatory lock-box trigger from $15 million of availability under the credit facility to $10 million of availability under the Credit Facility.

We had approximately $16.4 million in outstanding borrowings under the Credit Facility at June 30, 2016. Remaining availability under the Credit Facility was $64.3 million at June 30, 2016, based on the amended borrowing base formula, and we are currently in compliance with all covenants under the Credit Facility.

Capital Lease Obligations

During the first quarter of 2016, our vehicle lease agreements were amended, which resulted in a change in the classification of certain leases from operating leases to capital leases. On the amendment date we recorded $0.8 million in capital lease obligations, representing the lesser of fair market value or the present value of future minimum lease payments on the conversion date. These leases generally have initial terms of 36 months and are paid monthly.


7.	Stock-Based Compensation

In March 2012, we adopted the 2012 Omnibus Long-Term Incentive Plan (the “2012 Plan”) providing for common stock-based awards to employees and to non-employee directors. The 2012 plan was subsequently amended in August 2014 and June 2016. The 2012 Plan, as amended, permits the granting of various types of awards, including stock options, restricted stock and restricted stock unit awards, and up to 4,754,000 shares were authorized for issuance. Restricted stock and restricted stock units may be granted for no consideration other than prior and future services. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant. Stock options expire ten years after the grant date. We have the right to satisfy option exercises from treasury shares and from authorized but unissued shares. As of June 30, 2016, approximately 1,585,784 shares were available for future awards.

A summary of compensation cost recognized for stock-based payment arrangements is as follows:



(in thousands)	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Compensation cost recognized:
Stock options	$	3	$	74	$	72	$	288
Restricted stock and restricted stock units	1,135		929		2,221		1,869
Total stock-based compensation	$	1,138	$	1,003	$	2,293	$	2,157

No stock-based compensation was capitalized in connection with rig construction activity during the three and six months ended June 30, 2016. Approximately $0.2 million and $0.4 million in stock-based compensation was capitalized in connection with rig construction activity during the three and six months ended June 30, 2015, respectively.

Stock Options

We use the Black-Scholes option pricing model to estimate the fair value of stock options granted to employees and non-employee directors. The fair value of the options is amortized to compensation expense on a straight-line basis over the requisite service periods of the stock awards, which are generally the vesting periods.

There were no stock options granted during the six months ended June 30, 2016 or the six months ended June 30, 2015.

A summary of stock option activity and related information for the six months ended June 30, 2016 is as follows:



	Six Months Ended June 30, 2016
	Options		Weighted Average Exercise Price
Outstanding at January 1, 2016	956,653		$	12.74
Granted	—		—
Exercised	—		—
Forfeited/expired	(7,850	)	—
Outstanding at June 30, 2016	948,803		$	12.74
Exercisable at June 30, 2016	912,170		$	12.74

A summary of our unvested stock options as of June 30, 2016, and the changes during the six months then ended is presented below:



	Six Months Ended June 30, 2016
	Outstanding		Weighted Average Grant-Date Fair Value
Unvested as of January 1, 2016	104,143		$	3.88
Granted	—		—
Vested	(59,660	)	4.27
Forfeited/expired	(7,850	)	3.36
Unvested as of June 30, 2016	36,633		$	3.36

The number of options vested at June 30, 2016 was 912,170 with a weighted average remaining contractual life of 5.9 years and a weighted-average exercise price of $12.74 per share.

As of June 30, 2016, the unrecognized compensation cost related to outstanding stock options was $9.0 thousand. This cost is expected to be recognized over a weighted-average period of 0.1 years.

Restricted Stock

Restricted stock awards consist of grants of our common stock that vest ratably over three to four years. We recognize compensation expense on a straight-line basis over the requisite service period, which is generally the vesting period. The fair value of restricted stock awards is determined based on the fair market value of our shares on the grant date. As of June 30, 2016, there was $1.9 million of total unrecognized compensation cost related to unvested restricted stock awards. This cost is expected to be recognized over a weighted-average period of 0.6 years.

A summary of the status of our restricted stock awards as of June 30, 2016, and of changes in restricted stock outstanding during the six months ended June 30, 2016, is as follows:



	Six Months Ended June 30, 2016
	Shares		Weighted Average Grant-Date Fair Value Per Share
Outstanding at January 1, 2016	388,265		$	10.80
Granted	—		—
Vested	(71,905	)	11.26
Forfeited	—		—
Outstanding at June 30, 2016	316,360		$	10.70

Restricted Stock Units

We have granted restricted stock units ("RSUs") to key employees and directors under the 2012 Plan. We have granted three year vesting RSUs, as well as performance-based and market-based RSUs, where each unit represents the right to receive, at the end of a vesting period, up to one and a half to two shares of ICD common stock at no cost. Vesting of the market-based RSUs is based on our three year total shareholder return ("TSR") as measured against a three year TSR of a defined peer group and vesting of the performance-based RSUs is based on our cumulative EBITDA ("CEBITDA"), as defined in the restricted stock unit agreement, over a three year period. We used a Monte Carlo simulation model to value the TSR market-based RSUs at the date of grant. The fair value of the CEBITDA performance-based RSUs was based on the market price of our common stock on the date of grant. During the restriction period, the RSUs may not be transferred or encumbered, and the recipient does not receive dividend equivalents or have voting rights until the units vest. As of June 30, 2016, there was $3.7 million of unrecognized compensation cost related to unvested RSUs that is expected to be recognized over a weighted-average period of 1.0 year.

A summary of the status of our RSUs as of June 30, 2016, and of changes in RSUs outstanding during the six months ended June 30, 2016, is as follows:



	Six Months Ended June 30, 2016
	RSUs		Weighted Average Grant-Date Fair Value Per Share
Outstanding at January 1, 2016	463,413		$	12.97
Granted	814,170		4.01
Vested and converted	(51,487	)	10.94
Forfeited	(148,433	)	5.85
Outstanding at June 30, 2016	1,077,663		$	7.28


8.	Stockholders’ Equity and Earnings (Loss) per Share

As of June 30, 2016, we had a total of 37,646,398 shares of common stock, $0.01 par value, outstanding, including 316,360 shares of restricted stock. We also had 170,026 shares held as treasury stock. Total authorized common stock is 100,000,000 shares.

Basic earnings (loss) per common share (“EPS”) is computed by dividing income (loss) available to common stockholders by the weighted-average number of common shares outstanding for the period. Diluted EPS reflects the potential dilution that would occur if securities or other contracts to issue common stock were exercised or converted into common stock. A reconciliation of the numerators and denominators of the basic and diluted (loss) earnings per share computations is as follows:



(in thousands, except per share data)	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Net (loss) income (numerator):	$	(4,191	)	$	(652	)	$	(4,605	)	$	723
Net (loss) earnings per share:
Basic and diluted	$	(0.12	)	$	(0.03	)	$	(0.16	)	$	0.03
Shares (denominator):
Weighted-average number of shares outstanding - basic	33,608			23,851			28,812			24,455
Net effect of dilutive stock options, warrants and restricted stock units	—			—			—			—
Weighted-average number of shares outstanding - diluted	33,608			23,851			28,812			24,455

For all periods presented, the computation of diluted loss per share excludes the effect of certain outstanding stock options because their inclusion would be anti-dilutive. The number of options that were excluded from diluted loss per share were 948,803 during the three and six months ended June 30, 2016 and 963,169 during the three and six months ended June 30, 2015. Restricted stock units, which are not participating securities and are excluded from our basic and diluted earnings (loss) per share because they are anti-dilutive, were 1,077,663 for the three and six months ended June 30, 2016 and 495,227 for the three and six months ended June 30, 2015.


9.	Income Taxes

Our effective tax rate was (0.7)% and (0.8)% for the three and six months ended June 30, 2016, respectively and (17.1)% and (9.0)% for the three and six months ended June 30, 2015, respectively. The rate in all periods is primarily comprised of the effect of the Texas margin tax. For federal income tax purposes, we have applied a valuation allowance against any potential deferred tax asset which would have ordinarily resulted.


10.	Commitments and Contingencies

Purchase Commitments

As of June 30, 2016, we had outstanding purchase commitments to a number of suppliers totaling $26.0 million, net of deposits previously made, related primarily to the construction of drilling rigs. Of these commitments, $5.6 million relates to equipment currently scheduled for delivery in 2016, $13.1 million relates to equipment scheduled for delivery in 2017 and $7.2 million relates to equipment scheduled for delivery in 2018.

Lease Commitments

We lease certain equipment and vehicles under non-cancelable operating and capital leases. Future minimum lease payments under operating and capital lease commitments, with lease terms in excess of one year subsequent to June 30, 2016, were as follows:



(in thousands)
2016	$	227
2017	302
2018	127
2019	58
	$	714

As of June 30, 2016, property, plant and equipment in our balance sheets included $0.8 million of equipment under capital lease, net of $0.2 million of accumulated amortization. There were no capital leases as of December 31, 2015.

Contingencies

Our operations inherently expose us to various liabilities and exposures that could result in third-party lawsuits, claims and other causes of action. While we insure against the risk of these proceedings to the extent deemed prudent by our management, we can offer no assurance that the type or value of this insurance will meet the liabilities that may arise from any pending or future legal proceedings related to our business activities.


11.	Related Parties

During 2011, we entered into an asset contribution and share subscription agreement that involved our acquiring certain assets and liabilities from GES and Independence Contract Drilling LLC. One of our directors, was a director of the ultimate parent company of GES as of June 30, 2016, and one of our directors was a director of the ultimate parent company of GES through May 31, 2015. The director who continues to serve as a director of the ultimate parent company of GES is also the director of a fund that owned approximately 36% of the ultimate parent company of GES as of June 30, 2016.

We purchased certain items used in the construction of our drilling rigs from a former affiliate of GES. This vendor was sold by GES to a third party during the second quarter of 2015. As a related party, total purchases from the vendor amounted to $1.2 million during the six months ended June 30, 2015. We did not have any related party outstanding payables with this vendor as December 31, 2015.

One of our directors is also a director of one of our vendors from which we purchase oilfield and related supplies. Total purchases from this vendor were $7 thousand and $1.3 million during the three and six months ended June 30, 2016, respectively, and $3.1 million and $3.6 million during the three and six months ended June 30, 2015, respectively. We had no outstanding payables with this vendor as of June 30, 2016 and outstanding payables with this vendor of $0.1 million as of December 31, 2015.

During 2015, the son of a former executive officer and director of the Company began working in a sales capacity at, and became a minority owner of, a vendor from which we purchase oilfield equipment and related supplies. Total purchases from this vendor were $0.1 million during the three and six months ended June 30, 2016. We had outstanding payables of $12.0 thousand and $0.1 million as of June 30, 2016 and December 31, 2015, respectively. We did not do any business with this company during the first six months of 2015.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion and analysis of our financial condition and results of operations together with the financial statements and related notes that are included elsewhere in this Quarterly Report on Form 10-Q and with our audited financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2015, filed with the Securities and Exchange Commission on February 18, 2016 (the “Form 10-K”). This discussion contains forward-looking statements based upon current expectations that involve risks and uncertainties. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of various factors, including those described in the section titled "Cautionary Statement Regarding Forward-Looking Statements" and those set forth under Part 1“Item 1A. Risk Factors” or in other parts of the Form 10-K.

Management Overview

We were incorporated in Delaware on November 4, 2011. We provide land-based contract drilling services for oil and natural gas producers targeting unconventional resource plays in the United States. We construct, own and operate a premium fleet comprised entirely of technologically advanced, custom designed ShaleDriller® rigs that are specifically engineered and designed to optimize the development of our customers’ most technically demanding oil and gas properties. We are focused on creating stockholder and customer value through our commitment to operational excellence and our focus on safety.

In this regard, oil prices began to decline in the second half of 2014 and declined further during 2015 and 2016. The closing price of oil was as high as $106.06 per barrel during the third quarter of 2014, was $37.13 per barrel on December 31, 2015, but improved to a high of $51.23 during the second quarter of 2016 (WTI spot price as reported by the United States Energy Information Administration). Despite the recent moderate upturn in oil prices, our industry is still experiencing an exceptional overall downturn, market conditions remain very dynamic and are changing quickly. Although the magnitude, as well as the duration, of this downturn are not yet known, we believe that the remainder of 2016 will continue to be an exceptionally challenging year for ICD and our industry.

As a result of this deterioration in market conditions, our customers are principally focused on their most economic wells, drilling to maintain leasehold positions, and on maintaining their most cost efficient operations that deliver the overall lowest cost of producing their wells and minimize their capital expenditures. As a result, operators are focusing more of their capital spending on horizontal drilling programs compared to vertical drilling. They also are more focused on utilizing drilling equipment and techniques that optimize costs and efficiency. Thus, we believe this rapid market deterioration has significantly accelerated the pace of the ongoing land rig replacement cycle and continued shift to horizontal drilling from multi-well pads.

Emerging Growth Company

We are an emerging growth company ("EGC") as defined under the Jumpstart Our Business Startups Act of 2012, commonly referred to as the “JOBS Act”. We will remain an EGC for up to five years from the date of the completion of our initial public offering (the “IPO”) on August 13, 2014, or until the earlier of (1) the last day of the fiscal year in which our total annual gross revenues exceed $1 billion, (2) the date that we become a “large accelerated filer” as defined in Rule 12b-2 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), which would occur if the market value of our common equity that is held by non-affiliates is $700 million or more as of the last business day of our most recently completed second fiscal quarter or (3) the date on which we have issued more than $1 billion in non-convertible debt during the preceding three-year period.

As an EGC, we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not EGCs including, but not limited to:


•	not being required to comply with the auditor attestation requirements related to our internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act;


•	reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements; and


•	exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and shareholder approval of any golden parachute payments not previously approved.

In addition, Section 107 of the JOBS Act provides that an EGC can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended, for complying with new or revised accounting standards. Under this provision, an EGC can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies.

Recent Developments

Retirement and Resignation of Edward S. Jacob, III

On June 10, 2016, ICD and Edward S. Jacob, III, our President and Chief Operating, announced Mr. Jacob’s retirement as an officer of ICD effective June 30, 2016. ICD and Mr. Jacob also announced his resignation as director of ICD effective on June 30, 2016. In connection with Mr. Jacob’s retirement, ICD and Mr. Jacob entered into a Retirement Agreement on June 9, 2016 (the “Retirement Agreement”), setting out certain terms and conditions governing Mr. Jacob’s retirement. Under the terms of the Retirement Agreement, we agreed to make certain retirement benefits available to Mr. Jacob, including a cash retirement payment of approximately $1.5 million to be paid in one lump sum on January 2, 2017 and accelerated vesting of certain outstanding equity awards. The retirement payment and the impact from the accelerated vesting of equity awards are recorded as selling, general and administrative expense in our Statements of Operations for the quarter ended June 30, 2016.

Amendment of Revolving Credit Facility

On April 14, 2016, we entered into a Fourth Amendment to the Amended and Restated Credit Agreement dated November 5, 2014 (the “Fourth Amendment”), by and among ICD, the lenders party thereto and CIT, as Administrative Agent,

as so amended, and as otherwise amended, supplemented, revised, restated or otherwise modified from time to time, (the “Credit Agreement”).

Among other things, the Fourth Amendment (a) decreases the aggregate commitments under the Credit Agreement from $125.0 million to $85.0 million, but maintains the $25.0 million uncommitted accordion feature pursuant to which commitments may be increased in the future; (b) amends the Leverage Ratio, and Rig Utilization and Fixed covenants; (c) amends the advance rate on Eligible Equipment for purposes of calculating the borrowing base; and (d) adds a springing covenant associated with capital expenditures consistent with our previously announced capital plans.

In addition, in connection with the execution of the Fourth Amendment, the Administrative Agent has agreed to include certain capital spare equipment in the calculation of our borrowing base through December 31, 2016.

Public Offering of Common Stock

We used the net proceeds from this offering to repay a portion of the outstanding borrowings under our revolving credit facility and for general corporate purposes.

Our Revenues

We earn contract drilling revenues pursuant to drilling contracts entered into with our customers. We perform drilling services on a “daywork” basis, under which we charge a fixed rate per day, or “dayrate.” The dayrate associated with each of our contracts is a negotiated price determined by the capabilities of the rig, location, depth and complexity of the wells to be drilled, operating conditions, duration of the contract and market conditions. The term of land drilling contracts may be for a defined number of wells or for a fixed time period. While under contract, our rigs generally earn a reduced rate while the rig is moving between wells or drilling locations, or on standby waiting for the customer.

Our Operating Costs

Our operating costs include all expenses associated with operating and maintaining our drilling rigs. Operating costs include all “rig level” expenses such as labor and related payroll costs, repair and maintenance expenses, supplies, workers' compensation and other insurance, ad valorem taxes and equipment rental costs. Also included in our operating costs are certain costs that are not incurred at the “rig level.” These costs include expenses directly associated with our operations management team as well as our safety and maintenance personnel who are not directly assigned to our rigs but are responsible for the oversight and support of our operations and safety and maintenance programs across our fleet.

Our operating costs also include costs and expenses associated with construction activities at our Galayda yard location to the extent that construction activities cease or are not continuous. As a result of the significant downturn in industry conditions, we substantially reduced our rig construction activities during the fourth quarter of 2015 and the first six months of 2016. As a result, we began expensing a portion of our Galayda yard construction costs during the fourth quarter of 2015 and expect to continue expensing such costs until we resume continuous rig construction activities.

How We Evaluate our Operations

We regularly use a number of financial and operational measures to analyze and evaluate the performance of our business and compensate our employees, including the following:

•

Safety Performance. Maintaining a strong safety record is a critical component of our business strategy. We believe we are one of the few land drillers that utilizes a safety management system that complies with the Bureau of Safety and Environmental Enforcement’s SEMS II workplace safety rules. We measure safety by tracking the total recordable incident rate for our operations. In addition, we closely monitor and measure compliance with our safety policies and procedures, including “near miss” reports and job safety analysis compliance.

•

Utilization. Rig utilization measures the total amount of time that our rigs are earning revenue under a contract during a particular period. We measure utilization by dividing the total number of Operating Days for a rig by the total number of days the rig is available for operation in the applicable calendar period. A rig is available for operation commencing on the earlier of the date it spuds its initial well following construction or when it has been completed and is actively marketed. “Operating Days” represent the total number of days a rig is earning revenue under a

contract, beginning when the rig spuds its initial well under the contract and ending with the completion of the rig’s demobilization.


•	Revenue Per Day. Revenue per day measures the amount of revenue that an operating rig earns on a daily basis during a particular period. We calculate revenue per day by dividing total contract drilling revenue earned during the applicable period by the number of Operating Days in the period. Revenues attributable to costs reimbursed by customers are excluded from this measure.


•	Operating Cost Per Day. Operating cost per day measures the operating costs incurred on a daily basis during a particular period. We calculate operating cost per day by dividing total operating costs during the applicable period by the number of Operating Days in the period. Operating costs attributable to costs reimbursed by customers are excluded from this measure.


•	Operating Efficiency and Uptime. Maintaining our rigs’ operational efficiency is a critical component of our business strategy. We measure our operating efficiency by tracking each drilling rig’s unscheduled downtime on a daily, monthly, quarterly and annual basis.

Results of Operations

The following summarizes our financial and operating data for the three and six months ended June 30, 2016 and 2015:



	Three Months Ended						Six Months Ended
(In thousands, except per share data)	June 30, 2016			June 30, 2015			June 30, 2016			June 30, 2015
Revenues	$	15,155		$	21,082		$	37,610		$	43,388
Costs and expenses
Operating costs	7,398			12,057			19,965			25,163
Selling, general and administrative	5,005			3,755			8,626			7,582
Depreciation and amortization	5,816			5,169			11,641			9,458
(Insurance recoveries) asset impairment, net	—			—			—			(841		)
Loss (gain) on disposition of assets	37			(59		)	(88		)	334
Total cost and expenses	18,256			20,922			40,144			41,696
Operating (loss) income	(3,101		)	160			(2,534		)	1,692
Interest expense	(1,059		)	(717		)	(2,036		)	(1,029		)
(Loss) income before income taxes	(4,160		)	(557		)	(4,570		)	663
Income tax expense (benefit)	31			95			35			(60		)
Net (loss) income	$	(4,191	)	$	(652	)	$	(4,605	)	$	723

Other financial and operating data
Number of completed rigs (end of period) (1)	14			13			14			13
Rig operating days (2)	732.2			938.9			1,675.3			1,890.2
Average number of operating rigs (3)	8.0			10.3			9.2			10.4
Rig utilization (4)	65.6		%	79.4		%	75.9		%	85.3		%
Average revenue per operating day (5)	$	20,116		$	21,632		$	21,498		$	22,209
Average cost per operating day (6)	$	8,757		$	11,855		$	10,351		$	12,448
Average rig margin per operating day	$	11,359		$	9,777		$	11,147		$	9,761


(1)	Number of completed rigs as of June 30, 2016 increased by one compared to the number of completed rigs as of June 30, 2015, reflecting the addition of one newly constructed rig.

(2)

Rig operating days represent the number of days our rigs are earning revenue under a contract during the period, including days that standby revenues are earned. During the three and six months ended June 30, 2016, there were 368.4 and 554.1 operating days in which the Company earned revenue on a standby basis, respectively, including 362.9 and 525.0 standby-without-crew days, respectively. During the three and six months ended June 30, 2015, there were 240.1 and 423.8 operating days in which the Company earned revenue on a standby basis, respectively, including 85.0 and 85.0 standby-without-crew days, respectively.


(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 is calculated as rig operating days divided by the total number of days our drilling rigs are available during the applicable period. During the third quarter of 2015, the Company elected to remove its two 100 series non-walking rigs from its marketed fleet pending completion of their planned rig conversions to 200 series, pad-optimal status. Rig utilization during the first six months of 2016 excludes one of these 100 series rigs. The conversion of the other 100 series rig was completed during the second quarter of 2016 and the rig re-entered the marketed fleet in June 2016. Rig utilization excludes this rig during the first five months of 2016.

(5)

Average revenue per operating day represents total contract drilling revenues earned during the period divided by rig operating days in the period. Excluded in calculating average revenue per operating day are revenues associated with the reimbursement of out-of-pocket costs paid by customers of $0.4 million and $0.8 million during the three months ended June 30, 2016 and 2015, respectively, and $1.6 million and $1.4 million during the six months ended June 30, 2016 and 2015, respectively.

(6)

Average cost per operating day represents 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 $0.4 million and $0.8 million during the three months ended June 30, 2016 and 2015, respectively, and $1.6 million and $1.4 million during the six months ended June 30, 2016 and 2015, respectively, and (ii) new crew training costs of $0.1 million and $0.2 million during the three months ended June 30, 2016 and 2015, respectively, and $0.1 million and $0.2 million during the six months ended June 30, 2016 and 2015, respectively, and (iii) construction overhead costs expensed due to reduced rig construction activity of $0.5 million and $1.0 million during the three and six months of 2016.

Three Months Ended June 30, 2016 Compared to the Three Months Ended June 30, 2015

Revenues

Revenues for the three months ended June 30, 2016 were $15.2 million, representing a 28.1% decrease as compared to revenues of $21.1 million for the three months ended June 30, 2015. This decrease was directly attributable to a reduction in the average number of operating rigs between periods and an increase in the number of rigs earning revenue on a standby basis in 2016. On a revenue per operating day basis, our revenue per day decreased by 7.0% to $20,116 during the three months ended June 30, 2016, as compared to revenue per day of $21,632 for the three months ended June 30, 2015. This decrease resulted primarily from a larger number of rigs earning revenue on a standby basis compared to the prior year period.

Operating Costs

Operating costs for the three months ended June 30, 2016 were $7.4 million, representing a 38.6% decrease as compared to operating costs of $12.1 million for the three months ended June 30, 2015. This decrease was related to a reduction in operating rigs and a number of rigs operating on a standby-without-crew basis in the second quarter of 2016 as they incurred minimal operating costs. On a costs per operating day basis, our costs per operating day decreased to $8,757 per day during the three months ended June 30, 2016, representing a 26.1% decrease compared to cost per operating day of $11,855 for the three months ended June 30, 2015.

Selling, General and Administrative

Selling, general and administrative expenses for the three months ended June 30, 2016 were $5.0 million, representing a 33.3% increase as compared to selling, general and administrative expense of $3.8 million for the three months ended June 30, 2015. This increase primarily relates to the recognition of $1.5 million of expense associated with the retirement of our President and Chief Operating Officer as of June 30, 2016, partially offset by reduced compensation expense as compared to the three months ended June 30, 2015.

Depreciation and Amortization

Depreciation and amortization expense for the three months ended June 30, 2016 was $5.8 million, representing a 12.5% increase compared to depreciation and amortization expense of $5.2 million for the three months ended June 30, 2015. This increase was related primarily to the introduction of new drilling rigs constructed by us throughout 2015 and 2016. We begin depreciating our rigs when they commence drilling operations.

Loss (Gain) on Disposition of Assets

A loss on the disposition of assets totaling $37.0 thousand was recorded for the three months ended June 30, 2016 compared to a gain on the disposition of assets totaling $59.0 thousand in the prior year comparable period. In both quarters the loss or gain related to the sale or disposition of miscellaneous drilling equipment.

Interest Expense

Interest expense for the three months ended June 30, 2016 was $1.1 million, as compared to $0.7 million for the three months ended June 30, 2015. This increase was primarily due to the write-off of $0.5 million in deferred financing costs as a result of the reduction in aggregate commitments under the Credit Facility during the second quarter of 2016. Our interest expense is derived from borrowings under our revolving credit facility, which are primarily used to fund our rig construction activity and general corporate purposes.

Income Tax Expense

The income tax expense recorded for the three months ended June 30, 2016 amounted to $31.0 thousand compared to income tax expense of $95.0 thousand for the three months ended June 30, 2015. Our effective tax rates for the three months ended June 30, 2016 and 2015 were (0.7)% and (17.1)%, respectively. All taxes in both the current and prior year period relate to Texas Margin Tax.

Six Months Ended June 30, 2016 Compared to the Six Months Ended June 30, 2015

Revenues

Revenues for the six months ended June 30, 2016 were $37.6 million, representing a 13.3% decrease compared to revenues of $43.4 million for the six months ended June 30, 2015. This decrease was primarily related to the average number of operating rigs of 9.2 during the six months ended June 30, 2016 compared to 10.4 during the six months ended June 30, 2015. Revenue per operating day decreased to $21,498 during the six months ended June 30, 2016 compared to revenue per day of $22,209 for the six months ended June 30, 2015. This decrease resulted primarily from lower average day rates as compared to the prior year period.

Operating Costs

Operating costs for the six months ended June 30, 2016 were $20.0 million, representing a 20.7% decrease compared to operating costs of $25.2 million for the six months ended June 30, 2015. This decrease was related to a reduction in operating rigs and a number of rigs operating on a standby-without-crew basis in the first six months of 2016 as they incurred minimal operating costs. On a cost per operating day basis, our cost per day decreased to $10,351 during the six months ended June 30, 2016, representing a 16.8% decrease compared to cost per day of $12,448 for the six months ended June 30, 2015.

Selling, General and Administrative

Selling, general and administrative expenses for the six months ended June 30, 2016 were $8.6 million, representing a 13.8% increase compared to selling, general and administrative expenses of $7.6 million for the six months ended June 30, 2015. This increase primarily relates to the recognition of $1.5 million of expense associated with the retirement of our Chief Operating Officer as of June 30, 2016, offset by reduced compensation expense as compared to the comparable period.

Depreciation and Amortization

Depreciation and amortization expense for the six months ended June 30, 2016 was $11.6 million, representing a 23.1% increase compared to depreciation and amortization expense of $9.5 million for the six months ended June 30, 2015. This increase was primarily to the introduction of new drilling rigs constructed by us throughout 2015 and 2016. We begin depreciating our rigs when they commence drilling operations.

Loss (Gain) on Disposition of Assets

A gain on the disposition of assets totaling $0.1 million was recorded for the six months ended June 30, 2016 compared to a loss on the disposition of assets totaling $0.3 million in the prior year comparable period. In both periods, the amounts related to the sale or disposition of miscellaneous drilling equipment.

Interest Expense

Interest expense for the six months ended June 30, 2016 was $2.0 million compared to interest expense of $1.0 million for the six months ended June 30, 2015. This increase was primarily due to the write-off of $0.5 million in deferred financing costs as a result of the reduction in our borrowing capacity associated with the Amended Credit Facility during the second quarter of 2016 and reduced construction activity. Our interest expense is derived from borrowings under our revolving credit facility, which are primarily used to fund our rig construction activity and daily operations.

Income Tax Expense (Benefit)

The income tax expense recorded for the six months ended June 30, 2016 amounted to $35.0 thousand compared to an income tax benefit of $60.0 thousand for the six months ended June 30, 2015. The effective tax rates for the six months ended June 30, 2016 and 2015 were (0.8)% and (9.0)%, respectively. All taxes in both the current and prior year period relate to Texas Margin Tax.

Liquidity and Capital Resources

Our liquidity as of June 30, 2016 included approximately $64.3 million of availability under our revolving credit facility, $7.1 million of cash and $1.7 million of other net working capital. The aggregate commitments under our revolving credit facility are currently $85.0 million, and the borrowing base under our credit facility at June 30, 2016, was $80.7 million.

Our principal use of capital has been the construction of drilling rigs and associated equipment and working capital and inventories to support our drilling operations. Our first drilling rig was completed and began operating in May 2012. As of June 30, 2016, we had 14 rigs, including thirteen completed 200 series ShaleDriller® rigs and one non-walking rig. We have the ability to upgrade our remaining non-walking rig to 200 Series status when market conditions improve, but until such time this rig has been decommissioned, and we do not intend to market it. Our primary sources of capital to date have been funds received from our initial private placement, our IPO, our recent public offering and cash flows from operations and our revolving credit facility.

Net Cash Provided By Operating Activities

Cash provided by operating activities was $15.4 million for the six months ended June 30, 2016 compared to cash provided by operating activities of $17.8 million during the same period in 2015. Factors affecting changes in operating cash flows are similar to those that impact net earnings, with the exception of non-cash items such as depreciation and amortization, impairments, gains or losses on disposals of assets, stock-based compensation, deferred taxes and amortization of deferred financing costs. Additionally, changes in working capital items such as accounts receivable, inventory, prepaid expense and accounts payable can significantly affect operating cash flows. Cash flows from operating activities during the first six months of 2016 were lower as a result of a decrease in net loss, adjusted for non-cash items, of $10.1 million for the six months ended June 30, 2016 compared to $11.8 million during the same period in 2015. Working capital changes increased cash flows from operating activities by $5.3 million for the six months ended June 30, 2016 compared to $6.0 million during the same period in 2015.

Net Cash Used In Investing Activities

Cash used in investing activities was $9.6 million for the six months ended June 30, 2016 compared to cash used in investing activities of $55.0 million during the same period in 2015. During the first six months of 2016, cash payments of $10.5 million for capital expenditures, related primarily to the non-walking rig upgrade, were offset by insurance proceeds of $0.2 million and proceeds from the sale of property, plant and equipment of $0.7 million. Cash payments during the first six months of 2016 included approximately $2.6 million associated with equipment purchased in 2015. During the 2015 period, cash payments of $58.2 million for capital expenditures related primarily to new rig construction, were offset by the receipt of insurance proceeds of $2.9 million and proceeds from the sale of property, plant and equipment of $0.4 million.

Net Cash (Used In) Provided by Financing Activities

Cash used in financing activities was $4.1 million for the six months ended June 30, 2016 compared to cash provided by financing activities of $38.7 million during the same period in 2015. During the first six months of 2016, we received proceeds of $43.0 million from a public offering and made borrowings under our revolving credit facility of $34.8 million. These proceeds were offset by repayments under our revolving credit facility of $81.1 million, financing costs paid associated with the amendment to the credit facility of $0.2 million, the purchase of treasury stock $0.2 million and payments for capital lease obligations of $0.3 million. During the first six months of 2015, we made borrowings under our revolving credit facility of $89.6 million. These proceeds were offset by repayments under our revolving credit facility of $50.7 million and expenditures for deferred financing costs of $0.2 million.

Future Liquidity Requirements

We expect our future capital and liquidity needs to be related to funding capital expenditures for the conversion of a non-walking rig to pad optimal status, rig upgrades, operating expenses, maintenance capital expenditures, working capital and general corporate purposes. In light of current market conditions and lack of visibility relating to the timing of any market recovery, we have suspended new build construction activities until market conditions improve. We believe that our cash and cash equivalents, cash flows from operating activities and borrowings under our revolving credit facility will adequately finance all of our purchase commitments, capital expenditures and other cash requirements over the next 12 months.

Long-term Debt

In November 2014, we entered into an amended and restated credit agreement (the “Credit Facility”) with a syndicate of financial institutions led by CIT Finance, LLC, that provided for a committed $155.0 million revolving credit facility and an additional uncommitted $25.0 million accordion feature that allowed for future increases in the facility. On April 23, 2015, we amended the Credit Facility to provide for a springing lock-box arrangement. On October 20, 2015, in light of current market conditions and our reduced capital plans, we entered into an amendment to the Credit Facility to reduce aggregate commitments to $125.0 million and modified certain maintenance covenants. On April 14, 2016, we again amended the Credit Facility to reduce aggregate commitments to $85.0 million and further modify certain maintenance covenants. The obligations under the Credit Facility are secured by all of our assets and are unconditionally guaranteed by all of our current and future direct and indirect subsidiaries.

Borrowings under the Credit Facility are subject to a borrowing base formula that allows for borrowings of up to 85% of eligible trade accounts receivable not more than 90 days outstanding, plus up to 72.5% of the appraised forced liquidation value of our eligible, completed and owned drilling rigs. This advance rate declines 1.25% per quarter beginning in 2017. Rigs that remain idle for 90 consecutive days or longer are removed from the borrowing base until they are contracted. In addition, rigs are appraised on a semi-annual basis and are subject to upward or downward revisions as a result of market conditions as well as the age of the rig. The Credit Facility matures on November 5, 2018.

springing lock-box event occurs, regardless of the actual maturity of the borrowings. The Fourth Amendment reduces the requirement for a mandatory lock-box trigger from $15 million of availability under the credit facility to $10 million of availability under the Credit Facility.

In addition, in connection with the execution of the Fourth Amendment, the Administrative Agent under our revolving credit facility has agreed to include certain capital spare equipment in the calculation of our borrowing base through December 31, 2016. We had $16.4 million in outstanding borrowings under the Credit Facility at June 30, 2016. Remaining availability under the Credit Facility was $64.3 million at June 30, 2016, based on the amended borrowing base formula, and we are currently in compliance with all covenants under the Credit Facility.

Other Matters

Off-Balance Sheet Arrangements

We are party to certain arrangements defined as “off-balance sheet arrangements” that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors. These arrangements relate to non-cancelable operating leases and unconditional purchase obligations not fully reflected on our balance sheets. See note 10 in Part 1 “Item 1. Financial Statements” for additional information.

Emerging Growth Company

Recent Accounting Pronouncements

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to a variety of market risks including risks related to potential adverse changes in interest rates and commodity prices. We actively monitor exposure to market risk and continue to develop and utilize appropriate risk management techniques. We do not use derivative financial instruments for trading or to speculate on changes in commodity prices.

Interest Rate Risk

Total long-term debt at June 30, 2016 included $16.4 million of floating-rate debt attributed to borrowings at an average interest rate of 5.18%. As a result, our annual interest cost in 2016 will fluctuate based on short-term interest rates.

The impact on annual cash flow of a 10% change in the floating-rate (approximately 0.52%) would be approximately $0.1 million annually based on the floating-rate debt and other obligations outstanding at June 30, 2016; however, there are no assurances that possible rate changes would be limited to such amounts.

Commodity Price Risk

The demand for contract drilling services is a result of E&P companies spending money to explore and develop drilling prospects in search of oil and natural gas. This customer spending is driven by their cash flow and financial strength, which is affected by trends in crude oil and natural gas commodity prices. Crude oil prices are determined by a number of factors including supply and demand, worldwide economic conditions and geopolitical factors. Crude oil and natural gas prices have historically been volatile and very difficult to predict. This volatility can lead many E&P companies to base their capital spending on much more conservative estimates of commodity prices. As a result, demand for contract drilling services is not always purely a function of the movement of current commodity prices. Oil prices began to decline in the second half of 2014 and declined further during 2015 and 2016. The closing price of oil was as high as $106.06 per barrel during the third quarter of 2014, was $37.13 per barrel on December 31, 2015, but improved to a high of $51.23 during the second quarter of 2016 (WTI spot price as reported by the United States Energy Information Administration). Despite the recent moderate upturn in oil prices, our industry is still experiencing an exceptional overall downturn, market conditions remain very dynamic and are changing quickly. Although the magnitude, as well as the duration, of this downturn are not yet known, we believe that 2016 will continue to be an exceptionally challenging year for ICD and our industry.

Credit and Capital Market Risk

Our customers may finance their drilling activities through cash flow from operations, the incurrence of debt or the issuance of equity. Any deterioration in the credit and capital markets, as currently being experienced, can make it difficult for our customers to obtain funding for their capital needs. A reduction of cash flow resulting from declines in commodity prices, such as we are currently experiencing, or a reduction of available financing may result in a reduction in customer spending and the demand for our drilling services. This reduction in spending could have a material adverse effect on our business, financial condition and results of operations.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Our principal executive officer and principal financial officer have concluded that our current disclosure controls and procedures were effective as of June 30, 2016 at the reasonable assurance level.

Changes in Internal Control Over Financial Reporting

During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We may be the subject of lawsuits and claims arising in the ordinary course of business from time to time. Management cannot predict the ultimate outcome of such lawsuits and claims. While lawsuits and claims are asserted for amounts that may be material should an unfavorable outcome be the result, management does not currently expect that the outcome of any of these known legal proceedings or claims will have a material adverse effect on our financial position or results of operations.

ITEM 1A. RISK FACTORS

In addition to the other information set forth in this report, you should carefully consider the risks discussed in Part 1, "Item 1A. Risk Factors" in our Annual Report on Form 10-K for the year ended December 31, 2015. There has been no material change in our risk factors from those described in the Annual Report. These risks are not the only risks that we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may materially adversely affect our business, financial condition or results of operations.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Issuer Purchases of Equity Securities

During the second quarter of 2016, we withheld shares of our common stock to satisfy minimum tax withholding obligations in connection with the vesting of certain restricted stock awards. These shares are deemed to be “issuer purchases” of shares that are required to be disclosed pursuant to this Item but were not purchased as part of a publicly announced program to purchase common shares. The following table provides information relating to our repurchase of shares of common stock during the three months ended June 30, 2016 (dollars in thousands, except average price paid per share):



	Issuer Purchases of Equity Securities
Period	Total Number of Shares Purchased	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Program	Approximate Dollar Value of Shares That May Yet be Purchased Under the Program (1)
April 1 — April 30	—	$	—	—	$	—
May 1 — May 31	—	$	—	—	$	—
June 1 — June 30	33,748	$	5.43	—	$	—

(1) We do not have a current share repurchase program authorized by the board of directors.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not Applicable.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS



Exhibit Number		Description

3.1		Amended and Restated Certificate of Incorporation of Independence Contract Drilling, Inc. (Incorporated by reference to the Company’s Current Report on Form 8-K (File No. 001-36590) filed August 13, 2014, Exhibit 3.1)

3.2		Amended and Restated Bylaws of Independence Contract Drilling, Inc. (Incorporated by reference to the Company’s Registration Statement on Form S-1 (File No. 333-196914) filed July 18, 2014, Exhibit 3.3)

10.1		Fourth Amendment to Amended and Restated Credit Agreement, dated as of April 14, 2016, by and among Independence Contract Drilling, Inc., the Lenders party thereto and CIT Finance LLC as Administrative Agent and Collateral Agent, as Issuing Bank and as Swingline Lender (Incorporated by reference to the Company's Current Report on Form 8-K (File No. 001-36590) filed April 14, 2016, Exhibit 10.1)

10.2		Amendment No. 1 to the Second Amended and Restated Independence Contract Drilling, Inc. 2012 Omnibus Incentive Plan (Incorporated by reference to the Company’s Current Report on Form 8-K (File No. 001-36590) filed June 24, 2016.)

10.3		Retirement Agreement dated June 9, 2015, by and between Independence Contract Drilling, Inc. and Edward S. Jacob, III (Incorporated by reference to the Company’s Current Report on Form 8-K (File No. 001-36590) filed June 10, 2016.)

31.1*		Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act

31.2*		Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act

32.1*		Certification of Chief Executive Officer pursuant to 18 U.S.C Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2*		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101.CAL*		XBRL Calculation Linkbase Document

101.DEF*		XBRL Definition Linkbase Document

101.INS*		XBRL Instance Document

101.LAB*		XBRL Labels Linkbase Document

101.PRE*		XBRL Presentation Linkbase Document

101.SCH*		XBRL Schema Document


*	Filed with this report

SIGNATURES

Pursuant to the requirements 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.



INDEPENDENCE CONTRACT DRILLING, INC.
By:	/s/ Byron A. Dunn
	Name:	Byron A. Dunn
	Title:	President and Chief Executive Officer (Principal Executive Officer)



By:	/s/ Philip A. Choyce
	Name:	Philip A. Choyce
	Title:	Senior Vice President, Chief Financial Officer, Treasurer and Secretary (Principal Financial Officer)



By:	/s/ Michael J. Harwell
	Name:	Michael J. Harwell
	Title:	Vice President - Finance and Chief Accounting Officer (Principal Accounting Officer)

Date: July 28, 2016

Independence Contract Drilling, Inc. - FORM 10-Q - July 28, 2016

Attached files

Independence Contract Drilling, Inc. Reports