Edgar Filing: Independence Contract Drilling, Inc.

ICD-2015.06.30-10Q

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, 2015


¨	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	¨

Non-accelerated filer	x (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

24,445,380 shares of the registrant’s Common Stock were outstanding as of August 4, 2015.

INDEPENDENCE CONTRACT DRILLING, INC.

Index to Form 10-Q



Part I. FINANCIAL INFORMATION

Item 1. Financial Statements

Balance Sheets as of June 30, 2015 and December 31, 2014 (Unaudited)		4

Statements of Operations for the three and six months ended June 30, 2015 and 2014 (Unaudited)		5

Statements of Stockholders’ Equity for the six months ended June 30, 2015 (Unaudited)		6

Statements of Cash Flows for the six months ended June 30, 2015 and 2014 (Unaudited)		7

Notes to the Unaudited Financial Statements		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;


•	delays in construction or deliveries of our new land drilling rigs;


•	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 raise funds through debt financing and equity issuances sufficient to fund our planned rig construction projects;


•	our inability to comply with the financial and other covenants in debt agreements that we may enter into as a result of reduced revenues and financial performance;


•	a substantial reduction in borrowing base under our revolving credit facility as a result of a decline in the appraised value of our drilling rigs;


•	unanticipated costs, delays and other difficulties in executing our long-term growth strategy;


•	the loss of key management personnel;


•	new technology that may cause our drilling methods or equipment to become less competitive;


•	labor costs or shortages of skilled workers;


•	the loss of or interruption in operations of one or more key vendors;


•	the effect of operating hazards and severe weather on our rigs, facilities, business, operations and financial results, and limitations on our insurance coverage;


•	increased regulation of drilling in unconventional formations;


•	the incurrence of significant costs and liabilities in the future resulting from our failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment;


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


•	lack of operating history as a contract drilling company.

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, 2014. 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, 2015			December 31, 2014
Assets
Cash and cash equivalents	$	12,254		$	10,757
Accounts receivable, net	13,418			19,127
Inventory	2,292			2,124
Deferred taxes	402			323
Prepaid expenses and other current assets	4,503			3,969
Total current assets	32,869			36,300
Property, plant and equipment, net	282,667			250,498
Other long-term assets, net	2,461			2,749
Total assets	$	317,997		$	289,547
Liabilities and Stockholders’ Equity
Liabilities
Current portion of long-term debt	$	—		$	22,519
Accounts payable	7,988			21,993
Accrued liabilities	8,070			6,970
Income taxes payable	213			408
Total current liabilities	16,271			51,890
Long-term debt	61,361			—
Other long-term liabilities	347			598
Deferred taxes	402			323
Total liabilities	78,381			52,811
Commitments and contingencies
Stockholders’ equity
Common stock, $0.01 par value, 100,000,000 shares authorized; 24,530,391 and 24,540,720 issued, respectively; 24,445,380 and 24,455,709 outstanding, respectively	245			245
Additional paid-in capital	274,908			272,751
Accumulated deficit	(34,566		)	(35,289		)
Treasury shares, at cost, 85,011 shares	(971		)	(971		)
Total stockholders’ equity	239,616			236,736
Total liabilities and stockholders’ equity	$	317,997		$	289,547

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,
	2015			2014			2015			2014
Revenues	$	21,082		$	14,661		$	43,388		$	28,210
Costs and expenses
Operating costs	12,057			9,283			25,163			18,060
Selling, general and administrative	3,755			2,073			7,582			4,167
Depreciation and amortization	5,169			3,901			9,458			7,317
(Insurance recoveries) asset impairment, net	—			(2,038		)	(841		)	2,612
(Gain) loss on disposition of assets	(59		)	(2		)	334			(191		)
Total costs and expenses	20,922			13,217			41,696			31,965
Operating income (loss)	160			1,444			1,692			(3,755		)
Interest expense	(717		)	(598		)	(1,029		)	(992		)
Gain on warrant derivative	—			1,377			—			1,380
(Loss) income before income taxes	(557		)	2,223			663			(3,367		)
Income tax expense (benefit)	95			667			(60		)	(1,218		)
Net (loss) income	$	(652	)	$	1,556		$	723		$	(2,149	)
(Loss) earnings per share:
Basic	$	(0.03	)	$	0.13		$	0.03		$	(0.18	)
Diluted	$	(0.03	)	$	0.13		$	0.03		$	(0.18	)
Weighted average number of common shares outstanding:
Basic	23,851			12,263			24,455			12,257
Diluted	23,851			12,306			24,455			12,257

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, 2014	24,455,709		$	245	$	272,751	$	(35,289	)	$	(971	)	$	236,736
Restricted stock forfeited	(10,329	)	—		—		—			—			—
Stock-based compensation	—		—		2,157		—			—			2,157
Net income	—		—		—		723			—			723
Balances at June 30, 2015	24,445,380		$	245	$	274,908	$	(34,566	)	$	(971	)	$	239,616

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

Independence Contract Drilling, Inc.

Statements of Cash Flows

(Unaudited)

(in thousands)



	Six Months Ended June 30,
	2015			2014
Cash flows from operating activities
Net income (loss)	$	723		$	(2,149	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation and amortization	9,458			7,317
(Insurance recoveries) asset impairment, net	(841		)	2,612
Stock-based compensation	1,734			1,022
Gain on warrant derivative	—			(1,380		)
Loss (gain) on disposition of assets	334			(191		)
Deferred taxes	—			(1,218		)
Amortization of deferred financing costs	315			329
Bad debt expense	80			—
Changes in operating assets and liabilities
Accounts receivable	5,629			(1,045		)
Inventory	(253		)	(958		)
Vendor advances	—			(1,568		)
Prepaid expenses and other current assets	(1,820		)	(1,945		)
Accounts payable and accrued liabilities	2,620			2,486
Income taxes payable	(195		)	(160		)
Net cash provided by operating activities	17,784			3,152
Cash flows from investing activities
Purchases of property, plant and equipment	(58,215		)	(48,731		)
Proceeds from insurance claims	2,899			2,038
Proceeds from the sale of property, plant and equipment	351			488
Net cash used in investing activities	(54,965		)	(46,205		)
Cash flows from financing activities
Borrowings under credit facility	89,566			80,306
Repayments under credit facility	(50,724		)	(35,875		)
Financing costs paid	(164		)	(1,235		)
Net cash provided by financing activities	38,678			43,196
Net increase in cash and cash equivalents	1,497			143
Cash and cash equivalents
Beginning of period	10,757			2,730
End of period	$	12,254		$	2,873
Supplemental disclosure of cash flow information
Cash paid during the period for taxes	$	135		160
Cash paid during the period for interest	$	1,379		$	1,079
Supplemental disclosure of non-cash investing and financing activities
Stock-based compensation capitalized as property, plant and equipment	$	423		$	214
Change in property, plant and equipment purchases in accounts payable	$	(15,776	)	$	(6,011	)

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 newly constructed, 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. Our first rig began drilling in May 2012.

Our standardized fleet consisted of fourteen premium rigs as of June 30, 2015. Of these fourteen rigs, two were completed during the first quarter of 2015 and one was under construction and scheduled for completion during the third quarter of 2015. Currently, twelve of our fourteen rigs contain our integrated multi-directional walking system that is specifically designed to optimize pad drilling for our customers. One of our two non-walking rigs is scheduled to be upgraded during the second half of 2015.

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 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.

In this regard, oil prices declined significantly during the second half of 2014 and have remained depressed in 2015. The closing price of oil was as high as $106.06 per barrel during the third quarter of 2014, as low as $44.08 per barrel in late January 2015 and at $47.11 per barrel as of July 31, 2015 (WTI spot price as reported by the United States Energy Information Administration). As a result of the decline in oil prices, our industry is now experiencing a severe 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 2015 will continue to be a very challenging year for our industry.

We believe the vast majority of exploration and production companies, including our customers, have significantly reduced their 2015 capital spending plans. The initial impact of these spending reductions is evidenced by the active rig count in the United States, which has declined more than 50% since its recent peak in October 2014, and we believe the active rig count in the United States may decline further during the remainder of 2015 if oil prices remain at current levels.

As a result of this deterioration in market conditions, our customers are principally focused on their most economic wells and on maintaining their most cost efficient operations that deliver the overall lowest cost of production. As a result, operators are focusing more of their capital spending on horizontal drilling programs on multi-well pads compared to vertical drilling and 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.

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 will be 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 2014, we operated our premium drilling fleet with 99.7% utilization, but we have not been able to maintain this level of utilization during the current market downturn. In the first half of 2015, two non-walking rigs and two walking rigs became idle. We will be upgrading one of our idle rigs with our multi-directional walking system during the second half of 2015 and we are evaluating whether to upgrade the other idle non-walking rig. We expect to market our idle rigs at substantially lower dayrates than their expired contracts and at lower utilization rates than where we historically have operated, and there can be no assurance that these rigs will remain operating at profitable levels.

Damage Sustained on Rig 102

On March 9, 2014, one of our non-walking drilling rigs (Rig 102) suspended drilling operations due to damage to the rig’s mast and other operating equipment. While under repair, we upgraded this rig by adding a substructure and other equipment that includes a multi-directional walking system. The cost of the upgrades were not covered by insurance. The repairs and upgrades were completed in October 2014 and the upgraded rig was renamed Rig 208. We recorded an asset impairment charge of $4.7 million during the three months ended March 31, 2014, representing a preliminary estimate of the damage sustained to the rig ($2.9 million), as well as the impairment of certain non-damaged items associated with the upgrade ($1.8 million). During the three months ended June 30, 2014, we recorded approximately $2.3 million in insurance proceeds related to repairing damage to the rig ($2.0 million) as well as the recovery of certain out-of-pocket expenses ($0.3 million), for which we had received a partial proof of loss from the insurance company. As of September 30, 2014, all of the $2.3 million had been collected. In the fourth quarter of 2014, we recorded an additional $1.6 million in insurance recoveries related to repairing damage to the rig ($1.0 million) as well as the recovery of out-of-pocket expenses ($0.6 million), for which we had received a second partial proof of loss from the insurance company. During the first quarter of 2015, we received a final payment of $2.9 million from the insurance company, and recognized an additional $1.3 million insurance recovery, representing the excess of the insurance recovery over the total impairment attributable to the damage to the rig.

Stock Split

On July 14, 2014, our board of directors approved a resolution to effect a 1.57-for-1 stock split of our common stock in the form of a stock dividend. The dividend was distributed on July 24, 2014 to holders of record as of July 21, 2014. The earnings per share information and all common stock information in these financial statements have been retroactively restated for all periods presented to reflect this stock split.

Initial Public Offering

On August 7, 2014, our registration statement on Form S-1 (File No. 333-196914) (the "Form S-1") was declared effective by the Securities and Exchange Commission for our initial public offering, pursuant to which we sold an aggregate of 11,500,000 shares of our common stock at a price to the public of $11.00 per share, which included 1,500,000 shares of our common stock sold pursuant to the exercise by the underwriters in full of their option to purchase additional shares of common stock to cover over-allotments (the "Over-Allotment Option"). Morgan Stanley & Co. LLC, RBC Capital Markets, LLC and Tudor, Pickering, Holt & Co. Securities, Inc. acted as book runners. We completed our initial public offering of 10,000,000 shares of our common stock on August 13, 2014 and subsequently closed the issuance and sale of the additional 1,500,000 shares of our common stock pursuant to the Over-Allotment Option on August 29, 2014. Our common stock trades on the New York Stock Exchange under the ticker symbol "ICD." Net proceeds from the offering were $116.5 million after deducting $7.6 million of underwriting discounts and commissions, as well as legal, accounting, printing and other expenses directly associated with the offering totaling $2.4 million. All of the outstanding borrowings on our revolving credit facility were repaid immediately following the offering.


2.	Interim Financial Information

These unaudited financial statements include all 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, 2014, included in our Annual Report on Form 10-K, as certain information and footnote disclosures included in annual financial statements prepared in accordance with GAAP have been omitted. 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 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, 2015 may not be indicative of results that will be realized for the full year ending December 31, 2015.

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.

Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board ("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 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 June 2014, the FASB issued an accounting standards update to provide guidance on the accounting for share-based payments when the terms of an award provide that a performance target could be achieved after the requisite service period. The guidance requires that a performance target that affects vesting and that could be achieved after the requisite service period is treated as a performance condition. This guidance is effective for interim and annual periods beginning after December 15, 2015. 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 are currently evaluating the impact this will have on our financial statements.

In April 2015, the FASB issued an accounting standards update intended to simplify the presentation of debt issuance costs. This new guidance requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability, consistent with debt discounts. This guidance is effective for public companies for fiscal years beginning after December 15, 2015. We believe the guidance will affect the presentation of deferred issuance costs in the balance sheet but will not have any impact on the Company’s results of operations or financial position.

In April 2015, the FASB issued an accounting standards update intended to provide guidance about whether a cloud computing arrangement includes a software license and the related accounting treatment. The pronouncement is effective for annual reporting periods beginning after December 15, 2015. We are currently evaluating the impact this guidance will have on our financial statements.

In July 2015, the FASB issued an accounting standards update requiring an entity to measure inventory at the lower of cost or net realizable value versus lower of cost or market. Previously, market could be replacement cost, net realizable value, or net realizable value less an approximately normal profit margin. The amendment does not apply to inventory that is measured using last-in, first-out (LIFO) or the retail inventory method. The amendment applies 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 or 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 upon our consolidated financial statements or notes thereto.


3.	Revision of Prior Year Financial Statements

We revised the classification of long-term debt in our balance sheet as of December 31, 2014 from long-term debt to current portion of long-term debt due to our credit facility including both a required lock-box payment method and a subjective acceleration clause permitting the lenders to declare an event of default in the event of a material adverse change. We subsequently amended our credit facility to provide for a springing lock-box arrangement to permit the long-term classification of the debt, subject to the credit facility’s ultimate maturity and our compliance with its terms and conditions. The correction of the misclassification did not affect previously reported net income, total assets, total liabilities or stockholders' equity or cash flows as of and for the year ended December 31, 2014 or 2013. The net impact of the

reclassification to the balance sheet at December 31, 2014, was to (i) reduce long-term debt from $22.5 million to zero; (ii) increase the current portion of long-term debt from zero to $22.5 million; and (iii) increase current liabilities from $29.4 million to $51.9 million. We analyzed the reclassifications under SEC staff guidance and determined that the impact of the reclassification was not material to previously issued financial statements.


4.	Financial Instruments and 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. Our financial instruments that are subject to fair value measurements consist of a warrant to purchase approximately 2.2 million shares of our common stock, held by Global Energy Services Operating, LLC ("GES"), which expired unexercised on March 2, 2015,(the "GES Warrant") and long-term debt.

The GES Warrant contained a provision that protected the holder from a decline in the issue price of our common stock, or a “down-round” provision. Down-round provisions reduce the exercise or conversion price of a warrant or convertible instrument if a company either issues equity shares for a price that is lower than the exercise or conversion price of those instruments or issues new warrants or convertible instruments that have a lower exercise or conversion price. As a result of this provision, we accounted for this warrant as a liability. Following our initial public offering completed on August 13, 2014, and the full exercise of the Over-Allotment Option on August 29, 2014, the exercise price of the GES Warrant was reduced from $12.74 per share to $11.37 per share.

In accordance with Accounting Standards Codification ("ASC") 815 “Accounting for Derivative Instruments and Hedging Activities,” as amended, our warrant derivative liability was marked-to-market each reporting period, with a corresponding non-cash gain or loss charged to earnings (loss) in the applicable period. 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.

Prior to the completion of our initial public offering on August 13, 2014, the warrant liability was recorded at fair value using Level 3 inputs. Significant Level 3 inputs used to calculate the fair value of the warrant included the estimated share price on the valuation date, expected volatility, risk-free interest rate and management’s assumptions regarding the likelihood of a future repricing of these warrants pursuant to the down-round provision. After the initial public offering was completed on August 13, 2014, the warrant liability was recorded at fair value using Level 1 inputs.

As of December 31, 2014, the fair value of the GES Warrant was estimated at zero, and the warrant expired unexercised on March 2, 2015. There was no gain or loss associated with the warrant for the three or six months ended June 30, 2015 and we recorded a non-cash gain on the warrant derivative of $1.4 million during the three and six months ended June 30, 2014.

The following provides a reconciliation of financial liabilities measured at fair value on a recurring basis:



(in thousands)	Three Months Ended June 30,					Six Months Ended June 30,
	2015		2014			2015		2014
Beginning balance	$	—	$	3,186		$	—	$	3,189
Gain on warrant derivative	—		(1,377		)	—		(1,380		)
Ending balance	$	—	$	1,809		$	—	$	1,809

The fair value of our long-term debt is determined by Level 3 measurements based on quoted market prices and terms for similar instruments, where available, or on the amount of future cash flows associated with the debt, discounted using the current borrowing rate for comparable debt instruments. The estimated fair value of our long-term debt totaled $63.4 million and $22.9 million as of June 30, 2015 and December 31, 2014, respectively, compared to a carrying amount of $61.4 million and $22.5 million as of June 30, 2015 and December 31, 2014, 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 other long-lived assets.


5.	Inventory

Inventory consisted of the following:



(in thousands)	June 30, 2015		December 31, 2014

Rig components and supplies	$	2,292	$	2,124


6.	Accrued Liabilities

Accrued liabilities consisted of the following:



(in thousands)
	June 30, 2015		December 31, 2014
Accrued salaries and other compensation	$	2,398	$	2,710
Insurance	2,153		488
Deferred mobilization revenues	1,457		1,281
Property, sales and other taxes	1,522		1,710
Other	540		781
	$	8,070	$	6,970


7.	Long-Term Debt

On May 10, 2013, we entered into a credit agreement (the “Credit Facility”) with a syndicate of financial institutions led by CIT Finance LLC that provided for a committed $60.0 million revolving credit facility and an additional uncommitted $20.0 million accordion feature that allowed for future increases in the facility.

On February 21, 2014 we amended the Credit Facility in order to increase the aggregate commitments from $60.0 million to $125.0 million. The final $25.0 million of commitments under the amended Credit Facility was subject to our obtaining additional equity or indebtedness, subordinated to the Credit Facility, of at least $40.0 million (the “Junior Event”). The Credit Facility, as amended, also provided for an additional uncommitted $25.0 million accordion feature that allowed for future increases in the facility.

On May 12, 2014, we amended the Credit Facility again, to expand the commitments not subject to the Junior Event from $100.0 million to $110.0 million. The amendment also adjusted the minimum EBITDA covenants contained in the Credit Facility to reflect the removal of Rig 102 from service during the pendency of its upgrade. As a result of our initial public offering, completed on August 13, 2014, the final $25.0 of our $125.0 million Credit Facility became available to us.

On November 5, 2014, we amended the Credit Facility again to increase the commitments under the facility from $125.0 million to $155.0 million. In addition, the amendment provides for an additional uncommitted $25.0 million accordion feature that allows for future increases in borrowing availability.

On March 4, 2015, we further amended the Credit Facility to revise the definition of Eligible Completed Drilling Rigs and to reduce the Rig Utilization Ratio covenant through January 31, 2017.

On April 23, 2015, we amended the Credit Facility to provide for a springing lock-box arrangement.

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. Beginning on November 5, 2015, the 75% advance rate on our eligible completed and owned drilling rigs decreases by 1.25% per quarter. The amended 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. The obligations under the Credit Facility are secured by all our assets and is unconditionally guaranteed by all of our future direct and indirect subsidiaries.

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.

The Credit Facility provides for a springing lock-box arrangement that is only triggered upon the occurrence of an event of default under the Credit Facility or availability under the Credit Facility falls below the greater of (A) $15 million and (B) the lesser of 15% of the borrowing base or 15% of the total commitments under the facility. 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.

We had $61.4 million in outstanding borrowings under the Credit Facility at June 30, 2015. Remaining availability under the Credit Facility was $63.3 million at June 30, 2015, based on the borrowing base formula, and we are currently in compliance with all covenants under the Credit Facility and expect to remain in compliance throughout 2015.


8.	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. The 2012 Plan, as amended, permits the granting of various types of awards, including stock options, restricted stock and restricted stock units and up to 3,454,000 shares were authorized for issuance. Restricted stock and restricted stock units may be granted for no consideration other than prior and future services. The exercise 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 10 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, 2015, approximately 799,074 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,
	2015		2014		2015		2014
Compensation cost recognized:
Stock options	$	74	$	420	$	288	$	692
Restricted stock and restricted stock units	929		262		1,869		544
Total stock-based compensation	$	1,003	$	682	$	2,157	$	1,236

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. Approximately $0.1 million and $0.2 million in stock-based compensation was capitalized in connection with rig construction activity during the three and six months ended June 30, 2014, 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 are amortized to compensation expense on a straight-line basis over the requisite service periods of the awards, which is generally the vesting period.

There were no stock options granted during the six months ended June 30, 2015 or the six months ended June 30, 2014.

A summary of stock option activity and related information for the six months ended June 30, 2015 is as follows:



	Six Months Ended June 30, 2015
	Options	Weighted Average Exercise Price
Outstanding at January 1, 2015	963,196	$	12.74
Granted	—	—
Exercised	—	—
Forfeited/expired	—	—
Outstanding at June 30, 2015	963,196	$	12.74
Exercisable at June 30, 2015	801,485	$	12.74

A summary of our unvested stock options as of June 30, 2015, and the changes during the six months then ended is presented below:



	Six Months Ended June 30, 2015
	Outstanding		Weighted Average Grant-Date Fair Value
Unvested as of January 1, 2015	360,316		$	4.32
Granted	—		—
Vested	(198,605	)	4.84
Forfeited/expired	—		—
Unvested as of June 30, 2015	161,711		$	3.70

The number of options vested at June 30, 2015 was 801,485 with a weighted average remaining contractual life of 6.8 years and a weighted-average exercise price of $12.74 per share.

As of June 30, 2015, the unrecognized compensation cost related to outstanding stock options was $0.4 million. This cost is expected to be recognized over a weighted-average period of 0.7 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, 2015, there was $4.7 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 1.1 years.

A summary of the status of our restricted stock awards as of June 30, 2015, and of changes in restricted stock outstanding during the six months ended June 30, 2015, is as follows:



	Six Months Ended June 30, 2015
	Shares		Weighted Average Grant-Date Fair Value Per Share
Outstanding at January 1, 2015	605,141		$	10.82
Granted	—		—
Vested	—		—
Forfeited	(10,329	)	11.00
Outstanding at June 30, 2015	594,812		$	10.82

Restricted Stock Units

We have granted restricted stock units ("RSUs") to key employees under the 2012 Plan. We have granted cliff vesting RSUs and 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. 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. The fair value of the CEBITDA 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, 2015, there was $3.3 million of unrecognized compensation cost related to unvested RSUs that 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, 2015, and of changes in RSUs outstanding during the six months ended June 30, 2015, is as follows:



	Six Months Ended June 30, 2015
	RSUs		Weighted Average Grant-Date Fair Value Per Share
Outstanding at January 1, 2015	516,774		$	12.81
Granted	—		—
Vested and converted	—		—
Forfeited	(21,547	)	11.90
Outstanding at June 30, 2015	495,227		$	12.85


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

As of June 30, 2015, we had a total of 24,445,380 shares of common stock, $0.01 par value outstanding, including 594,812 shares of restricted stock, and 85,011 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 losses per share computations is as follows:



(in thousands, except per share data)	Three Months Ended June 30,					Six Months Ended June 30,
	2015			2014		2015		2014
Net income (loss) (numerator):	$	(652	)	$	1,556	$	723	$	(2,149	)
Earnings (loss) per share:
Basic	$	(0.03	)	$	0.13	$	0.03	$	(0.18	)
Diluted	$	(0.03	)	$	0.13	$	0.03	$	(0.18	)
Shares (denominator):
Weighted-average number of shares outstanding - basic	23,851			12,263		24,455		12,257
Net effect of dilutive stock options, warrants and restricted stock units	—			43		—		—
Weighted-average number of shares outstanding - diluted	23,851			12,306		24,455		12,257

For all periods presented, the computation of diluted earnings (loss) per share excludes the effect of certain outstanding stock options and warrants because their inclusion would be anti-dilutive. The number of options that were excluded from diluted earnings (loss) per share were 963,196 during each of the three months ended June 30, 2015 and 2014, and 963,196 during each of the six months ended June 30, 2015 and 2014. A warrant to purchase 2,198,000 shares of our common stock was anti-dilutive in both periods and expired unexercised on March 2, 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 495,227 and zero for the three months ended June 30, 2015 and 2014, respectively, and 495,227 and zero for the six months ended June 30, 2015 and 2014, respectively.


10.	Income Taxes

Our effective tax rate was (17.1)% and (9.0)% for the three and six months ended June 30, 2015, respectively. The rate is primarily comprised of the effect of the Texas margin tax, due to our valuation allowance for federal income tax purposes being applied against any potential deferred tax asset which would have ordinarily resulted. While we do not expect to receive a benefit for the full year, the negative effective tax rate is determined by applying the guidance in ASC 740-270. We expect to owe Texas margin tax for the full year 2015. We were not subject to a valuation allowance for federal taxes in the prior year comparable quarter.


11.	Commitments and Contingencies

Purchase Commitments

As of June 30, 2015, we had outstanding purchase commitments to a number of suppliers totaling $40.6 million, net of deposits previously made, related primarily to the construction of drilling rigs. Of these commitments, $13.5 million relates to equipment currently scheduled for delivery in 2016 and $13.6 million relates to equipment scheduled for delivery in 2017.

Lease Commitments

We lease certain equipment and vehicles under non-cancelable operating leases. The minimum rental commitments under non-cancelable operating leases, with lease terms in excess of one year subsequent to June 30, 2015, were as follows:



(in thousands)
2015	$	375
2016	467
2017	280
2018	60
2019	50
Thereafter	—
	$	1,232

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.


12.	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, 2015, and one of our directors was a director of the ultimate parent company of GES through May 31, 2015, upon which date he resigned. 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, 2015.

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. Total purchases from this vendor amounted to $1.2 million and $0.6 million during the six months ended June 30, 2015 and June 30, 2014, respectively. We had outstanding payables with this vendor totaling $0.2 million and $0.5 million as of June 30, 2015 and December 31, 2014, respectively.

The son of an executive officer and director of the Company has worked in a sales capacity at two vendors from which we purchase oilfield equipment and related supplies and currently is a minority owner of one of these vendors. Total purchases from one of the vendors amounted to $0.6 million and $0.5 million during the six months ended June 30, 2015 and June 30, 2014, respectively. We had outstanding payables with this vendor totaling $0.1 million and $0.6 million as of June 30, 2015 and December 31, 2014, respectively. During the six months ended June 30, 2015 and June 30, 2014, we did not make any purchases from the second vendor, in which the related party owns a minority interest, and we did not have any outstanding payables with them. We did have a purchase commitment for $.03 million outstanding as of June 30, 2015 with this vendor. We did not do any business with this vendor during the six months ended June 30, 2014.

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, 2014, filed with the Securities and Exchange Commission on March 16, 2015 (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 newly constructed, 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. Our first rig began drilling in May 2012.

In this regard, oil prices declined significantly during the second half of 2014 and have remain depressed in 2015. The closing price of oil was as high as $106.06 per barrel during the third quarter of 2014, as low as $44.08 per barrel in late January 2015 and at $47.11 per barrel as of July 31, 2015 (WTI spot price as reported by the United States Energy Information Administration). As a result of the decline in oil prices, our industry is now experiencing a severe 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 2015 will continue to be a very challenging year for our industry.

We believe the vast majority of exploration and production companies, including our customers, have significantly reduced their 2015 capital spending plans. The initial impact of these spending reductions is evidenced by the published active rig count in the United States, which has declined more than 50% since its recent peak in October 2014, and we believe the active rig count in the United States may decline further during the remainder of 2015 if oil prices remain at current levels.

As a result of this deterioration in market conditions, our customers are principally focused on their most economic wells and on maintaining their most cost efficient operations that deliver the overall lowest cost of production. As a result, operators are focusing more of their capital spending on horizontal drilling programs on multi-well pads, compared to vertical drilling, and 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.

during the current market downturn. In the first half of 2015, two non-walking rigs and two walking rigs became idle. We will be upgrading one of our idle rigs with our multi-directional walking system during the second half of 2015 and we are evaluating whether to upgrade the other idle non-walking rig. We expect to market our idle rigs at substantially lower dayrates than their expired contracts and at lower utilization rates than where we historically have operated, and there can be no assurance that these rigs will remain operating at profitable levels.

Recent Developments

Damage Sustained on Rig 102

Stock Split

Initial Public Offering

Our Revenues

We earn contract drilling revenues pursuant to drilling contracts entered into with our customers. We perform drilling services on a “daywork” contract 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.

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, 2015 and 2014 (in thousands):



	Three Months Ended						Six Months Ended
	June 30, 2015			June 30, 2014			June 30, 2015			June 30, 2014

Revenues	$	21,082		$	14,661		$	43,388		$	28,210
Costs and expenses
Operating costs	12,057			9,283			25,163			18,060
Selling, general and administrative	3,755			2,073			7,582			4,167
Depreciation and amortization	5,169			3,901			9,458			7,317
(Insurance recoveries) asset impairment, net	—			(2,038		)	(841		)	2,612
(Gain) loss on disposition of assets	(59		)	(2		)	334			(191		)
Total cost and expenses	20,922			13,217			41,696			31,965
Operating income (loss)	160			1,444			1,692			(3,755		)
Interest expense	(717		)	(598		)	(1,029		)	(992		)
Gain on warrant derivative	—			1,377			—			1,380
(Loss ) income before income taxes	(557		)	2,223			663			(3,367		)
Income tax expense (benefit)	95			667			(60		)	(1,218		)
Net (loss) income	$	(652	)	$	1,556		$	723		$	(2,149	)

Other financial and operating data
Number of completed rigs (end of period) (1)	13			8			13			8
Rig operating days (2)	938.9			636.1			1,890.2			1,243.4
Average number of operating rigs (3)	10.3			7.0			10.4			6.9
Rig utilization (4)	79.4		%	100.0		%	85.3		%	100.0		%
Average revenue per operating day (5)	$	21,632		$	22,026		$	22,209		$	21,480
Average cost per operating day (6)	$	11,855		$	12,740		$	12,448		$	12,716
Average rig margin per operating day	$	9,777		$	9,286		$	9,761		$	8,764


(1)	Number of completed rigs as of June 30, 2015 increased by five compared to the number of completed rigs as of June 30, 2014, reflecting the addition of four newly constructed rigs and the completion of an upgrade of one of the Company's drilling rigs (see Note 1 - Nature of Operations - Damage Sustained on Rig 102).


(2)	Rig operating days represent the number of days our rigs are earning revenue under a contract during the period.


(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 rigs are available during the period.

(5)

Average revenue per operating day represents total contract drilling revenues during the period divided by total 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 $0.8 million and $0.6 million during the three months ended June 30, 2015 and 2014, respectively, and $1.4 million and $1.3 million during the six months ended June 30, 2015 and 2014, respectively.

(6)

Average cost per operating day represents operating costs during the period divided by rig operating days during 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 $0.8 million and $0.6 million during the three months ended June 30, 2015 and 2014, respectively, and $1.4 million and $1.3 million during the six months ended June 30, 2015 and 2014, respectively, and (ii) new crew training costs of $0.2 million and $0.5 million during the three months ended June 30, 2015 and 2014, respectively, and $0.2 million and $0.8 million during the six months ended June 30, 2015 and 2014, respectively.

Three Months Ended June 30, 2015 Compared to the Three Months Ended June 30, 2014

Revenues

Revenues for the three months ended June 30, 2015 were $21.1 million, representing a 43.8% increase as compared to revenues of $14.7 million for the three months ended June 30, 2014. This increase was directly attributable to the addition of drilling rigs to our fleet between June 30, 2014 and June 30, 2015, which is reflected in the increase in our average number of operating rigs to 10.3 during the three months ended June 30, 2015, as compared to 7.0 during the three months ended June 30, 2014. On a revenue per operating day basis, our revenue per day decreased 1.8% to $21,632 during the three months ended June 30, 2015, as compared to revenue per day of $22,026 for the three months ended June 30, 2014. This decrease resulted primarily from two of our rigs earning revenue on standby-without-crew rates during the period, which are substantially lower than normal operating dayrates.

Operating Costs

Operating costs for the three months ended June 30, 2015 were $12.1 million, representing a 29.9% increase as compared to operating costs of $9.3 million for the three months ended June 30, 2014. This increase was directly related to the addition of drilling rigs to our fleet between June 30, 2014 and June 30, 2015. On a cost per operating day basis, our cost per operating day decreased to $11,855 per day during the three months ended June 30, 2015, representing a 6.9% decrease compared to cost per operating day of $12,740 for the three months ended June 30, 2014. The decrease in operating costs per day resulted primarily from several of our rigs operating on a standby-without-crew basis during the period, as they incurred minimal operating costs.

Selling, General and Administrative

Selling, general and administrative expenses for the three months ended June 30, 2015 were $3.8 million, representing a 81.1% increase as compared to selling, general and administrative expense of $2.1 million for the three months ended June 30, 2014. This increase relates to additional payroll, insurance, professional fees and other ongoing costs associated with being a public company. Additionally, non-cash stock compensation expense increased by $0.1 million as a result of new awards made in connection with our initial public offering.

Depreciation and Amortization

Depreciation and amortization expense for the three months ended June 30, 2015 was $5.2 million, representing a 32.5% increase compared to depreciation and amortization expense of $3.9 million for the three months ended June 30, 2014. This increase was related primarily to the introduction of new drilling rigs constructed by us throughout 2014 and 2015 and a change in the estimated useful life for certain of our drilling equipment. We begin depreciating our rigs when they commence drilling operations. This increase was offset by the reduction in amortization of intangible assets during the current period as a result of our rig manufacturing intellectual property being fully amortized as of December 31, 2014.

(Insurance Recoveries) Asset Impairment, net

The insurance recovery in the quarter ended June 30, 2014 related to damage sustained to a drilling rig that suspended drilling operations on March 9, 2014. We did not record any asset impairments during the three months ended June 30, 2015.

Gain on Disposition of Assets

A gain on the disposition of assets totaling $0.06 million was recorded for the three months ended June 30, 2015 compared to a gain on the disposition of assets totaling two thousand dollars 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 three months ended June 30, 2015 was $0.7 million, as compared to $0.6 million for the three months ended June 30, 2014. Our interest expense is derived from borrowings under our revolving credit facility, which are primarily used to fund our rig construction activity.

Gain (Loss) on Warrant Derivative

As part of the consideration paid to GES for its contribution of our rig construction operations and intellectual property, we issued to GES a warrant to purchase approximately 2.2 million shares of our common stock, which expired on March 2, 2015. The terms of this warrant contained a feature that allowed the exercise price to be adjusted in the event we issued any shares of common stock at a price below $12.74 per share during the term of the warrant. As a result of this feature, we accounted for the warrant as a derivative liability on our balance sheet and recorded changes in fair value each reporting period through earnings (loss). The warrant expired unexercised on March 2, 2015. At June 30, 2014, the fair value of the warrant was estimated at $1.8 million, and we recorded a non-cash gain of $1.4 million during the three months ended June 30, 2014.

Income Tax Expense (Benefit)

The income tax expense recorded for the three months ended June 30, 2015 amounted to $0.1 million compared to income tax expense of $0.7 million for the three months ended June 30, 2014. Our effective tax rate for the quarter ended June 30, 2015 was (17.1)%. The rate is primarily comprised of the effect of the Texas margin tax due to our valuation allowance for federal income tax purposes being applied against any potential deferred tax asset, which would have ordinarily resulted. While we do not expect to receive a benefit for the full year, the negative effective tax rate is determined by applying the guidance in ASC 740-270. We expect to owe Texas margin tax for the full year 2015. We were not subject to a valuation allowance for federal taxes in the prior year comparable quarter.

Six Months Ended June 30, 2015 Compared to the Six Months Ended June 30, 2014

Revenues

Revenues for the six months ended June 30, 2015 were $43.4 million, representing a 53.8% increase compared to revenues of $28.2 million for the six months ended June 30, 2014. This increase was directly related to the addition of drilling rigs to our fleet between June 30, 2014 and June 30, 2015, which is reflected in the increase in our average number of operating rigs to 10.4 during the six months ended June 30, 2015 compared to 6.9 during the six months ended June 30, 2014, offset partially by a decrease from two of our rigs earning revenue on standby-without-crew rates during the second quarter of 2015, which are substantially lower than normal operating dayrates.

On a revenue per operating day basis, our revenues per day increased to $22,209 during the six months ended June 30, 2015, representing an increase compared to revenues per day of $21,480 for the six months ended June 30, 2014.

Operating Costs

Operating costs for the six months ended June 30, 2015 were $25.2 million, representing a 39.3% increase compared to operating costs of $18.1 million for the six months ended June 30, 2014. This increase was directly related to the addition of drilling rigs to our fleet between June 30, 2014 and June 30, 2015, offset partially by a decrease in operating costs from two of our rigs operating on a standby-without-crew basis during the second quarter of 2015, as they incurred minimal operating costs. On a cost per operating day basis, our cost per day decreased to $12,448 during the six months ended June 30, 2015, representing a 2.1% decrease compared to cost per day of $12,716 for the six months ended June 30, 2014.

Selling, General and Administrative

Selling, general and administrative expenses for the six months ended June 30, 2015 were $7.6 million, representing a 82.0% increase compared to selling, general and administrative expenses of $4.2 million for the six months ended June 30, 2014. This increase relates to additional payroll, insurance, professional fees and other ongoing costs associated with being a public company. Additionally, non-cash stock compensation expense increased by $0.2 million as a result of new awards made in connection with our initial public offering.

Depreciation and Amortization

Depreciation and amortization expense for the six months ended June 30, 2015 was $9.5 million, representing a 29.3% increase compared to depreciation and amortization expense of $7.3 million for the six months ended June 30, 2014.

This increase was related to the introduction of new drilling rigs constructed by us throughout 2014 and 2015 and a change in the estimated useful life for certain of our drilling equipment in the second quarter of 2015. We begin depreciating our rigs when they commence drilling operations. This increase was offset by the reduction in amortization of intangible assets during the current period as a result of our rig manufacturing intellectual property being fully amortized as of December 31, 2014.

(Insurance Recoveries) Asset Impairment, net

On March 9, 2014, one of our non-walking drilling rigs suspended drilling operations due to damage to the rig’s mast and other operating equipment. The cost to repair and replace this equipment was covered by insurance, subject to a $250,000 deductible. While under repair, we upgraded this rig by adding a substructure and other equipment that included a multi-directional walking system. The cost of the upgrades was not covered by insurance. The repairs and upgrades were completed in October 2014 and the upgraded rig was renamed Rig 208. We recorded an asset impairment charge of $4.7 million during the three months ended March 31, 2014, representing a preliminary estimate of the damage sustained to the rig. During the three months ended June 30, 2014, we recorded approximately $2.3 million in insurance proceeds related to repairing damage to the rig ($2.0 million) as well as the recovery of certain out-of-pocket expenses ($0.3 million), for which we had received a partial proof of loss from the insurance company. As of September 30, 2014, all of the $2.3 million had been collected. In the fourth quarter of 2014, we recorded an additional $1.6 million in insurance recoveries related to repairing damage to the rig ($1.0 million) as well as the recovery of out-of-pocket expenses ($0.6 million), for which we had received a second partial proof of loss from the insurance company. During the first quarter of 2015, we received a final payment of $2.9 million from the insurance company, and recognized an additional $1.3 million insurance recovery, representing the excess of the insurance recovery over the total impairment attributable to the damage to the rig.

We also recorded an expected insurance recovery of $0.2 million associated with a damaged driller's cabin. Offsetting these insurance recoveries is an additional impairment of $0.6 million associated with the damage to the driller's cabin and the impairment of various other drilling equipment during the six months ended June 30, 2015.

Loss (Gain) on Disposition of Assets

A loss on the disposition of assets totaling $0.3 million was recorded for the six months ended June 30, 2015 compared to a gain on the disposition of assets totaling $0.2 million in the prior year comparable period. In both periods the amounts related to the sale or disposition of miscellaneous drilling and other equipment.

Interest Expense

Interest expense for the six months ended June 30, 2015 was $1.0 million compared to interest expense of $1.0 million for the six months ended June 30, 2014. The majority of our interest expense is derived from borrowings under our revolving credit facility, which are primarily used to fund our rig construction activity.

Gain (Loss) on Warrant Derivative

Income Tax Benefit

The income tax benefit recorded for the six months ended June 30, 2015 amounted to $0.1 million compared to an income tax benefit of $1.2 million for the six months ended June 30, 2014. The effective tax rates for the six months ended June 30, 2015 and 2014 were (9.0)% and 36.2%, respectively.

Liquidity and Capital Resources

Our liquidity as of June 30, 2015 included approximately $63.3 million of availability under our revolving credit facility. Our principal use of capital has been the construction of land drilling rigs and associated equipment and working capital and inventories to support our growing drilling operations. Our first drilling rig was completed and began operating in May 2012. As of June 30, 2015, we had 13 completed ShaleDriller™ rigs and one ShaleDriller™ rig under construction. Our

primary sources of capital to date have been funds received from our initial private placement, our initial public offering, cash flows from operations and our revolving credit facility.

Net Cash Provided By Operating Activities

Cash provided by operating activities was $17.8 million for the six months ended June 30, 2015 compared to cash provided by operating activities of $3.2 million during the same period in 2014. 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, 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 2015 were higher as a result of an increase in the net income (loss), adjusted for non-cash items, of $11.8 million for the six months ended June 30, 2015 compared to $6.3 million during the same period in 2014. Working capital changes increased cash flows from operating activities by $6.0 million for the six months ended June 30, 2015 compared to a reduction of $3.2 million during the same period in 2014.

Net Cash Used In Investing Activities

Cash used in investing activities was $55.0 million for the six months ended June 30, 2015 compared to cash used in investing activities of $46.2 million during the same period in 2014. During the first six months of 2015, cash payments of $58.2 million for capital expenditures made in 2014 and 2015, 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. During the 2014 period, cash payments of $48.7 million for capital expenditures related primarily to new rig construction, were offset by the receipt of insurance proceeds of $2.0 million and proceeds from the sale of property, plant and equipment of $0.5 million.

Net Cash Provided by Financing Activities

Cash provided by financing activities was $38.7 million for the six months ended June 30, 2015 compared to $43.2 million during the same period in 2014. 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. During the first six months of 2014, we made borrowings under our revolving credit facility of $80.3 million. These proceeds were offset by repayments under our revolving credit facility of $35.9 million and expenditures for deferred financing costs of $1.2 million.

Future Liquidity Requirements

We expect our future capital and liquidity needs to be related to funding capital expenditures for new rigs, operating expenses, expansion of our critical spare and tubular goods inventories, working capital and general corporate purposes. Using our existing cash, cash flow from operations and borrowings under our revolving credit facility, during the second half of 2015, we plan to complete one rig currently under construction and upgrade one non-walking rig with a multi-directional walking system, as well as fund capital expenditures associated with our inventory of critical spares and maintenance capital expenditures for our existing rigs. We currently estimate that our remaining capital expenditures in 2015 will range between $13.0 million and $18.0 million. 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. However, should our liquidity needs increase, we may seek additional equity or debt financing.

Long-Term Debt

Credit Facility to reflect the removal of Rig 102 from service during the pendency of its upgrade. As a result of our initial public offering, completed on August 13, 2014, the final $25.0 of our $125.0 million Credit Facility became available to us.

On March 4, 2015, we further amended the Credit Facility to revise the definition of Eligible Completed Drilling Rigs and to reduce the Rig Utilization Ratio covenant through January 31, 2017.

On April 23, 2015, we amended the Credit Facility to provide for a springing lock-box arrangement.

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 footnote 11 in Part 1 “Item 1. Financial Statements” for additional information.

Recent Accounting Pronouncements

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 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 upon our consolidated financial statements or notes thereto.

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, 2015 included $61.4 million of floating-rate debt attributed to borrowings at an average interest rate of 4.9%. As a result, our annual interest cost in 2015 will fluctuate based on short-term interest rates.

The impact on annual cash flow of a 10% change in the floating-rate (approximately 0.49%) would be approximately $0.3 million annually based on the floating-rate debt and other obligations outstanding at June 30, 2015; 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 exploration and production ("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 declined significantly during the second half of 2014 and have continued to decline in 2015. The closing price of oil was as high as $106.06 per barrel during the third quarter of 2014, as low as $44.08 per barrel in late January 2015 and at $47.11 per barrel as of July 31, 2015 (WTI spot price as reported by the United States Energy Information Administration). Further declines in oil prices, for a prolonged period, could adversely impact the level of exploration and production activity by our customers and the demand for our services.

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 Securities Exchange Act of 1934, as amended (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 Rules 13a-15(e) and 15d-15(e) under the Exchange Act) 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. Based upon this evaluation, our principal executive officer and principal financial officer have concluded that our current disclosure controls and procedures were effective as of June 30, 2015 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, 2014. 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 Amendment to Amended and Restated Credit Agreement, dated as of April 23, 2015, 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 Quarterly Report on Form 10-Q (File No. 001-36590) filed May 11, 2015, Exhibit 10.2)

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:	Chief Executive Officer and Director (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: August 6, 2015