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EX-31.2 - EXHIBIT 31.2 - Glori Energy Inc.gloriexhibit312-q215.htm
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EX-32.1 - EXHIBIT 32.1 - Glori Energy Inc.gloriexhibit321-q215.htm
EX-32.2 - EXHIBIT 32.2 - Glori Energy Inc.gloriexhibit322-q215.htm


 
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 June 30, 2015
or
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):

Large accelerated filer o
 
Accelerated filer  þ
 
Non-accelerated filer o
 
Smaller reporting company þ
 
 
 
 
(Do not check if a smaller reporting company.)
 
 
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 31,843,980 common shares outstanding on August 4, 2015. 



INDEX TO FINANCIAL STATEMENTS
 
Table of Contents
 
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


1


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 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;
our estimates of oil reserves; and
the costs associated with being a public company.

2



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.


3


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
 
June 30, 2015
 
 
 
(Unaudited)
ASSETS
 

 
 

 
 
 
 
Current assets:
 

 
 

Cash and cash equivalents
$
29,751

 
$
17,076

Accounts receivable
1,371

 
1,149

Prepaid expenses and other current assets
244

 
433

  Commodity derivatives
2,905

 
2,095

Total current assets
34,271

 
20,753

 
 
 
 
Property and equipment:
 
 
 
 Proved oil and gas properties - successful efforts
45,694

 
47,605

 Other property and equipment
5,941

 
6,369

 
51,635

 
53,974

 
 
 
 
 Less: accumulated depreciation, depletion and amortization
(22,822
)
 
(21,671
)
Total property and equipment, net
28,813

 
32,303

 
 
 
 
Commodity derivatives
2,891

 
2,319

Deferred loan costs and other
490

 
357

Deferred tax asset
970

 
683

Total assets
$
67,435

 
$
56,415

 
 
 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
 

 
 

 
 
 
 
Current liabilities:
 

 
 

Accounts payable
$
2,251

 
$
1,297

Deferred revenues
653

 
33

Accrued expenses
1,792

 
1,680

Current portion of long-term debt
2,380

 
2,473

Current deferred tax liability, net
970

 
683

Total current liabilities
8,046

 
6,166

 
 
 
 
Long-term liabilities:
 

 
 

Long-term debt, less current portion
16,845

 
14,564

Asset retirement obligation
1,329

 
1,402

Total long-term liabilities
18,174

 
15,966

Total liabilities
26,220

 
22,132

 
 
 
 
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 June 30, 2015

 

Common stock, $.0001 par value, 100,000,000 shares authorized, 31,499,303 and 31,828,626 shares issued and outstanding as of December 31, 2014 and June 30, 2015, respectively
3

 
3

Additional paid-in capital
105,383

 
106,351

Accumulated deficit
(64,171
)
 
(72,071
)
Total stockholders' equity
41,215

 
34,283

Total liabilities and stockholders' equity
$
67,435

 
$
56,415


The accompanying notes are an integral part of these consolidated financial statements.
4


GLORI ENERGY INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data) 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2014
 
2015
 
2014
 
2015
 
(Unaudited)
 
(Unaudited)
Revenues:
 

 
 

 
 
 
 
Oil and gas revenues
$
3,644

 
$
2,136

 
$
4,386

 
$
4,136

Service revenues
1,912

 
496

 
2,172

 
1,063

Total revenues
5,556

 
2,632

 
6,558

 
5,199

 
 
 
 
 
 
 
 
Operating expenses:
 

 
 

 
 
 
 
Oil and gas operations
2,994

 
2,500

 
4,221

 
4,892

Service operations
1,517

 
534

 
2,058

 
1,055

Science and technology
397

 
629

 
717

 
1,103

Selling, general and administrative
1,370

 
1,534

 
2,632

 
3,252

Depreciation, depletion and amortization
1,158

 
1,039

 
1,606

 
2,107

Total operating expenses
7,436

 
6,236

 
11,234

 
12,409

 
 
 
 
 
 
 
 
Loss from operations
(1,880
)
 
(3,604
)
 
(4,676
)
 
(7,210
)
 
 
 
 
 
 
 
 
Other (expense) income:
 

 
 

 
 
 
 
Interest expense
(1,257
)
 
(530
)
 
(1,604
)
 
(1,245
)
Gain on change in fair value of warrants

 

 
2,454

 

(Loss) gain on commodity derivatives
(2,791
)
 
(980
)
 
(2,791
)
 
389

Other income (expense)
10

 
10

 
15

 
(5
)
Total other (expense) income, net
(4,038
)
 
(1,500
)
 
(1,926
)
 
(861
)
 
 
 
 
 
 
 
 
Net loss before taxes on income
(5,918
)
 
(5,104
)
 
(6,602
)
 
(8,071
)
 
 
 
 
 
 
 
 
Income tax expense (benefit)
142

 
(188
)
 
142

 
(171
)
 
 
 
 
 
 
 
 
Net loss
$
(6,060
)
 
$
(4,916
)
 
$
(6,744
)
 
$
(7,900
)
 
 
 
 
 
 
 
 
Net loss per common share, basic and diluted
$
(0.20
)
 
$
(0.15
)
 
$
(0.26
)
 
$
(0.25
)

 

 
 

 
 
 
 
Weighted average common shares outstanding,
basic and diluted
29,642

 
31,803

 
26,179

 
31,684



The accompanying notes are an integral part of these consolidated financial statements.
5


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
 
125,808

 

 
838

 

 
838

 
 
 
 
 
 
 
 
 
 
 
Stock option exercises
 
203,515

 

 
130

 

 
130

 
 
 
 
 
 
 
 
 
 
 
Net loss
 

 

 

 
(7,900
)
 
(7,900
)
 
 
 
 
 
 
 
 
 
 
 
Balances as of June 30, 2015
 
31,828,626

 
$
3

 
$
106,351

 
$
(72,071
)
 
$
34,283




The accompanying notes are an integral part of these consolidated financial statements.
6


GLORI ENERGY INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
 
Six Months Ended June 30,
 
2014
 
2015
 
(Unaudited)
Cash flows from operating activities:
 
 
 
Net loss
$
(6,744
)
 
$
(7,900
)
Adjustments to reconcile net loss to net cash used in operating activities:
 

 
 

Depreciation, depletion and amortization of property and equipment
1,606

 
2,107

Stock-based compensation
155

 
838

Bad debt expense

 
36

Amortization of deferred loan costs
223

 
194

Accretion of end-of-term charge
48

 
40

Unrealized loss on change in fair value of commodity derivatives
2,568

 
1,382

Gain on change in fair value of warrant liabilities
(2,454
)
 

Accretion of discount on long-term debt
33

 
28

Changes in operating assets and liabilities:
 

 
 

Accounts receivable
(1,394
)
 
186

Prepaid expenses and other current assets
(132
)
 
(101
)
Accounts payable
433

 
(1,437
)
Deferred revenues
(473
)
 
(620
)
Accrued expenses
864

 
(587
)
Net cash used in operating activities
(5,267
)
 
(5,834
)
 
 
 
 
Cash flows from investing activities:
 

 
 

Purchase of proved oil and gas property
(39,581
)
 
(4,403
)
Purchase of other property and equipment
(149
)
 
(312
)
Net cash used in investing activities
(39,730
)
 
(4,715
)
 
 
 
 
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

 

Proceeds from the exercise of stock options

 
130

Proceeds from merger with Infinity Corp. including private placement of common stock
38,490

 

Proceeds from the exercise of warrants
4,137

 

Payments for deferred offering costs
(2,794
)
 

Payments for deferred loan costs
(767
)
 
(40
)
Payments on long-term debt
(5,786
)
 
(2,216
)
Net cash provided by (used in) financing activities
62,334

 
(2,126
)
 
 
 
 
Net increase (decrease) in cash and cash equivalents
17,337

 
(12,675
)
 
 
 
 
Cash and cash equivalents, beginning of period
20,867

 
29,751

 
 
 
 
Cash and cash equivalents, end of period
$
38,204

 
$
17,076

 
 
 
 
Non-cash financing and investing activities:
 

 
 

Asset retirement obligation assumed
$
745

 
$
432

 
 

 
 

Supplemental cash flow information:
 
 
 
Interest paid
$
888

 
$
1,338


The accompanying notes are an integral part of these consolidated financial statements.
7


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.
 
Glori Energy Inc., GETI, Glori Oil (Argentina) Limited, Glori Oil S.R.L., 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 June 30, 2015 (unaudited), condensed consolidated statements of operations for the three and six months ending June 30, 2014 and June 30, 2015 (unaudited), condensed consolidated statement of stockholders’ equity for the six months ended June 30, 2015 (unaudited) and condensed consolidated statements of cash flows for the six months ended June 30, 2014 and June 30, 2015 (unaudited). All such adjustments represent normal recurring items. The financial information contained in this report for the three and six months ended June 30, 2014 and June 30, 2015, and as of June 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.


8


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
 
June 30, 2015
 
 
 
(Unaudited)
 
 
 
 
Proved oil and gas properties - successful efforts
$
45,694

 
$
47,605

Unproved oil and gas properties
196

 
404

Construction in progress
589

 
624

Laboratory and warehouse facility
640

 
648

Laboratory and field service equipment
3,158

 
3,202

Office equipment, computer equipment, vehicles and other
1,358

 
1,491

 
51,635

 
53,974

 
 
 
 
Less:  accumulated depreciation, depletion and amortization (1)
(22,822
)
 
(21,671
)
 
 
 
 
 Total property and equipment, net
$
28,813

 
$
32,303

(1) Excludes accretion of asset retirement obligation.
  
Depreciation, depletion and amortization consists of the following (in thousands):
 
Three Months Ended June 30,
 
2014
 
2015
Depreciation and amortization expense
$
112

 
$
159

Depletion expense
1,032

 
840

Accretion of asset retirement obligation
14

 
40

Total depreciation, depletion, and amortization of property and equipment
$
1,158

 
$
1,039


 
Six Months Ended June 30,
 
2014
 
2015
Depreciation and amortization expense
$
236

 
$
314

Depletion expense
1,259

 
1,717

Accretion of asset retirement obligation
111

 
76

Total depreciation, depletion, and amortization of property and equipment
$
1,606

 
$
2,107


As of June 30, 2015, the Company committed to a plan to sell its mineral interests in the "Etzold Field" located in Seward County, Kansas. The associated net assets held for sale of $89,000, which are composed primarily of the purchase and development charges less accumulated depreciation and depletion, were moved from property, plant and equipment to the prepaid expenses and other current assets line item on the Company's condensed consolidated balance sheet. The associated liabilities held for sale of $435,000 related to the plugging and abandonment obligation associated with the Etzold Field was moved from the asset retirement obligation line item to accrued liabilities on the Company's condensed consolidated balance sheet.


9


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. The Company executed a purchase and sale agreement to sell the Etzold Field subsequent to June 30, 2015 (see NOTE 12).

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

 
Three months ended June 30,
 
Six months ended June 30,
 
2014
 
2015
 
2014
 
2015
Revenues
$
103

 
$
41

 
$
174

 
$
57

Expenses
76

 
61

 
170

 
161

Net income (loss) from operations
27

 
(20
)
 
4

 
(104
)
 
 
 
 
 
 
 
 
Income taxes

 

 

 

 
 
 
 
 
 
 
 
Net income (loss)
$
27

 
$
(20
)
 
$
4

 
$
(104
)

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 sale was May 1, 2015, and the purchase price is subject to post-closing adjustments related to the settlement of revenues and expenses for ninety days subsequent to the effective date. 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.
 
The Company has included revenues and expenses related to the Coke Field for the period from March 15 through June 30, 2014 in the condensed consolidated statement of operations for the six months ended June 30, 2014. For this period, the revenues and net loss attributable to the Coke Field were $4.2 million and $2.8 million, respectively which included a $2.8 million loss on commodity derivatives.

The following summary presents unaudited pro forma information for the six months ended June 30, 2014 as if the Coke Field had been acquired on January 1, 2014 (in thousands).

 
For the Six Months Ended June 30,
 
2014
 
 
Total revenues
$
9,294

Net loss
(7,085
)
 
 
Net loss per common share, basic and diluted
$
(0.22
)
 
 
Weighted average shares outstanding:
 

Basic
31,684

Diluted
31,684




10


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 June 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


 
Fair value measurements using
 
 
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(Unaudited)
 
 
 
 
 
 
 
 
June 30, 2015
 
 
 
 
 
 
 
     Short-term commodity derivatives, asset

 
$
2,095

 

 
$
2,095

     Long-term commodity derivatives, asset

 
2,319

 

 
2,319

 

 
$
4,414

 

 
$
4,414


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.


11


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 June 30, 2015, the Company had the following open positions on outstanding commodity derivative contracts:

Period
 
Volume/Month (Bbls)
 
Price/Unit
 
Fair Value - Asset
(Unaudited)
 
 
 
 
 
 
 
July 2015 - March 2016
 
7,300

 
$
86.50

 
2,095,000

April 2016 - March 2017
 
6,550

 
$
82.46

 
1,468,000

April 2017 - March 2018
 
5,800

 
$
80.53

 
851,000


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 (expense) income.

The following tables summarize the unrealized and realized (loss) gain on commodity derivatives (in thousands):
 
Three Months Ended June 30,
 
2014
 
2015
 
(Unaudited)
 
 
 
 
Unrealized loss on commodity derivatives
$
(2,568
)

$
(1,605
)
Realized (loss) gain on commodity derivatives
(223
)

625

 
$
(2,791
)

$
(980
)

 
Six Months Ended June 30,
 
2014
 
2015
 
(Unaudited)
 
 
 
 
Unrealized loss on commodity derivatives
$
(2,568
)
 
$
(1,382
)
Realized (loss) gain on commodity derivatives
(223
)
 
1,771

 
$
(2,791
)
 
$
389




12


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 facility 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. As of December 31, 2014 and June 30, 2015 the outstanding loan balance was $17.4 million and $17.0 million. Glori Energy Production is in compliance with all covenants as of June 30, 2015.
 
The $4.0 million note had a two year term bearing interest at 12.0% per annum and is secured by the assets of the Company but is 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.
 
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 two years are as follows (in thousands):
 
Year ending June 30,
 
Amount
 
 
(Unaudited)
 
 
 
2016
 
$
2,473

2017
 
14,564

 
 
$
17,037

 


13


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 June 30,
 
Six Months Ended June 30,
 
2014
 
2015
 
2014
 
2015
 
(Unaudited)
 
(Unaudited)
Numerator:
 

 
 

 
 
 
 
Net loss
$
(6,060
)
 
$
(4,916
)
 
$
(6,744
)
 
$
(7,900
)
 
 
 
 
 
 
 
 
Denominator:
 

 
 

 
 
 
 
Weighted-average common shares outstanding - basic
29,642

 
31,803

 
26,179

 
31,684

Effect of dilutive securities

 

 

 

Weighted-average common shares - diluted
29,642

 
31,803

 
26,179

 
31,684

 
 
 
 
 
 
 
 
Net loss per common share - basic and diluted
$
(0.20
)
 
$
(0.15
)
 
$
(0.26
)
 
$
(0.25
)


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

 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2014
 
2015
 
2014
 
2015
 
(Unaudited)
 
(Unaudited)
 
 
 
 
 
 
 
 
Common stock warrants ($10 strike price)
7,177

 
5,321

 
8,864

 
5,321

Common stock options
6,724

 
2,048

 
6,716

 
2,154

Restricted shares

 
132

 

 
102

 
NOTE 8 - INCOME TAXES
 
At December 31, 2014 and June 30, 2015, the Company has net operating loss carryforwards for federal income tax reporting purposes of approximately $51.9 million and $59.0 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 six months ended June 30, 2014 and June 30, 2015 varies from the statutory rate primarily due to the effect of the valuation allowance. For the three and six months ended June 30, 2014 the Company had an income tax expense of $142,000 due to taxes payable on foreign income. For the three and six months ended June 30, 2015 the Company had an income tax benefit of $188,000 and $171,000, respectively due to a reduction in taxes payable on foreign income as the Company revised its methodology for service fee applications charged to foreign subsidiaries.
 

14


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 June 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 June 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.
 
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 June 30, 2015 are as follows (in thousands):
 
 
Year Ending June 30,
 
 
(Unaudited)
 
 
 
2016
 
$
351

2017
 
172

 
 
$
523


Total rent expense was approximately $60,000 and $90,000 for the three and six months ended June 30, 2014 and $120,000 and $180,000 for the three and six months ended June 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. 


15


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

 

 
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)
(203,515
)
 
0.64

 
 
 
 
Forfeited or Expired (unaudited) (1)
(23,768
)
 
1.17

 
 
 
 
Outstanding as of June 30, 2015 (unaudited)
2,391,001

 
$
1.14

 
6.67
 
$
1,231,000

Exercisable as of December 31, 2014
2,099,345

 
$
0.79

 
6.60
 
$
7,119,000

Exercisable as of June 30, 2015 (unaudited)
1,977,576

 
$
0.84

 
6.17
 
$
1,200,000

 
(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 six months ended June 30, 2014 and June 30, 2015 was $0.66 and $2.40, respectively. There were no option awards issued in the the three months ended June 30, 2014 and June 30, 2015. The total fair value of options vested during the three months ended June 30, 2014 and June 30, 2015 was $80,000 and $95,000, respectively. The total fair value of options vested during the six months ended June 30, 2014 and June 30, 2015 was $159,000 and $160,000, 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 included primarily in selling, general and administrative expense was $78,000 and $417,000 for the three months ended June 30, 2014 and June 30, 2015, respectively, and $155,000 and $836,000 for the six months ended June 30, 2014 and June 30, 2015, respectively. The Company has future unrecognized compensation expense for nonvested shares at June 30, 2015 of $2,755,000 with a weighted average vesting period of 3.1 years.


16


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 three such arrangements for oil sales, one for the Etzold Field located in Seward County, Kansas, 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.
 
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 June 30, 2014
 

 
 

 
 

 
 

Revenues
$
3,644

 
$
1,912

 
$

 
$
5,556

Total operating expenses
2,994

 
1,517

 
1,767

 
6,278

Depreciation, depletion and amortization
1,071

 
78

 
9

 
1,158

(Loss) income from operations
(421
)
 
317

 
(1,776
)
 
(1,880
)
 
 
 
 
 
 
 
 
Other income, net
(2,791
)
 

 
(1,247
)
 
(4,038
)
 
 
 
 
 
 
 
 
Income tax benefit

 

 
142

 
142

 
 
 
 
 
 
 
 
Net (loss) income
$
(3,212
)
 
$
317

 
$
(3,165
)
 
$
(6,060
)


17


 
Oil and Gas
 
AERO Services
 
Corporate
 
Total
 
(Unaudited)
 
 
 
 
 
 
 
 
Three months ended June 30, 2015
 

 
 

 
 

 
 

Revenues
$
2,136

 
$
496

 
$

 
$
2,632

Total operating expenses
2,500

 
534

 
2,163

 
5,197

Depreciation, depletion and amortization
912

 
109

 
18

 
1,039

Loss from operations
(1,276
)
 
(147
)
 
(2,181
)
 
(3,604
)
 
 
 
 
 
 
 
 
Other expense, net
(980
)
 

 
(520
)
 
(1,500
)
 
 
 
 
 
 
 
 
Income tax benefit

 

 
(188
)
 
(188
)
 
 
 
 
 
 
 
 
Net loss
$
(2,256
)
 
$
(147
)
 
$
(2,513
)
 
$
(4,916
)

 
Oil and Gas
 
AERO Services
 
Corporate
 
Total
 
(Unaudited)
Six Months Ended June 30, 2014
 

 
 

 
 

 
 

Revenues
$
4,386

 
$
2,172

 
$

 
$
6,558

Total operating expenses
4,221

 
2,058

 
3,349

 
9,628

Depreciation, depletion and amortization
1,400

 
190

 
16

 
1,606

Loss from operations
(1,235
)
 
(76
)
 
(3,365
)
 
(4,676
)
 
 
 
 
 
 
 
 
Other (expense) income, net
(2,791
)
 

 
865

 
(1,926
)
 
 
 
 
 
 
 
 
Taxes on income

 

 
142

 
142

 
 
 
 
 
 
 
 
Net loss
(4,026
)
 
(76
)
 
(2,642
)
 
(6,744
)

 
Oil and Gas
 
AERO Services
 
Corporate
 
Total
 
(Unaudited)
Six Months Ended June 30, 2015
 

 
 

 
 

 
 

Revenues
$
4,136

 
$
1,063

 
$

 
$
5,199

Total operating expenses
4,892

 
1,055

 
4,355

 
10,302

Depreciation, depletion and amortization
1,865

 
209

 
33

 
2,107

Loss from operations
(2,621
)
 
(201
)
 
(4,388
)
 
(7,210
)
 
 
 
 
 
 
 
 
Other income (expense), net
389

 

 
(1,250
)
 
(861
)
 
 
 
 
 
 
 
 
Income tax benefit

 

 
(171
)
 
(171
)
 
 
 
 
 
 
 
 
Net loss
(2,232
)
 
(201
)
 
(5,467
)
 
(7,900
)


 
 


18


NOTE 12 - SUBSEQUENT EVENTS

The Company transferred its mineral interests in the Etzold Field to a third party on July 1, 2015 in exchange for $75,000 and the purchaser's assumption of the related asset retirement obligation. The Company estimates a gain on the sale of approximately $400,000 will be recognized the third quarter of 2015.

On July 15, 2015, the Company made an additional principal paydown of $2 million on the remaining $17 million principal balance of the senior secured term loan facility in connection with the redetermination of the associated collateral value.

19



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 June 30, 2015 and for the three and six months ended June 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 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 ROFSM 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 perfect the model, we are continuing to work closely with the National Energy Technology Labs (NETL) and a major U.S. research university to further study our progress with results that management believes are encouraging.

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 the United States 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 which is dependent on customer adoption of the AERO System technology. 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.

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.

20



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. The effective date of the sale was May 1, 2015, and the purchase price is subject to post closing adjustments related to the settlement of revenues and expenses subsequent to the effective date.

Net loss for the second quarter of 2015 was $4.9 million or $0.15 per share. This compares to a second quarter 2014 net loss of $6.1 million, or a loss of $0.20 per share.

Revenues for the second quarter of 2015 were $2.6 million, reflecting a decrease of $2.9 million from the second quarter of 2014. Oil and gas revenues decreased to $2.1 million from $3.6 million in the second quarter 2014 due to a 39% decrease in average oil prices and a 3% decline in oil and gas volumes produced in the second quarter of 2015. Revenues from our AERO technology services segment decreased to $496 thousand in the second quarter of 2015 from $1.9 million, a decrease of 74% from the second quarter of 2014 due to the completion, and recognition of revenue on a large customer project that contributed $1.5 million in revenues in the second quarter of 2014. 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 second quarter of 2015, we produced 40,128 net barrels of oil equivalents ("BOE") or approximately 441 net BOE per day, including 36,938 barrels of oil and 19,141 thousand cubic feet of natural gas, and received an average realized price of $57.06 per barrel and $1.47 per thousand cubic foot. After the effect of oil swap settlements, our oil price per barrel for the quarter was approximately $73.99 per barrel. Production from liquids (oil and condensate) represented approximately 92% of total production. Total production in the second quarter of 2015 decreased approximately 7% from first quarter 2015 production as a result of shutting in certain lower performing wells to reduce costs in the lower oil price environment, due to equipment failures which have since been repaired and to the natural field decline. Such declines were partially offset by the inclusion of production from the Bonnie View Field assets, purchased June 1, 2015, which produced 1,804 barrels of oil in the month of June.

Oil and gas operating expenses in the second quarter of 2015 were $2.5 million compared to $3.0 million in the second quarter of 2014 due primarily to an 80% reduction in ad valorem taxes based on a revised tax assessment, a 41% reduction in severance taxes as a result of lower oil prices and revenues, and a 21% reduction in lease operating expenses. These decreases were partially offset by additions to professional and technical staff associated with the growth of our oil and gas segment, consulting fees and costs associated with the sourcing and evaluation of potential oil property acquisitions. Included in oil and gas operating expenses for the second quarter of 2015 are direct lease operating expenses of approximately $1.7 million, ad valorem taxes of $36 thousand, production taxes of $99 thousand, third party professional fees of $160 thousand, acquisition expenses of $18 thousand and compensation and other administrative expenses associated with our acquisitions and production professional personnel of $522 thousand.

Oil and gas operating expenses in the second quarter of 2015 of $2.5 million increased from $2.4 million in the first quarter of 2015, due to a 21% increase in lease operating expenses from $1.4 million to $1.7 million, which was partially offset by decreases in ad valorem taxes, compensation expense and third party professional fees. The increase in lease operating expenses was due to increased well workover expenses and the acquisition of the Bonnie View Field on June 1, 2015.
 
Service operations expense decreased to $534 thousand in the second quarter of 2015 compared to $1.5 million in the prior year second quarter due primarily to a decrease in nutrient costs and other project costs for a large Canadian project in the Field Deployment Phase which concluded in June 2014. 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.

Science and technology expenses increased to $629 thousand in the second quarter of 2015 compared to $397 thousand in the prior year second quarter. The increase was driven by increased third party research fees and increased stock based compensation expense. 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 first quarter of 2015, science and technology expenses increased from $474 thousand to $629 thousand due to increased costs for stock based compensation and for third party research fees.


21


Selling, general and administrative ("SG&A") expenses totaled $1.5 million in the second quarter of 2015, reflecting an increase of $164 thousand from the prior year period. The increase is primarily due to increased compensation expense for additional staff, and for board members, including stock based compensation expense and other shareholder related expenses, as a result of becoming a public company. When compared to the first quarter of 2015, SG&A expense decreased from $1.7 million to $1.5 million primarily due to decreased stock based compensation expense and decreased professional fees for legal, audit and tax services.

Depreciation, depletion and amortization ("DD&A") was $1.0 million in the second quarter of 2015 compared to $1.2 million in the prior-year period. The decrease in DD&A expense was the result of lower overall production and lower capitalized costs as a result of impairment recognized in December 2014.

Interest expense totaled $530 thousand in the second quarter of 2015, compared with $1.3 million in the second quarter of 2014. The decrease was primarily the result of the lower level of debt in the second quarter of 2015 compared to the second quarter of 2014 including the prepayment of a $4.0 million note for which we incurred a $400 thousand prepayment penalty in May 2014. Additionally, we recognized $181 thousand of interest expense in the second quarter 2014 for another note which was prepaid in March 2015.

We had price swap derivatives in place covering approximately 59% of our oil and condensate production for the second quarter of 2015. We continue to maintain price swaps covering a portion of our estimated future production. In the second quarter ended June 30, 2015, we recorded a net loss on commodity derivatives of approximately $980 thousand due to an increase in NYMEX oil futures prices from the beginning to the end of the quarter. This decline is net of $625 thousand in realized cash settlements received. In the previous year's second quarter, we recorded a net loss on commodity derivatives of $2.8 million, which included $223 thousand in realized cash settlements paid.


22


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 June 30,
 
Six months ended June 30,
 
2014
 
2015
 
2014
 
2015
Revenues:
 

 
 

 
 
 
 
Oil and gas revenues
$
3,644

 
$
2,136

 
$
4,386

 
$
4,136

Service revenues
1,912

 
496

 
2,172

 
1,063

Total revenues
5,556

 
2,632

 
6,558

 
5,199


 
 
 
 
 
 
 
Operating expenses:
 

 
 

 
 
 
 
Oil and gas operations
2,994

 
2,500

 
4,221

 
4,892

Service operations
1,517

 
534

 
2,058

 
1,055

Science and technology
397

 
629

 
717

 
1,103

Selling, general and administrative
1,370

 
1,534

 
2,632

 
3,252

Depreciation, depletion and amortization
1,158

 
1,039

 
1,606

 
2,107

Total operating expenses
7,436

 
6,236

 
11,234

 
12,409


 
 
 
 
 
 
 
Loss from operations
(1,880
)
 
(3,604
)
 
(4,676
)
 
(7,210
)

 
 
 
 
 
 
 
Other (expense) income:
 

 
 

 
 
 
 
Interest expense
(1,257
)
 
(530
)
 
(1,604
)
 
(1,245
)
Gain on change in fair value of warrants

 

 
2,454

 

(Loss) gain on commodity derivatives
(2,791
)
 
(980
)
 
(2,791
)
 
389

Other income (expense)
10

 
10

 
15

 
(5
)
Total other (expense) income, net
(4,038
)
 
(1,500
)
 
(1,926
)
 
(861
)
 
 
 
 
 
 
 
 
Income tax expense (benefit)
142

 
(188
)
 
142

 
(171
)
 
 
 
 
 
 
 
 
Net loss
$
(6,060
)
 
$
(4,916
)
 
$
(6,744
)
 
$
(7,900
)


23


The following table sets forth selected production data for the periods indicated:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2014
 
2015
 
2014
 
2015
Revenues (in thousands):
 
 
 
 
 
 
 
Oil revenues
$
3,563

 
$
2,108

 
$
4,305

 
$
4,075

Natural gas revenues
81

 
28

 
81

 
61

Total oil and gas revenues
$
3,644

 
$
2,136

 
$
4,386

 
$
4,136

 
 
 
 
 
 
 
 
Volumes:
 
 
 
 
 
 
 
Oil volumes (MBbls)
38

 
37

 
46

 
77

Gas volumes (MMcf)
25

 
19

 
25

 
40

Gas volumes (MBoe)
4

 
3

 
4

 
7

Total volumes (MBoe)
42

 
40

 
50

 
84

 
 
 
 
 
 
 
 
Price (1):
 
 
 
 
 
 
 
Average oil price per Bbl
$
93.68

 
$
57.06

 
$
93.31

 
$
53.05

Average oil price per Bbl including swap settlements
$
87.78

 
$
73.99

 
$
88.45

 
$
76.18

Average gas price per Mcf
$
3.25

 
$
1.47

 
$
3.25

 
$
1.53

(1) Average realized prices are calculated before the impact of swap settlements.

The following table details oil and gas operations expense for the periods indicated (in thousands):
 
Three months ended June 30,
 
Six months ended June 30,
 
2014
 
2015
 
2014
 
2015
Lease operating expense
$
2,120

 
$
1,664

 
$
2,746

 
$
3,086

Ad valorem taxes
182

 
36

 
212

 
174

Severance taxes
169

 
99

 
205

 
192

Acquisition expenses
29

 
18

 
140

 
44

Oil and gas overhead expense
494

 
683

 
918

 
1,396

Oil and gas operations expense
$
2,994

 
$
2,500

 
$
4,221

 
$
4,892


Three Months Ended June 30, 2014 and 2015
 
Oil and gas revenues. Oil and gas revenues decreased by $1.5 million, or 41%, from $3.6 million in the three months ended June 30, 2014 to $2.1 million in the three months ended June 30, 2015. The decrease was primarily attributable to a 39% decrease in average oil prices and a 3% decrease in oil and gas volumes produced.
 
Service revenues. Service revenues decreased by $1.4 million, or 74%, from $1.9 million in the three months ended June 30, 2014 to $496 thousand in the three months ended June 30, 2015. The decrease in revenues was attributable to decreases of $131 thousand and $1.3 million 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 due to a decrease of $1.5 million in Canadian revenues due to the completion, and recognition of revenue on a large customer project that contributed $1.5 million in revenues in the second 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.


24


Oil and gas operations. Oil and gas operating expense decreased by $494 thousand from $3.0 million in the three months ended June 30, 2014 to $2.5 million in the three months ended June 30, 2015. The overall decrease was primarily attributable to a decrease in lease operating expenses of $456 thousand as a result of cost reduction efforts and a decline in repairs and workover costs. Ad valorem tax expense decreased $146 thousand due to a revised tax assessment, and severance tax expense decreased $70 thousand as a result of lower sustained oil prices and revenues. These decreases were partially offset by a $189 thousand increase in overhead charges, including $131 thousand for employee compensation and charges for additional professional and technical personnel.

Service operations. Service operations expense decreased by $983 thousand from $1.5 million in the second quarter of 2014 to $534 thousand in the second quarter 2015. The decrease was attributable to a $924 thousand decrease in Canadian project expenses, including $773 thousand in AERO nutrient costs, as a large Canadian project in the Field Deployment Phase concluded during June 2014.
 
Science and technology. Science and technology expenses increased by $232 thousand from $397 thousand in the three months ended June 30, 2014 to $629 thousand for the three months ended June 30, 2015 mostly due to increases in expenses for employee compensation, including $80 thousand in stock based compensation, and for a research project assisted by a major U.S. research university.
 
Selling, general and administrative ("SG&A"). SG&A expenses increased by $164 thousand, or 12%, from $1.4 million in the three months ended June 30, 2014 to $1.5 million in the three months ended June 30, 2015. The increase was primarily attributable to an increase of $253 thousand in compensation expense for an increase in professional staff and for members of our Board of Directors in connection with our transition to being a public company including $189 thousand in stock compensation expense. This increase was partially offset by a decrease in legal and consulting fees.
 
Depreciation, depletion and amortization ("DD&A"). DD&A decreased by $119 thousand from $1.2 million in the three months ended June 30, 2014 to $1.0 million in the three months ended June 30, 2015. The decrease was primarily attributable to decreases in depletion expense of $276 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 impaired properties for the second quarter of 2015 was calculated based on a lower value as compared to the second quarter of 2014. These decreases in depletion were partially offset by an increase in depletion related to the Bonnie View Field acquisition in June 2015.
 
Total other (expense) income, net. Total other (expense) income, net, decreased $2.5 million from an expense of $4.0 million in the three months ended June 30, 2014 to an expense of $1.5 million in the three months ended June 30, 2015. Our commodity swaps that were entered into in connection with the acquisition of the Coke Field in March 2014 resulted in a loss of $980 thousand in the three months ended June 30, 2015 compared to a $2.8 million loss on commodity swaps in the prior year period. In the 2015 period, the derivative loss consisted of a $625 thousand realized gain on swap settlements which was offset by a $1.6 million unrealized loss on the change in fair value of future settlements due to an increase in NYMEX oil futures prices from the beginning to the end of the quarter. In the 2014 period, the derivative loss consisted of a $223 thousand realized loss on swap settlements and a $2.6 million unrealized loss on the change in fair value of future settlements. Interest expense also decreased $727 thousand compared to the second 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.

Six Months Ended June 30, 2014 and 2015

Oil and gas revenues. Oil and gas revenues decreased by $250 thousand from $4.4 million in the six months ended June 30, 2014 to $4.1 million in the six months ended June 30, 2015. The decrease was attributable to a 43% decrease in average oil prices and was partially offset by the purchase of the Bonnie View Field which closed on June 1, 2015 and resulted in the inclusion of an additional $126 thousand in revenues. The oil price decline was also partially offset by the inclusion of a full six months of oil and gas sales from the Coke Field, which were purchased in March 2014 during the prior year six month period.
 
Service revenues. Service revenues decreased by $1.1 million, or 51%, from $2.2 million in the six months ended June 30, 2014 to $1.1 million in the six months ended June 30, 2015. The decrease in revenues was attributable to decreases of $166 thousand and $938 thousand 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 $1.5 million in Canadian revenues 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.
    

25


Oil and gas operations. Oil and gas operating expense increased by $671 thousand from $4.2 million in the six months ended June 30, 2014 to $4.9 million in the six months ended June 30, 2015. The increase was mainly attributable to the acquisition of the Coke Field which was completed on March 14, 2014 and resulted in the inclusion of an additional $252 thousand of lease operating expenses in the six months 2015 period compared to the period from March 14, 2014 to June 30, 2014. Overhead charges increased $478 thousand, including $301 thousand for employee compensation related to additions to professional and technical staff associated with the growth of our oil and gas segment and $125 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. The remaining increase related to the lease operating expenses for the Bonnie View Field, purchased June 1, 2015.

Service operations. Service operations expense decreased by $1.0 million from $2.1 million in the six months ended June 30, 2014 to $1.1 million in the six months ended June 30, 2015. Approximately $904 thousand of the decrease is attributable to reduced project costs such as trucking and nutrient solution related to a large Canadian project which concluded during June 2014.
 
Science and technology. Science and technology expenses increased by $386 thousand, or 54%, from $717 thousand in the six months ended June 30, 2014 to $1.1 million in the six months ended June 30, 2015 mostly due to increases in expenses for employee compensation, including $90 thousand for stock based compensation and other charges due to added personnel, and for core flood research assisted by a major U.S. research university.
 
Selling, general and administrative ("SG&A"). SG&A expenses increased by $620 thousand, or 24%, from $2.6 million in the six months ended June 30, 2014 to $3.3 million in the six months ended June 30, 2015. The increase was primarily attributable to an increase of $707 thousand in 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, including $492 thousand in stock compensation expense. This increase was partially offset by a decrease in legal and consulting fees.
 
Depreciation, depletion and amortization. Depreciation, depletion and amortization increased by $501 thousand from $1.6 million in the six months ended June 30, 2014 to $2.1 million in the six months ended June 30, 2015. The increase was primarily attributable to the inclusion of six months of depletion of the Coke Field, purchased in March 2014, in the 2015 period resulting in an additional $433 thousand of depletion expense. The Bonnie View Field, purchased June 1, 2015, also contributed to the increase over the prior year period and resulted in depletion expense of $84 thousand during the six months ended June 30, 2015. These increases were partially offset by a decrease in depletion expense related to the Etzold Field, which for which we recognized a full impairment of such assets in December 2014.
 
Total other (expense) income, net. Total other (expense) income, net decreased by $1.1 million from an expense of $1.9 million in the six months ended June 30, 2014 to an expense of $861 thousand in the six months ended June 30, 2015. Our commodity swaps that were entered into in connection with the acquisition of the Coke Field in March 2014 resulted in a gain of $389 thousand in the six months ended June 30, 2015 compared to a $2.8 million loss on commodity swaps in the prior year period. In the 2015 period, the derivative gain consisted of a $1.8 million realized gain on swap settlements and a $1.4 million unrealized loss on the change in fair value of future settlements. In the 2014 period, the derivative loss consisted of a $223 thousand realized loss on swap settlements and a $2.6 million unrealized loss on the change in fair value of future settlements. Additionally during the six months ended June 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 an offsetting $2.5 million gain on the change in fair value of warrant liabilities. Interest expense decreased $359 thousand from the first half of 2014 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 June 30, 2015, we had working capital of $14.6 million, made up of current assets of $20.8 million and current liabilities of $6.2 million. The current asset balance is comprised of cash and cash equivalents of $17.1 million, accounts receivable of $1.1 million, prepaid expenses and other current assets of $433 thousand, and commodity derivative contracts receivable of $2.1 million. Included in current liabilities is $1.3 million in accounts payable, $33 thousand in deferred revenues, $1.7 million in accrued expenses, $2.5 million in current portion of long-term debt, and a deferred tax liability of $683 thousand.
 

26


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. We expect these sources of liquidity will enable us to fund our capital expenditures and working capital needs for the next twelve months.

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 $5.4 million for Coke Field and Bonnie View Field expansion and implementation of our AERO System technology. The $5.4 million of expected capital expenditures consists primarily of the drilling of three water injection wells and related surface equipment for expansion of our AERO System technology on the Coke Field and two water injection wells for the initial implementation of our AERO System technology on the Bonnie View Field. We will adjust the timing of our capital spending dependent upon our cash on hand, our cash flow from operations and the availability of credit facilities. As of June 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, will principally be 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 increased 19% during the second quarter of 2015 based on the Cushing, Oklahoma - West Texas Intermediate spot prices of $50.12 per barrel on April 1, 2015 and $59.48 on June 30, 2015. Subsequent to June 2015, the oil price fell to approximately $50 per barrel as of July 24, 2015. A sustained lower oil price through September 2015 will negatively impact third 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 $50 per barrel, assuming second quarter production volumes and assuming the Bonnie View acquisition had been completed as of April 1, 2015, oil and gas revenues would have decreased from $2.3 to $2.1 million, and the realized gain on monthly oil swap settlements would have increased from $625 thousand in the second quarter to $799 thousand 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):
 
 
Six Months Ended June 30,
 
2014
 
2015
Net cash used in operating activities
$
(5,267
)
 
$
(5,834
)
Net cash used in investing activities
(39,730
)
 
(4,715
)
Net cash provided by (used in) financing activities
$
62,334

 
$
(2,126
)


27


Operating Activities
 
During the six months ended June 30, 2015, our operating activities used $5.8 million in cash. Our net loss for the six months ended June 30, 2015 was $7.9 million. Non-cash items totaled to an expense of $4.6 million, consisting of $2.1 million of depreciation, depletion and amortization, $1.4 million for an unrealized loss on commodity swaps, $838 thousand for stock based compensation expense, $194 thousand for amortization of deferred loan costs and other non-cash expenses totaling $104 thousand. Changes in operating assets and liabilities reduced net cash by $2.6 million for the period. The cash decrease from changes in operating assets and liabilities was caused by a decrease in accounts payable of $1.4 million, a decrease in deferred revenues of $620 thousand and a decrease in accrued expenses of $587 thousand. These uses of cash were partially offset by a decrease in accounts receivable of $186 thousand. The decrease in accounts payable and accrued expenses was due to the timing of payments for obligations which we recognized during our annual close, 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 six months ended June 30, 2014, our operating activities used $5.3 million in cash. Our net loss for the six months ended June 30, 2014 was $6.7 million. Non-cash items totaled to an expense of $2.2 million, consisting of $2.6 million for an unrealized loss on commodity swaps, $1.6 million of depreciation, depletion and amortization, $223 thousand for amortization of deferred loan costs, $155 thousand for stock based compensation expense and other non-cash expenses totaling $81 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 $702 thousand for the period. The cash reduction from changes in operating assets and liabilities was caused by an increase in accounts receivable of $1.4 million, a decrease in deferred revenues of $473 thousand and an increase in prepaid expenses and other current assets of $132 thousand. These uses of cash were partially offset by an increase in accrued expenses of $864 thousand and an increase in accounts payable of $433 thousand. Accounts receivable increased primarily due to a receivable outstanding at June 30, 2014 for $1.3 million for oil and gas sales related to the Coke Field. The increase in accrued expenses was driven by the current portion of the commodities swap payable, which was $837 thousand.
 
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 $4.7 million for the six months ended June 30, 2015 compared to $39.7 million for the six months ended June 30, 2014. The $35.0 million decrease is due to the purchase of the Coke Field in the prior year period. For the six months ended June 30, 2015, capital expenditures of $2.6 million were due to the June 1, 2015 purchase 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. Additional expenditures were made for other unproved property leasing efforts in East Texas.
 
Financing Activities
 
During the six months ended June 30, 2015, cash used by financing activities was $2.1 million consisting of $2.2 million in payments on long-term debt and $40 thousand in payments for deferred loan costs. These cash outflows were partially offset by proceeds of $130 thousand from stock option exercises. Payments on long-term debt included $888 thousand for the prepayment of the remaining principal balance on an $8.0 million secured term promissory note originated in 2012.
 
During the six months ended June 30, 2014, net cash provided by financing activities was $62.3 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 facility, $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 $4.1 million was received from the exercise of warrants. Cash generated from financing activities during the six months ended June 30, 2014 was partially offset by principal payments on long-term debt of $5.8 million, payments for deferred offering costs of $2.8 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 facility and the $4.0 million subordinated debt facility.
 

28


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 June 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)
 
$
526

 
$
354

 
$
172

 
$

 
$

Asset retirement obligation(2)
 
1,837

 

 
435

 
693

 
709

Long-term debt(3)
 
20,296

 
4,199

 
16,097

 

 

Total
 
$
22,659

 
$
4,553

 
$
16,704

 
$
693

 
$
709

 
(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.


29


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 I