Edgar Filing: Independence Contract Drilling, Inc.

Document

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, 2017


¨	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, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer” “smaller reporting company” and "emerging growth 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	¨

		Emerging growth company	x

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. x

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

37,807,467 shares of the registrant’s Common Stock were outstanding as of July 24, 2017.

INDEPENDENCE CONTRACT DRILLING, INC.

Index to Form 10-Q



Part I. FINANCIAL INFORMATION

Item 1. Financial Statements

Balance Sheets as of June 30, 2017 and December 31, 2016 (Unaudited)		4

Statements of Operations for the three and six months ended June 30, 2017 and 2016 (Unaudited)		5

Statement of Stockholders’ Equity for the six months ended June 30, 2017 (Unaudited)		6

Statements of Cash Flows for the six months ended June 30, 2017 and 2016 (Unaudited)		7

Notes to the Financial Statements (Unaudited)		8

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		17

Item 3. Quantitative and Qualitative Disclosures About Market Risk		28

Item 4. Controls and Procedures		28

Part II. OTHER INFORMATION

Item 1. Legal Proceedings		30

Item 1A. Risk Factors		30

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		30

Item 3. Defaults Upon Senior Securities		30

Item 4. Mine Safety Disclosures		30

Item 5. Other Information		30

Item 6. Exhibits		31

Signatures		32

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in this Quarterly Report on 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 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, 2016. 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, 2017			December 31, 2016
Assets
Cash and cash equivalents	$	5,465		$	7,071
Accounts receivable, net	12,946			11,468
Inventories	2,407			2,336
Assets held for sale	6,388			3,915
Prepaid expenses and other current assets	3,737			3,102
Total current assets	30,943			27,892
Property, plant and equipment, net	271,725			273,188
Other long-term assets, net	865			1,027
Total assets	$	303,533		$	302,107
Liabilities and Stockholders’ Equity
Liabilities
Current portion of long-term debt	$	468		$	441
Accounts payable	10,825			10,031
Accrued liabilities	5,867			7,821
Total current liabilities	17,160			18,293
Long-term debt	39,527			26,078
Deferred income taxes	476			396
Other long-term liabilities	1			88
Total liabilities	57,164			44,855
Commitments and contingencies (Note 10)
Stockholders’ equity
Common stock, $0.01 par value, 100,000,000 shares authorized; 38,025,637 and 37,831,723 shares issued, respectively; and 37,807,467 and 37,617,920 shares outstanding, respectively	378			376
Additional paid-in capital	325,630			323,918
Accumulated deficit	(77,920		)	(65,347		)
Treasury stock, at cost, 218,170 and 213,803 shares, respectively	(1,719		)	(1,695		)
Total stockholders’ equity	246,369			257,252
Total liabilities and stockholders’ equity	$	303,533		$	302,107

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,
	2017			2016			2017			2016
Revenues	$	21,285		$	15,155		$	41,521		$	37,610
Costs and expenses
Operating costs	15,808			7,398			30,706			19,965
Selling, general and administrative	3,435			5,005			7,153			8,626
Depreciation and amortization	6,335			5,816			12,591			11,641
Asset impairment, net	546			—			675			—
Loss (gain) on disposition of assets, net	745			37			1,573			(88		)
Total costs and expenses	26,869			18,256			52,698			40,144
Operating loss	(5,584		)	(3,101		)	(11,177		)	(2,534		)
Interest expense	(686		)	(1,059		)	(1,316		)	(2,036		)
Loss before income taxes	(6,270		)	(4,160		)	(12,493		)	(4,570		)
Income tax expense	34			31			80			35
Net loss	$	(6,304	)	$	(4,191	)	$	(12,573	)	$	(4,605	)
Loss per share:
Basic and diluted	$	(0.17	)	$	(0.12	)	$	(0.33	)	$	(0.16	)
Weighted average number of common shares outstanding:
Basic and diluted	37,679			33,608			37,613			28,812

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

Independence Contract Drilling, Inc.

Statement 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, 2016	37,617,920		$	376	$	323,918		$	(65,347	)	$	(1,695	)	$	257,252
Restricted stock forfeited	(3,195	)	—		—			—			—			—
RSUs vested, net of shares withheld for taxes	197,109		2		(457		)	—			—			(455		)
Purchase of treasury stock	(4,367	)	—		—			—			(24		)	(24		)
Stock-based compensation	—		—		2,169			—			—			2,169
Net loss	—		—		—			(12,573		)	—			(12,573		)
Balances at June 30, 2017	37,807,467		$	378	$	325,630		$	(77,920	)	$	(1,719	)	$	246,369

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)	2017			2016
Cash flows from operating activities
Net loss	$	(12,573	)	$	(4,605	)
Adjustments to reconcile net loss to net cash provided by operating activities
Depreciation and amortization	12,591			11,641
Asset impairment, net	675			—
Stock-based compensation	2,169			2,360
Stock-based compensation - executive retirement	—			(67		)
Loss (gain) on disposition of assets, net	1,573			(88		)
Deferred income taxes	80			36
Amortization of deferred financing costs	250			283
Write-off of deferred financing costs	—			504
Changes in operating assets and liabilities
Accounts receivable	(1,478		)	11,368
Inventories	(3		)	(146		)
Prepaid expenses and other assets	(644		)	176
Accounts payable and accrued liabilities	(392		)	(6,078		)
Net cash provided by operating activities	2,248			15,384
Cash flows from investing activities
Purchases of property, plant and equipment	(17,367		)	(10,521		)
Proceeds from insurance claims	—			188
Proceeds from the sale of assets	1,060			747
Net cash used in investing activities	(16,307		)	(9,586		)
Cash flows from financing activities
Borrowings under credit facility	22,611			34,775
Repayments under credit facility	(9,363		)	(81,129		)
Public offering proceeds, net of offering costs	—			42,983
Purchase of treasury stock	(24		)	(183		)
RSUs withheld for taxes	(455		)	—
Financing costs paid	(8		)	(217		)
Payments for capital lease obligations	(308		)	(285		)
Net cash provided by (used in) financing activities	12,453			(4,056		)
Net (decrease) increase in cash and cash equivalents	(1,606		)	1,742
Cash and cash equivalents
Beginning of period	7,071			5,344
End of period	$	5,465		$	7,086
Supplemental disclosure of cash flow information
Cash paid during the period for interest	$	1,157		$	1,426
Supplemental disclosure of non-cash investing and financing activities
Change in property, plant and equipment purchases in accounts payable	$	(855	)	$	(2,577	)
Additions to property, plant and equipment through capital leases	$	536		$	965

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

INDEPENDENCE CONTRACT DRILLING, INC.

Notes to Financial Statements

(Unaudited)


1.	Nature of Operations

Except as expressly stated or the context otherwise requires, the terms "we," "us," "our," "ICD," and the "Company" refer to Independence Contract Drilling, Inc.

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 fleet comprised entirely of custom designed ShaleDriller® rigs.

Our standardized fleet currently consists of 14 premium 200 Series ShaleDriller® rigs, all of which are equipped with our integrated omni-directional walking systems. Our final rig that was converted to 200 Series status during the second quarter of 2017 will commence operating during the third quarter of 2017. Every ShaleDriller® rig in our fleet is a 1500-hp, AC programmable rig designed to be fast-moving between drilling sites and is equipped with 7500 psi mud systems, top drives, automated tubular handling systems and blowout preventer handling systems. All 14 of our 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 commenced 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 operating in the Permian Basin, Eagle Ford Shale and the Haynesville Shale, however, our rigs have previously operated in the Mid-Continent and Eaglebine regions as well.

Our business depends on the level of exploration and production activity by oil and natural gas companies operating in the United States, and in particular, the regions where we actively market our contract drilling services. The oil and natural gas exploration and production industry is a historically cyclical industry characterized by significant changes in the levels of exploration and development activities. Oil and natural 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 natural 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 United States and the regions where we market our contract drilling services, whether resulting from changes in oil and natural gas prices or otherwise, could materially and adversely affect our business.

Oil and Natural Gas Prices and Drilling Activity

Oil prices began to decline in the second half of 2014, declined further during 2015 and remained low in 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, and reached a low of $26.19 on February 11, 2016 (WTI spot price as reported by the United States Energy Information Administration). As a result, our industry experienced an exceptional downturn and market conditions have only begun to stabilize and slowly recover.

Recently, and in particular, following the November 2016 decision by the Organization of Petroleum Exporting Countries (“OPEC”) to reduce production quotas, oil prices began to recover. However, there are no indications at this time that oil prices and rig counts will recover, in the near term to their previous highs experienced in 2014.

As market conditions have improved from trough levels in 2016 and begun to stabilize, demand for our ShaleDriller® rigs has improved. At June 30, 2017, all of our rigs were under contract. In addition to improving utilization, contract tenors are improved with customers willing to sign term contracts of six to twelve months or longer, and at higher dayrates compared to trough levels. However, the pace and duration of the current recovery is unknown, and recently, oil prices have fallen below $45 per barrel at times. If oil prices were to fall below $45 per barrel for any sustained period of time, market conditions and demand for our products and services could deteriorate.

Amendment to Revolving Credit Facility

On July 14, 2017, we amended our existing credit facility ("the Credit Facility"). The Credit Facility amendment maintained the aggregate commitments under the facility at $85 million and extended the maturity date two years to November 5, 2020. In addition, the amendment provided for an additional uncommitted $65.0 million accordion feature that allows for future increases in facility commitments.

The Credit Facility is secured by substantially all of our assets. Borrowings under the 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 75% of the appraised forced liquidation value of our eligible, completed and owned drilling rigs. Beginning on October 1, 2017, the 75% advance rate on our eligible completed and owned drilling rigs decreases by 1.25% per quarter, subject to a floor of 65%. At June 30, 2017, our aggregate borrowings under the credit facility were $39.0 million and the borrowing base was $89.7 million. Proforma for the amendment our borrowing base would have been $95.4 million.

Interest under the Credit Facility remains unchanged. The amendment contained various changes to the financial and other covenants to accommodate the extension in term, including changes to the leverage ratio covenant, fixed charge coverage ratio covenant and rig utilization ratio covenant.

Assets Held For Sale

During the fourth quarter of 2016, we began a review of our rig fleet and other capital equipment with a focus on opportunities to standardize certain rig components across our fleet. The standardization of this equipment creates operating efficiencies in maintaining this equipment, as well as efficiencies when crews transfer between rigs. As a result of our review, we identified several non-standard items which, while fully functional, were less than optimal from an operations perspective. Such assets were classified as held for sale on our December 31, 2016 balance sheet. In the second quarter of 2017, we sold $1.6 million of these assets and recognized a loss on the sale of assets of $0.8 million.

During the second quarter of 2017, our management committed to a plan to sell our corporate headquarters and rig assembly yard complex located at 11601 North Galayda Street, Houston, Texas, in order to relocate to office space and a yard facility more suitable to our needs. As a result, we reclassified an aggregate $4.0 million of land, buildings and equipment from property, plant and equipment to assets held for sale on our June 30, 2017 balance sheet and recognized a $0.5 million asset impairment charge representing the difference between the carrying value and the fair value, less the costs to sell the related property.


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 (“GAAP”). These financial statements should be read along with our audited financial statements for the year ended December 31, 2016, included in our Annual Report on Form 10-K for the year ended December 31, 2016. 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, 2017 may not be indicative of results that will be realized for the full year ending December 31, 2017.

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 Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers, 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 in the process of evaluating the impact this guidance will have on our financial statements and have engaged a third party expert to assist us on this evaluation process. We, along with our third party experts, have identified and begun to analyze a sample of contracts that are representative of our business and are in the process of performing a detailed analysis of the performance obligations and pricing arrangements therein. We are also still evaluating the portion of our contract drilling revenues that will be subject to the new leasing guidance discussed below. We currently expect to adopt this new guidance utilizing the modified retrospective approach. Once this new guidance is adopted, additional disclosures will be required in our financial statements.

In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers: Narrow-Scope Improvements and Practical Expedients, to address certain narrow aspects of ASU No. 2014-09 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 in the process of evaluating the impact this guidance will have on our financial statements and have engaged a third party expert to assist us on this evaluation process. Once this new guidance is adopted, additional disclosures will be required in our financial statements.

In February 2016, the FASB issued ASU No. 2016-02, Leases, 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. We are currently evaluating the impact this guidance will have on our financial statements with respect to revenue recognition as a lessor, and have engaged a third party expert to assist us on this evaluation process. Furthermore, the majority of our operating leases with lease terms greater than twelve months, where we are the lessee, are currently accounted for as capital leases.

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses: Measurement of Credit Losses on Financial Instruments, as additional guidance on the measurement of credit losses on financial instruments. The new guidance requires the measurement of all expected credit losses for financial assets held at the reporting date based on historical experience, current conditions and reasonable supportable forecasts. In addition, the guidance amends the accounting for credit losses on available-for-sale debt securities and purchased financial assets with credit deterioration. The new guidance is effective for SEC filers for interim and annual periods beginning after December 15, 2019, with early adoption permitted for interim and annual periods beginning after December 15, 2018. We are in the initial stages of evaluating the impact this guidance will have on our accounts receivable.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows, to address diversity in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The update addresses the following eight specific cash flow issues: Debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies (COLIs) (including bank-owned life insurance policies (BOLIs)); distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. The amendments are effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. We expect the implementation of this standard to change the classification of the described transactions within our Statement of Cash Flows.


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 or liabilities; 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 5.9%. 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 $39.5 million and $26.6 million as of June 30, 2017 and December 31, 2016, respectively, compared to a carrying amount of $39.5 million and $26.1 million as of June 30, 2017 and December 31, 2016, 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.	Inventories

All of our inventory as of June 30, 2017 and December 31, 2016 consisted of rig components and supplies.


5.	Accrued Liabilities

Accrued liabilities consisted of the following:



(in thousands)	June 30, 2017		December 31, 2016
Accrued salaries and other compensation	$	1,754	$	3,784
Insurance	1,094		787
Deferred revenues	1,248		1,139
Property, sales and other taxes	1,623		1,943
Other	148		168
	$	5,867	$	7,821


6.	Long-term Debt

Our Long-term Debt consisted of the following:



(in thousands)	June 30, 2017			December 31, 2016
Credit facility due November 5, 2018	$	39,000		$	25,752
Capital lease obligations	995			767
	39,995			26,519
Less: current portion	(468		)	(441		)
Long-term debt	$	39,527		$	26,078

Credit Facility

In November 2014, we entered into an amended and restated credit agreement 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. In April 2015, we amended the Credit Facility to provide for a springing lock-box arrangement. In October 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. In April 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.

On July 14, 2017, we again amended our existing Credit Facility. The Credit Facility amendment maintained the aggregate commitments at $85 million and extended the maturity date two years to November 5, 2020. In addition, the amendment provided for an additional uncommitted $65.0 million accordion feature that allows for future increases in facility commitments. The amendment contained various changes to the financial and other covenants to accommodate the extension in term, including changes to the leverage ratio covenant, fixed charge coverage ratio covenant and rig utilization ratio covenant. Additionally, the advance rate increased to 75% through September 30, 2017, decreasing 1.25% per quarter, subject to a floor of 65%. At June 30, 2017, our aggregate borrowings under the Credit Facility were $39.0 million and the borrowing base was $89.7 million. Proforma for the amendment our borrowing base would have been $95.4 million.

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. Under the Credit Facility, for purposes of calculating EBITDA, non-cash stock-based compensation expense is added back to EBITDA, as well as up to $2.0 million of previously capitalized construction costs that may be incurred in 2017. The Credit Facility also permits us to incur up to $20.0 million of additional indebtedness for the purchase of additional rigs or rig equipment. As of June 30, 2017, we are in compliance with these covenants.

The Credit Facility provides that an event of default may occur if a material adverse change to ICD occurs, which is considered a subjective acceleration clause under applicable accounting rules. In accordance with 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 requirement for a mandatory lock-box trigger occurs when availability under the Credit Facility is $10.0 million or less.

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 75% of the appraised forced liquidation value of our eligible, completed and owned drilling rigs. 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 two 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.

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, 2017, the weighted average interest rate on our borrowings was 5.68%.

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 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, 2017, approximately 1,194,974 shares were available for future awards.

In the first quarter of 2017, we adopted ASU 2016-09, Compensation - Stock Compensation: Improvements to Employee Share-Based Payment Accounting. The FASB issued this accounting standard in an effort to simplify the accounting for employee share-based payments and improve the usefulness of the information provided to users of financial statements. Our policy is to account for forfeitures of share-based compensation awards as they occur.

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,
	2017		2016		2017		2016
Compensation cost recognized:
Stock options	$	—	$	3	$	—	$	72
Restricted stock and restricted stock units	1,157		1,135		2,169		2,221
Total stock-based compensation	$	1,157	$	1,138	$	2,169	$	2,293

No stock-based compensation was capitalized in connection with rig construction activity during the three and six months ended June 30, 2017 or the three and six months ended June 30, 2016.

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, 2017 or the six months ended June 30, 2016.

A summary of stock option activity and related information for the six months ended June 30, 2017 is as follows:



	Six Months Ended June 30, 2017
	Options		Weighted Average Exercise Price
Outstanding at January 1, 2017	935,720		$	12.74
Granted	—		—
Exercised	—		—
Forfeited/expired	(135,020	)	12.74
Outstanding at June 30, 2017	800,700		$	12.74
Exercisable at June 30, 2017	800,700		$	12.74

The number of options vested at June 30, 2017 was 800,700 with a weighted average remaining contractual life of 4.8 years and a weighted average exercise price of $12.74 per share. There were no unvested options or unrecognized compensation cost related to outstanding stock options at June 30, 2017.

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 vesting period. The fair value of restricted stock awards is determined based on the estimated fair market value of our shares on the grant date. As of June 30, 2017, there was $0.2 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 0.1 years.

A summary of the status of our restricted stock awards as of June 30, 2017, and of changes in restricted stock outstanding during the six months ended June 30, 2017, is as follows:



	Six Months Ended June 30, 2017
	Shares		Weighted Average Grant-Date Fair Value Per Share
Outstanding at January 1, 2017	147,368		$	10.67
Granted	—		—
Vested	(15,968	)	8.35
Forfeited	(3,195	)	8.35
Outstanding at June 30, 2017	128,205		$	11.02

Restricted Stock Units

We have granted restricted stock units ("RSUs") to key employees under the 2012 Plan. We have granted three-year cliff 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 two shares of ICD common stock with no exercise price. Exercisability 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, safety or uptime performance statistics, 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. The fair value of the performance-based RSUs is 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, 2017, there was $4.3 million of total unrecognized compensation cost related to unvested RSUs. This cost is expected to be recognized over a weighted average period of 1.1 years.

A summary of the status of our RSUs as of June 30, 2017, and of changes in RSUs outstanding during the six months ended June 30, 2017, is as follows:



	Six Months Ended June 30, 2017
	RSUs		Weighted Average Grant-Date Fair Value Per Share
Outstanding at January 1, 2017	1,030,658		$	7.18
Granted	656,631		5.76
Vested and converted	(197,109	)	4.75
Forfeited	(122,357	)	5.47
Outstanding at June 30, 2017	1,367,823		$	7.00


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

As of June 30, 2017, we had a total of 37,807,467 shares of common stock, $0.01 par value, outstanding, including 128,205 shares of restricted stock. We also had 218,170 shares held as treasury stock. Total authorized common stock is 100,000,000 shares.

Basic earnings (loss) per common share (“EPS”) are 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 losses per share computations is as follows:



	Three Months Ended June 30,						Six Months Ended June 30,
(in thousands, except per share data)	2017			2016			2017			2016
Net loss (numerator):	$	(6,304	)	$	(4,191	)	$	(12,573	)	$	(4,605	)
Loss per share:
Basic and diluted	$	(0.17	)	$	(0.12	)	$	(0.33	)	$	(0.16	)
Shares (denominator):
Weighted average common shares outstanding - basic	37,679			33,608			37,613			28,812
Net effect of dilutive stock options, warrants and restricted stock units	—			—			—			—
Weighted average common shares outstanding - diluted	37,679			33,608			37,613			28,812

For all periods presented, the computation of diluted loss per share excludes the effect of certain outstanding stock options and RSUs because their inclusion would be anti-dilutive. The number of options that were excluded from diluted loss per share were 800,700 during the three and six months ended June 30, 2017 and 948,803 during the three and six months ended June 30, 2016. RSUs, which are not participating securities and are excluded from our basic and diluted loss per share because they are anti-dilutive, were 1,367,823 for the three and six months ended June 30, 2017 and 1,077,663 for the three and six months ended June 30, 2016.


9.	Income Taxes

Our effective tax rate was (0.5)% and (0.6)% for the three and six months ended June 30, 2017, respectively, and (0.7)% and (0.8)% for the three and six months ended June 30, 2016, 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, 2017, we had outstanding purchase commitments to a number of suppliers totaling $16.0 million, net of deposits previously made, related primarily to the construction of drilling rigs. Of these commitments, $8.4 million relates to equipment currently scheduled for delivery in 2017 and $7.6 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, 2017, were as follows:



(in thousands)
2017	$	298
2018	454
2019	332
2020	99
	$	1,183

As of June 30, 2017, property, plant and equipment in our balance sheets included $1.0 million of equipment under capital lease, net of $0.4 million of accumulated amortization. As of December 31, 2016, property, plant and equipment in our balance sheets included $0.8 million of equipment under capital lease, net of $0.3 million of accumulated amortization. This equipment consists entirely of vehicles used in our operations.

Contingencies

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 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, 2016, filed with the Securities and Exchange Commission on February 28, 2017 (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 land rig fleet comprised entirely of newly constructed, technologically advanced, custom designed 200 Series ShaleDriller® rigs that are specifically engineered and designed to optimize the development of our customers’ most technically demanding oil and natural gas properties. Our first rig commenced drilling in May 2012.

Our standardized fleet currently consists of 14 premium ShaleDriller® rigs, all of which are equipped with our integrated omni-directional walking systems. Our final rig that was converted to 200 Series status during the second quarter of 2017 will commence operating during the third quarter of 2017. Every ShaleDriller® rig in our fleet is a 1500-hp, AC programmable rig designed to be fast-moving between drilling sites and is equipped with 7500 psi mud systems, top drives, automated tubular handling systems and blowout preventer handling systems. All 14 of our rigs are equipped with bi-fuel capabilities that enable the rig to operate on either diesel or a natural gas-diesel blend.

Oil prices began to decline in the second half of 2014, declined further during 2015 and remained low in 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 and reached a low of $26.19 on February 11, 2016 (WTI spot price as reported by the United States Energy Information Administration). As a result, our industry experienced an exceptional downturn and market conditions have only begun to stabilize and slowly recover.

As a result of this drive towards production and cost efficiencies, operators are focusing more of their capital spending on horizontal drilling programs compared to vertical drilling, and are more focused on utilizing drilling equipment and techniques that optimize costs and efficiency. Thus, we believe the rapid market deterioration and stabilization of oil prices well below historical highs 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. As market conditions have improved from trough levels in 2016 and begun to stabilize, demand for our ShaleDriller® rigs has improved. At June 30, 2017, all of our 200 Series rigs were under contract. In addition to improving utilization, contract tenors improved with customers willing to sign term contracts of six to twelve months or longer, and at higher dayrates compared to trough levels, with the potential to move higher if market conditions continue to improve. However, the pace and duration of the current

recovery is unknown, and recently oil prices have fallen below $45 per barrel. If oil prices were to fall below $45 per barrel for any sustained period of time, market conditions and demand for our products and services could deteriorate.

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 $1.1 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 $1.0 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

Amendment to Revolving Credit Facility

Assets Held For Sale

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 throughout 2016 and 2017. 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.

During the three and six months ended June 30, 2017, our operating costs also included approximately $0.4 million and $1.1 million, respectively of costs associated with the reactivation of idle and standby rigs. These costs include costs associated with recommissioning the rig, the hiring and training of new crews and the purchase of supplies and other consumables required for the operation of the rigs.

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 percentage 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 (defined below) 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, 2017 and 2016:



	Three Months Ended						Six Months Ended
(In thousands, except per share data)	June 30, 2017			June 30, 2016			June 30, 2017			June 30, 2016
Revenues	$	21,285		$	15,155		$	41,521		$	37,610
Costs and expenses
Operating costs	15,808			7,398			30,706			19,965
Selling, general and administrative	3,435			5,005			7,153			8,626
Depreciation and amortization	6,335			5,816			12,591			11,641
Asset impairment, net	546			—			675			—
Loss (gain) on disposition of assets, net	745			37			1,573			(88		)
Total cost and expenses	26,869			18,256			52,698			40,144
Operating loss	(5,584		)	(3,101		)	(11,177		)	(2,534		)
Interest expense	(686		)	(1,059		)	(1,316		)	(2,036		)
Loss before income taxes	(6,270		)	(4,160		)	(12,493		)	(4,570		)
Income tax expense	34			31			80			35
Net loss	$	(6,304	)	$	(4,191	)	$	(12,573	)	$	(4,605	)

Other financial and operating data
Number of completed rigs (end of period)	14			14			14			14
Rig operating days (1)	1,111.2			732.2			2,184.1			1,675.3
Average number of operating rigs (2)	12.2			8.0			12.1			9.2
Rig utilization (3)	93.9		%	65.6		%	92.8		%	75.9		%
Average revenue per operating day (4)	$	18,201		$	20,116		$	18,077		$	21,498
Average cost per operating day (5)	$	12,926		$	8,757		$	12,435		$	10,351
Average rig margin per operating day	$	5,275		$	11,359		$	5,642		$	11,147

(1)

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, 2017, there were zero and 77.9 operating days in which we earned revenue on a standby basis, respectively, including zero and 69.0 standby-without-crew days, respectively. During the three and six months ended June 30, 2016, there were 368.4 and 554.1 operating days in which we earned revenue on a standby basis, respectively, including 362.9 and 525.0 standby-without-crew days, respectively.


(2)	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.

(3)

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, we elected to remove our two 100 Series non-walking rigs from the marketed fleet pending completion of their planned rig conversions to 200 Series, pad-optimal status. The conversion of one of the 100 series rig was completed during the second quarter of 2016 and the rig re-entered the marketed fleet in June 2016. The conversion of the second 100 series rig was completed in the second quarter of 2017 and the rig will begin operating in July 2017.

(4)

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 $1.1 million and $0.4 million during the three months ended June 30, 2017 and 2016, respectively, and $2.0 million and $1.6 million during the six months ended June 30, 2017 and 2016, respectively. Included in calculating average revenue per operating day were early termination revenues associated with a contract termination at the end of the first quarter of 2016 of $1.6 million and $1.8 million during the three and six months ended June 30, 2016. The first six months of 2017 did not include any early termination revenues.

(5)

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) out-of-pocket costs reimbursed by customers of $1.1 million and $0.4 million during the three months ended June 30, 2017 and 2016, respectively, and $2.0 million and $1.6 million during the six months ended June 30, 2017 and 2016, respectively, (ii) new crew training costs of $0.1 million during the three months ended June 30, 2017 and 2016, and $0.1 million during the six months ended June 30, 2017 and June 30, 2016, (iii) construction overhead costs expensed due to reduced rig construction activity of $0.5 million during the three months ended June 30, 2016, and $0.2 million and $1.0 million during the six months ended June 30, 2017 and 2016, respectively, (iv) rig reactivation costs associated with the redeployment of previously stacked rigs, excluding $0.1 million of new crew training costs (included in (ii) above), of $0.3 million and $1.0 million during the three and six months ended June 30, 2017, respectively, and (v) out-of-pocket expenses of $0.1 million, net of insurance recoveries, incurred as a result of damage to one of our rig's mast during the first quarter of 2017.

Three Months Ended June 30, 2017 Compared to the Three Months Ended June 30, 2016

Revenues

Revenues for the three months ended June 30, 2017 were $21.3 million, representing a 40.4% increase as compared to revenues of $15.2 million for the three months ended June 30, 2016. This increase was attributable to an increase in operating days to 1,111 days as compared to 732 days in the prior year period. Additionally, 363 days in the prior year period represented standby-without-crew days at lower dayrates. On a revenue per operating day basis, our revenue per day decreased by 9.5% to $18,201 during the three months ended June 30, 2017, as compared to revenue per day of $20,116 for the three months ended June 30, 2016. This decrease in revenue per day is attributable to a larger portion of our revenues being earned at lower dayrates as opposed to under legacy contracts entered into prior to the market decline that began in late 2014.

Operating Costs

Operating costs for the three months ended June 30, 2017 were $15.8 million, representing an 113.7% increase as compared to operating costs of $7.4 million for the three months ended June 30, 2016. This increase was attributable to an increase in operating days to 1,111 days as compared to 732 days in the prior year period. Additionally, 363 days in the prior year period represented standby-without-crew days. Rigs on standby-without-crew incur minimal operating costs. On a cost per operating day basis, our cost increased to $12,926 per day during the three months ended June 30, 2017, representing a 47.6% increase compared to cost per operating day of $8,757 for the three months ended June 30, 2016. This increase was primarily the result of a decrease in rigs earning revenue on a standby-without-crew basis during the current period.

Selling, General and Administrative

Selling, general and administrative expenses for the three months ended June 30, 2017 were $3.4 million, representing a 31.4% decrease as compared to selling, general and administrative expense of $5.0 million for the three months ended June 30, 2016. This decrease as compared to the prior year quarter primarily relates to the recognition of $1.5 million retirement expense in the second quarter of 2016.

Depreciation and Amortization

Depreciation and amortization expense for the three months ended June 30, 2017 was $6.3 million, representing a 8.9% increase compared to depreciation and amortization expense of $5.8 million for the three months ended June 30, 2016. This increase relates primarily to upgrades and additions to certain rigs in 2016 and 2017. We begin depreciating our rigs on a straight-line basis, when they commence drilling operations.

Asset Impairment

Loss on Disposition of Assets, net

A loss on the disposition of assets totaling $0.7 million was recorded for the three months ended June 30, 2017 compared to a loss on the disposition of assets totaling $37.0 thousand in the prior year comparable period. The loss in the current quarter relates primarily to a loss of $0.8 million on the sale of certain assets classified as held for sale, offset by a gain on the sale or disposition of miscellaneous drilling equipment. In the prior year period, the loss related to the sale or disposition of miscellaneous drilling equipment.

Interest Expense

Interest expense for the three months ended June 30, 2017 was $0.7 million, as compared to $1.1 million for the three months ended June 30, 2016. The decrease as compared to the prior year quarter was primarily the result of the write-off of $0.5 million in deferred financing costs as a result of the reduction in our borrowing capacity associated with 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, 2017 amounted to $34.0 thousand compared to an income tax expense of $31.0 thousand for the three months ended June 30, 2016. Our effective tax rates for the three months ended June 30, 2017 and 2016 were (0.5)% and (0.7)%, respectively. All taxes in both the current and prior year period relate to Texas margin tax.

Six Months Ended June 30, 2017 Compared to the Six Months Ended June 30, 2016

Revenues

Revenues for the six months ended June 30, 2017 were $41.5 million, representing a 10.4% increase compared to revenues of $37.6 million for the six months ended June 30, 2016. This increase was attributable to an increase in operating days to 2,184 days as compared to 1,675 days in the prior year period. Additionally, 525 days in the prior year period represented standby-without-crew days at lower dayrates. Revenue per operating day decreased to $18,077 during the six months ended June 30, 2017 compared to revenue per day of $21,498 for the six months ended June 30, 2016. This decrease in revenue per day is attributable to a larger portion of our revenues being earned at lower dayrates as opposed to under legacy contracts entered into prior to the market decline that began in late 2014.

Operating Costs

Operating costs for the six months ended June 30, 2017 were $30.7 million, representing a 53.8% increase compared to operating costs of $20.0 million for the six months ended June 30, 2016. This increase was attributable to an increase in operating days to 2,184 days as compared to 1,675 days in the prior year period. Additionally, 525 days in the prior year period represented standby-without-crew days. Rigs on standby-without-crew incur minimal operating costs. Additionally incurred during the first six months of 2017 were rig reactivation and crew staging costs of approximately $1.1 million related to rigs that were reactivated during the first and second quarter of 2017. On a cost per operating day basis, our cost per day increased to $12,435 during the six months ended June 30, 2017, representing a 20.1% increase compared to cost per day of $10,351 for the six months ended June 30, 2016. This increase was primarily due to an decrease in the number of rigs earning revenue on a standby-without-crew basis during the current period.

Selling, General and Administrative

Selling, general and administrative expenses for the six months ended June 30, 2017 were $7.2 million, representing a 17.1% decrease compared to selling, general and administrative expenses of $8.6 million for the six months ended June 30, 2016. This decrease as compared to the prior year period primarily relates to the recognition of $1.5 million of retirement expense in the second quarter of 2016.

Depreciation and Amortization

Depreciation and amortization expense for the six months ended June 30, 2017 was $12.6 million, representing a 8.2% increase compared to depreciation and amortization expense of $11.6 million for the six months ended June 30, 2016. This increase was primarily due to upgrades and additions to certain rigs in 2016 and 2017. We begin depreciating our rigs when they commence drilling operations.

Asset Impairment

Loss (Gain) on Disposition of Assets, net

A loss on the disposition of assets totaling $1.6 million was recorded for the six months ended June 30, 2017 compared to a gain on the disposition of assets totaling $0.1 million in the prior year comparable period. The loss in the current period relates primarily to a loss of $0.8 million on the sale of certain assets classified as held for sale and a $0.8 million loss on the disposal of certain rig components associated with the upgrade of three of our rigs to 7,500 psi mud systems. In the prior year period, the gain related to the sale or disposition of miscellaneous drilling equipment.

Interest Expense

Interest expense for the six months ended June 30, 2017 was $1.3 million compared to interest expense of $2.0 million for the six months ended June 30, 2016. The decrease as compared to the prior year period was primarily the result of the write-off of $0.5 million in deferred financing costs as a result of the reduction in our borrowing capacity associated with 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 daily operations.

Income Tax Expense

The income tax expense recorded for the six months ended June 30, 2017 amounted to $80.0 thousand compared to an income tax expense of $35.0 thousand for the six months ended June 30, 2016. The effective tax rates for the six months ended June 30, 2017 and 2016 were (0.6)% and (0.8)%, 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, 2017 included approximately $46.0 million of availability under our revolving credit facility and $5.5 million of cash.

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, 2017, we had 14 200 Series rigs. Our primary sources of capital to date have been funds received from our initial private placement, our IPO, our April 2016 public offering of common stock, and cash flows from operations and our revolving credit facility.

Net Cash Provided By Operating Activities

Cash provided by operating activities was $2.2 million for the six months ended June 30, 2017 compared to cash provided by operating activities of $15.4 million during the same period in 2016. 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 2017 were lower as a result of an increase in net loss of $8.0 million, adjusted for non-cash items, of $17.3 million for the six months ended June 30, 2017 compared to $14.7 million during the same period in 2016. Working capital changes decreased cash flows from operating activities by $2.5 million for the six months ended June 30, 2017 compared to increased cash flows of $5.3 million during the same period in 2016.

Net Cash Used In Investing Activities

Cash used in investing activities was $16.3 million for the six months ended June 30, 2017 compared to cash used in investing activities of $9.6 million during the same period in 2016. During the first six months of 2017, cash payments of $17.4 million for capital expenditures were offset by proceeds from the sale of property, plant and equipment of $1.1 million. During the 2016 period, cash payments of $10.5 million for capital expenditures were offset by proceeds from the sale of property, plant and equipment of $0.7 million and proceeds from insurance claims of $0.2 million.

Net Cash Provided by (Used In) Financing Activities

Cash provided by financing activities was $12.5 million for the six months ended June 30, 2017 compared to cash used in financing activities of $4.1 million during the same period in 2016. During the first six months of 2017, we made borrowings under our revolving credit facility of $22.6 million. These proceeds were offset by repayments under our revolving credit facility of $9.4 million, restricted stock unit's withheld for taxes paid of $0.5 million and payments for capital lease obligations of $0.3 million. 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 and payments for capital lease obligations of $0.3 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 twelve 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. In April 2015, we amended the Credit Facility to provide for a springing lock-box arrangement. In October 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. In April 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.

On July 14, 2017, we further amended our existing credit facility. This amendment maintained the aggregate commitments at $85 million and extended the maturity date two years to November 5, 2020. In addition, the amendment provided for an additional uncommitted $65.0 million accordion feature that allows for future increases in facility commitments. The amendment contained various changes to the financial and other covenants to accommodate the extension in term, including changes to the leverage ratio covenant, fixed charge coverage ratio covenant and rig utilization ratio covenant. Additionally, the advance rate increased to 75% through September 30, 2017, decreasing 1.25% per quarter, subject to a floor of 65%. At June 30, 2017, our aggregate borrowings under the Credit Facility were $39.0 million and the borrowing base was $89.7 million. Proforma for the amendment our borrowing base would have been $95.4 million.

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

effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. We expect the implementation of this standard to change the classification of the described transactions within our Statement of Cash Flows.

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, 2017 included $39.0 million of floating-rate debt attributed to borrowings at an average interest rate of 5.68%. As a result, our annual interest cost in 2017 will fluctuate based on short-term interest rates.

The impact on annual cash flow of a 10% change in the floating-rate (approximately 0.57%) would be approximately $0.2 million annually based on the floating-rate debt and other obligations outstanding at June 30, 2017; 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.

Due to this deterioration and stabilization of commodity prices well below previous highs, our customers are principally focused on their most economic wells, and driving cost and production efficiencies that deliver the most economic wells with the lowest capital costs. As a result of this drive towards production and cost efficiencies, operators are focusing more of their capital spending on horizontal drilling programs compared to vertical drilling, and are more focused on utilizing drilling equipment and techniques that optimize costs and efficiency. Thus, we believe the rapid market deterioration and stabilization of oil prices well below historical highs 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.

As market conditions have improved from trough levels in 2016 and begun to stabilize, demand for our ShaleDriller® rigs has improved. At June 30, 2017, all 14 of our rigs were under contract. In addition to improving utilization, contract tenors are improved with customers willing to sign term contracts of six to twelve months or longer, and at higher dayrates compared to trough levels. However, the pace and duration of the current recovery is unknown, and recently oil prices have fallen below $45 per barrel. If oil prices were to fall below $45 per barrel for any sustained period of time, market conditions and demand for our products and services could deteriorate.

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, 2017 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

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, 2016. 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

None.

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		Second Amended and Restated Credit Facility, dated July 14, 2017 (Incorporated by reference to the Company’s Current Report on Form 8-K (File No. 001-36590) filed July 17, 2017, Exhibit 10.1)

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:	Executive 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 27, 2017