VICTORY OILFIELD TECH, INC. - Quarter Report: 2017 June (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)



☒	QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2017



☐	TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE EXCHANGE ACT

For the transition period from _______________ to _______________.

Commission file number 002-76219-NY

VICTORY ENERGY CORPORATION

(Exact Name of Company as Specified in its Charter)



Nevada		87-0564472
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

3355 Bee Caves Road Suite 608, Austin, Texas		78746
(Address of principal executive offices)		(Zip Code)

(512)-347-7300

(Registrant’s telephone number, including area code)

_____________________________________________________________

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒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, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company”, and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):



Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☒
Emerging growth company	☐
(Do not check if a smaller reporting company)

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

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

As of August 11, 2017, there were 31,220,326 shares of common stock, par value $0.001, issued and outstanding.

VICTORY ENERGY CORPORATION

QUARTERLY REPORT ON

FORM 10-Q

FOR THE SIX MONTHS ENDED JUNE 30, 2017

TABLE OF CONTENTS



		Page

Part I – Financial Information

Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets as of June 30, 2017 (unaudited) and December 31, 2016	8
	Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2017 and 2016 (unaudited)	9
	Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2017, and 2016 (unaudited)	10
	Notes to the Condensed Consolidated Financial Statements	11
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 3.	Qualitative and Quantitative Discussions About Market Risk	30
Item 4.	Controls and Procedures	30

Part II – Other Information

Item 1.	Legal Proceedings	32
Item 1A.	Risk Factors	33
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	34
Item 3.	Default Upon Senior Securities	34
Item 4.	Mine Safety Disclosures	34
Item 5.	Other Information	34
Item 6.	Exhibits	35

Signature		36

Cautionary Notice Regarding Forward Looking Statements

We desire to take advantage of the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. This report contains a number of forward-looking statements that reflect management's current views and expectations with respect to business, strategies, future results and events and financial performance. All statements made in this Quarterly Report on Form 10-Q other than statements of historical fact, including statements that address operating performance, events or developments that management expects or anticipates will or may occur in the future, including statements related to revenues, cash flow, profitability, adequacy of funds from operations, statements expressing general optimism about future operating results and non-historical information, are forward looking statements. In particular, the words “believe,” “expect,” “intend,” “anticipate,” “estimate,” “may,” “will,” variations of such words, and similar expressions identify forward-looking statements, but are not the exclusive means of identifying such statements and their absence does not mean that the statement is not forward-looking.

Readers should not place undue reliance on these forward-looking statements, which are based on management’s current expectations and projections about future events, are not guarantees of future performance, are subject to risks, uncertainties and assumptions and apply only as of the date of this report. Our actual results, performance or achievements could differ materially from the results expressed in, or implied by, these forward-looking statements, including, without limitation, the risks outlined under “Item 1A. Risk Factors” included in our Annual Report on Form 10-K for the year ended December 31, 2016, and matters described in this report generally. In light of these risks and uncertainties, there can be no assurance that the forward-looking statements contained in this report will in fact occur.

Potential investors should not place undue reliance on any forward-looking statements. Except as expressly required by the federal securities laws, there is no undertaking to publicly update or revise any forward-looking statements, whether as a result of new information, future events, changed circumstances or any other reason. Potential investors should not make an investment decision based solely on our company’s projections, estimates or expectations.

In particular, our business, including our financial condition and results of operations and our ability to continue as a going concern may be impacted by a number of factors, including, but not limited to, the following:


•	continued operating losses;


•	our ability to continue as a going concern;


•	our dependence on external sources of financing to operate our business and meet our debt service obligations;


•	difficulties in raising additional capital;


•	our inability to pay our accounts payable or our expenses as they arise;


•	our inability to meet the required financial covenants of our lender;


•	our inability to pay a preferred return to The Navitus Energy Group for capital contributions to Aurora Energy Partners;


•	challenges in growing our business;


•	the designation of our common stock as a “penny stock” under the Securities and Exchange Commission, which we refer to as the SEC, regulations;


•	FINRA requirements that may limit the ability to buy and sell our common stock;


•	illiquidity and price volatility of our common stock;


•	the highly speculative nature of an investment in our common stock;


•	climate change and greenhouse gas regulations;


•	global economic conditions;


•	the substantial amount of capital required by our operations;


•	the volatility of oil and natural gas prices;


•	the high level of risk associated with drilling for and producing oil and natural gas;


•	assumptions associated with reserve estimates;


•	the potential that drilling activities will not yield oil or natural gas in commercial quantities;


•	the potential that exploration, production and acquisitions may not maintain revenue levels in the future;


•	the potential that our acquisition of additional oil and natural gas assets in the Permian Basin and other future acquisitions may yield revenues or production that differ significantly from our projections;


•	expenditure of significant resources on potential acquisitions or other projects that we may fail to consummate;


•	difficulties associated with managing a small and growing enterprise;


•	strong competition from other oil and natural gas companies;


•	the unavailability or high cost of drilling rigs and related equipment;


•	our inability to control properties that we do not operate;


•	our dependence on third parties for the marketing of our crude oil and natural gas production;


•	our dependence on key management personnel and technical experts;


•	our inability to keep pace with technological advancements in our industry;


•	the potential for write-downs in the carrying values of our oil and natural gas properties;


•	our compliance with complex laws governing our business;


•	our failure to comply with environmental laws and regulations;


•	the demand for oil and natural gas and our ability to transport our production;


•	the financial condition of the operators of the properties in which we own an interest;


•	the dilutive effect of additional issuances of our common stock, options or warrants;


•	any impairments of our oil and natural gas properties;


•	the results of pending litigation.

Glossary of Certain Industry Terms

The definitions set forth below shall apply to the indicated terms as used throughout this Quarterly Report on Form 10-Q.

Bbl. One barrel (of oil or natural gas liquids).

BOE. One barrel of oil equivalent. A BOE is determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids, which approximates the relative energy content of oil, condensate and natural gas liquids as compared to natural gas. Despite holding this ratio constant at six Mcf to one Bbl, prices have historically often been higher or substantially higher for oil than natural gas on an energy equivalent basis, although there have been periods in which they have been lower or substantially lower.

Completion. Installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.

Developed acreage. The number of acres which are allocated or held by producing wells or wells capable of production.

Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole or dry well. A well found to be incapable of economically producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in Regulation S-X.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Liquids. Describes oil, condensate, and natural gas liquids.

MBbls. Thousands of barrels of oil or natural gas liquids.

MBoe. Million barrels of oil equivalent.

Mcf. Thousand cubic feet (of natural gas).

MMcf. Million cubic feet (of natural gas).

Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells expressed in whole numbers.

NGL. Natural gas liquids.

Present value or PV10% or SEC PV10%. When used with respect to oil and gas reserves, means the estimated future gross revenue to be generated from the production of net proved reserves, net of estimated production and future development and abandonment costs, using prices and costs under the SEC guideline at the balance sheet date, without giving effect to non-property related expenses such as general and administrative expenses, debt service, accretion, and future income tax expense or to depreciation, depletion, and amortization, discounted using monthly end-of-period discounting at a nominal discount rate of ten percent (10%) per annum.

Productive wells. Producing wells and wells that are capable of production in sufficient quantities to justify completion, including injection wells, salt water disposal wells, service wells, and wells that are shut-in.

Proved developed reserves. Estimated proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved reserves. Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to

operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

Proved undeveloped reserves. Estimated proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required.

Resource play. Refers to an expansive contiguous geographical area with prospective crude oil and/or natural gas reserves that has the potential to be developed uniformly with repeatable commercial success due to advancements in horizontal drilling and completion technologies.

Undeveloped acreage. Acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains estimated proved reserves.

Working Interest or WI. An operating interest which gives the owner the right to drill, produce, and conduct operating activities on the property and a share of production.

Part I – Financial Information

Item 1. Financial Statements

VICTORY ENERGY CORPORATION AND SUBSIDIARY

CONDENSED CONSOLIDATED BALANCE SHEETS



	June 30, 2017			December 31, 2016
	(Unaudited)
ASSETS
Current Assets
Cash and cash equivalents	$	47,157		$	56,456
Accounts receivable	28,972			44,379
Prepaid expenses	26,715			9,951
Total current assets	102,844			110,786
Fixed Assets
Furniture and equipment	43,622			46,883
Accumulated depreciation	(40,211		)	(30,893		)
Total furniture and fixtures, net	3,411			15,990
Oil and gas properties, net of impairment (successful efforts method)	2,795,557			2,787,986
Accumulated depletion, depreciation and amortization	(2,214,709		)	(2,166,643		)
Total oil and gas properties, net	580,848			621,343
Other Assets
Management fee receivable - affiliate	139,455			137,556
Total Assets	$	826,558		$	885,675
LIABILITIES AND STOCKHOLDERS' DEFICIT
Current Liabilities
Accounts payable	$	570,667		$	420,559
Accrued liabilities	404,419			746,491
Accrued liabilities - related parties	1,273,616			1,489,973
Liability for unauthorized preferred stock issued	9,283			9,283
Note payable (net of unamortized deferred financing costs)	254,500			564,263
Note payable (net of debt discount) - affiliate	284,055			—
Asset retirement obligation	52,321			76,850
Total current liabilities	2,848,861			3,307,419
Other Liabilities
Asset retirement obligations	40,895			7,141
Total long term liabilities	40,895			7,141
Total Liabilities	2,889,756			3,314,560
Stockholders' Equity (Deficit)
Common stock, $0.001 par value, 47,500,000 shares authorized, 31,220,326 shares and 31,220,326 shares issued and outstanding for June 30, 2017 and December 31, 2016, respectively	31,220			31,220
Additional paid-in capital	36,134,513			35,795,479
Accumulated deficit	(47,393,299		)	(46,140,750		)
Total Victory Energy Corporation stockholders' deficit	(11,227,566		)	(10,314,051		)
Non-controlling interest	9,164,368			7,885,166
Total stockholders' equity (deficit)	(2,063,198		)	(2,428,885		)
Total Liabilities and Stockholders' Deficit	$	826,558		$	885,675

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

VICTORY ENERGY CORPORATION AND SUBSIDIARY

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



	For the Three Months Ended June 30,							For the Six Months Ended June 30,
	2017				2016			2017			2016
Revenues
Oil and gas sales	$	70,680			$	79,185		$	155,980		$	145,178
Gain on settlement and sale of oil and gas properties	—			—	64,824			—			64,824
Total revenues	70,680				144,009			155,980			210,002
Operating Expenses:
Lease operating costs	31,836				25,774			57,740			63,127
Exploration and dry hole cost	315				—			2,218			—
Production taxes	3,806				3,782			8,491			7,055
General and administrative	513,826				623,995			1,117,488			1,068,156
Depreciation, depletion, amortization, and accretion	37,259				28,267			62,300			76,286
Total operating expenses	587,042				681,818			1,248,237			1,214,624
Loss from operations	(516,362		)		(537,809		)	(1,092,257		)	(1,004,622		)
Other Income (Expense):
Management fee income	822				1,305			1,899			2,641
Interest expense	(98,633		)		(33,124		)	(187,991		)	(66,313		)
Total other income and expense	(97,811		)		(31,819		)	(186,092		)	(63,672		)
Loss before Tax Benefit	(614,173		)		(569,628		)	(1,278,349		)	(1,068,294		)
Tax benefit	—				—			—			—
Net loss	(614,173		)		$	(569,628	)	(1,278,349		)	(1,068,294		)
Less: Net loss attributable to non-controlling interest	(28,883		)		(26,154		)	(25,798		)	(83,196		)
Net loss attributable to Victory Energy Corporation	$	(585,290	)		$	(543,474	)	$	(1,252,551	)	$	(985,098	)

Weighted average shares, basic and diluted	31,220,326				31,220,326			31,220,326			31,220,326
Net loss per share, basic and diluted	$	(0.02	)		$	(0.02	)	$	(0.04	)	$	(0.03	)

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

VICTORY ENERGY CORPORATION AND SUBSIDIARY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOW

(Unaudited)



	For the Six Months Ended June 30,
	2017			2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(1,278,349	)	$	(1,068,294	)
Adjustments to reconcile net loss to net cash used in operating activities
Accretion of asset retirement obligations	1,655			1,597
Amortization of debt discount	124,055			—
Amortization of deferred financing costs	6,237			20,412
Gain on settlement and sale of oil and gas properties	—			(64,824		)
Depletion, depreciation, and amortization	60,645			74,689
Stock based compensation	179,034			57,409

Change in operating assets and liabilities
Accounts receivable	15,407			(20,274		)
Management fee receivable - affiliate	(1,899		)	(2,641		)
Prepaid expense	(16,764		)	3,492
Accounts payable	150,107			15,599
Accrued liabilities - related parties	(216,357		)	215,683
Accrued liabilities	(357,789		)	(140,319		)
Accrued interest note payable - affiliate	15,719			—
Net cash used in operating activities	(1,318,299		)	(907,471		)
CASH FLOWS FROM INVESTING ACTIVITIES:
Lease purchases, drilling capital expenditures	—			(18,442		)
Proceeds from sale of assets	—			8,294
Net cash used in investing activities	—			(10,148		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Non-controlling interest contributions	1,305,000			972,000
Debt financing proceeds - affiliate	320,000			—
Principal payments of debt financing	(316,000		)	—
Net cash provided by financing activities	1,309,000			972,000
Net Change in Cash and Cash Equivalents	(9,299		)	54,381
Beginning Cash and Cash Equivalents	56,456			2,384
Ending Cash and Cash Equivalents	$	47,157		$	56,765

Supplemental cash flow information:
Cash paid for:
Interest	$	18,362		$	22,412
Non-cash investing and financing activities:
Interest - accrued interest and amortization of debt discount	$	163,392		$	—
Accrued capital expenditures	$	173,568		$	305,983
Revisions to asset retirement obligations	$	7,570		$	—

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

Victory Energy Corporation and Subsidiary

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

These consolidated financial statements have been prepared by Victory Energy Corporation ("Victory" or the "Company") without audit, pursuant to the rules and regulations of the Securities and Exchange Commission ("SEC"). They reflect all adjustments that are, in the opinion of management, necessary for a fair presentation of the results for the interim periods, on a basis consistent with the annual audited financial statements. All such adjustments are of a normal recurring nature. Certain information, accounting policies, and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States ("GAAP") have been omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. This Quarterly Report on Form 10-Q should be read along with Victory’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016, which contains a summary of the Company’s significant accounting policies and other disclosures.

Note 1 – Organization and Summary of Significant Accounting Policies

Victory is an independent, growth-oriented oil and natural gas company engaged in the acquisition, exploration, development, and production of domestic oil and natural gas properties, through its partnership with Aurora Energy Partners ("Aurora"). In this report, “the Company”, "we" and "our" refers to the consolidated accounts and presentation of Victory and Aurora, with the equity of non-controlling interests stated separately. Current operations are primarily located onshore in Texas and New Mexico. The Company was organized under the laws of the State of Nevada on January 7, 1982. The Company is authorized to issue 47,500,000 shares of $0.001 par value common stock, and has 31,220,326 shares of common stock outstanding as of June 30, 2017. Our corporate headquarters are located at 3355 Bee Caves Rd. Ste. 608, Austin, Texas.

A summary of significant accounting policies followed in the preparation of the accompanying consolidated financial statements is set forth below.

Basis of Presentation and Consolidation:

Victory is the managing partner of Aurora, and holds a fifty percent (50%) partnership interest in Aurora. Aurora, a subsidiary of the Company, is consolidated with Victory for financial statement reporting purposes, as the terms of the partnership agreement that govern the operations of Aurora give Victory effective control of the partnership. The consolidated financial statements include the accounts of Victory and the accounts of Aurora. The Company’s management, in considering accounting policies pertaining to consolidation, has reviewed the relevant accounting literature. The Company follows the relevant accounting literature in assessing whether the rights of the non-controlling interests should overcome the presumption of consolidation when a majority voting or controlling interest in its investee “is a matter of judgment that depends on facts and circumstances". In applying the circumstances and contractual provisions of the partnership agreement, management determined that the non-controlling rights do not, individually or in the aggregate, provide for the non-controlling interest to “effectively participate in significant decisions that would be expected to be made in the ordinary course of business.” The rights of the non-controlling interest are protective in nature. All intercompany balances have been eliminated in consolidation. Certain reclassifications of prior year balances have been made to confirm such amounts to current year classifications. The reclassifications have no prior impact on net income.

Non-controlling Interests:

The Navitus Energy Group ("Navitus"), a Texas general partnership, is a partner with Victory in Aurora. The two partners each own a fifty percent (50%) interest in Aurora. Victory is the Managing partner and has contractual authority to manage the business affairs of Aurora. Navitus currently has four partners. They are James Capital Consulting, LLC ("JCC"), James Capital Energy, LLC ("JCE"), Rodinia Partners, LLC and Navitus Partners, LLC. Although this partnership has been in place since January 2008, its members and other elements have changed since that time.

The non-controlling interest in Aurora is held by Navitus. As of June 30, 2017, $9,164,368 was recorded as the equity of the non-controlling interest in our consolidated balance sheets representing a third-party investment in Aurora, with net loss attributable to non-controlling interest of $28,883 and $26,154 for the three months ended June 30, 2017 and 2016, respectively, and $25,798 and $83,196 for the six months ended June 30, 2017 and 2016, respectively. As of December 31, 2016, $7,885,166 was recorded as the equity of the non-controlling interest in our consolidated balance sheets representing a third-party investment in Aurora.

Use of Estimates:

The preparation of our consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the 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 those estimates. Estimates are used primarily when accounting for depreciation, depletion, and amortization (“DD&A”) expense, property costs, estimated future net cash flows from proved reserves, assumptions related to abandonments and impairments of oil and natural gas properties, taxes, accruals of capitalized costs, operating costs and production revenue, general and administrative costs and interest, purchase price allocation on properties acquired, various common stock, warrants and option transactions, and loss contingencies.

Oil and Natural Gas Properties:

We account for investments in oil and natural gas properties using the successful efforts method of accounting. Under this method of accounting, only successful exploration drilling costs that directly result in the discovery of proved reserves are capitalized. Unsuccessful exploration drilling costs that do not result in an asset with future economic benefit are expensed. All development costs are capitalized because the purpose of development activities is considered to be building a producing system of wells, and related equipment facilities, rather than searching for oil and natural gas. Items charged to expense generally include geological and geophysical costs. Capitalized costs for producing wells and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed and total proved reserves, respectively.

We review our proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected undiscounted future cash flows of our oil and gas properties and compare such undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value are subject to our judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges for proved properties will be recorded.

The assessment of unproved properties to determine any possible impairment requires significant judgment. We assess our unproved properties to determine any possible impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage. Due to the uncertainty inherent in these factors, we cannot predict the amount of impairment charges that may be recorded in the future.

The Company recorded no impairment expense for the six months ended June 30, 2017 and 2016, respectively based on the analysis above.

Asset Retirement Obligations:

The Company records the estimate of the fair value of liabilities related to future asset retirement obligations (“ARO”) in the period the obligation is incurred. Asset retirement obligations relate to the removal of facilities and tangible equipment at the end of an oil and natural gas property’s useful life. The application of this rule requires the use of management’s estimates with respect to future abandonment costs, inflation, market risk premiums, useful life and cost of capital and required government regulations. GAAP requires that the estimate of our ARO does not give consideration to the value the related assets could have to other parties.

Other Property and Equipment:

Our office equipment in Austin, Texas is being depreciated on the straight-line method over the estimated useful life of three to seven years.

Cash and Cash Equivalents:

The Company considers all liquid investments with original maturities of three months or less from the date of purchase that are readily convertible into cash to be cash equivalents. The Company had no cash equivalents at June 30, 2017 and December 31, 2016.

Accounts Receivable:

Our accounts receivable are primarily from purchasers of natural gas and oil and exploration and production companies which own an interest in properties we operate.

Fair Value:

At June 30, 2017 and December 31, 2016, the carrying value of the Company's financial instruments such as prepaid expenses and payables approximated their fair values based on the short-term maturities of these instruments. The carrying value of other liabilities approximated their fair values because the underlying interest rates approximated market rates at the balance sheet dates. Management believes that due to the Company's current credit worthiness, the fair value of debt could be less than the book value; however, due to current market conditions and available information, the fair value of such debt is not readily determinable. Financial Accounting Standard Board ("FASB") Accounting Standards Codification ("ASC") Topic 820, Fair Value Measurements and Disclosures, established a hierarchical disclosure framework associated with the level of pricing observability utilized in measuring fair value. This framework defined three levels of inputs to the fair value measurement process and requires that each fair value measurement be assigned to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety. The three broad levels of inputs defined by FASB ASC Topic 820 hierarchy are as follows:

Level 1 - quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date;

Leve1 2 - inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Leve1 2 input must be observable for substantially the full term of the asset or liability; and

Leve1 3 - unobservable inputs for the asset or liability. These unobservable inputs reflect the entity's own assumptions about the assumptions that market participants would use in pricing the asset or liability and are developed based on the best information available in the circumstances (which might include the reporting entity's own data).

The initial measurement of ARO is calculated using discounted cash flow techniques and based on internal estimates of future ARO costs associated with proved oil and gas properties. Inputs used in the calculation of ARO include plugging costs and reserve lives, which are considered Level 3 inputs. A reconciliation of Victory’s ARO is presented in Note 4.

Unamortized Discount:

Unamortized discount consists of value attributed to free standing equity instruments issued to the holders of affiliate note payable (see Note 6) and are amortized over the life of the related loans using a method consistent with the interest method. Amortization of debt discount totaled $124,055 for the six months ended June 30, 2017 and is included in interest expense in the condensed consolidated statements of operations. The following table shows the discount and related accumulated amortization as of June 30, 2017 and December 31, 2016:



	June 30,			December 31,
	2017			2016
Original issuance discount	$	160,000		$	—

Accumulated amortization	(124,055		)	—

Unamortized discount, net	$	35,945		$	—

Revenue Recognition:

The Company uses the sales method of accounting for oil and natural gas revenues. Under this method, revenues are recognized based on actual volumes of gas and oil sold to purchasers. The volumes sold may differ from the volumes to which the Company is entitled based on our interests in the properties. Differences between volumes sold and entitled volumes create oil and natural gas imbalances which are generally reflected as adjustments to reported proved oil and natural gas reserves and future cash flows in their supplemental oil and natural gas disclosures. If their excess takes of natural gas or oil exceed their estimated remaining proved reserves for a property, a natural gas or oil imbalance liability is recorded in the Consolidated Balance Sheets.

Concentrations:

There is a ready market for the sale of crude oil and natural gas. During 2017 and 2016, our gas field and our producing wells sold their respective gas and oil production to one purchaser for each field or well. However, because alternate purchasers of oil and natural gas are readily available at similar prices, we believe that the loss of any of our purchasers would not have a material adverse effect on our financial results. A majority of the Company’s production and reserves are from the Eagle Ford property in South Texas and the Permian Basin of West Texas.

Earnings (Losses) per Share:

Basic earnings per share (“EPS”) is computed by dividing net income (loss) attributable to controlling interests by the weighted-average number of shares of common stock outstanding during the period. Diluted EPS takes into account the dilutive effect of potential common stock that could be issued by the Company in conjunction with stock awards that have been granted to directors and employees. In accordance with FASB ASC 260, Earnings per Share, awards of unvested shares shall be considered outstanding as of the respective grant dates for purposes of computing diluted EPS even though their exercise is contingent upon vesting. Given the historical and projected future losses of the Company, all potentially dilutive common stock equivalents are considered anti-dilutive.

Income Taxes:

The Company accounts for income taxes in accordance with FASB ASC 740, Income Taxes, which requires an asset and liability approach for financial accounting and reporting of income taxes. Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities for financial reporting purposes and such amounts as measured by tax laws and regulations. Deferred tax assets include tax loss and credit carry forwards and are reduced by a valuation allowance if, based on available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

The realization of future tax benefits is dependent on our ability to generate taxable income within the carry forward period. Given the Company’s history of net operating losses, management has determined that it is likely that the Company will not be able to realize the tax benefit of the carry forwards. ASC 740 requires that a valuation allowance be established when it is more likely than not that all or a portion of deferred tax assets will not be realized.

Accordingly, the Company has a full valuation allowance against its net deferred tax assets at June 30, 2017 and December 31, 2016. Upon the attainment of taxable income by the Company, management will assess the likelihood of realizing the deferred tax benefit associated with the use of the net operating loss carry forwards and will recognize a deferred tax asset at that time.

Stock-Based Compensation:

The Company applies FASB ASC 718, Compensation-Stock Compensation, to account for the issuance of options and warrants to employees, key partners, directors, officers and Navitus investors. The standard requires all share-based payments, including employee stock options, warrants and restricted stock, be measured at the fair value of the award and expensed over the requisite service period (generally the vesting period). The fair value of options and warrants granted to employees, directors and officers is estimated at the date of grant using the Black-Scholes option pricing model by using the historical volatility of the Company’s stock price. The calculation also takes into account the common stock fair market value at the grant date, the exercise price, the expected term of the common stock option or warrant, the dividend yield and the risk-free interest rate.

The Company from time to time may issue stock options, warrants and restricted stock to acquire goods or services from third-parties. Restricted stock, options or warrants issued to third parties are recorded on the basis of their fair value, which is measured as of the date issued. The options or warrants are valued using the Black-Scholes option pricing model on the basis of the market price of the underlying equity instrument on the “valuation date,” which for options and warrants related to contracts that have substantial disincentives to non-performance, is the date of the contract, and for all other contracts is the vesting date. Expense related to the options and warrants is recognized on a straight-line basis over the shorter of the period over which services are to be received or the vesting period and is included in general and administrative expenses in the accompanying consolidated statements of operations.

The Company recognized stock-based compensation expense from stock awards, warrants, and stock options granted to directors, officers, and employees for services of $8,337 and $33,994 for the three months ended June 30, 2017 and 2016, respectively and $179,034 and $57,409 for the six months ended June 30, 2017 and 2016, respectively.

Recently Adopted Accounting Standards:

In January 2017, FASB issued Accounting Standards Update (“ASU”) 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business, which changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities is deemed to be a business. Determining whether a transferred set constitutes a business is important because the accounting for a business combination differs from that of an asset acquisition. The definition of a business also affects the accounting for dispositions. Under ASU 2017-01, when substantially all of the fair value of assets acquired is concentrated in a single asset, or a group of similar assets, the assets acquired would not represent a business and business combination accounting would not be required. ASU 2017-01 may result in more transactions being accounted for as asset acquisitions rather than business combinations. ASU 2017-01 is effective for interim and annual periods beginning after December 15, 2017 and shall be applied prospectively. Early adoption is permitted. The Company adopted ASU 2017-01 on January 1, 2017 and will apply the new guidance to applicable transactions going forward.

In March 2016, FASB issued guidance regarding the simplification of employee share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. We adopted this guidance in the second quarter of 2016 as permitted by the guidance. Adoption of this guidance did not impact our financial statements, except for the simplification in accounting for income taxes using a modified retrospective approach. Upon adoption, we recorded a related deferred tax asset for previously unrecognized excess tax benefits of $37 million. As we consider it more likely than not that the deferred tax asset will not be realized, we recorded a full valuation allowance of $37 million, resulting in no net effect on our consolidated statement of operations. We elected to continue our current policy of estimating forfeitures.

In April 2015, FASB issued ASU 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. Entities that have historically presented debt issuance costs as an asset, related to a recognized debt liability, will be required to present those costs as a direct deduction from the carrying amount of that debt liability. ASU 2015-03 does not change the recognition, measurement, or subsequent measurement guidance for debt issuance costs. In August 2015, FASB issued ASU 2015-15, Interest—Imputation of Interest (Subtopic 835-30), which addresses the presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements, given the absence of authoritative guidance within ASU 2015-03 for debt issuance costs related to line-of-credit arrangements. The amendments are effective for interim and annual reporting periods beginning after December 15, 2015. Therefore, the Company adopted ASU 2015-03 beginning January 1, 2016. Changes to the balance sheet have been applied on a retrospective basis. This resulted in the reclassification of debt issuance costs of $6,237 and $40,823 associated with our Credit Agreement from Other Assets to Current Note Payable in the Consolidated Balance Sheet as of the six months ended June 30, 2017 and the year ended December 31, 2016.

In February 2015, FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidated Analysis. ASU 2015-02 amended the consolidation guidance by modifying the evaluation criteria for whether limited partnerships and similar legal entities are variable interest entities, eliminating the presumption that a general partner should consolidate a limited partnership, and affecting the consolidated analysis of reporting entities that are involved with variable interest entities. The adoption of ASU 2015-02, effective January 1, 2016, did not have a material impact on our consolidated balance sheets, statements of operations or statements of cash flows.

Recently Issued Accounting Standards:

In February 2016, the FASB issued guidance regarding the accounting for leases. The guidance requires recognition of most leases on the balance sheet. The guidance requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The guidance is effective for interim and annual periods beginning after December 15, 2018. We are currently evaluating the impact of this guidance on our consolidated financial statements.

In January 2016, the FASB issued guidance regarding several broad topics related to the recognition and measurement of financial assets and liabilities. The guidance is effective for interim and annual periods beginning after December 15, 2017. We do not expect this guidance to have a material impact on our consolidated financial statements.

In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. In April 2016, May 2016 and December 2016, FASB issued additional guidance, addressed implementation issues and provided technical corrections. The guidance may be applied retrospectively or using a modified retrospective approach to adjust retained earnings (deficit). The guidance is effective for interim and annual periods beginning after December 15, 2017. We are currently evaluating the impact of this guidance on our consolidated financial statements.

Going Concern:

The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business. As presented in the consolidated financial statements, the Company has incurred a net loss of $585,290 and $543,474 for the three months ended June 30, 2017 and 2016, respectively, and net losses of $1,252,551 and $985,098 for the six months ended June 30, 2017 and 2016, respectively.

The cash proceeds from new contributions to the Aurora partnership by Navitus, and loans from affiliates have allowed the Company to continue operations and invest in new oil and natural gas properties. Management anticipates that operating losses will continue in the near term until new wells are drilled, successfully completed and incremental production increases revenue. The Company has invested $0 and $18,442, respectively, in leases, and drilling and completion costs, for the six months ended June 30, 2017 and 2016, respectively.

The Company remains in active discussions with Navitus and others related to longer term financing required for our capital expenditures planned for 2017. Without additional outside investment from the sale of equity securities and/or debt financing, our capital expenditures and overhead expenses must be reduced to a level commensurate with available cash flows.

The accompanying consolidated financial statements are prepared as if the Company will continue as a going concern. The consolidated financial statements do not contain adjustments, including adjustments to recorded assets and liabilities, which might be necessary if the Company were unable to continue as a going concern.

Note 2 - Acquisitions

During February 2015, Victory entered into a letter of intent ("LOI") and subsequently into (a) the Pre-Merger Collaboration Agreement (the “Collaboration Agreement”) with Lucas Energy Inc. (“Lucas”), Navitus and AEP Assets, LLC ("AEP"), a wholly-owned subsidiary of Aurora; and (b) the Pre-Merger Loan and Funding Agreement (the “Loan Agreement”) with Lucas. During March 2015 the parties entered into Amendment No. 1 to the Pre-Merger Collaboration which amendments affected thereby are included in the discussion of the Collaboration Agreement below. Payments of $195,928 and $317,027 were made by Aurora, on behalf of Victory, to Earthstone Energy/Oak Valley Resources and Penn Virginia, respectively, for costs related to the two Earthstone Energy/ Oak Valley Resources and the five Penn Virginia operated Eagle Ford wells, respectively.

The initial draw, and additional amounts borrowed by Lucas under the Loan Agreement were evidenced by a Secured Subordinated Delayed Draw Term Note issued by Lucas in favor of Victory, which was in an initial amount of $250,000 (the “Draw Note”). Borrowings evidenced by the Draw Note accrued interest at one-half of one percent (0.5%) per annum, with accrued interest payable in one lump sum on maturity. The maturity date of the Draw Note was February 26, 2015. A total of $600,000 was paid to Lucas under the Draw Note.

Subsequent to March 31, 2015, the Company terminated the LOI and notified Lucas pursuant to the Loan Agreement, that it would not extend any further credit to Lucas under the Loan Agreement. There were $0 associated costs incurred during the six-month periods ended June 30, 2017 and 2016.

Further, the Company entered into: (1) a Settlement Agreement and Mutual Release (the “Lucas Settlement Agreement”) with Lucas; (2) a Settlement Agreement and Mutual Release (the “Rogers Settlement Agreement”) with Louise H. Rogers, (“Rogers”), and; (3) a Compromise Settlement Agreement and Mutual General Release, effective as of September 25, 2015 (the “Earthstone Settlement Agreement”, and, together with the Lucas Settlement Agreement and the Rogers Settlement Agreement, the “Settlement Agreements”) with Earthstone Operating, LLC, Earthstone Energy, Inc., Oak Valley Resources, LLC, Oak Valley Operating LLC and Sabine River Energy, LLC (collectively, “Earthstone”), Lucas, AEP, and Aurora.

Lucas Settlement Agreement

The Company and Lucas agreed to terminate any and all obligations between the parties arising under the LOI and the Collaboration Agreement. The Company and Lucas further agreed that the Company would retain ownership and control over five Penn Virginia well-bores previously assigned by Lucas to the Company (the “Penn Virginia Well-Bores”), as well as the obligations to pay the expenses associated with such Penn Virginia Well-Bores effective after August 1, 2014. Under the terms of the Lucas Settlement Agreement, Lucas agreed to assign to the Company all of Lucas’ rights in a certain oil and gas property located in the same field as the Penn Virginia Well-Bores (the “Additional Penn Virginia Property”), including the rights to all revenues from all wells on some properties.

Rogers Settlement and Amended Rogers Settlement Agreements

The Company and Rogers agreed, among other things: (i) to terminate the contingent promissory note in the principal amount of $250,000 payable to Rogers that was issued by Victory in connection with the entry by Lucas and the Company into the Collaboration Agreement; (ii) that the Company would pay Rogers, on or before July 15, 2015, $258,125; and (iii) that Rogers’ legal counsel will hold the assignment of the Additional Penn Virginia Property and the Settlement Shares in escrow until such time as the payment of $258,125 is made by the Company to the Rogers. Failure of the Company to make the payment of $258,125 on or before July 15, 2015, would result in the Company being in default under the Rogers Settlement Agreement and default interest on the amount due would begin to accrue at a per diem rate of $129.0625. Additionally, the Company acknowledged in the Amendment its obligation to pay Rogers’ attorney’s fees in the amount of $25,000. The Company has not made any payments to Rogers pursuant to the Rogers Settlement Agreement and as a result the additional Penn Virginia Property was returned to Lucas in September 2015. The full amount due under the Roger’s obligation including accrued interest at June 30, 2017 totals $348,788 and is included in accrued liabilities on the consolidated balance sheet.

Note 3 – Oil and natural gas properties, net of accumulated impairment (under successful efforts accounting)

Oil and natural gas properties are comprised of the following:



	June 30, 2017			December 31, 2016
Proved property	$	9,702,938		$	9,695,367
Unproved property	$	1,375,940		$	1,375,940
Total oil and natural gas properties, at cost	$	11,078,878		$	11,071,307
Less: accumulated impairment	$	(8,283,321	)	$	(8,283,321	)
Oil and natural gas properties, net of impairment	$	2,795,557		$	2,787,986
Less: accumulated depletion	(2,214,709		)	(2,166,643		)
Oil and natural gas properties, net	$	580,848		$	621,343

Depletion and accretion expense for the three months ended June 30, 2017 and 2016 was $26,295 and $26,651, respectively, and $49,720 and $73,054 for the six months ended June 30, 2017 and 2016, respectively. During the three and six months ended June 30, 2017 and 2016, the Company recorded no impairment losses.

Note 4 – Asset Retirement Obligations

The following table is a reconciliation of the ARO liability as of and for the six months ended June 30, 2017 and the twelve months ended December 31, 2016.



	June 30, 2017		December 31, 2016
Asset retirement obligation at beginning of period	$	83,991	$	109,171
Liabilities incurred on properties acquired and developed	—		—
Revisions to previous estimates	7,570		—
Liabilities on properties sold or settled	—		(27,850		)
Accretion expense	1,655		2,670
Asset retirement obligation at end of period	$	93,216	$	83,991

Note 5 – Revolving Credit Agreement

On February 20, 2014, Aurora, as borrower, entered into a credit agreement (the "Credit Agreement") with Texas Capital Bank (“the Lender”). Guarantors on the Credit Agreement are Victory and Navitus, the two partners of Aurora. Pursuant to the Credit Agreement, the Lender agreed to extend credit to Aurora in the form of: (a) one or more revolving credit loans (each such loan, a “Loan”); and (b) the issuance of standby letters of credit, of up to an aggregate principal amount at any one time not to exceed the lesser of: (i) $25,000,000; or (ii) the borrowing base in effect from time to time (the “Commitment”). The initial borrowing

base on February 20, 2014 was set at $1,450,000. The borrowing base is determined by the Lender, in its sole discretion, based on customary lending practices, review of the oil and natural gas properties included in the borrowing base, financial review of Aurora, the Company and Navitus and such other factors as may be deemed relevant by the Lender. The borrowing base is re-determined: (i) on or about June 30 of each year based on the previous December 31 reserve report prepared by an independent reserve engineer; and (ii) on or about August 31 of each year based on the previous June 30 reserve report prepared by Aurora’s internal reserve engineers or an independent reserve engineer and certified by an officer of Aurora. The Credit Agreement will mature on February 20, 2017. Amounts borrowed under the Credit Agreement will bear interest at rates equal to the lesser of: (i) the maximum rate of interest which may be charged or received by the Lender in accordance with applicable Texas law; and (ii) the interest rate per annum publicly announced from time to time by the Lender as the prime rate in effect at its principal office plus the applicable margin. The applicable margin is: (i) with respect to Loans, one percent (1.00%) per annum; (ii) with respect to letter of credit fees, two percent (2.00%) per annum; and (iii) with respect to commitment fees, one-half of one percent (0.50%) per annum. Loans made under the Credit Agreement are secured by: (i) a first priority lien in the oil and gas properties of Aurora, the Company and Navitus; and (ii) a first priority security interest in substantially all of the assets of Aurora and its subsidiaries, if any, as well as in all (100%) of the partnership interests in Aurora held by the Company and Navitus. Loans made under the Credit Agreement to Aurora are fully guaranteed by the Company and Navitus.

The Credit Agreement contains various affirmative and negative covenants. These covenants, among other things, limit additional indebtedness, additional liens and transactions with affiliates. Among the covenants contained in the Credit Agreement are financial covenants that Aurora will maintain a minimum earnings before interest, taxes, depreciation, depletion, amortization, and exploration expenses ("EBITDAX") to Cash Interest Ratio of 3.5 to 1.0 and a minimum Current Ratio of not less than 1.0 to 1.0. The Current Ratio is defined under the covenants to include, as a current asset, the revolving credit availability.

On April 13, 2015, the Company received the annual Borrowing Base Adjustment called for under the terms of the Credit Agreement, which called for a decrease in the borrowing base of $300,000 payable by May 13, 2015, and an increase in the monthly reduction amount to $10,000 commencing as of June 1, 2015. Additionally, the Lender notified Aurora that, based on the Lender’s redetermination of Aurora’s borrowing base, the monthly reduction amount under the Credit Agreement will be increased, commencing on June 1, 2015, from $0 to $10,000. Pursuant to this increase in the monthly reduction amount, Aurora’s borrowing base will be automatically reduced by $10,000 on the first day of each calendar month beginning in June 2015 until the Lender’s next periodic borrowing base redetermination. The Company made one payment in the amount of $10,000 in June 2015.

On May 13, 2015, Aurora informed the Lender it would not make the required $300,000 payment but was submitting the newly acquired five Eagle Ford wells as additional collateral to be considered and its willingness to execute mortgages regarding the properties to meet the Deficiency.

On August 21, 2015, the Company executed a Forbearance Agreement whereby the Lender would forbear all existing events of default which includes all payments under the previously mentioned Borrowing Base Deficiency payments not yet paid under the April 13, 2015 Redetermination Date notification, as well as the late interest payments for June, July and August 2015, violations of Aurora financial covenants for the three months ended March 31, 2015, and June 30, 2015, and default notice for the late filing of March 31, 2015 financial reports. On August 26, 2015, the Company paid the Lender $76,081 to cover a portion of the deficiency payment, as well as a Forbearance document fee and Lender's legal expenses, as required by the Forbearance Agreement, and the aforementioned Forbearance Agreement went into effect for the $260,000 remaining borrowing base deficiency payment. On August 31, 2015, the Forbearance Agreement terminated pursuant to its terms. The Company did not make the above payment and has been in continuous contact with its lender regarding its plan of payment of the $260,000 as well as the remaining credit facility balance. The Company made a $50,000 principle payment to the Lender on October 14, 2015 as part of that plan.

On December 5, 2016, the Company entered into a new Forbearance Agreement to the Credit Agreement. Pursuant to the Forbearance Agreement, the Lender agreed to forbear from exercising any of its rights and remedies under the Credit Agreement until February 20, 2017 with respect to the historical events of default.

The Forbearance Period was amended and extended on March 2, 2017 and will end on the first to occur of the following: (i) the expiration of the amended Forbearance Period on August 20, 2017; (ii) a breach by Aurora or any Guarantor of any of the conditions, covenants, representations and/or warranties set forth in the Forbearance Agreement; (iii) the occurrence of any new event of default under the Credit Agreement; (iv) the occurrence or threat of the occurrence of any enforcement action against Aurora or any Guarantor by any of their creditors which, in Lender’s reasonable judgment, would materially interfere with the operation of Aurora’s or the Guarantor’s business or the Lender’s ability to collect on the obligations due under the Credit Agreement; (v) the institution of any bankruptcy proceeding relating to Aurora or any Guarantor; or (vi) the initiation by Aurora or any Guarantor of any judicial, administrative or arbitration proceedings against the Lender. The Lender’s agreement to forbear from exercising its rights and remedies as a result of the Existing Events of Default is subject to and conditioned upon the following: (i) the payment by Aurora to the Lender of at least $20,000 on or before the last business day of each calendar week occurring hereafter; and (ii)

the delivery by Aurora of such other documents, instruments and certificates as reasonably requested by Lender. The foregoing description of the Forbearance Agreement is a summary only and is qualified in its entirety by reference to the complete text of the Forbearance Agreement. Since the execution of the extended Forbearance Agreement, the Company has paid the Lender $316,000. The balance owed on the Credit Agreement was $254,500 and $564,263 as of June 30, 2017 and December 31, 2016, respectively.

As of June 30, 2017 and 2016, the Company was out of compliance with the Current Ratio and with the EBITDAX to Cash Interest Ratio due to its reduced revenue streams from price and production declines and continued high general and administrative expenses. Therefore, the Company is in technical default of the Credit Agreement and related agreements. The Company has not yet been advised by the Lender of any additional actions the Lender plans to take.

Amortization of debt financing costs on this debt was $6,237 and $20,412 for the six months ended June 30, 2017 and 2016, respectively. Interest expense was $18,308 and $22,412 for the six months ended June 30, 2017, and 2016, respectively.

Note 6 – Related Party Transactions

David McCall, our general counsel and a director, is a partner in The McCall Firm. Fees related to his services are attributable to litigation involving the Company’s oil and natural gas operations in Texas. As of June 30, 2017 and December 31, 2016, the Company owed The McCall Firm $527,098, and $503,377, respectively.

On February 1, 2017, the Company entered into a securities purchase agreement (the “Securities Purchase Agreement”) with Visionary Private Equity Group I, LP, a Missouri limited partnership (the “Investor”), pursuant to which the Investor agreed to purchase a unit comprised of: (i) $320,000 principal amount of twelve percent (12% ) unsecured six-month promissory note with a maturity date of the earlier of six months from the date of the note or the date the Company consummates a material business combination transaction (the "Note"); and (ii) a common stock purchase warrant to purchase 5,203,252 shares of the Company’s common stock, par value $0.001 per shares (the “Common Stock”) at an exercise price of $0.0923 per share (the “Warrant” and together with the Note, the “Unit”). Visionary PE GP I, LLC is the general partner of the Investor. Mr. Ronald Zamber, one of the Company's directors, is the Managing Director and Chairman of Visionary Private Equity Group I, LP, and the Manager of Visionary PE GP I, LLC. The sale by the Company to the Investor of the Unit, pursuant to the Securities Purchase Agreement is referred to herein as the “Private Placement.” For more information, see the Company's Current Report on Form 8-K filed on February 7, 2017.

During the six months ended June 30, 2017, temporary capital advances totaling $135,000 had been made by Visionary Private Equity Group I, LP. Mr. Ronald Zamber, one of the Company's directors, is the Managing Director and Chairman of Visionary Private Equity Group I, LP. These amounts are recorded in Accrued Liabilities - related parties.

Note 7 – Shareholders’ Equity

Common stock

The Company estimates the fair value of employee stock options and warrants granted using the Black-Scholes Option Pricing Model. Key assumptions used to estimate the fair value of warrants and stock options include the exercise price of the award, the fair value of the Company’s common stock on the date of grant, the expected warrant or option term, the risk free interest rate at the date of grant, the expected volatility and the expected annual dividend yield on the Company’s common stock.

During the six months ended June 30, 2017 the Company issued 2,640,000 warrants to directors, officers and employees for 2016 services with an exercise price of $0.06. Also during the six months ended June 30, 2017 the Company issued 1,170,000 warrants to purchase shares of common stock to Navitus at exercise prices ranging from $0.06 - $0.09. During the six months ended June 30, 2016 the Company issued 302,000 warrants to Navitus with an exercise price ranging from $0.15 - $0.21. These warrants to purchase shares of common stock were issued in consideration of capital contributions to Aurora pursuant to the Company's capital contribution agreement with Aurora. The warrants vest immediately and the Company valued the common stock warrants using the Black Scholes Option Pricing Model. The values for the three months ended June 30, 2017 and 2016 were $24,929 and $98,540, respectively, and were $75,342 and $154,374, for the six months ended June 30, 2017 and 2016, respectively.

Note 8 - Commitments and Contingencies

Contingencies

Liabilities and other contingencies are recognized upon determination of an exposure, which when analyzed indicates that it is both probable that an asset has been impaired or that a liability has been incurred and that the amount of such loss is reasonably estimable.

Volatility of Oil and Natural Gas Prices

Our revenues, future rate of growth, results of operations, financial condition and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent upon prevailing prices of oil and natural gas.

Litigation

Legal Cases Settled

Cause No. 08-04-07047-CV; Oz Gas Corporation v. Remuda Operating Company, et al. v. Victory Energy Corporation.; In the 112th District Court of Crockett County, Texas.

Plaintiff Oz Gas Corporation (“Oz”) filed a lawsuit in April 2008 against various parties for bad faith trespass, among other claims, regarding the drilling of two wells on lands that Oz claims title to. On November 18, 2009, Victory Energy Corporation intervened in the lawsuit to protect its fifty percent (50%) interest in one of the named wells in the lawsuit (that being the 155-2 well located on the Adams Baggett Ranch in Crockett County, Texas).

This case was mediated, with no settlement reached. It went to trial February 8-9, 2012. The Court found in favor of Oz and rendered verdict against Victory and the other Defendants, jointly and severally. Victory appealed this case to the 8th Court of Appeals in El Paso, Texas where the Court of Appeals affirmed the verdict of the District Court and Victory filed a Motion for Rehearing, which was denied. Victory filed a Petition for Review in the Supreme Court of Texas on December 15, 2014, which was denied. Victory filed a Motion for Rehearing with the Supreme Court which was denied. Oz then filed Interrogatories and Request for Production in Aid of Judgment, which were answered by Victory.

A Settlement and Forbearance Agreement was entered into on March 22, 2016, between the parties wherein no further post-judgment discovery or collection efforts will be made by Oz, for $140,000 net of a $14,000 payment received by the Oz receiver (see next following Cause No. C-1-CV-16-001610), with monthly payments of $7,500 commencing April 15, 2016. The balance as of June 30, 2017 was $12,500 and is included in Accrued Liabilities on the balance sheet.

Cause No. C-1-CV-16-001610; Oz Gas Corporation v. Victory Energy Corporation; In the County Court at Law No. 1 of Travis County, Texas.

Plaintiff Oz Gas Corporation (“Oz”) filed an Application for Turnover Relief in Travis County, Texas on February 19, 2016. This order was granted and Thomas L. Kolker was appointed as Receiver to assist in the collection of non-exempt assets. Victory itself has not been placed into Receivership. Victory filed its Motion to Vacate the Turnover that was heard and denied by the trial court. Oz has since filed an Amended Application for Turnover Relief and Appointment of a Receiver to be heard March 10, 2016. Victory filed its Notice of Appeal March 4, 2016.

A Settlement and Forbearance Agreement was entered into on March 22, 2016 as described above.

Cause No. D-1-GN-13-000044; Aurora Energy Partners and Victory Energy Corporation v. Crooked Oaks, LLC; In the 261st District Court of Travis County, Texas.

Victory Energy Corporation sued Crooked Oaks, LLC a/k/a Crooked Oak, LLC for breach of a purchase and sale agreement dated May 7, 2012 in which Victory sold certain assets to Crooked Oaks, LLC for $400,000 of which only $200,000 has been paid as of December 31, 2014. The lawsuit seeks to recover the remaining balance owed of $200,000 from Crooked Oaks, LLC in addition to attorney’s fees and all costs of court. Crooked Oaks, LLC has asserted a counterclaim for rescission of the underlying contract.

Victory and Crooked Oaks attended a mediation on February 10, 2016 where it was determined that Crooked Oaks was insolvent and since that date the case has been dismissed with prejudice.

Cause No. 50916; Trilogy Operating Inc. v. Aurora Energy Partners; In the 118^th Judicial District Court of Howard County, Texas.

This lawsuit was filed on January 6, 2016. This lawsuit alleges causes of action for a suit on a sworn account, breach of contract and a suit to foreclose on liens regarding the drilling and completion of seven wells. Aurora filed an answer on January 29, 2016. Trilogy filed a Motion for Partial Summary Judgment on March 23, 2016.

The parties entered into a Settlement Agreement and Release on April 26, 2016, effective April 1, 2016 to dismiss the lawsuit with prejudice. The court granted the Joint Motion to Dismiss with Prejudice on May 2, 2016. In conjunction with the Joint Motion to Dismiss, Aurora assigned Trilogy all of its interests in the seven wells and related oil and gas leases.

Cause No. 2015-05280; TELA Garwood Limited, LP. v. Aurora Energy Partners, Victory Energy Corporation, Kenneth Hill, David McCall, Robert Miranda, Robert Grenley, Ronald Zamber, and Patrick Barry; In the 164th District Court of Harris County, Texas.

This lawsuit was filed on January 30, 2015 and supplemented on March 4, 2015. This lawsuit alleges breach of contract regarding a Purchase and Sale Agreement that TELA Garwood Limited, LP and Aurora Energy Partners entered into on June 30, 2014. A first closing was held on June 30, 2014 and a purchase price adjustment payment was made on July 31, 2014. Between these two dates, Aurora paid TELA approximately $3,050,133. A second closing was to take place in September, however several title defects were found to exist. The title defects could not be cured and a purchase price reduction could not be agreed upon by the parties in relation to the title defects, therefore, the second closing never took place. Aurora and Victory filed an answer and counterclaim in this case. Both parties filed opposing motions for summary judgment which were heard on April 14, 2016. The Court granted Aurora's partial motions for summary judgment dismissing claims against Aurora/Victory's officers and directors, including Kenny Hill, David McCall, Robert Grenley, Ronald Zamber, Patrick Barry, and Fred Smith. The Court denied the remaining summary judgment issues of both parties. On June 2, 2016 Aurora/Victory filed a second Motion for Partial Summary Judgment on some discrete contract interpretation issues. The Court denied this motion on September 2, 2016.

On December 9, 2016, Aurora/Victory and TELA entered into a Mutual Release and Settlement Agreement in which Aurora agreed to pay TELA $320,000 and in turn each Party agreed to release the other Party from any matter relating to the Purchase and Sale Agreement, the litigation or any claims that were or could have been brought in the litigation. In accordance with the Mutual Release and Settlement Agreement, Aurora made the full payment on February 1, 2017.

Cause No. 10-09-07213; Perry Howell, et al. v. Charles Gary Garlitz, et al.; In the 112th District Court of Crockett County, Texas.

The above referenced lawsuit was filed on or about September 6, 2010. This lawsuit alleges that Cambrian Management, Ltd. and Victory were trespassers on their land, and that they, along with other Defendants, drilled a well (115 #8) on land belonging to Plaintiffs. Plaintiffs claim trespass and unjust enrichment by certain Defendants because of the drilling of the 115 #8 well.

The Court placed this case on the Dismissal Docket asking any party to show cause as to why it should maintain this case on the docket on July 8, 2016. No party came forward stating why the case should be maintained and the Court entered and Order of Dismissal on August 9, 2016.

Legal Cases Pending

Cause No. CV-47230; James Capital Energy, LLC and Victory Energy Corporation v. Jim Dial, et al.; In the 142nd District Court of Midland County, Texas.

This is a lawsuit filed on or about January 19, 2010, by James Capital Energy, LLC and Victory Energy Corporation against numerous parties for fraud, fraudulent inducement, negligent misrepresentation, breach of contract, breach of fiduciary duty, trespass, conversion and a few other related causes of action. This lawsuit stems from an investment Victory made involving the purchase of six wells on the Adams Baggett Ranch with the right of first refusal on option acreage.

On December 9, 2010, Victory was granted an interlocutory Default Judgment against Defendants Jim Dial, 1st Texas Natural Gas Company, Inc., Universal Energy Resources, Inc., Grifco International, Inc., and Precision Drilling & Exploration, Inc. The total judgment amounted to approximately $17,183,987.

Victory has added a few more parties to this lawsuit. Discovery is ongoing in this case and no trial date has been set at this time.

Victory believes it will prevail against all the remaining Defendants in this case.

On October 20, 2011, Defendant Remuda filed a Motion to Consolidate and a Counterclaim against Victory. Remuda is seeking to consolidate this case with two other cases wherein Remuda is the named Defendant. An objection to this motion was filed and the cases have not been consolidated. Additionally, we do not believe that the counterclaim made by Remuda has any legal merit.

Note 9 - Subsequent Events

During the period of July 1, 2017 through August 11, 2017, additional capital contributions from an affiliate of $200,000 were received.

On July 25, 2017, Plaintiff Penn Virginia Oil and Gas, L.P. filed a lawsuit in the 295th Judicial Court of Harris County, Texas, of which Victory Energy Corporation is a defendant. This lawsuit alleges breach of contract and seeks to foreclose on its liens on the Eagle Ford wells in conjunction with collecting monetary damages.

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

The following discussion is intended to assist you in understanding our business and results of operations together with our present financial condition. This section should be read in conjunction with: (i) our condensed consolidated financial statements and the accompanying notes included elsewhere in this Quarterly Report on Form 10-Q; and (ii) our Annual Report on Form 10-K for the year ended December 31, 2016 ("2016 Form 10-K"). Statements in our discussion may be forward-looking statements. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause future production, revenues and expenses to differ materially from our expectations.

The following is management’s discussion and analysis of certain significant factors that have affected certain aspects of our financial position and results of operations during the periods included in the accompanying unaudited condensed consolidated financial statements.

General Overview

We are an independent growth-oriented oil and natural gas acquisition, exploration, development and production company based in Austin, Texas. The Company was organized under the laws of the State of Nevada on January 7, 1982. We have historically been focused on the acquisition and development of unconventional resource play opportunities in the Permian Basin, the Eagle Ford shale of south Texas and other strategically important areas that offer predictable economic outcomes and long-lived reserve characteristics. However, we intend to pursue opportunistic acquisitions in other areas of the country. Our current asset portfolio includes both vertical and horizontal wells in prominent formations such as the Eagle Ford, Austin Chalk, Woodbine, Spraberry, Wolfcamp, Wolfberry, Mississippian, Cline, Fusselman and Ellenberger. We are focused on creating shareholder value by growing conventional oil and liquids-rich natural gas reserves and cash-flow via continued low-risk vertical well development on existing properties, as well as through the acquisition of new economically strong producing properties. This focus on returns is achieved by targeting predictable conventional and resources plays that provide favorable operating environments and lifting costs.

Currently we utilize a team of third-party professionals on an interim as-needed basis to support both the operational and financial aspects of the Company. This team includes geologists for prospect evaluation and assessment, reservoir engineering resources for the analysis of current and new properties and a finance executive for accounting, financial reporting and other back office support. Reserve reporting is performed by a third-party engineer located in Midland, Texas. Each independent operator utilized by the Company also has their own array of experts tailored for the specific formations and well completion techniques of each property that we hold an interest in. We strategically utilize both internal capabilities and industry relationships to acquire non-operated, high-grade working interest positions in predictable, low-to-moderate risk oil and gas prospects, and are focused on oil and liquids rich gas. To help grow the Company and lower field level operating expenses, we also plan to build-out an internal operating team in the future.

As of June 30, 2017, we held a working interest in 30 completed wells located in Texas and New Mexico, predominantly in the Permian Basin of West Texas and the Eagle Ford area of south Texas.

Moving forward, we plan to utilize all available capital sources to complete strategic acquisition targets that hold proved producing assets and future proven undeveloped drilling locations, with competitive economics in today's market. Although we are currently a non-operator, we do anticipate building-out internal operating capabilities in 2017. As has been previously disclosed, we are actively reviewing prospects for acquisition.

Our Relationship with Aurora Energy Partners

We are the managing partner of Aurora Energy Partners, a Texas general partnership, which we refer to as Aurora, and we hold a fifty percent (50%) partnership interest in Aurora. Aurora is a consolidated subsidiary with Victory for financial statement purposes. The Second Amended Partnership Agreement of Aurora, which we refer to as the Aurora Partnership Agreement, gives us control of Aurora. Article XI of the Aurora Partnership Agreement cannot be modified without the approval of all (100%) of the partners of Aurora, therefore we cannot be removed as a managing member of Aurora without our consent regardless of the percentage partnership interest held by the other partners of Aurora. Accordingly, consolidation is appropriate for all reporting periods. We currently conduct all of our oil and natural gas operations through, and hold all of our oil and natural gas assets through, Aurora. Aurora is the record title-holder to substantially all of the oil and natural gas properties, wells and reserves referred to in this quarterly report. Through our partnership interest in Aurora, we are the beneficial owner of fifty percent (50%) of the oil and gas properties, wells and reserves held of record by Aurora.

Victory is one of two partners in Aurora, which was established in January 2008. The second partner in Aurora is the Navitus Energy Group, a Texas general partnership, which we refer to as Navitus. We work together with Nativus to increase proved

reserves and the valuation of Aurora. We plan to eventually consolidate all (100%) of the ownership of Aurora under Victory and thereafter move to a national securities exchange such as the NYSE or NASDAQ.

Navitus Partners, LLC, a partner in the Navitus general partnership, continues to raise capital for contribution through Navitus to the Aurora partnership, the net proceeds of which will generally be used to fund Aurora's operations, as well as for the potential acquisition and development of targeted oil and gas opportunities. The investors in this offering will receive a ten percent (10%) preferred return through their indirect interest in the Navitus partnership for five years and one warrant to purchase one share of Victory common stock for every dollar invested and additional benefits. Under the terms of the offering, Navitus has the right to contribute up to $15 million into Aurora and Victory is obligated to match the capital contribution amount of Navitus resulting from the offering. Victory is also required to match previous contributions made by Navitus. Under the agreement, Victory may also raise funds from other sources. Substantially all producing oil and natural gas assets are held in the Aurora partnership during the five year term of the Aurora Partnership Agreement which ends in October 2017. As of June 30, 2017, Navitus has contributed an aggregate of $10.6 million into Aurora.

Going Concern

As presented in the consolidated financial statements, we have incurred a net loss of $585,290 and $543,474 during the three months ended June 30, 2017 and 2016, respectively, and net losses of $1,252,551 and $985,098 during the six months ended June 30, 2017 and 2016, respectively and losses are expected to continue in the near term. The accumulated deficit at June 30, 2017 was $47,393,299. We have been funding our operations from contributions made by Aurora, the Aurora bank credit facility, and advances from affiliated parties. Management anticipates that significant additional capital expenditures will be necessary to develop our oil and natural gas properties, which consist of proved and unproved reserves, some of which may be non-producing, before significant positive operating cash flows will be achieved.

Management is pursuing business partnering arrangements for the acquisition and development of its properties as well as debt and equity funding through private placements and other sources. Without outside investment from the sale of equity securities, debt financing or partnering with other oil and natural gas companies, operating activities and overhead expenses will be reduced to a pace that will match available operating cash flows.

The accompanying consolidated financial statements are prepared as if we will continue as a going concern. The consolidated financial statements do not contain adjustments, including adjustments to recorded assets and liabilities, which might be necessary if we were unable to continue as a going concern.

Recently Adopted Accounting Standards

In January 2017, the Financial Accounting Standards Board, or FASB, issued Accounting Standards Update, or ASU, 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business, which changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities is deemed to be a business. Determining whether a transferred set constitutes a business is important because the accounting for a business combination differs from that of an asset acquisition. The definition of a business also affects the accounting for dispositions. Under the new standard, when substantially all of the fair value of assets acquired is concentrated in a single asset, or a group of similar assets, the assets acquired would not represent a business and business combination accounting would not be required. The new standard may result in more transactions being accounted for as asset acquisitions rather than business combinations. The standard is effective for interim and annual periods beginning after December 15, 2017 and shall be applied prospectively. Early adoption is permitted. The Company adopted ASU 2017-01 on January 1, 2017 and will apply the new guidance to applicable transactions going forward.

Factors affecting financial reporting of our general and administrative expenses

Our historical general and administrative expenses included in our results of operations for the periods presented may not be comparable, either from period to period or going forward, for the following reasons:

Growth-in-business related general expenses

As part of our stated growth through acquisitions and development business plan, the Company incurred costs associated with one key acquisition during the quarter ended June 30, 2017. Among other things, these additional general and administrative expenses include legal and professional fees. These specific expenses are not quarterly recurring per se, however they may occur again when additional opportunities present themselves. These expenses were significant, but enabled these key business growth transactions to be prudently managed. We estimate the acquisition related costs to be significant as we continue the execution of our strategy.

We have incurred significant costs to structure and manage our debt facility and will continue to incur such costs as our asset base allows prudent borrowing against our proved reserves. These costs can fluctuate as debt instruments are ended, modified and replaced with new creditor entities.

We have incurred non-recurring costs associated with investor and public relations, which are critical to operate and expand in the public company arena. These include our engagement of an SEC registered broker-dealer that is a member of the Financial Industry Regulatory Authority as our Designated Advisor for Disclosure, or DAD, in connection with the change of our trading platform or market from OTCQB to the OTCQX. We believe that this change of markets to the OTCQX is a stepping stone for us to achieve our ultimate goal of becoming listed on a national securities exchange.

We have incurred director, employee, and vendor stock based compensation, all non-cash in nature, as part of our key employee acquisition and retention plan. As we grow, we need to add new talent and incentivize our current key employees to stay with the Company. The 2014 Long Term Incentive Plan, approved by our shareholders in February 2014, was a key element of the platform to fulfill this need. Among other things, the Company incurred SEC related legal expenses as part of this plan and shareholder vote. Stock grants and multi-year stock option award based compensation is now a fundamental part of the Company’s key-employee retention plan.

Volume and Price Trends

The following tables summarize the volumes and prices realized by the Company for the three and six months ended June 30, 2017 compared to the three and six months ended June 30, 2016.

Overall, Barrel of Oil Equivalent, or BOE, production increased 1% for the three months ended June 30, 2017 and decreased 15% for the six months ended June 30, 2017. While BOE production for the three months ended June 30, 2017 was relatively flat, there was a 20% decrease in oil production, which was offset by a 35% increase in gas production. BOE production for the six months ended June 30, 2017 declined by 15% due to a 26% increase in gas production, which was offset by a 36% decrease in oil production.



	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2017	2016	Change		2017	2016	Change
Period Production
Oil (Bbl)	1,299	1,622	(20	)%	2,467	3,862	(36	)%
Gas (Mcf)	7,947	5,899	35	%	14,980	11,878	26	%
BOE	2,624	2,605	1	%	4,964	5,842	(15	)%
Daily Production
Oil (Bbl/d)	14	18	(22	)%	14	21	(33	)%
Gas (Mcf/d)	87	65	34	%	83	65	28	%
BOE/d	29	29	—	%	27	32	(16	)%

During the three months ended June 30, 2016 and 2017, the price per barrel realized by the Company decreased from $42.56 to $41.22 or 3%, respectively. For the three months ended June 30, 2016 and 2017 the price per Mcf realized by the Company increased from $1.72 to $2.16 or 26%, respectively.

During the six months ended June 30, 2016 and 2017, the price per barrel realized by the Company increased from $31.95 to $44.39 or 39%, respectively. For the six months ended June 30, 2016 and 2017 the price per Mcf realized by the Company increased from $1.83 to $3.10 or 69%, respectively.



	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2017		2016		Change		2017		2016		Change
Realized Prices
Oil ($/Bbl)	$	41.22	$	42.56	(3	)%	$	44.39	$	31.95	39	%
Gas ($/Mcf)	2.16		1.72		26	%	3.10		1.83		69	%
Value per BOE	$	26.94	$	30.39	(11	)%	$	31.42	$	24.85	26	%

The volume and price changes in the tables above caused the following changes to our oil, gas and NGL sales between the three and six months ended June 30, 2017 and 2016.



	For the Three Months Ended June 30,								For the Six Months Ended June 30,
	Oil			Gas		Total			Oil			Gas		Total

2016 Sales	$	69,031		$	10,154	$	79,185		$	123,394		$	21,784	$	145,178
Change due to Volumes	(13,747		)	3,525		(10,222		)	(44,571		)	5,688		(38,883		)
Change due to Prices	(1,739		)	3,456		1,717			30,689			18,996		49,685
2017 Sales	$	53,545		$	17,135	$	70,680		$	109,512		$	46,468	$	155,980

The Company’s oil and gas revenue fluctuations are directly related to the volumes produced and the commodity prices paid over the respective periods presented.

Oil and gas sales decreased $10,222 due to volumes in the three months ended June 30, 2017 compared to the three months ended June 30, 2016. The decrease was primarily driven by lower oil production.

Oil and gas sales increased $1,717 due to prices in the three months ended June 30, 2017 compared to the three months ended June 30, 2016. The increase was due to higher market prices for gas, which was partially offset by lower market prices for oil.

Oil and gas sales decreased $38,883 due to volumes in the six months ended June 30, 2017 compared to the six months ended June 30, 2016. The decrease was primarily driven by lower oil production.

Oil and gas sales increased $49,685 due to prices in the six months ended June 30, 2017 compared to the six months ended June 30, 2016. The increase was due to higher market prices for both oil and gas.

Public Company Expenses

We incur direct, incremental general and administrative expenses as a result of being a publicly traded company, including but not limited to, increased scope of operations as we evaluate potential acquisitions, corporate structure planning, implementation of stock based compensation programs to attract and retain talent, periodic public reporting to shareholders, tax consulting, independent auditor fees, legal fees, investor relations activities, registrar and transfer fees, director and officer liability insurance, and director compensation. In some cases, our small reporting company status will make key acquisitions and divestitures fall into “significant” status. This requires the Company to perform a series of financial accounting and reporting processes and filings. As we grow, these transactions will become a smaller part of our overall size, and may no longer be required.

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

The condensed consolidated operating statements of our revenue, operating expenses, and net income for the three months ended June 30, 2017 as compared to the three months ended June 30, 2016 were as follows:



	(Unaudited)
	Three Months Ended June 30,									Percentage
	2017			2016			Change			Change
Revenues
Oil and gas sales	$	70,680		$	79,185		$	(8,505	)	(11	)%
Gain on settlement and sale of oil and gas properties	—			64,824			(64,824		)	(100	)%
Total revenues	70,680			144,009			(73,329		)	(51	)%
Operating Expenses:
Lease operating costs	31,836			25,774			6,062			24	%
Exploration and dry hole costs	315			—			315			100	%
Production taxes	3,806			3,782			24			1	%
General and administrative	513,826			623,995			(110,169		)	(18	)%
Depreciation, depletion, amortization and accretion	37,259			28,267			8,992			32	%
Total operating expenses	587,042			681,818			(94,776		)	(14	)%
Loss from operations	(516,362		)	(537,809		)	21,447			(4	)%
Other Income (Expense):
Management fee income	822			1,305			(483		)	(37	)%
Interest expense	(98,633		)	(33,124		)	(65,509		)	198	%
Total other income and expense	(97,811		)	(31,819		)	(65,992		)	207	%
Loss before Tax Benefit	(614,173		)	(569,628		)	(44,545		)	8	%
Tax benefit	—			—			—			—	%
Net loss	(614,173		)	(569,628		)	(44,545		)	8	%
Less: Net loss attributable to non-controlling interest	(28,883		)	(26,154		)	(2,729		)	10	%
Net Loss Attributable To Victory Energy Corporation	$	(585,290	)	$	(543,474	)	$	(41,816	)	8	%

Oil and gas sales: Our revenues decreased $8,505 or 11% to $70,680 for the three months ended June 30, 2017 from $79,185 for the three months ended June 30, 2016. The decrease is primarily the result of lower oil volumes and prices, which was partially offset by increases in natural gas volumes and prices.

Gain on settlement and sale of oil and natural gas properties: The $64,824 decrease in the gain on settlement and sale of oil and natural gas properties is due no properties being sold or legally settled for the three months ended June 30, 2017.

Lease operating costs: Lease operating expenses increased $6,062 or 24% to $31,836 for the three months ended June 30, 2017 from $25,774 for the three months ended June 30, 2016. The increase is primarily the result of higher operating costs at the Eagle Ford area wells.

Exploration and dry hole costs: Exploration expense increased $315 or 100% to $315 for the three months ended June 30, 2017 from $0 for the three months ended June 30, 2016. The increase in exploration expense is primarily the result of geological and geophysical (G&G) costs associated with the services related to acquisition and divestiture work.

Production taxes: Production taxes are charged at the well head on the value of production of oil and natural gas. Production taxes increased 1% during the three months ended June 30, 2017 compared to the three months ended June 30, 2016, which is consistent with the increase in natural gas revenues during the period.

General and administrative: General and administrative expenses decreased $110,169 or 18% to $513,826 for the three months ended June 30, 2017 from $623,995 for the three months ended June 30, 2016. The decrease is primarily due to lower salaries expense due to lower headcount.

Depletion, depreciation, amortization and accretion: Depletion, depreciation, amortization and accretion increased $8,992 or 32% to $37,259 for the three months ended June 30, 2017 from $28,267 for the three months ended June 30, 2016. The increase is primarily due to an adjustment made to depreciation on furniture and equipment during the three months ended June 30, 2017.

Management fee income: Management fee income decreased $483 or 37% to $822 for the three months ended June 30, 2017. This decline resulted from lower management fee billings to the Navitus Energy Group due to lower total revenues.

Interest expense: Interest expense increased $65,509 or 198% for the three months ended June 30, 2017 from $33,124 for the three months ended June 30, 2016. The increase is primarily due to the newly issued note payable - affiliate.

Tax benefit: There is no provision for income tax or tax benefit recorded for either the three months ended June 30, 2017 or June 30, 2016 due to the net operating loss carry forwards (NOLs) through the period ending June 30, 2017. Accordingly, the Company has recorded a full valuation allowance against its net deferred tax assets. Our NOLs generally begin to expire in 2025.

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




	(Unaudited)
	Six Months Ended June 30,										Percentage Change
	2017				2016			Change			Inc (Dec)
Revenues
Oil and gas sales	155,980				145,178			$	10,802		7	%
Gain on settlement and sale of oil and gas properties	—				64,824			(64,824		)	(100	)%
Total revenues	155,980				210,002			(54,022		)	(26	)%
Operating Expenses:
Lease operating costs	57,740				63,127			(5,387		)	(9	)%
Exploration and dry hole costs	2,218				—			2,218			100	%
Production taxes	8,491				7,055			1,436			20	%
General and administrative	1,117,488				1,068,156			49,332			5	%
Depreciation, depletion, amortization and accretion	62,300				76,286			(13,986		)	(18	)%
Total operating expenses	1,248,237				1,214,624			33,613			3	%
Loss from operations	(1,092,257		)		(1,004,622		)	(87,635		)	9	%
Other Income (Expense):
Management fee income	1,899				2,641			(742		)	(28	)%
Interest expense	(187,991		)		(66,313		)	(121,678		)	183	%
Total other income and expense	(186,092		)	—	(63,672		)	(122,420		)	192	%
Loss before Tax Benefit	(1,278,349		)		(1,068,294		)	(210,055		)	20	%
Tax benefit	—				—			—			—	%
Net loss	(1,278,349		)		(1,068,294		)	(210,055		)	20	%
Less: Net income (loss) attributable to non-controlling interest	(25,798		)		(83,196		)	57,398			(69	)%
NET LOSS ATTRIBUTABLE TO VICTORY ENERGY CORPORATION	$	(1,252,551	)		$	(985,098	)	$	(267,453	)	27	%

Oil and gas sales: Our revenues increased $10,802 or 7% to $155,980 for the six months ended June 30, 2017 from $145,178 for the six months ended June 30, 2016. The increase is primarily the result of an increase in natural gas production and increases in commodity prices of both oil and natural gas.

Gain on settlement and sale of oil and gas properties: The $64,824 decrease in the gain on settlement and sale of oil and gas properties is due to no properties being sold or legally settled for the six months ended June 30, 2017.

Lease operating costs: Lease operating expenses decreased $5,387 to $57,740 or 9% for the six months ended June 30, 2017 from $63,127 for the six months ended June 30, 2016. This is due to a decrease in the net working interest held in oil and gas producing properties.

Exploration and dry hole costs: Exploration expense increased $2,218 or 100% from $0 for the six months ended June 30, 2017 compared to the six months ended June 30, 2016. The increase in exploration expense is primarily the result of geological and geophysical (G&G) costs associated with the services related to acquisition and divestiture work.

Production taxes: Production taxes are charged at the well head on the value of production of oil and natural gas. Production taxes increased $1,436 or 20% to $8,491 for the six months ended June 30, 2017 from $7,055 for the six months ended June 30, 2016. The increase in production taxes is associated with higher oil natural gas revenues during the period.

General and administrative: General and administrative expenses increased $49,332 or 5% to $1,117,488 for the six months ended June 30, 2017 from $1,068,156 for the six months ended June 30, 2016. The increase is primarily due to professional service fees and stock compensation expense.

Depletion, depreciation, amortization and accretion: Depletion, depreciation, amortization and accretion decreased $13,986 or 18% to $62,300 for the six months ended June 30, 2017 from $76,286 for the six months ended June 30, 2016. This is due to a decrease in the net working interest in oil and gas producing properties.

Management fee income: Management fee income decreased $742 or 28% to $1,899 for the six months ended June 30, 2017. Victory charges a two percent (2%) management fee to Navitus Energy Group, a fifty percent (50%) partner of Aurora, on gross revenues attributable to Aurora. The decrease is due to lower total revenues.

Interest expense: Amortization of debt financing costs and interest expense increased $121,678 or 183% for the six months ended June 30, 2017 from $66,313 of interest income (net) for the six months ended June 30, 2016. The increase is primarily due to the newly issued note payable - affiliate.

Tax benefit: There is no provision for income tax or tax benefit recorded for either the six months ended June 30, 2017 or for the six months ended June 30, 2016 due to the NOLs through the period ending June 30, 2017. Accordingly, the Company has recorded a full valuation allowance against its net deferred tax assets. Our NOLs generally begin to expire in 2025.

Liquidity and Capital Resources

Our cash, total current assets, total assets, total current liabilities, and total liabilities as of June 30, 2017 as compared to December 31, 2016, are as follows:



	June 30, 2017		December 31, 2016
Cash	$	47,157	$	56,456
Total current assets	$	102,844	$	110,786
Total assets	$	826,558	$	885,675
Total current liabilities	$	2,848,861	$	3,307,419
Total liabilities	$	2,889,756	$	3,314,560

At June 30, 2017, the Company had a working capital deficit of $2,746,017 compared to a working capital deficit of $3,196,633 at December 31, 2016. Current liabilities decreased to $2,848,861 at June 30, 2017 from $3,307,419 at December 31, 2016. The decrease is primarily due to payments made to our Lender and other payables.

Operating Activities

Net cash used in operating activities for the six months ended June 30, 2017 was $1,318,299 after the net loss of $1,278,349 was decreased by $371,626 in non-cash charges and offset by $411,576 in changes to the other operating assets and liabilities. This compares to cash used in operating activities for the six months ended June 30, 2016 of $907,471 after the net loss for that period of $1,068,294 was decreased by $89,283 in non-cash charges and $71,540 in changes to other operating assets and liabilities.

Investing Activities

Net used in investing activities for the six months ended June 30, 2017 was $0 compared to $10,148 for the six months ended June 30, 2016 all of which was used for acquisitions, leases, drilling and related costs net of proceeds from sale of assets.

Financing Activities

Net cash provided by financing activities for six months ended June 30, 2017 was $1,309,000 which primarily relates to contributions from Navitus and affiliate note payable proceeds offset by principal payments on the debt financing. This compares to $972,000 of contributions from Navitus for the six months ended June 30, 2016.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements that have or are reasonably likely to have a current of future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

Item 3. Qualitative and Quantitative Discussions about Market Risk

As a smaller reporting company we are not required to provide the information required by this Item. However, we did include market risk factors in our Annual Report on Form 10-K for the year ended December 31, 2016 filed with the SEC on March 31, 2017.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

Pursuant to Rule 13a-15(e) under the Exchange Act, we carried out an evaluation, with the participation of our management, including the Chief Executive Officer, or CEO (our principal executive officer), and Chief Financial Officer, or CFO (our principal financial officer), of the effectiveness of our disclosure controls and procedures (as defined under Rule 13a-15(e) under the Exchange Act) as of June 30, 2017. Based upon this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were ineffective as of June 30, 2017.

Management’s Report on Internal Control over Financial Reporting

Because of its inherent limitations, internal control over financial reporting may not prevent or detect all misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim consolidated financial statements will not be prevented or detected on a timely basis. Our management assessed the effectiveness of our internal control over financial reporting as of June 30, 2017. Based on this assessment, our management concluded that our disclosure controls and procedures may not be effective as of June 30, 2017.

We lack sufficient segregation of duties within accounting functions, which is a basic internal control. Due to our size and nature, segregation of all conflicting duties may not always be possible and may not be economically feasible. However, to the extent possible, the initiation of transactions, the custody of assets and the recording of transactions should be performed by separate individuals. Management evaluated the impact of our failure to have segregation of duties on our assessment of our disclosure controls and procedures and has concluded that the control deficiency represents a material weakness. To address this material weakness, management performs additional analysis and other procedures to ensure that the consolidated financial statements included herein, fairly present, in all material respects, our financial position, results of operations and cash flows for the periods presented.

This Quarterly Report on Form 10-Q does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit us to provide only our management’s report in this Quarterly Report on Form 10-Q.

Changes in Internal Controls

There have been no changes in our internal controls over financial reporting (or deferred in Rule 13a-15(f) under the Securities Exchange Act) that occurred during the six months ended June 30, 2017 that materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

Part II – Other Information

Item 1. Legal Proceedings

Cause No. 08-04-07047-CV; Oz Gas Corporation v. Remuda Operating Company, et al. v. Victory Energy Corporation.; In the 112th District Court of Crockett County, Texas.

This case was mediated, with no settlement reached. It went to trial February 8-9, 2012. The Court found in favor of Oz and rendered verdict against Victory and the other Defendants, jointly and severally. Victory appealed this case to the 8th Court of Appeals in El Paso, Texas where the Court of Appeals affirmed the verdict of the District Court and Victory filed a Motion for Rehearing, which was denied. Victory filed a Petition for Review in the Supreme Court of Texas on December 15, 2014 which was denied. Victory filed a Motion for Rehearing with the Supreme Court which was denied. Oz then filed Interrogatories and Request for Production in Aid of Judgment which were answered by Victory.

Cause No. C-1-CV-16-001610; Oz Gas Corporation v. Victory Energy Corporation; In the County Court at Law No. 1 of Travis County, Texas.

A Settlement and Forbearance Agreement was entered into on March 22, 2016 as described above.

Cause No. D-1-GN-13-000044; Aurora Energy Partners and Victory Energy Corporation v. Crooked Oaks, LLC; In the 261st District Court of Travis County, Texas.

Victory and Crooked Oaks attended a mediation on February 10, 2016 where it was determined that Crooked Oaks was insolvent and since that date the case has been dismissed with prejudice.

Cause No. 50916; Trilogy Operating Inc. v. Aurora Energy Partners; In the 118^th Judicial District Court of Howard County, Texas.

The parties entered into a Settlement Agreement and Release on April 26, 2016, effective April 1, 2016 to dismiss the lawsuit with prejudice. The Joint Motion to Dismiss with Prejudice was granted by the court May 2, 2016. In conjunction with the Joint Motion to Dismiss, Aurora assigned Trilogy all of its interests in the seven wells and related oil and gas leases.

This lawsuit was filed on January 30, 2015 and supplemented on March 4, 2015. This lawsuit alleges breach of contract regarding a Purchase and Sale Agreement that TELA Garwood Limited, LP and Aurora Energy Partners entered into on June 30, 2014. A first closing was held on June 30, 2014 and a purchase price adjustment payment was made on July 31, 2014. Between these two dates Aurora paid TELA approximately $3,050,133. A second closing was to take place in September, however several title defects were found to exist. The title defects could not be cured and a purchase price reduction could not be agreed upon by the parties in relation to the title defects, therefore, the second closing never took place. Aurora and Victory filed an answer and counterclaim in this case. Both parties filed opposing motions for summary judgment, which were heard on April 14, 2016. The Court granted Aurora's partial motions for summary judgment dismissing claims against Aurora/Victory's officers and directors, including Kenny Hill, David McCall, Robert Grenley, Ronald Zamber, Patrick Barry, and Fred Smith. The Court denied the remaining summary judgment issues of both parties. On June 2, 2016 Aurora/Victory filed a second Motion for Partial Summary Judgment on some discrete contract interpretation issues. The Court denied this motion on September 2, 2016.

On December 9, 2016, Aurora/Victory and TELA entered into a Mutual Release and Settlement Agreement in which Aurora agreed to pay TELA $320,000 and in turn each Party agreed to release the other Party from any matter relating to the PSA, the litigation or any claims that were or could have been brought in the litigation. In accordance with the Mutual Release and Settlement Agreement, Aurora made the full payment on February 1, 2017.

Cause No. 10-09-07213; Perry Howell, et al. v. Charles Gary Garlitz, et al.; In the 112th District Court of Crockett County, Texas.

Legal Cases Pending

Cause No. CV-47230; James Capital Energy, LLC and Victory Energy Corporation v. Jim Dial, et al.; In the 142nd District Court of Midland County, Texas.

Victory has added a few more parties to this lawsuit. Discovery is ongoing in this case and no trial date has been set at this time.

Victory believes it will prevail against all the remaining Defendants in this case.

On October 20, 2011 Defendant Remuda filed a Motion to Consolidate and a Counterclaim against Victory. Remuda is seeking to consolidate this case with two other cases wherein Remuda is the named Defendant. An objection to this motion was filed and the cases have not been consolidated. Additionally, we do not believe that the counterclaim made by Remuda has any legal merit.

Item 1A. Risk Factors

Except as set forth below, there have been no material changes from the risk factors disclosed in the “Risk Factors” section of the Company’s Annual Report on Form 10-K for the year ended December 31, 2016.

We have substantial liabilities that require that we raise additional financing to support our operations. Such financing may only be available on disadvantageous terms, or may not be available at all. Any new financing could have a substantial dilutive effect on our existing stockholders.

As of June 30, 2017, we had $47,157 of cash, current assets of $102,844, current liabilities of $2,848,861 and a working capital deficit of $2,746,017. Our current liabilities include $2,248,702 of accounts payable and accrued liabilities, some of which are past due, and $538,555 of loans payable that are classified as current because the loan is either evidenced by a note that has matured or is not documented by a note at all. We are currently unable to pay our accounts payable. If any material creditor decides to commence legal action to collect from us, it could jeopardize our ability to continue in business.

We will be required to seek additional debt or equity financing in order to pay our current liabilities and to support our anticipated operations. We may not be able to obtain additional financing on satisfactory terms, or at all, and any new equity financing could have a substantial dilutive effect on our existing stockholders. If we cannot obtain additional financing, we will not be able to achieve the operating activities that we need to cover our costs, and our results of operations would be negatively affected.

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

Unregistered sales of equity securities during the six months ended June 30, 2017:

We issued 2,640,000 warrants to purchase shares of common stock to directors, officers and employees for services provided during 2016 with an exercise price of $0.06.

We issued 1,170,000 warrants to purchase shares of common stock to Navitus at exercise prices ranging from $0.06 - $0.09. These warrants to purchase shares of common stock were issued in consideration of capital contributions to Aurora of $1,170,000 pursuant to our capital contribution agreement with Aurora.

We issued 5,203,252 warrants to purchase shares of common stock to Visionary Private Equity Group I, LP at an exercise price of $0.0923 per share. These warrants to purchase shares of common stock were issued in conjunction with the Private Placement discussed in Note 6 to the Condensed Consolidated Financial Statements.

We relied on the exemption from registration relating to offerings that do not involve any public offering pursuant to Section 4(2) under the Securities Act of 1933 (the “Act”) and/or Rule 506 of Regulation D of the Act. We believe that each investor had adequate access to information about us through the investor’s relationship with us.

Dividends:

Our Credit Agreement with Texas Capital Bank includes certain restrictions on our ability to pay dividends or make other payments or distributions to the holders of our common stock.

Item 3. Default Upon Senior Securities

There is no information required to be reported under this Item.

Item 4. Mine Safety Disclosures

Not Applicable.

Item 5. Other Information

There is no information required to be reported under this Item.

Item 6. Exhibits

(a) Exhibits



31.1 **		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.**

31.2 **		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.**

32.1 **		Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350.**

32.2 **		Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350.**

101.INS*		XBRL Instance Document

101.SCH*		XBRL Taxonomy Extension Schema Document

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document

101.LAB*		XBRL Taxonomy Extension Label Linkbase Document

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document

_____________

* XBRL (Extensible Business Reporting Language) information is furnished and not filed or part of a registration statement or prospectus for purposes of Section 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections.

** Filed herewith.

Signature

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



		VICTORY ENERGY CORPORATION

Date:	August 11, 2017	By:	/s/ Kenneth Hill
			Kenneth Hill
			Chief Executive Officer and Director