Glori Energy Inc. - FORM 10-Q

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EX-31.1 - EXHIBIT 31.1 - Glori Energy Inc.	gloriexhibit311-q315.htm
EX-32.2 - EXHIBIT 32.2 - Glori Energy Inc.	gloriexhibit322-q315.htm
EX-32.1 - EXHIBIT 32.1 - Glori Energy Inc.	gloriexhibit321-q315.htm
EX-10.1 - EXHIBIT 10.1 - Glori Energy Inc.	gloriexhibit101-q315.htm
EX-31.2 - EXHIBIT 31.2 - Glori Energy Inc.	gloriexhibit312-q315.htm

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

Form 10-Q

(Mark One)



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

For the quarterly period ended September 30, 2015



o	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: 000-55261

GLORI ENERGY INC.

(Exact name of registrant as specified in its charter)



Delaware		46-4527741
(State or Other Jurisdiction of		(I.R.S. Employer
Incorporation or Organization)		Identification No.)

10350 Richmond Avenue, Suite 850
Houston, Texas 77042		77042
(Address of Principal Executive Offices)		(Zip Code)

Registrant’s telephone number, including area code: (713) 237-8880

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. þ Yes o 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). þ Yes o 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 definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12-b2 of the Exchange Act). o Yes þ No

There were 31,861,357 common shares outstanding on November 4, 2015.

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INDEX TO FINANCIAL STATEMENTS

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		Page
PART I: FINANCIAL INFORMATION		4

Item 1.	Financial Statements	4

	Condensed Consolidated Balance Sheets	4

	Condensed Consolidated Statements of Operations	5

	Condensed Consolidated Statement of Stockholders' Equity	6

	Condensed Consolidated Statements of Cash Flows	7

	Notes to Condensed Consolidated Financial Statements	8

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	20

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	31

Item 4.	Controls and Procedures	32

PART II: OTHER INFORMATION		33

Item 1.	Legal Proceedings	33

Item 1A.	Risk Factors	33

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	33

Item 3.	Defaults Upon Senior Securities	33

Item 4.	Mine Safety Disclosures	33

Item 6.	Exhibits	33

Signature		35

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements provide our current expectations or forecasts of future events. Forward-looking statements include statements:


•	containing a projection of revenues, income (including income loss), earnings (including earnings loss) per share, capital expenditures, dividends, capital structure, or other financial items;


•	of the plans and objectives of management for future operations, including plans or objectives relating to the products or services of Glori;


•	of future economic performance, including any such statement contained in a discussion and analysis of financial condition by the management or in the results of operations included pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”);


•	of the assumptions underlying or relating to any statement described above; or


•	containing a projection or estimate of such other items as may be specified by rule or regulation of the SEC.

Forward-looking statements may also include any report issued by an outside reviewer retained by Glori, to the extent that the report assesses a forward-looking statement made by Glori. Forward-looking statements may include statements about our expectations, strategy, beliefs, plans, objectives, intentions, assumptions, prospects, estimates, projections, the future of our industry, our future profitability, estimates and projections of future activity and trends in the oil and natural gas industry, and other statements that are not historical facts. Words or phrases such as “anticipate,” “believe,” “continue,” “estimate,” “expect,” “intend,” “may,” “ongoing,” “plan,” “potential,” “predict,” “project,” “will” or similar words or phrases, or the negatives of those words or phrases, may identify forward-looking statements, but the absence of these words does not necessarily mean that a statement is not forward-looking. Examples of forward-looking statements in this Quarterly Report on Form 10-Q include, but are not limited to, statements regarding our disclosure concerning Glori's proposed operations, cash flows, and financial position.

These forward-looking statements are neither historical facts nor are they guarantees of future performance. These statements are based on management’s expectations that involve a number of business risks and uncertainties, any of which could cause actual results to differ materially from those expressed in or implied by the forward-looking statements. These statements involve known and unknown risks, uncertainties and other factors, most of which are difficult to predict and many of which are beyond our control, including the factors described under “Risk Factors”, that may cause our actual results and performance to be materially different from any future results or performance expressed or implied by these forward-looking statements. Such risks and uncertainties include, among other things:


•	the sustained or an increased decline of oil and gas commodity prices;


•	the potential delisting of our common stock from NASDAQ;


•	our ability to comply with debt covenants, service our debt, and make future required prepayments;


•	the increase in oil production rate and ultimate quantity of oil recovered using our AERO System;


•	the percentage of the world’s reservoirs that are suitable for our AERO System;


•	our ability to prove our technology and develop and maintain positive relationships with our customers and prospective customers;


•	competition and competitive factors in the markets in which we operate;


•	demand for our AERO System and our expectations regarding future projects;


•	adaptability of our AERO System and our development of additional capabilities that will expand the types of oil fields to which we can apply our technology;


•	our plans and ability to acquire and develop additional currently producing mature oil fields and the AERO System’s impact on these fields;


•	our plans to develop some abandoned and low producing mature oil fields;


•	the expected cost of recovering oil using our AERO System in our projects;


•	potential environmental or other liabilities associated with our acquired properties;


•	any projections, including earnings, revenues, expenses or any other financial items;


•	the impact of legislation and regulations on our operations;


•	our ability to compete with other enhanced oil recovery methods;


•	our ability to generate positive cash flows, including from the acquisition of oil producing properties, increases in oil prices, and improvement in our AERO System revenues;


•	our cash needs and expectations regarding cash flow from operations;


•	our ability to manage and grow our business and execution of our business strategy;


•	our financial performance;

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•	our estimates of oil reserves; and


•	the costs associated with being a public company.

We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, changed circumstances or otherwise, except to the extent law requires.

MARKET, INDUSTRY AND OTHER DATA

Unless otherwise indicated, information contained in this Quarterly Report on Form 10-Q concerning Glori’s industry and the markets in which Glori operates, including its general expectations and market position, market opportunity and market size, is based on information from various sources, on assumptions that it has made that are based on that information and other similar sources and on Glori’s knowledge of the markets for its services. That information involves a number of assumptions and limitations, and you are cautioned not to give undue weight to such estimates. While Glori believes that information from third-party sources used in this Quarterly Report on Form 10-Q is generally reliable, it has not independently verified the accuracy or completeness of this information. In addition, projections, assumptions and estimates of Glori’s future performance and the future performance of the industry in which Glori operates are necessarily subject to a high degree of uncertainty and risk due to a variety of factors, including those described in “Risk Factors” and elsewhere in this Quarterly Report on Form 10-Q. These and other factors could cause results to differ materially from those expressed in the estimates made by the independent parties and by Glori.

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PART I - FINANCIAL INFORMATION

Item 1: Financial Statements

GLORI ENERGY INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands, except share and per share data)



	December 31, 2014			September 30, 2015
				(Unaudited)
ASSETS

Current assets:
Cash and cash equivalents	$	29,751		$	12,298
Accounts receivable	1,371			1,228
Prepaid expenses and other current assets	244			276
Commodity derivatives	2,905			3,049
Total current assets	34,271			16,851

Property and equipment:
Proved oil and gas properties - successful efforts	45,694			47,859
Other property and equipment	5,941			6,455
	51,635			54,314

Less: accumulated depreciation, depletion, and amortization	(22,822		)	(22,848		)
Total property and equipment, net	28,813			31,466

Commodity derivatives	2,891			3,115
Deferred loan costs and other	490			305
Deferred tax asset, net	970			1,041
Total assets	$	67,435		$	52,778

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	2,251		$	857
Deferred revenues	653			—
Accrued expenses	1,792			1,213
Current portion of long-term debt	2,380			2,081
Current deferred tax liability, net	970			1,041
Total current liabilities	8,046			5,192

Long-term liabilities:
Long-term debt, less current portion	16,845			12,889
Asset retirement obligation	1,329			1,441
Total long-term liabilities	18,174			14,330
Total liabilities	26,220			19,522

Commitments and contingencies (Note 9)

Stockholders' equity:
Preferred stock, $.0001 par value, 5,000,000 shares authorized, no shares issued and outstanding as of December 31, 2014 and September 30, 2015	—			—
Common stock, $.0001 par value, 100,000,000 shares authorized, 31,499,303 and 31,848,857 shares issued and outstanding as of December 31, 2014 and September 30, 2015, respectively	3			3
Additional paid-in capital	105,383			106,627
Accumulated deficit	(64,171		)	(73,374		)
Total stockholders' equity	41,215			33,256
Total liabilities and stockholders' equity	$	67,435		$	52,778

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

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GLORI ENERGY INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2015			2014			2015
	(Unaudited)						(Unaudited)
Revenues:
Oil and gas revenues	$	4,103		$	1,738		$	8,489		$	5,874
Service revenues	1,355			281			3,527			1,344
Total revenues	5,458			2,019			12,016			7,218

Operating expenses:
Oil and gas operations	3,088			2,539			7,309			7,431
Service operations	657			395			2,715			1,450
Science and technology	449			425			1,166			1,528
Selling, general and administrative	1,572			1,297			4,204			4,549
Depreciation, depletion and amortization	1,325			1,230			2,931			3,337
Total operating expenses	7,091			5,886			18,325			18,295

Loss from operations	(1,633		)	(3,867		)	(6,309		)	(11,077		)

Other income (expense):
Interest expense	(705		)	(483		)	(2,309		)	(1,728		)
Gain on change in fair value of warrants	—			—			2,454			—
Gain (loss) on commodity derivatives	2,027			2,628			(764		)	3,017
Other income	6			422			21			417
Total other income (expense), net	1,328			2,567			(598		)	1,706

Net loss before taxes on income	(305		)	(1,300		)	(6,907		)	(9,371		)

Income tax expense (benefit)	51			3			193			(168		)

Net loss	$	(356	)	$	(1,303	)	$	(7,100	)	$	(9,203	)

Net loss per common share, basic and diluted	$	(0.01	)	$	(0.04	)	$	(0.25	)	$	(0.29	)

Weighted average common shares outstanding, basic and diluted	31,475			31,845			27,975			31,738

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

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GLORI ENERGY INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(in thousands, except share data)



	Stockholders' equity
	(Unaudited)

				Additional					Total
	Common stock			paid-in		Accumulated			stockholders'
	Shares	Par value		capital		deficit			equity

Balances as of December 31, 2014	31,499,303	$	3	$	105,383	$	(64,171	)	$	41,215

Stock based compensation	138,308	—		1,105		—			1,105

Stock option exercises	211,246	—		139		—			139

Net loss	—	—		—		(9,203		)	(9,203		)

Balances as of September 30, 2015	31,848,857	$	3	$	106,627	$	(73,374	)	$	33,256

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

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GLORI ENERGY INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)



	Nine Months Ended September 30,
	2014			2015
	(Unaudited)
Cash flows from operating activities:
Net loss	$	(7,100	)	$	(9,203	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization of property and equipment	2,931			3,337
Exploration expenses	—			102
Stock-based compensation	232			1,105
Bad debt expense	—			36
Amortization of deferred loan costs	326			248
Accretion of end-of-term charge	72			40
Unrealized loss (gain) on change in fair value of commodity derivatives	362			(368		)
Gain on change in fair value of warrant liabilities	(2,454		)	—
Accretion of discount on long-term debt	50			28
Loss on disposal of property and equipment	—			71
Non-cash gain on the sale of Etzold	—			(347		)
Changes in operating assets and liabilities:
Accounts receivable	(1,985		)	107
Prepaid expenses and other current assets	(141		)	(32		)
Accounts payable	409			(1,555		)
Deferred revenues	(896		)	(653		)
Accrued expenses	1,041			(619		)
Net cash used in operating activities	(7,153		)	(7,703		)

Cash flows from investing activities:
Purchase of proved oil and gas property	(41,048		)	(4,983		)
Purchase of other property and equipment	(643		)	(560		)
Net cash used in investing activities	(41,691		)	(5,543		)

Cash flows from financing activities:
Proceeds from issuance of common stock, preferred stock and preferred warrants	5,019			—
Proceeds from issuance of long-term debt	24,035			52
Proceeds from the exercise of stock options	—			139
Proceeds from merger with Infinity Corp. including private placement of common stock	38,441			—
Proceeds from the exercise of warrants	4,188			—
Payments for deferred offering costs	(3,337		)	—
Payments for deferred loan costs and other	(767		)	(63		)
Payments on long-term debt	(6,948		)	(4,335		)
Net cash provided by (used in) financing activities	60,631			(4,207		)

Net increase (decrease) in cash and cash equivalents	11,787			(17,453		)

Cash and cash equivalents, beginning of period	20,867			29,751

Cash and cash equivalents, end of period	$	32,654		$	12,298

Non-cash financing and investing activities:
Asset retirement obligation assumed	$	885		$	432

Supplemental cash flow information:
Interest paid	$	1,397		$	1,812

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

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GLORI ENERGY INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1 - ORGANIZATION, NATURE OF BUSINESS AND LIQUIDITY

Glori Energy Technology Inc., a Delaware corporation (formerly Glori Energy Inc.) ("GETI"), was incorporated in November 2005 (as successor in interest to Glori Oil LLC) to increase production and recovery from mature oil wells using state of the art biotechnology solutions.

In January 2014, GETI entered into a merger and share exchange agreement with Infinity Cross Border Acquisition Corporation ("INXB") and certain of its affiliates, Glori Acquisition Corp., Glori Merger Subsidiary, Inc., and Infinity-C.S.V.C. Management Ltd., an INXB Representative. On April 14, 2014, the merger and share exchange agreement was closed and the merger was consummated. As a result of this transaction, Infinity Cross Border Acquisition Corporation merged with and into Glori Acquisition Corp., with Glori Acquisition Corp. surviving the merger. Following that merger, Glori Merger Subsidiary, Inc. merged with and into GETI, with GETI surviving the merger. Following both of these mergers (collectively referred to herein as the "Merger"), GETI became the wholly-owned subsidiary of Glori Acquisition Corp., and Glori Acquisition Corp. adopted the name "Glori Energy Inc."

In March 2014, GETI incorporated Glori Energy Production Inc., a wholly-owned subsidiary of Glori Holdings Inc., to purchase the Coke Field (see NOTE 3) and incur the associated acquisition debt.

Management had previously undertaken the dissolution of Glori Oil S.R.L. During the nine months ended September 30, 2014 and 2015 there were no revenues and no assets associated with Glori Oil S.R.L. The dissolution of Glori Oil S.R.L and Glori Oil (Argentina) Limited were effective on August 24, 2015.

Glori Energy Inc., GETI, Glori Canada Ltd., Glori Holdings Inc., Glori California Inc., OOO Glori Energy and Glori Energy Production Inc. are collectively referred to as the “Company” in the condensed consolidated financial statements.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

We have prepared the condensed consolidated financial statements included herein pursuant to the rules and regulations of the U.S. Securities and Exchange Commission. Certain information and disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to these rules and regulations. In the opinion of management, these condensed consolidated financial statements contain all adjustments necessary to present fairly the Company’s condensed consolidated balance sheets as of December 31, 2014 and September 30, 2015 (unaudited), condensed consolidated statements of operations for the three and nine months ending September 30, 2014 and September 30, 2015 (unaudited), condensed consolidated statement of stockholders’ equity for the nine months ended September 30, 2015 (unaudited) and condensed consolidated statements of cash flows for the nine months ended September 30, 2014 and September 30, 2015 (unaudited). All such adjustments represent normal recurring items. The financial information contained in this report for the three and nine months ended September 30, 2014 and September 30, 2015, and as of September 30, 2015, is unaudited. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements as of and for the year ended December 31, 2014 and the notes thereto.

Principles of Consolidation

The accompanying condensed consolidated financial statements include the accounts of Glori Energy Inc. and its wholly-owned subsidiaries. Intercompany balances and transactions have been eliminated in consolidation.

Use of Estimates

The preparation of the condensed consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

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Reclassifications

Certain 2014 amounts related to inventory and prepaid expenses and other current assets have been reclassified for comparative purposes.

NOTE 3 - PROPERTY AND EQUIPMENT

Property and equipment consists of the following (in thousands):



	December 31, 2014			September 30, 2015
				(Unaudited)

Proved oil and gas properties - successful efforts	$	45,694		$	47,859
Unproved oil and gas properties	196			443
Construction in progress	589			607
Laboratory and warehouse facility	640			648
Laboratory and field service equipment	3,158			3,343
Office equipment, computer equipment, vehicles and other	1,358			1,414
	51,635			54,314

Less: accumulated depreciation, depletion and amortization (1)	(22,822		)	(22,848		)

Total property and equipment, net	$	28,813		$	31,466

(1) Excludes accretion of asset retirement obligation.

Depreciation, depletion, amortization and impairment consists of the following (in thousands):



	Three Months Ended September 30,
	2014		2015
Depreciation and amortization expense	$	117	$	158
Depletion expense	1,199		1,032
Accretion of asset retirement obligation	9		40
Total depreciation, depletion and amortization of property and equipment	$	1,325	$	1,230



	Nine Months Ended September 30,
	2014		2015
Depreciation and amortization expense	$	352	$	472
Depletion expense	2,458		2,749
Accretion of asset retirement obligation	121		116
Total depreciation, depletion and amortization of property and equipment	$	2,931	$	3,337

On July 1, 2015 the Company sold its mineral interests in the "Etzold Field" located in Seward County, Kansas. The Etzold Field was originally purchased in 2010 as a greenfield lab to advance the development of the Company's AERO technology, and the operations have historically been included in the Company's Oil and Gas Segment (see NOTE 11). With the purchase of the larger Coke Field and with the Company's future acquisition plans, the Company made the strategic decision to divest the Etzold Field. Prior to the sale the Company had associated net assets of $89,000, which were composed primarily of the purchase and development charges less accumulated depreciation and depletion and associated liabilities of $435,000 related to the plugging and abandonment obligation associated with the Etzold Field. In exchange for the leasehold interest in the field, the Company received $75,000 and the purchaser's assumption of the related asset retirement obligation. The Company recognized a gain on the sale of $420,000.

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The following table is a summarized operational history of the Etzold Field (in thousands):



	Three months ended September 30,				Nine months ended September 30,
	2014		2015		2014			2015
Revenues	$	74	$	—	$	249		$	57
Expenses	50		—		366			187
Net income (loss) from operations	24		—		(117		)	(130		)

Income taxes	—		—		—			—

Net loss	$	24	$	—	$	(117	)	$	(130	)

On June 1, 2015, a subsidiary of the Company, Glori Energy Production Inc., executed a purchase and sale agreement to acquire certain proved oil and gas mineral leases in Refugio County, Texas (the “Bonnie View Field”) from a third party seller for $2,644,000. The carrying value of the Bonnie View Field assets is also increased by an asset retirement obligation associated with plugging and abandoning the Bonnie View Field assets of $432,000. The effective date of the purchase was May 1, 2015. The Bonnie View Field does not meet the definition of a significant acquisition which would require pro forma financial information.

On March 14, 2014, a subsidiary of the Company, Glori Energy Production Inc., acquired the Coke Field which is composed of certain proved oil and gas mineral leases in Wood County, Texas from Petro-Hunt L.L.C. (“Petro-Hunt”) for (i) $38.0 million in cash and a $2.0 million convertible note payable (see NOTE 6) to Petro-Hunt and (ii) the assumption of the asset retirement obligation.

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The Company has included revenues and expenses related to the Coke Field for the period from March 15, 2014 through September 30, 2014 in the condensed consolidated statement of operations for the nine months ended September 30, 2014. For this period, the revenues and net loss attributable to the Coke Field were $8.1 million and $251,000, respectively which included a $745,000 loss on commodity derivatives.

The following summary presents unaudited pro forma information for the nine months ended September 30, 2014 as if the Coke Field had been acquired on January 1, 2014 (in thousands, except per share amounts).



	For the Nine Months Ended September 30,
	2014

Total revenues	$	14,752
Net loss	(7,441		)

Net loss per common share, basic and diluted	$	(0.27	)

Weighted average shares outstanding:
Basic	27,975
Diluted	27,975

NOTE 4 – FAIR VALUE MEASUREMENTS

FASB standards define fair value as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The standard also establishes a fair value hierarchy that requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The standard describes three levels of inputs that may be used to measure fair value:

Level 1 – Quoted prices in active markets for identical assets or liabilities.

Level 2 – Observable inputs other than Level 1 prices, such as quoted prices for similar assets or liabilities; or other inputs that are observable or can be corroborated by observable market data.

Level 3 – Unobservable inputs that are supported by little or no market activity and that are financial instruments whose values are determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant judgment or estimation.

If the inputs used to measure the financial assets and liabilities fall within more than one level described above, the categorization is based on the lowest level input that is significant to the fair value measurement of the instrument.

The following table summarizes the financial assets measured at fair value, on a recurring basis as of December 31, 2014 and September 30, 2015 (in thousands):



	Fair value measurements using
	Level 1	Level 2		Level 3	Total

December 31, 2014
Short-term commodity derivatives, asset	—	$	2,905	—	$	2,905
Long-term commodity derivatives, asset	—	2,891		—	2,891
	—	$	5,796	—	$	5,796

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	Fair value measurements using
	Level 1	Level 2		Level 3	Total
	(Unaudited)

September 30, 2015
Short-term commodity derivatives, asset	—	$	3,049	—	$	3,049
Long-term commodity derivatives, asset	—	3,115		—	3,115
	—	$	6,164	—	$	6,164

The Level 2 instruments presented in the table above consists of derivative instruments made up of commodity price swaps. The fair values of the Company's commodity derivative instruments are based upon the NYMEX futures value of oil compared to the contracted per barrel rate to be received. The Company records a liability associated with the futures contracts when the futures price of oil is greater than the contracted per barrel rate to be received and an asset when the futures price of oil is less than the contracted per barrel rate to be received.

NOTE 5 - DERIVATIVE INSTRUMENTS

The Company utilizes derivative financial instruments to manage risks related to changes in oil prices. The Company is currently engaged in oil commodity price swaps where a fixed price is received from the counterparty for a portion of the Company's oil production. In return the Company pays a floating price based upon NYMEX oil prices. Although these arrangements are designed to reduce the downside risk of a decline in oil prices on the covered production, they conversely limit potential income from increases in oil prices and expose the Company to the credit risk of counterparties. The Company manages the default risk of counterparties by engaging in these agreements with only high credit quality companies and through the continuous monitoring of their performance.

As of September 30, 2015, the Company had the following open positions on outstanding commodity derivative contracts:



Period	Volume/Month (Bbls)	Price/Unit		Fair Value - Asset
(Unaudited)

October 2015 - March 2016	7,300	$	86.50	1,746,000
April 2016 - March 2017	6,550	$	82.46	2,531,000
April 2017 - March 2018	5,800	$	80.53	1,887,000

The Company has not elected to designate any of these as derivative contracts for hedge accounting. Accordingly, the derivative contracts are carried at fair value on the condensed consolidated balance sheet as assets or liabilities. For each reporting period the contracts are marked-to-market and the resulting unrealized changes in the fair value of the assets and liabilities are recognized on the condensed consolidated statements of operations. The settlements of the closed derivative contracts result in realized gains and losses recorded on the Company's condensed consolidated statements of operations. The unrealized and realized gains and losses on derivative instruments are recognized in the (loss) gain on commodity derivatives line item located in other income (expense).

The following tables summarize the unrealized and realized gain (loss) on commodity derivatives (in thousands):



	Three Months Ended September 30,
	2014			2015
	(Unaudited)

Unrealized gain on commodity derivatives	$	2,206		$	1,750
Realized (loss) gain on commodity derivatives	(179		)	878
	$	2,027		$	2,628

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	Nine Months Ended September 30,
	2014			2015
	(Unaudited)

Unrealized (loss) gain on commodity derivatives	$	(362	)	$	368
Realized (loss) gain on commodity derivatives	(402		)	2,649
	$	(764	)	$	3,017

NOTE 6 - LONG TERM DEBT

On June 11, 2012, the Company entered into a secured term promissory note in the amount of $8.0 million. The note contained a 10.0% annual interest rate subject to increase based upon an increase in the prime rate. The loan was secured by substantially all assets of the Company with the exception of the Coke Field assets. The lender also received a warrant to purchase shares of the Company’s stock which was exchanged for 18,208 common shares upon consummation of the Merger. Equal monthly principal payments were due over 27 months beginning in April 2013 through June 2015 plus an end of term charge of $280,000. As of December 31, 2014 the ratable liability for the end of term charge was $240,000, and it is included in accrued expenses in current liabilities on the accompanying 2014 condensed consolidated balance sheet. The loan agreement contained covenants which placed restrictions on the incurrence of debt, liens and capital expenditures. On March 2, 2015 the Company elected to prepay the entire remaining indebtedness. The payment included remaining principal of $888,000 and the end of term charge of $280,000.

On March 14, 2014 in connection with the closing of the acquisition of the Coke Field, the Company entered into two financing agreements of $18.0 million and $4.0 million in order to fund a portion of the $38.0 million in cash required for the acquisition.

The $18.0 million note is a senior secured term loan of Glori Energy Production Inc. and is secured by the Coke Field and shares of common stock of Glori Energy Production Inc. The loan has a three year term bearing interest at 11.0% per annum, subject to increase upon a LIBOR rate increase above 1%. The credit agreement requires quarterly principal payments equal to 50% of the excess cash flows, as defined, from the Coke Field during the first year and 75% thereafter subject to a minimum quarterly principal payment of $112,500 plus interest. The loan was funded net of closing costs of 2%, or $360,000, which was initially included in deferred loan costs on the condensed consolidated balance sheets and amortized over the loan term. The loan agreement contains covenants which place restrictions on Glori Energy Production’s ability to incur additional debt, incur other liens, make other investments, capital expenditures and the sale of assets.

Glori Energy Production is also required to maintain certain financial ratios related to leverage, working capital and proved reserves, all as defined in the loan agreement. In May and November of each year, in accordance with a procedure outlined in the loan agreement, the value of the collateral securing the note is redetermined based on engineering reserve reports submitted by Glori Energy Production. On July 15, 2015 the Company made an additional $2 million principal paydown on the remaining principal balance in connection with a redetermination of the associated collateral value. As of December 31, 2014 and September 30, 2015 the outstanding loan balance was $17.4 million and $14.9 million, respectively.

Glori Energy Production was not in compliance with one of the quarterly loan covenants as of September 30, 2015. The Company was required to meet a maximum debt to EBITDA ratio ("Leverage Ratio") of 3.25 whereas the actual calculated ratio was 3.32. Glori Energy Production and the lender have executed a waiver regarding this noncompliance as of September 30, 2015. Additionally the Company entered into an amendment to the debt agreement with the lender on November 5, 2015, whereby the maximum permitted Leverage Ratio was increased to 3.5 through quarter ended December 31, 2015 and then to 3.25 through quarter ended June 30, 2016. Thereafter, the Leverage Ratio is 3.0. In connection with this amendment, the Company prepaid $1.6 million (see NOTE 12) of principal on the debt which will facilitate future compliance with the ratio. Glori Energy Production is in compliance with all other covenants as of September 30, 2015. If the Company fails to comply with future covenants this could result in a partial or full acceleration of the remaining principal balance.

The $4.0 million note had a two year term bearing interest at 12.0% per annum and was secured by the assets of the Company and subordinated to existing Company debt. The loan was funded net of closing costs of 2%, or $80,000, which was included in deferred loan costs on the consolidated balance sheet and amortized over the loan term. The $4.0 million note principal and a $400,000 prepayment penalty plus accrued interest were paid in full on May 13, 2014 and the remaining related deferred loan costs were expensed.

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On March 14, 2014, in connection with the purchase of the Coke Field, a subsidiary of the Company, Glori Energy Production, issued to Petro-Hunt an unsecured, subordinated convertible promissory note for $2.0 million bearing interest at 6.0% per annum. On April 14, 2014 the note was converted into 250,000 shares of post-Merger common stock.

Maturities on long-term debt during the next five years are as follows (in thousands):



Year ending September 30,	Amount
	(Unaudited)

2016	$	2,081
2017	12,853
2018	9
2019	9
2020	9
Thereafter	9
	$	14,970

NOTE 7 - LOSS PER SHARE

The Company follows current guidance for share-based payments which are considered as participating securities. Share-based payment awards that contain non-forfeitable rights to dividends, whether paid or unpaid, are designated as participating securities and are included in the computation of basic earnings per share. However, in periods of net loss, participating securities other than common stock are not included in the calculation of basic loss per share because there is not a contractual obligation for owners of these securities to share in the Company’s losses, and the effect of their inclusion would be anti-dilutive.

The following table sets forth the computation of basic and diluted earnings per share (in thousands, except per share data):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2015			2014			2015
	(Unaudited)						(Unaudited)
Numerator:
Net loss	$	(356	)	$	(1,303	)	$	(7,100	)	$	(9,203	)

Denominator:
Weighted-average common shares outstanding - basic	31,475			31,845			27,975			31,738
Effect of dilutive securities	—			—			—			—
Weighted-average common shares - diluted	31,475			31,845			27,975			31,738

Net loss per common share - basic and diluted	$	(0.01	)	$	(0.04	)	$	(0.25	)	$	(0.29	)

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The following weighted average securities outstanding during the three and nine months ended September 30, 2014 and September 30, 2015 were not included in the calculation of diluted shares outstanding as they would have been anti-dilutive (in thousands):



	Three Months Ended September 30,		Nine Months Ended September 30,
	2014	2015	2014	2015
	(Unaudited)		(Unaudited)

Common stock warrants ($10 strike price)	5,517	5,321	4,752	5,321
Common stock options	2,307	1,646	2,315	2,122
Restricted shares	—	200	—	105

NOTE 8 - INCOME TAXES

At December 31, 2014 and September 30, 2015, the Company has net operating loss carryforwards for federal income tax reporting purposes of approximately $51.9 million and $62.9 million, respectively, which will begin to expire in the year 2025, and tax credits of approximately $450,000 which will begin to expire in 2027. The NOL carry forward has not been reduced by approximately $5.4 million of loss carryforwards that management estimates will expire due to limitations from changes in control.

The Company has recorded valuation allowances against the Company's deferred tax assets. The effective tax rate for the three and nine months ended September 30, 2014 and September 30, 2015 varies from the statutory rate primarily due to the effect of the valuation allowance. For the three and nine months ended September 30, 2014 the Company had an income tax expense of $51,000 and $193,000, respectively, due to taxes payable on foreign income. For the three months ended September 30, 2015 the Company had an income tax expense of $3,000 and for the nine months ended September 30, 2015 the Company had an income tax benefit of $168,000 due to a reduction in taxes payable on foreign income as the Company revised its methodology for service fee applications charged to foreign subsidiaries.

ASC 740, Income Taxes ("ASC 740") prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of income tax positions taken or expected to be taken in an income tax return. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. The Company has amended its 2010 and 2011 federal income tax returns to correct the omission of Form 926 Return by a U.S. Transferor of Property to a Foreign Corporation regarding transfers to support the operations of its subsidiary Glori Oil S.R.L. Management estimates the liability for this omission is approximately $31,000, but believes any liability will be abated and, accordingly, has not recognized any liability in the accompanying consolidated financial statements. As of September 30, 2015, the Company has no other uncertain tax positions.

The Company's policy is to recognize interest and penalties related to uncertain tax positions as income tax expense in the Company's condensed consolidated statements of operations. The Company had no interest or penalties related to unrecognized tax expense for the quarter ended September 30, 2015.

NOTE 9 - COMMITMENTS AND CONTINGENCIES

Litigation

From time to time, the Company may be subject to legal proceedings and claims that arise in the ordinary course of business. The Company is not currently a party to any material litigation or proceedings and is not aware of any material litigation or proceedings, pending or threatened against it.

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Commitments

The Company leases two buildings in Houston, Texas and a warehouse facility in Gull Lake, Saskatchewan under operating leases. The Company entered into a two-year lease agreement in October 2014, for 7,805 square feet of office space in Houston's Westchase District for approximately $18,000 per month, with a one-year extension option at a 4% increase in rent and two one year extension options at a to be mutually agreed upon market rate with the lessor. The Company's original Houston building lease, which contains office space, warehouse space and a laboratory, expires in May 2017 and is leased for $11,000 per month. The Saskatchewan warehouse is a month-to-month lease which rents for C$1,000 per month and is cancelable with 30 days notice.

In addition to the facility lease commitments, the Company also has various other commitments such as technology hardware and support and software commitments.

Approximate minimum future rental payments under these noncancelable operating leases as of September 30, 2015 are as follows (in thousands):



	Year Ending September 30,
	(Unaudited)

2016	$	353
2017	85
	$	438

Total rent expense was approximately $74,000 and $217,000 for the three and nine months ended September 30, 2014 and $90,000 and $305,000 for the three and nine months ended September 30, 2015, respectively.

NOTE 10 - STOCK-BASED COMPENSATION

Stock Incentive Plan

In December 2014, the Company shareholders approved the adoption of the 2014 Long Term Incentive Plan ("the 2014 Plan") which authorized 2,000,000 shares to be available for issuance to officers, directors, employees, and consultants of the Company. Options are issued at an exercise price equal to the fair market value of the Company’s common stock at the grant date. Generally, the options vest 25 percent after 1 year, and thereafter ratably each month over the following 36 months, and may be exercised for a period of 10 years subject to vesting.

The Company has computed the fair value of all options granted during the year ended December 31, 2014 and nine months ended September 30, 2015, using the Black-Scholes option pricing model using the following assumptions:



	Year ended December 31,		Nine months ended September 30,
	2014		2015
			(Unaudited)

Risk-free interest rate	2.44	%	1.39	%
Expected volatility	55	%	73	%
Expected dividend yield	—		—
Expected life (in years)	7.00		6.00
Expected forfeiture rate	—		—

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The following table summarizes the activity of the Company’s plan related to stock options:



	Number of options		Weighted average exercise price per share		Weighted average remaining contractual term (years)	Aggregate intrinsic value
Outstanding as of December 31, 2014	2,300,050		$	0.82	6.72	$	7,725,000
Awarded (unaudited)	318,234		3.10
Exercised (unaudited)	(211,314	)	0.66
Forfeited or Expired (unaudited) (1)	(164,092	)	1.77
Outstanding as of September 30, 2015 (unaudited)	2,242,878		$	1.09	6.33	$	370,270
Exercisable as of December 31, 2014	2,099,345		$	0.79	6.60	$	7,119,000
Exercisable as of September 30, 2015 (unaudited)	1,915,130		$	0.83	5.89	$	370,270


(1)	Management considers the circumstances generating these forfeitures to be unusual and nonrecurring in nature; accordingly, no allowance for forfeitures of options to purchase shares has been considered in determining future vesting or expense.

The weighted-average grant date fair value for equity options granted during the nine months ended September 30, 2014 and September 30, 2015 was $0.66 and $2.00, respectively. There were no option awards issued in the three months ended September 30, 2014 and September 30, 2015. The total fair value of options vested during the three months ended September 30, 2014 and September 30, 2015 was $77,000 and $54,000, respectively. The total fair value of options vested during the nine months ended September 30, 2014 and September 30, 2015 was $236,000 and $207,000, respectively.

In addition to stock options, the Company issued two restricted stock grants to directors during 2015. The first grant for 100,806 shares vested entirely on April 14, 2015 and the second grant for 191,326 shares vests on April 14, 2016. There were also 686,333 shares of restricted stock issued primarily to executives. The executives' awards vest over a four year period with 25% of the vesting occurring annually and initial vesting occurring on the first anniversary of the issuance date.

Stock-based compensation expense is included primarily in selling, general and administrative expense was $78,000 and $247,000 for the three months ended September 30, 2014 and September 30, 2015, respectively, and $232,000 and $1.1 million for the nine months ended September 30, 2014 and September 30, 2015, respectively. The Company has future unrecognized compensation expense for nonvested shares at September 30, 2015 of $2.3 million with a weighted average vesting period of 2.8 years.

NOTE 11 – SEGMENT INFORMATION

The Company generates revenues through the production and sale of oil and natural gas (the “Oil and Gas Segment”) and through the Company’s AERO services provided to third party oil companies (the “AERO Services Segment”). The Oil and Gas Segment produces and develops the Company’s acquired oil and natural gas interests. The revenues derived from the segment are from sales to the first purchaser. The Company uses two such arrangements for oil sales, one for the Coke Field and Quitman Fields located in Wood County, Texas and one for the Bonnie View Field in Refugio County, Texas.

The AERO Services Segment derives revenues from external customers by providing the Company’s biotechnology solution of enhanced oil recovery through a two-step process consisting of (1) the Analysis Phase and (2) the Field Deployment Phase.

The Analysis Phase work is a reservoir screening process whereby the Company obtains field samples and evaluates the Company’s potential for AERO Services Segment success. This process is performed at the Company’s Houston laboratory facility. The science and technology expenses shown on the Company’s condensed consolidated statements of operations are the expenses that are directly attributable to the Analysis Phase and expenses associated with the Company’s on-going research and development of its technology and are included in the "Corporate Segment".

In the Field Deployment Phase the Company deploys skid mounted injection equipment used to inject nutrient solution in the oil reservoir. The work in this phase is performed in oil fields of customers located in the United States and internationally and in the Company’s own oil fields. The service operations expense shown on the Company’s condensed consolidated statements of operations are the expenses that are directly attributable to the Field Deployment Phase and included in the AERO Services Segment.

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Earnings of industry segments exclude income taxes, interest income, interest expense and unallocated corporate expenses.

Although the AERO Services Segment provides enhanced oil recovery services to the Oil and Gas Segment, the Company does not utilize intercompany charges. The direct costs of the services such as the injection solution, transportation of the solution and expenses associated with the injection are charged directly to the Oil and Gas Segment. All of the AERO Services Segment capital expenditures and depreciation associated with injection equipment is viewed as part of the AERO Services Segment.

The following table sets forth the operating segments of the Company and the associated revenues and expenses (in thousands):



	Oil and Gas			AERO Services		Corporate			Total
	(Unaudited)

Three months ended September 30, 2014
Revenues	$	4,103		$	1,355	$	—		$	5,458
Total operating expenses	3,088			657		2,021			5,766
Depreciation, depletion and amortization	1,245			73		7			1,325
(Loss) income from operations	(230		)	625		(2,028		)	(1,633		)

Other income (expense), net	2,027			—		(699		)	1,328

Income tax expense	—			—		51			51

Net income (loss)	$	1,797		$	625	$	(2,778	)	$	(356	)



	Oil and Gas			AERO Services			Corporate			Total
	(Unaudited)

Three months ended September 30, 2015
Revenues	$	1,738		$	281		$	—		$	2,019
Total operating expenses	2,539			395			1,722			4,656
Depreciation, depletion and amortization	1,096			69			65			1,230
Loss from operations	(1,897		)	(183		)	(1,787		)	(3,867		)

Other income (expense), net	3,050			—			(483		)	2,567

Income tax expense	—			—			3			3

Net income (loss)	$	1,153		$	(183	)	$	(2,273	)	$	(1,303	)

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	Oil and Gas			AERO Services		Corporate			Total
	(Unaudited)
Nine Months Ended September 30, 2014
Revenues	$	8,489		$	3,527	$	—		$	12,016
Total operating expenses	7,309			2,715		5,370			15,394
Depreciation, depletion and amortization	2,645			263		23			2,931
(Loss) income from operations	(1,465		)	549		(5,393		)	(6,309		)

Other (expense) income, net	(764		)	—		166			(598		)

Income tax expense	—			—		193			193

Net (loss) income	(2,229		)	549		(5,420		)	(7,100		)



	Oil and Gas			AERO Services			Corporate			Total
	(Unaudited)
Nine Months Ended September 30, 2015
Revenues	$	5,874		$	1,344		$	—		$	7,218
Total operating expenses	7,431			1,450			6,077			14,958
Depreciation, depletion and amortization	2,961			278			98			3,337
Loss from operations	(4,518		)	(384		)	(6,175		)	(11,077		)

Other income (expense), net	3,439			—			(1,733		)	1,706

Income tax benefit							(168		)	(168		)

Net loss	(1,079		)	(384		)	(7,740		)	(9,203		)

NOTE 12 – SUBSEQUENT EVENTS

On November 5, 2015, the Company made an additional principal paydown of $1.6 million on the remaining $14.9 million principal balance of the senior secured term loan in connection with the amended credit agreement (see NOTE 6).

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the accompanying unaudited condensed consolidated financial statements as of September 30, 2015 and for the three and nine months ended September 30, 2015 and 2014 included elsewhere herein, and with our annual report on Form 10-K for the year ended December 31, 2014. The following discussion and analysis contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of certain factors, including those set forth under “Risk Factors” in Item 1A of our annual report and elsewhere in this quarterly report. See “Cautionary Note Regarding Forward-Looking Statements” above.

Overview

We are a Houston-based energy technology and oil production company that deploys our proprietary AERO technology to increase the amount of oil that can be produced from conventional fields at a substantially lower cost than traditional enhanced oil recovery methods ("AERO System"). Only about one-third of the oil discovered in a typical reservoir is recoverable using conventional oil production technology, leaving the remaining two-thirds trapped in the reservoir rock. Our AERO System technology stimulates the native microorganisms that reside in the reservoir to improve the recoverability of this trapped oil. The AERO System can reverse production declines and significantly increase ultimate reserve recovery at a low incremental cost per barrel. Glori owns and operates oil fields onshore in the U.S. where we deploy our technology, and additionally market the AERO System as a technology service to exploration and production ("E&P") companies globally. We derive revenues from fees earned as a service provider of our technology to third party E&P companies, and we also use our technology to increase oil production in fields that we acquire and operate in the United States.

Glori scientists continue to work on research initiatives that further advance our understanding of how to alter the total amount of recoverable oil in conventional oilfields, drive down costs per incremental barrel of oil produced by increasing oil yield and increase the number of candidate oil fields that will benefit from this technology. Initial field deployment of our water conditioning technology, which will simplify the AERO deployment and will significantly increase the available market, has shown results that we believe are encouraging. We are now expanding the pilot deployment to test the limits of efficacy. In addition, we are making good progress in furthering the development of our Residual Oil Flow model, or ROF^SM model. The objectives of the development of the ROF model are to match demonstrated field results and further optimize recovery performance based on fundamentals of the interactions between microbiology and residual oil. Ultimately, the ROF model may significantly alter the way that residual oil is viewed in a reservoir and pave the way to even greater extraction success. In addition to our efforts to develop the model, we are continuing to work closely with the National Energy Technology Labs (NETL) and a major U.S. research university to further investigate flow mechanisms of residual oil.

We intend to acquire and redevelop additional mature oil fields with historically long-lived, predictable production profiles that fit our criteria for the AERO System. We target mature sandstone assets onshore in North America with good permeability and production supported by waterflood or waterdrive systems, or with clear potential for waterflooding. We believe our acquisition strategy can enhance the revenues, cash flows and returns from such oil fields through waterflood optimization and implementation of our AERO System of enhanced oil recovery. We believe this strategy will enable us to further demonstrate the efficacy of our AERO System while allowing us to capture the increase in revenues and ultimate recovery. We believe the acquisition of principally proved producing oil reserves, with production and cash flow history, is an economically attractive, low-risk complement to our service business. Further, by owning our own oil properties, we can manage the implementation of AERO System in a controlled environment and accelerate the industry adoption of our technology. Over the past year as oil prices decreased, potential sellers have been reluctant to sell at the lower prices, thereby decreasing acquisition opportunities. We believe, in the near future, however, many oil operators will seek to divest non-core oil properties to strengthen their liquidity. We expect conditions will improve for us to further our strategy to acquire oil properties that have a significant amount of oil remaining in place with reservoir characteristics that would make it possible for the AERO System to recover residual oil.

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On January 8, 2014, we executed a merger and share exchange agreement with INXB and certain of its affiliates. On April 14, 2014, the Merger was consummated. We obtained effective control of INXB subsequent to the Merger and thus the Merger was accounted for as a reverse acquisition and recapitalization of the Company. Subsequent to the Merger, our shareholders retained a substantial majority of voting interest and positions on the Board of Directors. Additionally our management is retained and our operations comprise the ongoing operations post-Merger. In connection with the Merger, we received approximately $24.7 million, net of certain expenses and fees, and approximately $13.7 million in cash from the private placement of common stock for total proceeds of $38.4 million.

On March 14, 2014, we acquired the Coke Field from Petro-Hunt for (i) $38.0 million in cash and a $2.0 million convertible note payable to Petro-Hunt, and (ii) the assumption of the asset retirement obligation related to plugging and abandoning the Coke Field. Subsequent to the Merger the note payable to Petro-Hunt was converted into common stock.

On June 1, 2015, a subsidiary of the Company, Glori Energy Production Inc., executed a purchase and sale agreement to acquire certain proved oil and gas mineral leases in Refugio County, Texas (the “Bonnie View Field”) from a third party seller for $2.6 million. The carrying value of the Bonnie View Field assets is also increased by an asset retirement obligation associated with plugging and abandoning the Bonnie View Field assets of $432 thousand.

Net loss for the third quarter of 2015 was $1.3 million or $0.04 per share. This compares to a third quarter 2014 net loss of $356 thousand, or a loss of $0.01 per share.

Revenues for the third quarter of 2015 were $2.0 million, reflecting a decrease of $3.4 million from the third quarter of 2014. Oil and gas revenues decreased to $1.7 million from $4.1 million in the third quarter 2014 due to a 56% decrease in average oil prices received and a 7% decrease in oil and gas volumes produced and sold in the third quarter of 2015. Revenues from our AERO technology services segment decreased to $281 thousand in the third quarter of 2015 from $1.4 million, a decrease of 79% from the third quarter of 2014 due to a decline in the number of new projects in the 2015 period. Although our AERO System is a low cost enhanced oil recovery solution, our 2015 service revenues were adversely affected by the general decline of E&P industry spending on new projects as a result of the sharp drop in oil prices.

During the third quarter of 2015, we produced 44,470 net barrels of oil equivalents ("BOE") or approximately 483 net BOE per day, including 40,360 barrels of oil and 24,659 thousand cubic feet of natural gas, and received an average realized price of $42.44 per barrel and $1.48 per thousand cubic foot. We utilized 8,050 thousand cubic feet of natural gas production in operations at the Bonnie View field during the quarter. After the effect of oil price swap settlements, our oil price per barrel for the quarter was approximately $64.18 per barrel. Production from liquids (oil and condensate) represented approximately 91% of total production. Total production in the third quarter of 2015 increased approximately 11% from second quarter 2015 production due to the addition of production from the Bonnie View Field, which was acquired in June 2015 and produced 6,053 BOE in the third quarter and an increase in production at the Coke Field. The contribution to production from the Bonnie View Field was partially offset by the exclusion of production from the Etzold Field, which was sold July 1, 2015.

Oil and gas expenses in the third quarter of 2015 were $2.5 million compared to $3.1 million in the third quarter of 2014 due primarily to a 12% reduction in lease operating expenses, despite the acquisition of the Bonnie View field, a 94% reduction in acquisition expenses, and a 58% reduction in severance taxes as a result of lower oil prices. These decreases were partially offset by exploration expenses related to a radial jetting recovery technology project incurred in the third quarter of 2015. Included in oil and gas operating expenses for the third quarter of 2015 are direct lease operating expenses of approximately $1.8 million, exploration expenses of $102 thousand, ad valorem taxes of $91 thousand, production taxes of $81 thousand, third party professional fees of $21 thousand, acquisition expenses of $16 thousand and compensation and other administrative expenses associated with our acquisitions and production professional personnel of $475 thousand.

Service operations expense decreased 40% to $395 thousand in the third quarter of 2015 compared to $657 thousand in the prior year third quarter due primarily to a decrease in project costs for domestic projects as certain client projects were concluded in 2015 that were ongoing during the 2014 period. Service operations salaries also decreased due to cost reduction efforts. Services operating expenses include outlays for nutrient solution, materials, supplies, travel and transportation and costs of personnel engaged in our AERO Services Field Deployment Phase.

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Science and technology expenses decreased to $425 thousand in the third quarter of 2015 compared to $449 thousand in the prior year third quarter. The decrease was driven by a reduction in supplies and materials used in support of client AERO projects, which were fewer during the 2015 period. Science and technology expenses include personnel expenses, supplies and other administrative expenses attributable to the Analysis Phase of our AERO service projects and ongoing research and development of technology performed at our Houston laboratory facility. When compared to the second quarter of 2015, science and technology expenses decreased from $629 thousand to $425 thousand due to decreased costs for salaries due to cost reduction efforts, for stock based compensation and for third party research fees.

Selling, general and administrative ("SG&A") expenses totaled $1.3 million in the third quarter of 2015, reflecting a decrease of $275 thousand from the prior year period or 17%. The overall decrease is due to decreased professional fees in the third quarter of 2015. When compared to the second quarter of 2015, SG&A expense decreased from $1.5 million to $1.3 million primarily due to decreased sales and marketing costs, professional fees and salaries due to cost reduction efforts.

Depreciation, depletion, amortization and impairment ("DD&A") was $1.2 million in the third quarter of 2015 compared to $1.3 million in the prior-year period. DD&A expense declined as the result of decreased depletion offset by increased depreciation and accretion. Depletion decreased due to lower overall production and lower capitalized costs as a result of impairment recognized in December 2014.

Interest expense totaled $483 thousand in the third quarter of 2015, compared with $705 thousand in the third quarter of 2014. The decrease was primarily the result of the lower level of debt in the third quarter of 2015 compared to the third quarter of 2014 including the prepayment of a secured term promissory note in March 2015.

We had price swap derivatives in place covering approximately 54% of our oil and condensate production for the third quarter of 2015. We continue to maintain price swaps covering a portion of our estimated future production. In the third quarter ended September 30, 2015, we recorded a net gain on commodity derivatives of approximately $2.6 million due to a decrease in NYMEX oil futures prices from the beginning to the end of the quarter. This gain included $878 thousand in realized cash settlements received. In the previous year's third quarter, we recorded a net gain on commodity derivatives of $2.0 million, which was net of $179 thousand in realized cash settlements paid.

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Results of Operations

Historical Results of Operations for Glori

The following table sets forth selected financial data for the periods indicated (in thousands):



	Three Months Ended September 30,						Nine months ended September 30,
	2014			2015			2014			2015
Revenues:
Oil and gas revenues	$	4,103		$	1,738		$	8,489		$	5,874
Service revenues	1,355			281			3,527			1,344
Total revenues	5,458			2,019			12,016			7,218

Operating expenses:
Oil and gas operations	3,088			2,539			7,309			7,431
Service operations	657			395			2,715			1,450
Science and technology	449			425			1,166			1,528
Selling, general and administrative	1,572			1,297			4,204			4,549
Depreciation, depletion and amortization	1,325			1,230			2,931			3,337
Total operating expenses	7,091			5,886			18,325			18,295

Loss from operations	(1,633		)	(3,867		)	(6,309		)	(11,077		)

Other income (expense):
Interest expense	(705		)	(483		)	(2,309		)	(1,728		)
Gain on change in fair value of warrants	—			—			2,454			—
Gain (loss) on commodity derivatives	2,027			2,628			(764		)	3,017
Other income	6			422			21			417
Total other income (expense), net	1,328			2,567			(598		)	1,706

Income tax expense (benefit)	51			3			193			(168		)

Net loss	$	(356	)	$	(1,303	)	$	(7,100	)	$	(9,203	)

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The following table sets forth selected production data for the periods indicated:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2015		2014		2015
Revenues (in thousands):
Oil revenues	$	4,052	$	1,713	$	8,357	$	5,788
Natural gas revenues	51		25		132		86
Total oil and gas revenues	$	4,103	$	1,738	$	8,489	$	5,874

Sales volumes:
Oil volumes (MBbls)	42		40		88		117
Gas volumes (MMcf)	23		17		48		57
Gas volumes (MBoe)	4		3		8		9
Total volumes (MBoe)	46		43		96		126

Price:
Average oil price received per Bbl	$	95.90	$	42.44	$	94.55	$	49.56
Average oil price per Bbl including price swap settlements	$	91.68	$	64.18	$	90.00	$	72.24
Average gas price per Mcf	$	2.18	$	1.48	$	2.73	$	1.51

The following table details oil and gas operations expense for the periods indicated (in thousands):



	Three months ended September 30,				Nine months ended September 30,
	2014		2015		2014		2015
Lease operating expense	$	2,002	$	1,753	$	4,767	$	4,813
Ad valorem taxes	136		91		330		265
Severance taxes	192		81		397		273
Acquisition expenses	278		16		418		60
Exploration expense	—		102		—		102
Oil and gas overhead expense	480		496		1,397		1,918
Oil and gas operations expense	$	3,088	$	2,539	$	7,309	$	7,431

Three Months Ended September 30, 2014 and 2015

Oil and gas revenues. Oil and gas revenues decreased by $2.4 million, or 58%, from $4.1 million in the three months ended September 30, 2014 to $1.7 million in the three months ended September 30, 2015. The decrease was primarily attributable to a 56% decrease in average oil prices received and a 7% decrease in oil and gas volumes produced and sold.

Service revenues. Service revenues decreased by $1.1 million, or 79%, from $1.4 million in the three months ended September 30, 2014 to $281 thousand in the three months ended September 30, 2015. The decrease in revenues was attributable to decreases of $875 thousand and $193 thousand in Analysis Phase and Field Deployment Phase services, respectively. The decrease in Analysis Phase revenues was due to a decline in the number of projects during the 2015 period. The decrease in Field Deployment Phase revenues was primarily due to a decrease of $160 thousand in Canadian revenues due to the July 2015 completion and recognition of revenue on a customer project that contributed $170 thousand in revenues in the third quarter of 2014. During the 2015 period, service revenues were adversely impacted by the decrease in oil prices which resulted in significant decreases in spending by our E&P customers and prospects.

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Oil and gas operations. Oil and gas expense decreased by $549 thousand, or 18%, from $3.1 million in the three months ended September 30, 2014 to $2.5 million in the three months ended September 30, 2015. The overall decrease was attributable to decreases in lease operating expenses of $249 thousand, acquisition expenses of $262 thousand, and severance taxes of $111 thousand. Lease operating expenses decreased as a result of cost reduction efforts and a decline in repairs and workover costs which were high shortly after we acquired the Coke Field in 2014. The decrease in lease operating expenses was achieved in spite of the acquisition of the Bonnie View field on June 1, 2015 which resulted in an additional $136 thousand in lease operating expenses in the third quarter of 2015. Acquisition expenses decreased as a result of third party acquisition sourcing fees as well as due diligence expenses incurred for a significant acquisition target in the prior year period. Severance taxes decreased due to sustained lower oil prices and revenues. Ad valorem tax expense decreased by $45 thousand due to a revised tax assessment. These decreases were partially offset by an increase in exploration expense for $102 thousand as a result of an unsuccessful radial jetting project.

Service operations. Service operations expense decreased by $262 thousand, or 40%, from $657 thousand in the third quarter of 2014 to $395 thousand in the third quarter 2015. The decrease was primarily attributable to a $145 thousand decrease in domestic project expenses as two projects in the Field Deployment Phase during the third quarter of 2014 were concluded in February and July 2015. Project expenses in Brazil also decreased $87 thousand due to costs incurred during the initial mobilization and deployment of our AERO system technology in the third quarter of 2014. Additionally, operations salaries decreased $30 thousand due to cost reduction efforts.

Science and technology. Science and technology expenses decreased by $24 thousand from $449 thousand in the three months ended September 30, 2014 to $425 thousand in the three months ended September 30, 2015 mostly due to a decrease of $65 thousand in supplies and materials purchased in support of client AERO projects and a decrease of $21 thousand in salaries expense due to cost reduction efforts. These decreases were partially offset by increases in stock based compensation and third party research fees.

Selling, general and administrative ("SG&A"). SG&A expenses decreased by $275 thousand, or 17%, from $1.6 million in the three months ended September 30, 2014 to $1.3 million in the three months ended September 30, 2015. The decrease was primarily attributable to a decrease of $305 thousand in legal fees associated with various nonrecurring filings associated with being a new public company such as form S-8, calling a special meeting, and filing the final SEC form 20-F of our predecessor, Infinity Corp, as well as other general shareholder matters. Salaries decreased $75 thousand over the prior year third quarter due to cost reduction efforts. Increases in insurance and facilities expenses partially offset the decrease in professional fees and salaries.

Depreciation, depletion and amortization ("DD&A"). DD&A decreased from $1.3 million for the three months ended September 30, 2014 to $1.2 million for three months ended September 30, 2015. The overall decrease was due to decrease in depletion expense of $167 thousand related to the December 2014 impairment of the Coke Field and Etzold Field as a result of the oil price decline. Depletion expense for the third quarter of 2015 was calculated based on a lower value as compared to the third quarter of 2014 as a result of impairment during 2014. This decrease was partially offset by increases of $41 thousand and $31 thousand in depreciation and accretion expense, respectively. Depreciation increased due to the deployment of skid-mounted injection units into service in Brazil in October 2014.

Total other income (expense), net. Total other income (expense), net, increased $1.2 million from an income of $1.3 million in the three months ended September 30, 2014 to an income of $2.6 million in the three months ended September 30, 2015. Our commodity price swaps that were entered into in connection with the acquisition of the Coke Field in March 2014 resulted in a gain of $2.6 million in the three months ended September 30, 2015 compared to a gain of $2.0 million in the prior year period. In the 2015 period, the derivative gain consisted of an $878 thousand realized gain on price swap settlements and a $1.8 million unrealized gain on the change in fair value of future settlements due to a decrease in NYMEX oil futures prices from the beginning to the end of the quarter. In the 2014 period, the unrealized derivative gain of $2.2 million as a result of falling NYMEX futures prices was partially offset by a $179 thousand realized loss on price swap settlements. Interest expense also decreased $222 thousand compared to the third quarter 2014 due to the reduction of debt used to partially fund the Coke Field acquisition and the March 2015 prepayment of remaining indebtedness of the $8.0 million secured term promissory note which was outstanding in the full prior year period. Other income (expense) also increased $416 thousand in the third quarter of 2015 compared to the same prior year period as a result of the gain on the sale of the Etzold property on July 1, 2015.

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Nine Months Ended September 30, 2014 and 2015

Oil and gas revenues. Oil and gas revenues decreased by $2.6 million from $8.5 million in the nine months ended September 30, 2014 to $5.9 million in the nine months ended September 30, 2015. The decrease was attributable to a 48% decrease in average oil prices and was partially offset by a 31% increase in production volume sold. The increase in production was a result of the purchase of the Bonnie View Field which closed on June 1, 2015 as well as the inclusion of a full nine months of oil and gas sales from the Coke Field, which was purchased in March 2014 during the prior year nine month period.

Service revenues. Service revenues decreased by $2.2 million, or 62%, from $3.5 million in the nine months ended September 30, 2014 to $1.3 million in the nine months ended September 30, 2015. The decrease in revenues was attributable to decreases of $1.0 million and $1.1 million in Analysis Phase and Field Deployment Phase services, respectively. The decrease in Analysis Phase revenues was due to fewer ongoing projects in the 2015 period. The decrease in Field Deployment Phase revenues was due to a decrease of $1.7 million in Canadian revenues primarily due to the conclusion of a large AERO field project in June 2014. During the 2015 period, service revenues were adversely impacted by the decrease in oil prices which resulted in significant decreases in spending by our E&P customers and prospects.

Oil and gas operations. Oil and gas operating expense increased to $7.4 million for the nine months ended September 30, 2015 to $7.3 million for the nine months ended September 30, 2014. Overhead charges increased by a net $521 thousand, including $425 thousand for employee compensation related to additions to professional and technical staff associated with the growth of our oil and gas segment and $264 thousand due to commissions paid to a third party consultant who located a new purchaser for Coke Field oil production, which resulted in a higher realized price per barrel than that received from the previous purchaser. Additionally there was an increase in exploration expense for $102 thousand as a result of an unsuccessful radial jetting project. These increases in oil and gas operations were partially offset by a decrease in due diligence related costs of $168 thousand in association with the Coke Field acquisition during 2014. Lease operating expenses increased $46 thousand due primarily to the operating cost of the Bonnie View Field, purchased in June 2015. These increases were offset by decreases of $358 thousand in acquisition expenses due to due diligence and acquisition sourcing fees incurred in the prior period, $124 thousand in severance taxes due to sustained lower oil prices and revenues, and $65 thousand in ad valorem tax expense due to a revised tax assessment.

Service operations. Service operations expense decreased by $1.3 million, or 47%, from $2.7 million in the nine months ended September 30, 2014 to $1.5 million in the nine months ended September 30, 2015. Approximately $833 thousand of the decrease is attributable to reduced project costs such as trucking and nutrient solution related to a large Canadian field project which concluded during June 2014 and another Canadian project which concluded during July 2015. The remaining decrease is primarily attributable to reduced project costs related to two domestic field projects which concluded during February and July 2015.

Science and technology. Science and technology expenses increased by $362 thousand, or 31%, from $1.2 million in the nine months ended September 30, 2014 to $1.5 million in the nine months ended September 30, 2015 mostly due to an increase of $173 thousand in third party research fees, including those for core flood research assisted by a major U.S. research university. Employee compensation expenses also increased, including $129 thousand for stock based compensation.

Selling, general and administrative ("SG&A"). SG&A expenses increased by $345 thousand, or 8%, from $4.2 million in the nine months ended September 30, 2014 to $4.5 million in the nine months ended September 30, 2015. The increase was primarily attributable to an increase of $322 thousand in insurance and compensation expenses for an increase in professional staff and for members of our Board of Directors in connection with our transition to being a public company.

Depreciation, depletion and amortization ("DD&A"). DD&A increased by $406 thousand from $2.9 million in the nine months ended September 30, 2014 to $3.3 million in the nine months ended September 30, 2015. The depletion increase of $291 thousand was primarily attributable to the addition of depletion expense for the Bonnie View Field, purchased June 1, 2015. Depreciation increased $120 thousand primarily due to deployment of skid-mounted AERO injection units into service in Brazil.

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Total other income (expense), net. Total other income (expense), net increased by $2.3 million from an expense of $598 thousand in the nine months ended September 30, 2014 to an income of $1.7 million in the nine months ended September 30, 2015. Our commodity price swaps that were entered into in connection with the acquisition of the Coke Field in March 2014 resulted in a gain of $3.0 million in the nine months ended September 30, 2015 compared to a $764 thousand loss on commodity price swaps in the prior year period. In the 2015 period, the derivative gain consisted of a $2.6 million realized gain on price swap settlements and a $368 thousand unrealized gain on the change in fair value of future settlements. In the 2014 period, the derivative loss consisted of a $402 thousand realized loss on price swap settlements and a $362 thousand unrealized loss on the change in fair value of future settlements. Additionally during the nine months ended September 30, 2014 there was a gain on change in the fair value of warrant liabilities in conjunction with the Merger which resulted in the recognition of a $2.5 million gain on the change in fair value of warrant liabilities. Interest expense decreased $581 thousand from the 2015 period due to the declining balance of our outstanding notes, including debt used to partially fund the Coke Field acquisition and the $8.0 million secured term promissory note which was prepaid in March 2015.

Liquidity and Capital Resources

Our primary sources of liquidity and capital since our formation have been proceeds from equity issuances and borrowings. To date, our primary use of capital has been to fund acquisitions, principally the purchase of the Coke Field, to fund our operations and for payments on debt.

At September 30, 2015, we had working capital of $11.7 million, made up of current assets of $16.9 million and current liabilities of $5.2 million. The current asset balance is comprised of cash and cash equivalents of $12.3 million, accounts receivable of $1.2 million, prepaid expenses and other current assets of $276 thousand, and commodity derivative contracts receivable of $3.0 million. Included in current liabilities is $857 thousand in accounts payable, $1.2 million in accrued expenses, $2.1 million in current portion of long-term debt, and a deferred tax liability of $1.0 million. On July 15, 2015, we made an additional principal paydown of $2 million of the senior secured term loan facility in connection with the redetermination of the associated collateral value. We have also prepaid $1.6 million on this facility in connection with an amendment to our Note Purchase Agreement, as reported in NOTES 6 and 12 of our consolidated financial statements. (See NOTE 6 - Long Term Debt and 12 - Subsequent Events). We could be required to make additional pay downs as a result of maintaining compliance with debt covenants or future redetermination of associated collateral values.

During the next twelve months, we expect our principal sources of liquidity to be from cash on hand, new financing to be used for future potential oil property acquisitions and cash flows from our oil properties. If we are successful in acquiring additional oil properties, the associated debt facilities will likely be based on the value of the oil and gas reserves acquired and secured by the respective assets. Depending on the size of the acquisitions, we may require additional equity capital. We expect these sources of liquidity will enable us to fund our capital expenditures and working capital needs for the next twelve months.

On October 23, 2015, we received a notice from the Listing Qualifications Department of the NASDAQ Stock Market LLC indicating that, for the last 30 consecutive business days, the bid price for our common stock had closed below the minimum $1.00 per share required for continued inclusion on The NASDAQ Capital Market under NASDAQ Listing Rule 5550(a)(2). The Company will be afforded 180 calendar days, or until April 20, 2016, to regain compliance with the minimum bid price requirement. In order to regain compliance, shares of the Company’s common stock must maintain a minimum bid closing price of at least $1.00 per share for a minimum of ten consecutive business days. If we do not regain compliance by that date, we may be eligible for an additional 180 day grace period as long as we meet certain listing requirements and provide written notice of our intention to cure the deficiency during this additional compliance period. The notification letter has no immediate effect on Glori’s listing or trading of common stock, does not affect the Company’s business operations or its SEC reporting requirements, and does not cause a default under any material agreement.

The Company will continue to execute its business strategy and, if necessary, will consider implementing available options to regain compliance with the minimum bid price requirement of NASDAQ Listing Rule 5810(c)(3)(A), including a reverse stock split. If our common stock is delisted, it would likely trade in the over-the-counter market. Such NASDAQ delisting or further declines in our stock price could greatly impair our ability to raise additional capital to finance additional capital expenditures and could significantly increase the ownership dilution to shareholders caused by our issuing equity in financing or other transactions.

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We intend to pursue additional acquisitions of producing oil assets in which to deploy the AERO System. Planned capital expenditures for the next twelve months consist of approximately $2 million to $3 million for Coke Field and Bonnie View Field expansion and implementation of our AERO System technology. Expected capital expenditures consist primarily of the recompletion of four water injection wells and related surface equipment for expansion of our AERO System technology on the Coke Field and the drilling of two wells for the initial implementation of our AERO System technology on the Bonnie View Field. We will adjust the amount and timing of our capital spending dependent upon our cash on hand, our cash flow from operations and the availability of capital. As of September 30, 2015, we did not have any commitments for the acquisition of oil properties or any other significant capital commitments.

Revenues and cash flows from our existing oil properties, in the near-term, represent the majority of our cash from operating activities until we complete other acquisitions of oil producing assets or experience significant growth in our services revenues. Operating cash flow from our existing oil properties, after direct operating expenses and related overhead costs, are principally dedicated to servicing acquisition-related debt and capital expenditures. Such operating cash flow will be influenced by a number of factors such as oil production rates, oil prices and operating expenses. While we have entered into hedges for a portion of our oil production, variability in operating cash flow may require us to pursue additional resources to fund future capital expenditures and service associated debt.

The price of oil decreased 21% during the third quarter of 2015 based on the Cushing, Oklahoma - West Texas Intermediate spot prices of $56.94 per barrel on July 1, 2015 and $45.06 on September 30, 2015. Subsequent to September 2015, the oil price fell to approximately $43.19 per barrel as of October 26, 2015. A sustained lower oil price through December 2015 will negatively impact fourth quarter oil revenues and profitability from our oil producing assets, which will be partially offset by other income realized from oil price swap settlements. Using an estimated average oil price of $40 per barrel, assuming third quarter production volumes, oil and gas revenues would have decreased from $1.7 to $1.6 million, and the realized gain on monthly oil price swap settlements would have increased from $878 thousand in the third quarter to $1.0 million in the third quarter of 2015. See ITEM 3. Quantitative and Qualitative Disclosures About Market Risk for further discussion on the potential impact of an oil price decline.

Future cash requirements and the requirement for new financing will be dependent primarily upon our success in generating additional acquisition opportunities and the related capital expenditures. We have not historically generated positive cash flow from operating activities. Our ability to increase our cash flow from operating activities will depend on closing additional oil property acquisitions which contribute positive cash flow, an increase in oil prices, successful results from AERO implementation on our oil properties and improvement in our AERO services revenues. We intend to pursue additional acquisition opportunities which will require additional debt or equity financing. If we are not successful in securing such financing, our ability to generate growth in revenues and achieve positive cash flows will be materially adversely affected.

The following table sets forth the major sources and uses of cash for the periods presented (in thousands):



	Nine Months Ended September 30,
	2014			2015
Net cash used in operating activities	$	(7,153	)	$	(7,703	)
Net cash used in investing activities	(41,691		)	(5,543		)
Net cash provided by (used in) financing activities	$	60,631		$	(4,207	)

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Operating Activities

During the nine months ended September 30, 2015, our operating activities used $7.7 million in cash. Our net loss for the nine months ended September 30, 2015 was $9.2 million. Non-cash items totaled an expense of $4.3 million, consisting of $3.3 million of depreciation, depletion and amortization, $1.1 million for stock based compensation expense, $248 thousand for amortization of deferred loan costs and other non-cash expenses totaling $175 thousand. These non-cash expenses were partially offset by a $368 thousand unrealized gain on the change in fair value of the commodity price swap and a $347 thousand non-cash gain on the sale of the Etzold Field. For a more detailed description of the Etzold Field and its sale, please see NOTE 3 to our condensed consolidated financial statement included with this report. Changes in operating assets and liabilities reduced net cash by $2.8 million for the period. The cash decrease from changes in operating assets and liabilities was caused by a decrease in accounts payable of $1.6 million, a decrease in deferred revenues of $653 thousand, a decrease in accrued expenses of $619 thousand, and an increase in prepaid expenses and other current assets of $32 thousand. These uses of cash were partially offset by a decrease in accounts receivable of $107 thousand. The decrease in accounts payable and accrued expenses was due to the timing of payments for obligations at fiscal year end, and the decrease in deferred revenue is due to recognition of previously unearned revenues which was triggered as certain services projects progressed through the Field Deployment Phase.

During the nine months ended September 30, 2014, our operating activities used $7.2 million in cash. Our net loss for the nine months ended September 30, 2014 was $7.1 million. Non-cash items totaled to an expense of $1.5 million, consisting of $2.9 million of depreciation, depletion and amortization, $362 thousand for an unrealized loss on commodity price swaps, $326 thousand for amortization of deferred loan costs, $232 thousand for stock based compensation expense and other non-cash expenses totaling $122 thousand. These non-cash expenses were partially offset by a gain on the change in fair value of warrant liabilities of $2.5 million. Changes in operating assets and liabilities reduced net cash by $1.6 million for the period. The cash reduction from changes in operating assets and liabilities was caused by an increase in accounts receivable of $2.0 million, a decrease in deferred revenues of $896 thousand and an increase in prepaid expenses and other current assets of $141 thousand. These uses of cash were partially offset by an increase in accrued expenses of $1.0 million and an increase in accounts payable of $409 thousand. Accounts receivable increased primarily due to a receivable outstanding at September 30, 2014 for $1.5 million for oil and gas sales related to the Coke Field. The increase in accrued expenses was driven by an increase in accrued interest of $501 thousand related to the $18.0 million note secured by the Coke Field as well as a $496 thousand increase related to ad valorem taxes payable on the Coke Field.

Our future cash flow from operations will depend on many factors including our ability to acquire oil fields, successfully deploy our AERO System technology on such oil fields, and on oil prices. Other variables affecting our cash flow from operations are the adoption rate of our technology and the demand for our services, which is also impacted by the level of oil prices and the capital expenditure budgets of our customers and potential customers.

Investing Activities

Our capital expenditures were $5.5 million for the nine months ended September 30, 2015 compared to $41.7 million for the nine months ended September 30, 2014. The $36.1 million decrease is due to the purchase of the Coke Field in the prior year period. For the nine months ended September 30, 2015, capital expenditures of $2.9 million were due to the June 1, 2015 purchase and subsequent development of the Bonnie View Field. A majority of the remainder of the capital expenditures were efforts associated with implementing our AERO System technology at the Coke Field, including unitization, drilling of a water source well and an injection well.

Financing Activities

During the nine months ended September 30, 2015, cash used by financing activities was $4.2 million consisting of $4.3 million in principal payments on long-term debt and $63 thousand in payments for deferred loan costs. These cash outflows were partially offset by proceeds of $139 thousand from stock option exercises and $52 thousand from the financing of vehicles for the field.

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During the nine months ended September 30, 2014, net cash provided by financing activities was $60.6 million consisting primarily of cash proceeds of $38.5 million received in the Merger and new credit facilities totaling $24.0 million which were used to fund a portion of the Coke Field acquisition. The new borrowings mainly consisted of an $18.0 million senior secured term loan, $4.0 million subordinated debt and a $2.0 million convertible note to the seller, Petro-Hunt. Additionally $5.0 million was received from the issuance of C-2 preferred shares and warrants, which were exchanged for common shares in the Merger, and $4.2 million was received from the exercise of warrants. Cash generated from financing activities during the nine months ended September 30, 2014 was partially offset by principal payments on long-term debt of $6.9 million, payments for deferred offering costs of $3.3 million and payments for deferred loan costs of $767 thousand. The deferred offering costs represent legal expense payments related to the Merger and the deferred loan costs payments represent financing fees and legal expenses associated with the $18.0 million senior secured term loan and the $4.0 million subordinated debt.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements, except for operating lease obligations presented in the table below.

Contractual Obligations and Commercial Commitments

At September 30, 2015, we had contractual obligations and commercial commitments as follows (in thousands):



	Payments Due By Period
Contractual Obligations	Total		Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years
Operating lease obligations(1)	$	438	$	353	$	85	$	—	$	—
Asset retirement obligation(2)	1,441		—		184		713		544
Long-term debt(3)	17,741		3,718		13,994		20		9
Total	$	19,620	$	4,071	$	14,263	$	733	$	553


(1)	Our commitments for operating leases primarily relate to the leases of office and warehouse facilities in Houston, Texas and warehouse facilities in Gull Lake, Saskatchewan.


(2)	Relates to our oil properties, net of accretion.


(3)	Includes expected future interest payments.

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Recently Issued Accounting Pronouncements

In April 2015, the FASB issued ASU No. 2015-03, "Interest—Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs" (ASU 2015-03). ASU 2015-03 is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2015 and early adoption is permitted. Prior GAAP guidance mandates recognizing debt issuance costs as a deferred charge. Such treatment is different from the guidance in International Financial Reporting Standards (IFRS), which requires that transaction costs be deducted from the carrying value of the financial liability and not recorded as separate assets. Additionally, the requirement to recognize debt issuance costs as deferred charges conflicts with the guidance in FASB Concepts Statement No. 6, Elements of Financial Statements, which states that debt issuance costs are similar to debt discounts and in effect reduce the proceeds of borrowing, thereby increasing the effective interest rate. Concepts Statement 6 further states that debt issuance costs cannot be an asset because they provide no future economic benefit. To simplify presentation of debt issuance costs, the amendments in this Update require 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 that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this Update. We are currently evaluating this standard and the impact it will have on our consolidated financial statements.

In May 2014, the Financial Accounting Standards Board (FASB) and the International Accounting Standards Board (IASB) issued a comprehensive new revenue recognition standard that will supersede existing revenue recognition guidance under United States generally accepted accounting principles (U.S. GAAP) and International Financial Reporting Standards (IFRS). The issuance of this guidance completes the joint effort by the FASB and the IASB to improve financial reporting by creating common revenue recognition guidance for U.S. GAAP and IFRS. The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. The standard creates a five-step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for several transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the standard’s application impact to individual financial statement line items. This standard is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. In April 2015, the FASB agreed to propose a one-year deferral of the revenue recognition standard's effective date for all entities, which would change the effectiveness to annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. We are currently evaluating this standard and the impact it will have on our future revenue recognition policies.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodities Risk

Our major commodity price risk exposure is to the prices received for our oil production. Our results of operations and operating cash flows are affected by changes in market prices. Realized commodity prices received for our production are the spot prices applicable to oil in the region produced. Prices received for oil, condensate, and natural gas are volatile and unpredictable and are beyond our control, none of which are for trading purposes. To mitigate a portion of the exposure to adverse market changes, we have entered into derivative instruments. For the three months ended September 30, 2015 and nine months ended September 30, 2015, a 10% change in the prices received for oil, condensate, and natural gas production would have had an approximate $174 thousand and $587 thousand impact, respectively on our revenues prior to commodity derivatives which partially mitigate our commodity pricing risk. See NOTE 5 in the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1 of this report for additional information regarding our commodity derivative activities.

Interest Rate Risk

Our floating rate loan facilities expose us to interest rate risk. Our two major credit facilities outstanding are based on interest at a floating rates that are subject to increase based upon certain increases in the prime rate or LIBOR. Therefore upward fluctuations in interest rates expose us to additional interest payments. As of September 30, 2015, our total long-term debt was $15.0 million. An increase of 100 basis points in both the prime and LIBOR interest rate will expose us to a $38,000 quarterly increase in interest.

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Item 4. Controls and Procedures

Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of 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 Securities Exchange Act of 1934, as amended (“Exchange Act”), as of September 30, 2015. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of September 30, 2015, our disclosure controls and procedures were effective in providing reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the fiscal quarter ended September 30, 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II: OTHER INFORMATION

Item 1. Legal Proceedings

From time to time, we may be subject to legal proceedings and claims that arise in the ordinary course of business. We are not a party to any material litigation or proceedings and not aware of any material litigation or proceedings, pending or threatened against us.

Item 1A. Risk Factors

In addition to the disclosures in this report, see the risk factors discussed in the section "Risk Factors", beginning on page 14, of Item 1A. to our Annual Report on Form 10-K filed March 12, 2015 for discussion of other risk factors. Those risk and uncertainties are not the only ones facing us, and there may be additional matters of which we are unaware or that we currently consider immaterial. All of those risks and uncertainties could adversely affect our business, financial condition, and/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

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ITEM 6. EXHIBITS

EXHIBIT INDEX



Exhibit	Description
3.1	Amended and Restated Certificate of Incorporation of Glori Energy Inc. (incorporated by reference to Exhibit 3.3 of the Company's Form 8-K/A, filed May 2, 2014)
3.2	Amended and Restated Bylaws of Glori Energy, Inc. (incorporated by reference to Exhibit 3.4 of the Company's Form 8-K, filed April 18, 2014)
10.1*	Third Amendment to Note Purchase Agreement made and entered into as of November 5, 2015, between Glori Energy Production Inc., Stellus Capital Investment Corporation and each of the holders signatory signed thereto
31.1*	Certification by Stuart Page, Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*	Certification by Victor Perez, Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1*	Certification by Stuart Page, Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2*	Certification by Victor Perez, Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema Document
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document



*	Filed herewith

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SIGNATURE

Pursuant to the requirements of the Securities and Exchange Act of 1934, I have duly caused this report to be signed on our behalf by the undersigned thereunto duly authorized.

November 6, 2015

Date



		Glori Energy Inc.
		Registrant

By:		/s/ Victor M. Perez
		Victor M. Perez Chief Financial Officer (Principal Financial Officer)

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