8-K/A

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 8-K/A

(Amendment No. 1)

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported):  February 3, 2015

Hawker Energy, Inc.

(Exact name of registrant as specified in its charter)

Nevada	98-0511130
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

326 S. Pacific Coast Highway, Suite 102 Redondo Beach, CA	90277
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (310) 316-3623

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

ITEM 2.01. COMPLETION OF ACQUISITION OR DISPOSITION OF ASSETS

On February 9, 2015, Hawker Energy, Inc. (“Hawker”, “we”, “us” or “our”) filed a Current Report on Form 8-K reporting that on February 3, 2015, we closed our acquisition of TEG Oil & Gas U.S.A., Inc. (“TEG”).

This Form 8-K/A amends the Form 8-K we filed on February 9, 2015, to include TEG’s audited financial statements for the two years in the period ended December 31, 2014, and the unaudited pro forma financial information related to our acquisition of TEG required by Items 9.01(a) and 9.01(b) of Form 8-K.  In addition, reserve and related information for the acquired properties is included below.

Reserves

We engaged an independent reserve engineering firm, Reed W. Ferrill & Associates, Inc. (“RF&A”), to prepare a reserve estimate of the Tapia and Eureka oilfields (the “TEG Properties”) as of December 31, 2014, which report is attached as Exhibit 99.3.  The lead technical person at RF&A primarily responsible for the preparation of the reserve estimates is a Professional Engineer registered in the State of Colorado to practice Petroleum Engineering and has in excess of 40 years experience in the practice of Petroleum Engineering.

The following table summarizes TEG’s share of the estimated quantities of proved reserves as of December 31, 2014 for the based on $92.28 per barrel of oil, which represents the unweighted arithmetic average of the first-day-of-the month oil prices (being Plains Marketing LP Midway Sunset posting, less contracted differential and average gravity adjustment realized by TEG) during the twelve-month period prior to December 31, 2014.

Summary of Estimated Proved Oil Reserves

as of December 31, 2014

Proved Reserves Category	Net Barrels		PV10  (before tax)
Proved, Developed Producing		239,243	$	5,982,215
Proved, Developed Non-Producing		1,031,038		26,635,225
Proved, Undeveloped		2,074,515		51,527,443
Total Proved		3,344,796	$	84,144,883

The total PV10 (present value) of the TEG Properties’ proved reserves as of December 31, 2014 was approximately $84.1 million. "PV10" means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the U.S. Securities and Exchange Commission (“SEC”). PV10 is a non-GAAP financial measure and generally differs from the standardized measure of discounted future net cash flows, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues.

Uncertainties are inherent in estimating quantities of proved reserves, including many factors beyond our control. Reserve engineering is a subjective process of estimating subsurface accumulations of oil that cannot be measured in an exact manner, and the accuracy of any reserves estimate is a function of the quality of available data and its interpretation. As a result, estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing, and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices or development and production expenses, may require revision of such estimates. Accordingly, oil quantities ultimately recovered will vary from reserves estimates.

Neither we nor TEG filed any estimates of total proved net oil reserves for the TEG properties with, or included such information in reports to, any federal authority or agency during the twelve months ended December 31, 2014.

2

Drop in Oil Prices

TEG’s revenues, operating results, profitability, future rate of growth and the carrying value depend primarily upon the prevailing prices for oil. Historically, oil prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors.

During the second half of 2014 oil prices experienced a steep decline, which has continued into 2015. If prices remain at or near current levels for the rest of 2015, or if they decline further, the prices used to determine our year-end 2015 reserves will be significantly lower than those used for year-end 2014, as mandated by SEC regulations. Under such circumstances, we may experience significant negative price-related revisions to our proved reserves at year-end 2015. For example, under a much lower price scenario used for reserves reporting purposes, a portion of our proved undeveloped reserves may no longer meet the economic producibility criteria under the rules. Similarly, substantial costs of operation are fixed, having the effect of increasing costs on a per barrel basis in later years as production declines, rendering them uneconomic in a lower price environment.

Net Production, Average Sales Price and Average Lifting Costs

The table below sets forth TEG’s net oil production (net of all overriding royalties), the average sales prices and average lifting costs for the twelve months ended December 31, 2014 and 2013.  TEG’s year end was December 31st until its acquisition by Hawker effective February 1, 2015.

	Twelve Months Ended December 31, 2014		Twelve Months Ended December 31, 2013
Net production - oil (barrels per day)		70		117
Average sales price per barrel of oil, before royalties (1)	$	87.37	$	97.82
Average lifting costs (2) per net barrel of oil	$	60.05	$	60.49

(1)  Royalties averaged approximately 5.6% in 2014 and 5.4% in 2013.

(2)  Direct lifting costs do not include depreciation, depletion and amortization.

Active Wells, Acreage, Drilling Activity, Present Activity and Delivery Commitments

At December 31, 2014, there were fifteen gross wells (14.1 net wells) that were actively producing oil, and one gross well (0.9 net well) injecting water, at the Tapia oil field, and four gross wells (3.3 net wells) that were actively producing oil, and one gross well (0.8 net well) injecting water, at the Eureka oilfield.

At December 31, 2014 the TEG properties’ acreage was as follows: 

Project Name	Developed Acreage				Undeveloped Acreage				Total Acreage
	Gross		Net		Gross		Net		Gross		Net
Tapia		89		89		173		173		262		262
Eureka		36		36		1,474		1,474		1,510		1,510
Total		125		125		1,647		1,647		1,772		1,772

Gross wells or acres are the total numbers of wells or acres in which TEG owns a working interest.  Net wells or acres are the same as gross wells or acres as TEG owns a 100% working interest.  Undeveloped acreage is acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil, regardless of whether the acreage contains proved reserves.

There were no wells drilled in the twelve months ended December 31, 2014 and 2013.

Currently, there is no activity other than production from existing wellbores.

3

There are no commitments to provide a fixed and determinable quantity of oil in the near future under existing contracts or agreements.  

Overriding Royalty Interest Liability

Pursuant to an overriding royalty interest (“ORRI”) granted in January 2015 to a secured convertible note payable holder, oil sales from the Tapia oil field are subject to an additional 2.5% or 3.5% overriding royalty interest, depending on the lease.  Since this royalty interest was granted in connection with a loan, the loan proceeds were bifurcated and this royalty interest has been accounted for as a separate liability.This ORRI will be not be accounted for as a revenue reduction, nor an operating expense or reserve deduction, rather the ORRI is accounted for as debt.  This ORRI is not reflected in any of the information provided in the prior sections of the Form 8-K/A.

ITEM 9.01. FINANCIAL STATEMENTS AND EXHIBITS

(a)    Financial Statements of Business Acquired.

(i) The audited financial statements of TEG as of and for the years ended December 31, 2014 and December 31, 2013, are attached as Exhibit 99.1 to this Form 8-K/A and incorporated by reference into this Form 8-K/A.

(ii) The consents of RBSM LLP, TEG’s independent auditors for the year ended December 31, 2014, and L.L. Bradford & Co., TEG’s independent auditors for the year ended December 31, 2013, are attached as Exhibits 23 and 24, respectively, to this Form 8-K/A.

(b)   Pro Forma Financial Information.

The following unaudited pro forma condensed consolidated financial information related to the TEG acquisition is attached as Exhibit 99.2 to this Form 8-K/A and incorporated by reference into this Form 8-K/A:

(i) Unaudited Pro Forma Condensed Consolidated Statement of Operations for the six months ended February 28, 2015 and the year ended August 31, 2014.

(ii) Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements.

(c)   The following exhibits are being filed as part of this Current Report on Form 8-K/A.

Exhibit Number	Description
23	Consent of RBSM LLP
24	Consent of L.L Bradford & Company LLC
25	Consent of Reed W. Ferrill & Associates, Inc.
99.1	TEG Audited Financial Statements as of and for the years ended December 31, 2014 and December 31, 2013.
99.2	Unaudited Pro Forma Condensed Consolidated Financial Statements.
99.3	Reserve report of Reed W. Ferrill & Associates, Inc.

4

SIGNATURES

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

Hawker Energy, Inc.

Dated:	June 18, 2015
By:	/s/ Darren Katic
	Darren Katic
	Chief Executive Officer

5

EX-23

Exhibit 23                     

101 Larkspur Landing Circle Suite 321 Larkspur, CA 94939 415-306-7611 www.rbsmllp.com

Consent of Independent Registered Public Accounting Firm

The Board of Directors

Hawker Energy, Inc.

We consent to the use of our report dated June 18, 2015 with respect to the balance sheet as of December 31, 2014 and the related statements of operations, cash flows, stockholders’ equity (deficit) of TEG Oil & Gas U.S.A., Inc., (“TEG”) for the year ended December 31, 2014 included herein in the Form 8-K/A of Hawker Energy, Inc.

Our report dated June 18, 2015 contains an explanatory paragraph that states that TEG has suffered recurring losses from operations and has a net working capital deficiency, which raise substantial doubt about its ability to continue as a going concern. The financial statements do not include any adjustments that might result from the outcome of that uncertainty.

/s/ RBSM LLP

Larkspur, California

June 18, 2015

New York City, Washington DC, San Francisco, CA,   Athens, GRE Mumbai, IND, and  Beijing, CHN

Member of ANTEA Alliance with affiliated offices worldwide

EX-24

Exhibit 24

Consent of Independent Registered Public Accounting Firm

We hereby consent to the incorporation by reference in the Form 8-K/A of Hawker Energy, Inc. of our report dated June 16, 2015 with respect to the balance sheet as of December 31, 2013 and the related statements of operations, cash flows, stockholders’ deficit and schedule of TEG Oil & Gas U.S.A., Inc. for the year ended December 31, 2013 included in its Current Report on Form 8-K/A, filed with the Securities and Exchange Commission.

/s/ L.L. Bradford & Company, LLC

Las Vegas, NV

June 16, 2015

EX-25

Exhibit 25

Consent of Independent Petroleum Engineer

We hereby consent to the references to our firm in this Form 8-K/A of Hawker Energy, Inc. to our estimates of reserves and value of reserves and our report on reserves as of December 31, 2014 for the Tapia Canyon and Eureka oil fields dated February 23, 2015, prepared for Hawker Energy, Inc.  We also consent to the inclusion of our report as of December 31, 2014 as an exhibit included in this Form 8-K/A.

/s/ Reed W. Ferrill & Associates, Inc.

Golden, Colorado

June 17, 2015

EX-99.1

Exhibit 99.1

TEG Oil & Gas U.S.A., Inc.

INDEX TO AUDITED FINANCIAL STATEMENTS

Reports of Independent Registered Public Accounting Firms	2
Statements of financial condition as of December 31, 2014 and 2013	4
Statements of operations and changes in stockholder’s (deficit) for the years ended December 31, 2014 and 2013	5
Statements of cash flows for the years ended December 31, 2014 and 2013	7
Notes to financial statements	8

TEG Oil & Gas U.S.A., Inc.

Financial Statements

December 31, 2014 and 2013

Page 1 of 23

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors

TEG Oil and Gas U.S.A., Inc.

Redondo Beach, CA

We have audited the accompanying balance sheet of TEG Oil and Gas U.S.A., Inc. (the “Company”), as of December 31, 2014, and the related  statements of operations, changes in stockholders’ deficit, and cash flows for the year ended December 31, 2014. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We have conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States of America). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the  financial position of TEG Oil and Gas U.S.A., Inc. as of December 31, 2014, and the  results of its operations and its cash flows for the year ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.

The accompanying financial statements have been prepared assuming the Company will continue as a going concern. As discussed in Note 2 to the accompanying financial statements, the Company has suffered recurring losses from operations and has an accumulated deficit as of December 31, 2014, which raises substantial doubt about its ability to continue as a going concern. Management's plans in regard to this matter are described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Larkspur, CA

June 18, 2015

101 Larkspur Landing Circle, Suite 321, Larkspur, CA 94939

New York, NY   Washington DC San Francisco, CA   Mumbai, IND Athens, GRE Beijing, CHN

Member of ANTEA International with member offices worldwide

Page 2 of 23

Independent Auditor’s Report

Board of Directors and Stockholders’ of

Hawker Energy, Inc.

Report on the Financial Statements

We have audited the accompanying financial statements of TEG Oil & Gas U.S.A., Inc., which comprise the balance sheet as of December 31, 2013, and the related statements of income, changes in stockholders’ equity, and cash flows for the year then ended, and the related notes to the financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of TEG Oil & Gas U.S.A., Inc. as of December 31, 2013, and the results of its operations and its cash flows for the year then ended in accordance with accounting principles generally accepted in the United States of America.

Emphasis of Matter

The accompanying financial statements have been prepared assuming that the entity will continue as a going concern. As discussed in Note 2 to the financial statements, the entity has suffered recurring losses from operations and has a net capital deficiency that raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty. Our opinion is not modified with respect to this matter.

/s/ L.L. Bradford & Company, LLC

Las Vegas, Nevada

June 16, 2015

702-735-5030  ●  8880 West Sunset Road, Third Floor, Las Vegas NV 89148  ●  www.llbradford.com

Page 3 of 23

TEG Oil & Gas U.S.A., Inc.

Balance Sheets

December 31, 2014 and 2013

(in thousands, except share amounts)	2014			2013
Current assets
Cash and cash equivalents	$	3		$	24
Accounts receivable		-			308
Prepaid expenses		6			26
Total current assets		9			358
Fixed assets
Machinery and equipment, net of accumulated depreciation of $245 and $223 respectively		140			162
Other non-current assets
Proved oil and gas properties using full-cost accounting, net of accumulated depletion of $3,481 and $3,259 respectively		13,059			13,234
Total non-current assets		13,199			13,396
Total assets	$	13,208		$	13,754
Current liabilities
Accounts payable and accrued expenses	$	783		$	497
Debt		5,491			4,654
Total current liabilities		6,274			5,151
Long-term liabilities
Amounts due to parent		9,190			9,793
Employee benefit obligation		969			802
Asset retirement obligation		1,741			1,706
Total long-term liabilities		11,900			12,301
Total liabilities		18,174			17,452
Stockholders’ (deficit)
Common stock 1 share authorized at no par and 1 shares issued and outstanding as of December 31, 2014 and 2013 respectively		1			1
Accumulated deficit		(4,967	)		(3,699	)
Total stockholders’ deficit		(4,966	)		(3,698	)
Total liabilities and stockholders' deficit	$	13,208		$	13,754

The accompanying notes are an integral part of these financial statements

Page 4 of 23

TEG Oil & Gas U.S.A., Inc.

Statements of Operations

for the years ended December 31, 2014 and 2013

	2014			2013
(in thousands)
Oil revenues	$	2,348		$	4,511
Operating expenses:
Direct operating costs		1,691			2,890
Depletion, depreciation and amortization		279			363
Professional fees		10			43
General and administrative expense		978			1,296
Total expenses		2,958			4,592
Net operating (loss)		(610	)		(81	)
Other expense:
Interest expense		(658	)		(181	)
Total other expense		(658	)		(181	)
Net (loss)	$	(1,268	)	$	(262	)

The accompanying notes are an integral part of these financial statements

Page 5 of 23

TEG Oil & Gas U.S.A., Inc.

Statements of Changes in Stockholders’ (Deficit)

for the years ended December 31, 2014 and 2013

	Common Stock				Accumulated			Total Stock- holders’
(in thousands, except share amounts)	Shares		Amount		Deficit			Deficit
Balance at December 31, 2012		1	$	1	$	(3,436	)	$	(3,435	)
Net loss						(262	)		(262	)
Balance at December 31, 2013		1		1		(3,699	)		(3,698	)
Net loss						(1,268	)		(1,268	)
Balance at December 31, 2014		1	$	1	$	(4,967	)	$	(4,966	)

The accompanying notes are an integral part of these financial statements

Page 6 of 23

TEG Oil & Gas U.S.A., Inc.

Statements of cash flows

for the years ended December 31, 2014 and 2013

(in thousands)	2014			2013
Cash flows from operating activities
Net loss	$	(1,268	)	$	(262	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		244			326
Accretion of asset retirement obligation		35			37
Changes in operating assets and liabilities:
Accounts receivable		308			265
Prepaid expenses		20			55
Accounts payable and accrued expenses		286			281
Employee benefit obligation		167			92
Interest payable		18			5
Net cash (used in) provided by operating activities		(190	)		799
Cash flows from investing activities
Purchase of fixed and other assets		(47	)		(141	)
Net cash (used in) investing activities		(47	)		(141	)
Cash flows from financing activities
Interest and fees capitalized on bank loan		245			-
Repayment of bank loan		(913	)		(796	)
Loan proceeds from Hawker and subsidiary		1,487			-
Repayment of parent company advances		(603	)		-
Net cash provided by (used in) financing activities		216			(796	)
Net decrease in cash		(21	)		(138	)
Cash, beginning		24			162
Cash, ending	$	3		$	24
Supplemental disclosures:
Interest paid	$	306		$	176
Income taxes paid	$	-		$	-
Capitalized asset retirement costs	$	-		$	50

The accompanying notes are an integral part of these financial statements

Page 7 of 23

TEG Oil & Gas U.S.A., Inc.

Notes

(in thousands, except share amounts or as otherwise indicated)

Note 1 - Summary of Accounting Policies

Nature of Business

As of December 31, 2014 and 2013, we are a wholly-owned subsidiary of Sefton Resources, Inc. a British Virgin Islands corporation (“Sefton”). Effective February 1, 2015, we were acquired by Hawker Energy, Inc., a Nevada corporation. We currently operate as an independent energy company engaged in the business of producing and selling crude oil. The crude oil is obtained primarily by the acquisition and subsequent exploration and development of mineral leases.  Development and exploration may include drilling new exploratory or development wells on these leases. These operations are conducted primarily in the Tapia and Eureka Oilfields which consist of four oil and gas producing leases encompassing the Tapia Canyon field (“Tapia”) and one development lease west of the Tapia Canyon field (“Eureka”), and the accompanying production equipment, all located in California.  Tapia covers an area of approximately 262 acres located about 40 miles north of the Los Angeles, California metropolitan area. Eureka covers an area of approximately 1,510 acres located about 25 miles west of Tapia in Ventura County, California.  Virtually all present production comes from Tapia.

Basis of Presentation

Our financial statements have been prepared in accordance with accounting principles generally accepted in the United States. Our operations are considered to fall within a single industry segment, which are the acquisition, development, exploitation and production of crude oil properties in the United States.

 Use of Estimates in the Preparation of Financial Statements

The preparation of consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and 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.  Significant estimates included in the consolidated financial statements are: (1) oil and gas revenues and reserves; (2) depreciation, depletion and amortization; (3) valuation allowances associated with income taxes; (4) accrued assets and liabilities; (5) stock-based compensation; (6) asset retirement obligations; and (7) valuation of derivative instruments.  Although management believes these estimates are reasonable, changes in facts and circumstances or discovery of new information may result in revised estimates.  Actual results could differ from those estimates.

Cash and Cash Equivalents

We consider all highly liquid investment instruments purchased with original maturities of three months or less to be cash equivalents for purposes of the consolidated statements of cash flows and other statements. We maintain cash on deposit, which, at times, exceeds federally insured limits. We have not experienced any losses on such accounts and believe we are not exposed to any significant credit risk on cash and equivalents.

Page 8 of 23

Trade Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear any interest.  We regularly review receivables to insure that the amounts will be collected and establish or adjust an allowance for uncollectible amounts as necessary using the specific identification method.  Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. The allowance for doubtful accounts was $nil and $nil at December 31, 2014 and 2013, respectively.

Income Taxes

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized when items of income and expense are recognized in the financial statements in different periods than when recognized in the applicable tax return. Deferred tax assets arise when expenses are recognized in the financial statements before the tax returns or when income items are recognized in the tax return prior to the financial statements. Deferred tax assets also arise when operating losses or tax credits are available to offset tax payments due in future years. Deferred tax liabilities arise when income items are recognized in the financial statements before the tax returns or when expenses are recognized in the tax return prior to the financial statements. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date when the change in the tax rate was enacted.

We routinely assess the reliability of our deferred tax assets.  If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset is reduced by a valuation allowance.  In addition we routinely assess uncertain tax positions, and accrue for tax positions that are not more-likely-than-not to be sustained upon examination by taxing authorities.

Uncertain Tax Positions

We follow guidance in Topic 740 of the Codification for its accounting for uncertain tax positions. Topic 740 prescribes guidance for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. To recognize a tax position, we determine whether it is more-likely-than-not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based solely on the technical merits of the position. A tax position that meets the more-likely-than-not threshold is measured to determine the amount of benefit to be recognized in the financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement.

We have no liability for unrecognized tax benefits recorded as of December 31, 2014 and 2013. Accordingly, there is no amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate and there is no amount of interest or penalties currently recognized in the statement of operations or statement of financial position as of December 31, 2014. In addition, we do not believe that there are any positions for which it is reasonably possible that the total amounts of unrecognized tax benefits will significantly increase or decrease within the next twelve months. We recognize related interest and penalties as a component of income tax expense.

Page 9 of 23

Tax years open for audit by federal tax authorities as of December 31, 2014 are the years ended December 31, 2011, 2012, 2013 and 2014. Tax years ending prior to 2011 are open for audit to the extent that net operating losses generated in those years are being carried forward or utilized in an open year.

Fair Value Measurements

Accounting guidance establishes a single authoritative definition of fair value based upon the assumptions market participants would use when pricing an asset or liability and creates a fair value hierarchy that prioritizes the information used to develop those assumptions.  Additional disclosures are required, including disclosures of fair value measurements by level within the fair value hierarchy.  We incorporate a credit risk assumption into the measurement of certain assets and liabilities. The fair value hierarchy is defined into the following three categories:

Level 1: Quoted market prices in active markets for identical assets or liabilities

Level 2: Observable market-based inputs or inputs that are corroborated by market data

Level 3: Unobservable inputs that are not corroborated by market data

Revenue Recognition

Oil and gas revenues are recognized net of royalties when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collection of the revenue is probable. Cash received relating to future revenues is deferred and recognized when all revenue recognition criteria are met.

Comprehensive Loss

Comprehensive income or loss is defined as the change in equity during a reporting period resulting from transactions and other events and circumstances from non-owner sources, and is comprised of net income (loss) and other comprehensive income.  The Company has no elements of Comprehensive income or loss during the years ended December 31, 2014 and 2013.

Property and Equipment

Property and equipment are recorded at cost. Depreciation is on a straight-line method using the estimated lives of the assets (3-15 years).  Expenditures for maintenance and repairs are charged to expense.

Debt Issue Costs

Debt issuance costs incurred are capitalized and subsequently amortized over the term of the related debt on the effective interest rate method of amortization over the estimated life of the debt.

Page 10 of 23

Oil & Gas Properties

We follow the full cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized. We also capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not include costs related to production, general corporate overhead or similar activities.

Proved properties are amortized using the units of production method (UOP). Currently we only have operations in the United States of America. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the cost of these reserves. The amortization base in the UOP calculation includes the sum of proved property, net of accumulated depreciation, depletion and amortization (DD&A), estimated future development costs (future costs to access and develop proved reserves) and asset retirement costs, less related salvage value.

The cost of unproved properties are excluded from the amortization calculation until it is determined whether or not proved reserves can be assigned to such properties or until development projects are placed into service. Geological and geophysical costs not associated with specific properties are recorded as proved property immediately. Unproved properties are reviewed for impairment quarterly.

Under the full-cost-method of accounting, the net book value of oil and gas properties, less deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is (a) the present value of future net revenues computed by applying current prices of oil & gas reserves (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil & gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount factor of 10 percent and assuming continuation of existing economic conditions plus (b) the cost of properties not being amortized plus (c) the lower of cost or estimated fair value of unproven properties included in the costs being amortized less (d) income tax effects related to differences between book and tax basis of properties. Future cash outflows associated with settling accrued retirement obligations are excluded from the calculation. Estimated future cash flows are calculated using end-of-period costs and an un-weighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months held flat for the life of the production, except where prices are defined by contractual arrangements.

Any excess of the net book value of proved oil and gas properties, less related deferred income taxes, over the ceiling is charged to expense and reflected as additional DD&A in the statement of operations. The ceiling calculation is performed annually. During the years ended December 31, 2014 and 2013 there were no impairments resulting from the annual ceiling tests.

Proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion (greater than 25%) of our reserve quantities are sold, in which case a gain or loss is recognized in income.

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Long-Lived Assets

Long-lived assets include equipment and intangible assets other than those with indefinite lives.  Indicators of impairment include significant underperformance relative to historical or projected future operating results, significant changes in our use of the assets or in our business strategy, loss of or changes in customer relationships and significant negative industry or economic trends. Impairment of long-lived assets is recorded when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets' carrying value.  The carrying value of the assets is then reduced to their estimated fair value that is usually measured based on an estimate of future discounted cash flows.

Asset Retirement Obligations

The asset retirement obligation relates to the plug and abandonment costs when our wells are no longer useful. We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. We determine the value of the liability by obtaining quotes for this service and estimate the increase we will face in the future. We then discount the future value based on an intrinsic interest rate that is appropriate for us. If costs rise more than what we have expected there could be additional charges in the future, however, we monitor the costs of the abandoned wells and we will adjust this liability if necessary. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

Major Purchasers

For the years ended December 31, 2014, and 2013 we sold our produced crude oil to Plains Marketing, L.P., on a month-to-month basis. 

Reclassifications

Certain reclassifications have been made to prior periods to conform to current presentations.

Recent Accounting Pronouncements

We continually assess any new accounting pronouncements to determine their applicability to its operations and financial reporting. Where it is determined that a new accounting pronouncement affects our financial reporting, we undertake a study to determine the consequence of the change to our financial statements and assure that there are proper controls in place to ascertain that our financial statements properly reflect the change.

ASU 2014-15

In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements - Going Concern (Subtopic 205-40). ASU 2014-15 provides guidance related to management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and to provide related footnote disclosure. ASU 2014-15 is effective for annual periods ending after December 15, 2016, and for interim and annual periods thereafter. Early application is permitted. The adoption of ASU 2014-15 did not have a material effect on our financial position, results of operations or cash flows. As a result of adopting ASU 2014-15, we have provided additional disclosure in our footnote 2 related to liquidity.

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ASU 2014-09

The FASB has issued ASU No. 2014-09, Revenue from Contracts with Customers. This ASU supersedes the revenue recognition requirements in Accounting Standards Codification 605 - Revenue Recognition and most industry-specific guidance throughout the Codification. The standard requires that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. This ASU is effective on January 1, 2017 and should be applied retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying the ASU recognized at the date of initial application. We have not yet determined the effect of the adoption of this standard and it is not expected to have a material impact on our financial position and results of operations.

ASU 2013-11

In July 2013, the FASB issued ASU No. 2013-11, “Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists.” ASU 2013-11 amends the guidance related to the presentation of unrecognized tax benefits and allows for the reduction of a deferred tax asset for a net operating loss (“NOL”) carryforward whenever the NOL or tax credit carryforward would be available to reduce the additional taxable income or tax due if the tax position is disallowed. ASU 2013-11 is effective for annual and interim periods for fiscal years beginning after December 15, 2013. The adoption of ASU 2013-11 in January 2014 did not have any effect on our financial position, results of operations or cash flows.

We have evaluated other recent accounting pronouncements and their adoption has not had or is not expected to have a material impact on our financial position or our financial statements.

Note 2 – Going Concern

Our financial statements are prepared based on a going concern, which contemplates the realization of assets and liquidation of liabilities in the normal course of business. As of December 31, 2014, we had  total current assets of $9, but a working capital deficit in the amount of $6,265. We incurred a net loss of $1,268 for the year ended December 31, 2014 and have an accumulated net loss of $4,967 since inception.   Thus, we have not yet established an ongoing source of revenues sufficient to cover our operating costs and allow us to continue as a going concern. Our ability to continue as a going concern is dependent on us obtaining adequate capital to fund operating losses until it becomes profitable. Historically, we have obtained working capital from our parent company and issuance of debt.  If we are unable to obtain adequate capital, we could be forced to suspend operations.

In order to continue as a going concern, we will need, among other things, additional capital resources. Management's plan is to obtain such resources for us by obtaining capital from significant shareholders sufficient to meet its minimal operating expenses and seeking equity and/or debt financing, or a sale of the Company. However, management cannot provide any assurances that the Company will be successful in accomplishing any of its plans.

Sefton’s management’s plan in this regard is to conclude our sale to Hawker Energy, Inc., (“Hawker”) (which closed February 3, 2015). Future success will be dependent on Hawkers’ ability to obtain the necessary capital sufficient to finance continuing Company operations for the next twelve months.

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Our ability to continue as a going concern is dependent upon its ability to successfully accomplish the plans described in the preceding paragraph and eventually secure other sources of financing and attain profitable operations. The accompanying financial statements do not include any adjustments that might be necessary if we are unable to continue as a going concern.

Note 4 – Property and Equipment

As of December 31, 2014 and 2013 our oil and gas pumping and support equipment consisted of the following:

	December 31, 2014			December 31, 2013
Oil and gas pumping and support equipment	$	385		$	385
Accumulated depreciation		(245	)		(223	)
Net	$	140		$	162

Depreciation expense was $22 and $28 for the years ended December 31, 2014 and 2013, respectively.

Note 5 – Oil and Gas Properties

We hold oil and gas leases in California. Oil and gas properties are stated at cost. We recognized depletion expense totalling $222 and $298 during the years ended December 31, 2014 and 2013, respectively. As of December 31, 2014 and 2013 oil and gas properties consisted of the following:

	December 31, 2014			December 31, 2013
Proved producing properties	$	16,540		$	16,493
Accumulated depletion		(3,481	)		(3,259	)
Net oil and gas properties	$	13,059		$	13,234

Costs being amortized at December 31, 2014 and 2013 are as follows:

	December 31, 2014			December 31, 2013
Proved leasehold costs:
Costs of wells and equipment	$	15,034		$	14,987
Capitalized asset retirement costs		1,506			1,506
Total oil and gas properties		16,540			16,493
Accumulated depreciation and depletion		(3,481	)		(3,259	)
Net capitalized costs	$	13,059		$	13,234

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Note 6 - Asset Retirement Obligation

Our asset retirement obligations relate to the abandonment of oil and gas wells. The amounts recognized are based on numerous estimates and assumptions, including future retirement costs, inflation rates and credit adjusted risk-free interest rates. The following shows the changes in asset retirement obligations:

Asset retirement obligations, December 31, 2012	$	1,619
Liabilities incurred during the period		-
Liabilities settled during the period		-
Revision to estimate		50
Accretion		37
Asset retirement obligations, December 31, 2013		1,706
Liabilities incurred during the period		-
Liabilities settled during the period		-
Revision to estimate		-
Accretion		35
Asset retirement obligations, December 31, 2014	$	1,741

There were no properties acquired or disposed in 2014 and 2013, therefore no changes in asset retirement obligations resulting from such activities.

Note 7 - Debt

Senior Secured Credit Facility

On October 21, 2008, we entered into an Amended and Restated Credit Agreement with Bank of the West (“BOTW”), which has since been amended a number of times.  The credit facility bears interest at a rate equal to the prime lending rate, plus 0.50% or LIBOR plus 2.25%, at our option. The Credit Agreement contains various covenants that include restrictions on additional debt, sale of collateralized assets, as the notes are secured by a mortgage on the Tapia and Eureka oil properties, and maintenance of current, interest coverage, debt-to-net-worth and debt service ratios. The credit facility is secured by all the assets of the Tapia and Eureka oil properties, and has been guaranteed by Sefton and TEG MidContinent, Inc. (“TEGMC”)(TEG, Sefton and TEGMC are collectively referred to as the “Borrowers”.  The outstanding amount is subject to a borrowing base limitation.  In 2011, the maturity date of the loan was extended to June 1, 2013, and a May 13, 2013 amended further extended the maturity date to January 1, 2014.

Beginning January 1, 2014, the Borrowers have been in default under the terms of the Credit Agreement, at which time the default rate of interest of prime rate plus 5.0% began. Beginning with a Forbearance Agreement dated April 30, 2014, BOTW agreed to forbear in exercising certain rights available to it under the Credit Agreement, in each case, subject to various terms and conditions. This forbearance agreement was subsequently amended on several occasions, extending the loan repayment date to December 29, 2014.

See also Note 14, Subsequent Events, including further amendments to the Forbearance Agreements.  The loan repayment date is now December 31, 2015.

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As of December 31, 2014 and 2013, our outstanding principal balance totaled $3,982 and $4,654, respectively.

Secured Subordinated Loan Payable, Short Term

Under the terms of a 2014 loan agreement, we agreed to pay Hawker’s subsidiary Tapia Holdings, LLC the principal sum of $1,500, or such lesser amount as may be outstanding from time to time, with interest on the unpaid principal amount at the rate of 3.0% per annum.  Tapia Holdings advanced to us $1,509 through December 31, 2014 pursuant to this agreement. The loan was assigned to Tapia Holdings’ parent, Hawker, in January 2015, and the maximum principal amount was increased to $2,100.  The loan now matures on December 31, 2015, at which time all outstanding principal and accrued interest is due and payable in full.  The note is secured by all of our assets and was originally guaranteed on a limited recourse basis by Sefton. The note and security interest are subordinate to senior creditor BOTW, pursuant to an Amended and Restated Subordination and Inter-creditor Agreement (“Inter-creditor Agreement”) dated January 1, 2015, as amended, by and among us, Tapia Holdings, LLC, Hawker, Sefton, our affiliate TEG MidContinent, Inc., and BOTW.  See also Note 14, Subsequent Events.

Note 8 – Long-term related party liability

As of the years ended December 31, 2014 and 2013 we had advanced a total of $2,160 and $1,873, respectively to our related entities, TEG MidContinent, Inc. and TEG Transmission LLC. We also received advances totalling $11,350 and $11,666, respectively from our parent company, Sefton.  The net balance due to related parties at December 31, 2014 and 2013 totalled $9,190 and $9,793.

Subsequent to the balance sheet date, and in connection with our acquisition by Hawker Energy, Inc., the net amount of inter-company balances due to Sefton and its related entities has been contributed to equity.

Note 9 – Employee Retirement Obligation

In March 2013, we entered into employment contracts that include a deferred compensation component with key executives. The employment contract provides for certain retirement benefits, contingent on certain conditions. We accrue the present value of the estimated future benefit payments over the period from the date of the agreement to the retirement date. The assumed discount rate used to measure the postemployment benefit liability was 4.98% at December 31, 2014, and 5.75% at December 31, 2013.

We recognized expense of $167 in 2014 and $92 in 2013 related to these employment contracts.

The following outlines the retirement obligation in relation to these employees:

Retirement obligations, January 1, 2013	$	710
Liabilities incurred during the period		92
Retirement obligations, December 31, 2013		802
Liabilities incurred during the period		167
Retirement obligations, December 31, 2014	$	969

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Our retirement obligation is based on the individual’s ending monthly salary or fee arrangement at the date of retirement times a multiple for years of service.  This multiple ranges from one month of base salary or fee for two years of service or less, to two and a half times monthly salary or fee for ten or more years of service.  Two employees are covered by this arrangement at December 31, 2014, with their retirement dates under the agreement being 2020 and 2022.

Note 10 - Related party transactions

Since we are a wholly-owned subsidiary of Sefton, the financial statements include certain allocations from Sefton for certain general and administrative expenses.  Our management believes that the method used to allocate the costs and expenses is reasonable; however, such allocated amounts may or may not necessarily be indicative of what actual expenses would have been incurred had we operated independently of Sefton. Additionally, in the normal course of business we utilize the services of stockholders of Sefton, who perform work for us at normal business rates.

The following table summarizes the expenses allocated to us by Sefton for the years ended December 31, 2014, and 2013:

	Year Ended December 31
	2014		2013
General and Administrative	$	516	$	901

Note 11 - Commitments and Contingencies

Rent expense for the years ended December 31, 2014 and 2013 was approximately $19 and $19, respectively. Future non-cancellable minimum lease payments are approximately $1,657 for 2015.

We, as a lessee and operator of oil and gas properties, are subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject to the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area.  As of December 31, 2014, we have no reserve for environmental remediation and are not aware of any environmental claims.

Note 12 - Income Taxes

Deferred income tax assets and liabilities are computed annually for differences between financial statement and tax bases of assets and liabilities that will result in taxable or deductible amounts in the future based on enacted tax laws and rates applicable to the periods in which the differences are expected to affect taxable income. Valuation allowances are established when necessary to reduce deferred tax assets to the amount expected to be realized. Income tax expense is the tax payable or refundable for the period plus or minus the change during the period in deferred tax assets and liabilities.

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A reconciliation of the provision (benefit) for income taxes computed at the statutory rate is as follows:

	December 31, 2014			December 31, 2013
Federal statutory rate		34.00	%		34.00	%
State statutory rate, net of federal effects		5.97	%		5.97	%
Other adjustments		0.31	%		0.81	%
Valuation allowance		(40.28	)%		(40.78	)%
		-			-

The significant components of deferred tax assets and liabilities are as follows:

	December 31, 2014			December 31, 2013
Non-current deferred tax asset (liability):
Oil and gas costs and long-lived assets	$	(4,390	)	$	(4,380	)
Net operating loss carry-forward		6,737			6,282
Other deferred assets and liabilities, net		1,080			999
Valuation allowance		(3,427	)		(2,901	)
Net deferred tax asset (liability)	$	-		$	-

The net change in the valuation allowance for the year ended December 31, 2014 was a $526 increase.

We have a net operating loss carryover of $16,905 available to offset future income for income tax reporting purposes, which will expire in various years through 2033, if not previously utilized. However, our ability to use the carryover net operating loss may be substantially limited or eliminated pursuant to Internal Revenue Code Section 382.

We adopted the guidance the provisions of ASC 740-10-50, “Accounting for Uncertainty in Income Taxes”. We had no material unrecognized income tax assets or liabilities for the years ended December 31, 2014 and 2013.

Our policy regarding income tax interest and penalties is to expense those items as general and administrative expense but to identify them for tax purposes. During the years ended December 31, 2014 and 2013, there was no income tax or related interest and penalty items in the income statement, or liabilities on the balance sheet. We file income tax returns in the U.S. federal jurisdiction and various state jurisdictions. We are no longer subject to U.S. federal income tax examinations by tax authorities for periods prior to years prior to January 31, 2010 or state income tax examination by tax authorities for periods prior to years prior to January 1, 2009. We are not currently involved in any income tax examinations.

Subsequent to the balance sheet date, the Company incurred a change of control as defined by the Internal Revenue Code. Accordingly, the rules will limit the utilization of the Company’s net operating losses. The limitation is determined by multiplying the value of the stock immediately before the ownership change by the applicable long-term exempt rate. Any unused annual limitation may be carried over to later years. The amount of the limitation may under certain circumstances be increased by the built-in gains in assets held by the Company at the time of the change that are recognized in the five-year period after the change.

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 Note 13 - Fair Value Measurements

ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. We classify fair value balances based on the observability of those inputs. As required by ASC 820, a financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

We had no financial assets and liabilities that were accounted for at fair value as of December 31, 2014 and 2013. Thus, there were no transfers between fair value hierarchy levels for the years ended December 31, 2014 and 2013.

The carrying amounts reported in the balance sheets for cash, accounts receivable, loans payable, and accounts payable and accrued expenses, approximate their fair market value based on the short-term maturity of these instruments. We have no assets and liabilities that are measured and recognized at fair value on a recurring basis as of December 31, 2014 and 2013.

Note 14 - Subsequent Events

On January 12, 2015, Sefton entered into a Share Purchase Agreement (“Share Purchase Agreement”) with Hawker pursuant to which Sefton agreed to sell us, and Hawker agreed to buy, 100 percent of all of our issued and outstanding shares of capital stock in exchange for consideration comprised of $1.00 in cash, 3,000,000 shares of Hawker common stock and a five-year warrant to purchase up to an additional 5,000,000 shares of Hawker common stock at an exercise price of $0.25 per share.   The transaction closed on February 3, 2015, effective February 1, 2015.

On January 1, 2015, in anticipation of Hawker’s acquisition of TEG, TEG entered into a Fifth Amendment to Forbearance Agreement (“Fifth Amendment”) among Sefton, TEG, TEGMC, Hawker and BOTW. Under or in connection with the Fifth Amendment, (i) Hawker agreed to lend TEG a further amount of not less than $350, (ii) Tapia Holdings, LLC (“Tapia Holdings”), a subsidiary of Hawker, assigned to Hawker all of Tapia Holdings’ right, title and interest in outstanding loans made by Tapia Holdings to TEG evidenced by a Subordinated Note due December 29, 2014 in the original principal amount of $1,500, (iii) Hawker agreed not to contest or otherwise oppose an order appointing a receiver for the assets of TEG at the end of the period in which BOTW has agreed to forbear in exercising its rights under the Credit Agreement (the “Forbearance Period”), (iv) Tapia Holdings assigned to Hawker all of Tapia Holdings’ right to acquire 100% of the stock of TEG from Sefton, (v) effective as of January 1, 2015, the interest rate accruing on the principal of the Loan was increased to 9% with a monthly pay rate of 5% and the remaining 4% of unpaid interest to be accrued and compounded monthly until termination of the Forbearance Period and full payment of the Loan, and the default rate was increased to 14%, (vi) Borrowers agreed that the proceeds from any sale, assignment, licensing or other transfer of real or personal property rights that serve as collateral for the Loan will be remitted directly to BOTW, and (vii) Borrowers agreed to pay at least $15 per month of outstanding property taxes, commencing with the first month in which the California Midway-Sunset First Purchase Price as published by the U.S. Energy Information Administration is greater than $60 per barrel. As and in consideration of the foregoing, under the Fifth Amendment, BOTW agreed to extend the Forbearance Period to December 31, 2015.

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As a result of Hawker’s acquisition of TEG, TEG is no longer affiliated with Sefton or TEGMC and, accordingly, Sefton and TEGMC requested that BOTW release them from any further liability under the Credit Agreement as Borrowers. BOTW, Borrowers and Hawker subsequently discussed the terms on which BOTW would be willing to so release Sefton and TEGMC. On March 18, 2015, we entered into a Sixth Amendment to Forbearance Agreement (“Sixth Amendment”) among Sefton, TEG, TEGMC, Hawker and BOTW. Under the Sixth Amendment, BOTW released Sefton and TEGMC from all of their respective obligations under the Credit Agreement (other than any surviving obligations in respect of indemnification) and removed Sefton and TEGMC as Borrowers under the Credit Agreement. As and in consideration of that release, BOTW was (i) paid $400,000 by Sefton, which was applied against the amount outstanding under the Loan, (ii) delivered a Collateral Assignment of Note, executed by Sefton in favor of BOTW and acknowledged and agreed to by Hawker (“Collateral Assignment”), collaterally assigning to BOTW, to secure all obligations of Borrowers under the Credit Agreement, a Promissory Note, dated March 18, 2015 in the principal amount of $400,000, issued by Hawker in favor of Sefton (the “Hawker Note”), and (iii) delivered the original Hawker Note. In addition, under the terms of the Sixth Amendment, Sefton agreed to return to Hawker for cancellation (a) its Warrant to purchase up to an additional 5,000,000 shares of Hawker common stock for $0.25 per share (which was issued as part of Hawker’s acquisition of TEG), and (b) 1,500,000 shares of Hawker common stock.

Also on March 18, 2015, in connection with transactions contemplated by the Sixth Amendment, Hawker issued the Hawker Note. The Hawker Note bears simple interest at the rate of 6% per annum and is due on the earlier to occur of (i) March 18, 2018, or (ii) expiration of certain of BOTW’s covenants to forbear in exercising its rights under the Credit Agreement. Upon payment in full of the Loan obligations to BOTW, the Hawker Note will be returned to Hawker for cancellation.

On June 10, 2015, TEG sold an easement underlying a third-party owned cell tower on its Tapia property, and assigned the associated rental contract.  Gross proceeds were $175,000.  After deducting property tax payments and prorations, net proceeds of $157,792 were used to repay principal owed to BOTW.

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Note 15 - Supplemental Oil and gas Reserve Information (Unaudited)

Results of Operations from Oil and Gas Producing Activities

The following table shows the results of operations from the Company’s oil and gas producing activities.  Results of operations from these activities are determined using historical revenues, production costs and depreciation and depletion. The results of operations from the Company’s oil and gas producing activities below exclude non-oil and gas revenues, general and administrative expenses, interest income and interest expense. Income tax expense was determined by applying the statutory rates to pre-tax operating results.

	Year Ended December 31, 2014			Year Ended December 31, 2013
Production revenues	$	2,348		$	4,511
Production costs		(1,691	)		(2,890	)
Depletion and depreciation		(279	)		(363	)
Income tax		(164	)		(453	)
Results of operations for producing activities	$	214		$	805

 Capitalized Costs

The following table summarizes the Company’s capitalized costs of oil and gas properties.

	December 31, 2014			December 31, 2013
Unevaluated properties not subject to amortization	$	-		$	-
Properties subject to amortization		16,540			16,493
Capitalized costs		16,540			16,493
Accumulated depletion		(3,481	)		(3,259	)
Net capitalized costs	$	13,059		$	13,234

Cost Incurred in Property Acquisition, Exploration and Development Activities

	Year Ended December 31, 2014		Year Ended December 31, 2013
Acquisition of properties	$	-	$	-
Exploration costs	$	-	$	-
Development costs	$	47	$	127

  

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Estimated Quantities of Proved Reserves

Our ownership interests in estimated quantities of proved oil and gas reserves and changes in net proved reserves all of which are located in the United States are summarized below.  Proved reserves are estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those that are expected to be recovered through existing wells with existing equipment and operating methods. Reserves are stated in barrels of oil equivalent. Geological and engineering estimates by Reed W. Ferrill & Associates, of proved oil and gas reserves at one point in time are highly interpretive, inherently imprecise and subject to ongoing revisions that may be substantial in amount. Although every reasonable effort is made to ensure that the reserve estimates are accurate, by their nature reserve estimates are generally less precise than other estimates presented in connection with financial statement disclosures.

	Year Ended			Year Ended
	December 31,			December 31,
	2014			2013
Proved reserves (MBOE):
Beginning	$	3,563		$	3,511
Revisions of previous estimates		(191	)		99
Production		(27	)		(47	)
Ending	$	3,345		$	3,563

Proved developed reserves for December 31, 2014 consisted of 100% oil and totalled 1,270 MBOEs. Proved developed reserves for December 31, 2013 consisted of 100% oil and totalled 1,469 MBOEs. Proved undeveloped reserves for December 31, 2014 were 2,075 MBOEs. Proved undeveloped reserves at December 31, 2013 were 2,094 MBOEs.  “MBOE” is thousands of barrels of oil equivalent.

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows from our proved reserves for the periods presented in the financial statements is summarized below.

	December 31,			December 31,
	2014			2013
Future production revenue	$	308,651		$	351,575
Future production costs		(83,771	)		(105,689	)
Future development costs		(14,349	)		(15,320	)
Future cash flows before income tax		210,531			230,566
Future income taxes		(29,447	)		(35,019	)
Future net cash flows		181,085			198,571
10% annual discount for estimating of future cash flows		(96,940	)		(95,556	)
Standardized measure of discounted net cash flows	$	84,145		$	103,015

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Changes in Standardized Measure of Discounted Future Net Cash Flows 

The following table sets forth the changes in the standardized measure of discounted future net cash flows for the year ended December 31, 2014 and 2013:

	December 31,		December 31,
	2014		2013
Beginning of period	$	103,015	$	107,429
Revenues less production and other costs		(622)		(1,649)
Changes in price, net of production costs		(1,763)		(964)
Revisions of quantity estimates		(172)		156
Extensions and discoveries and other adjustments		-		-
Net changes in future development costs		(971)		(758)
Sale of reserves in place		(2,348)		(4,630)
Previously estimated development costs incurred		(47)		(77)
Accretion of discount		(35)		(37)
Net change in income taxes		(5,572)		(1,500)
Timing differences and other		(7,342)		5,045
End of period	$	84,145	$	103,015

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EX-99.2

Exhibit 99.2

Introduction to the unaudited pro forma

condensed consolidated financial statements of Hawker Energy, Inc.

The unaudited pro forma condensed consolidated financial statements present the impact on Hawker Energy, Inc. results of operations attributable to the acquisition of TEG on February 3, 2015, with an effective date of February 1, 2015 (the “TEG Acquisition”).

The purchase price was $1 plus the issuance of 3,000,000 shares of our common stock and a five-year warrant (“Warrant”) to purchase up to an additional 5,000,000 shares of our common stock for $0.25 per share.  In addition, between April 2014 and January 2015, Hawker and its subsidiary Tapia Holdings, LLC made advances pursuant to a secured subordinated loan agreement to TEG totaling approximately $1.6 million, including accrued interest receivable.  This amount constitutes additional consideration for the TEG Acquisition, as this note receivable was not settled prior to the closing of the TEG Acquisition.  As a result of this transaction, TEG became a wholly-owned subsidiary of Hawker.

TEG is an energy company focused on exploitation and production of crude oil in Southern California.   TEG’s assets comprise four oil and gas leases encompassing the Tapia Canyon field (the “Tapia Assets”) and one lease west of the Tapia Canyon field (the “Eureka Assets”), and the accompanying production equipment.  The Tapia Assets, located 40 miles north of Los Angeles, California, consist of four oil leases covering 262 gross acres.  The Eureka Assets, located 25 miles west of the Tapia Canyon oil field in Ventura County, California, cover an area of approximately 1,510 gross acres.

The unaudited pro forma condensed consolidated statements of operations for the year ended August 31, 2014 and six months ended February 28, 2015 are based on the historical financial statements of Hawker and TEG.  The unaudited pro forma condensed consolidated statements of operations have been prepared as if the TEG Acquisition had been closed on September 1, 2013.  As the balance sheet of TEG has been consolidated with Hawker on February 28, 2015, presentation of a pro forma condensed consolidated balance sheet is not necessary.  The unaudited pro forma condensed consolidated statements of operations have also been prepared based on certain pro forma adjustments, as described in the accompanying notes.

The following unaudited pro forma condensed consolidated statements of operations are qualified in their entirety by reference to, and should be read in conjunction with, such historical financial statements and related notes contained in: (1) Hawker’s audited historical financial statements set forth in its Annual Report on Form 10-K as of and for the year ended August 31, 2014, as amended, and unaudited historical financial statements set forth in its Quarterly Report on Form 10-Q as of and for the three months ended February 28, 2015, both as filed with the SEC; and (2) the TEG audited historical financial statements as of and for the years ended December 31, 2014 and 2013, as included in this Current Report on Form 8-K/A.

The pro forma adjustments reflected in the unaudited pro forma condensed consolidated statement of operations are based upon currently available information and certain assumptions and estimates; therefore the actual effects of these transactions will differ from the pro forma adjustments.  However, management considers the applied estimates and assumptions to provide a reasonable basis for the presentation of the significant effects of certain transactions that are expected to have a continuing impact on Hawker and TEG.  In addition, management considers the pro forma adjustments to be factually supportable and appropriately represent the expected impact of items that are directly attributable to the acquisition of TEG by Hawker.

The unaudited pro forma consolidated statement of operations is not necessarily indicative of the results that would have occurred if Hawkerhad acquired TEG on September 1, 2013 nor are they indicative of the future operating results of Hawker including TEG.

The pro forma financial statements do not include any adjustment for the March 2015 transaction described in Note 14 Subsequent Events to the audited financial statements of TEG included in this Form 8-K/A.  The March 2015 subsequent event will be accounted for by Hawker in the quarter ended May 31, 2015.  As part of that subsequent event:

· BOTW was paid $400,000 by Sefton, which was applied against the amount outstanding under TEG’s loan payable to BOTW.

· Hawker issued a note payable to Sefton in the amount of $400,000, which note bears simple interest at the rate of 6% per annum and is due on the earlier to occur of (a) March 18, 2018, or (b) expiration of certain of BOTW’s covenants to forbear in exercising its rights under the Credit Agreement. Upon TEG’s payment in full of the loan from BOTW, the note will be returned to Hawker for cancellation.

· Sefton agreed to return to Hawker for cancellation (a) its Warrant to purchase up to an additional 5,000,000 shares of Hawker common stock for $0.25 per share (which was issued as part of Hawker’s acquisition of TEG), and (b) 1,500,000 shares of Hawker common stock.

Historically, TEG’s fiscal year end was December 31st and Hawker’s fiscal year end is August 31st. For the six months ended February 28, 2015, and the twelve months ended August 31, 2014, the operating results for TEG included in the pro forma results of operations are for the six months ended December 31, 2014, and the twelve months ended June 30, 2014, respectively.

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Hawker Energy, inc.

Pro Forma Combined Consolidated Statement of Operations

Six Months Ended February 28, 2015

 (unaudited, in thousands except per unit)

	Hawker			TEG			TEG			TEG							Hawker
	Six Months			Twelve Months			Six Months			Six Months							Six Months
	Ended			Ended			Ended			Ended							Ended
	February 28,			December 31,			June 30,			December 31,							February 28,
	2015			2014			2014			2014			Pro Forma				2015
	Historical			Historical			Historical			Historical(1)			Adjustments				Pro Forma(2)
Oil revenue	$	101		$	2,348		$	1,374		$	974		$	(73	)	a	$	1,002
Expenses:
Direct operating expenses		106			1,691			821			870			(64	)	a		912
Depreciation, depletion and amortization		52			279			137			142			(27	)	a		134
														(33	)	b
Professional fees		612			10			9			1			(12	)	a		320
														(281	)	c
Bonuses		240			-			-			-			-				240
General and administrative		174			978			473			505			(3	)	a		676
Equity compensation expense		1,791			-			-			-			(670	)	d		1,121
Total operating expenses		2,975			2,958			1,440			1,518			(1,090	)			3,403
Net operating income (loss)		(2,874	)		(610	)		(66	)		(544	)		1,017				(2,401	)
Other expense (income):
Interest (income)		(18	)		-			-			-			18		e		-
Interest expense		230			658			190			468			(28	)	a		650
														(20	)	e
Change in fair value of conversion option		(27	)		-			-			-			-				(27	)
Total other expense		185			658			190			468			(30	)			623
Loss before provision for income tax		(3,059	)		(1,268	)		(256	)		(1,012	)		1,047				(3,024	)
Provision for income tax		-			-			-			-			-				-
Net income (loss)	$	(3,059	)	$	(1,268	)	$	(256	)	$	(1,012	)	$	1,047			$	(3,024	)
Net loss per common share - basic and diluted	$	(0.04	)														$	(0.04	)
Weighted average common shares outstanding -
basic and diluted		68,630,474												3,000,000		f		71,630,474

(1) Represents statement of operations for TEG for the twelve months ended December 31, 2014 less six months ended June 30, 2014.

(2) Represents Hawker historical statement of operations for the six months ended February 28, 2015 plus TEG historical statement of operations for the six months ended December 31, 2014.

See accompanying notes to the Pro Forma Financial Statements.

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Hawker Energy, inc.

Pro Forma Combined Consolidated Statement of Operations

Twelve Months Ended August 31, 2014

 (unaudited, in thousands except per unit)

	Hawker			TEG			TEG			TEG			TEG							Hawker
	Twelve Months			Twelve Months			Six Months			Six Months			Twelve Months							Twelve Months
	Ended			Ended			Ended			Ended			Ended							Ended
	August 31,			December 31,			June 30,			June 30,			June 30,							August 31,
	2014			2013			2013			2014			2014			Pro Forma				2014
	Historical			Historical			Historical			Historical			Historical(1)			Adjustments				Pro Forma(2)
Oil revenue	$	126		$	4,511		$	2,142		$	1,374		$	3,743		$	-			$	3,869
Expenses:
Direct operating expenses		63			2,890			1,726			821			1,985			-				2,048
Depreciation, depletion and amortization		42			363			166			137			334			(97	)	b		279
Professional fees		837			43			33			9			19			-				856
Bonuses		480			-			-			-			-			-				480
General and administrative		297			1,296			587			473			1,182			-				1,479
Equity compensation expense		69			-			-			-			-			-				69
Total operating expenses		1,788			4,592			2,512			1,440			3,520			(97	)			5,211
Net operating income (loss)		(1,662	)		(81	)		(370	)		(66	)		223			97				(1,342	)
Other expense (income):
Interest (income)		(8	)		-			-			-			-			8		e		-
Interest expense		95			181			91			190			280			(2	)	e		373
Change in fair value of conversion option		(20	)		-			-			-			-			-				(20	)
Total other expense		67			181			91			190			280			6				353
Loss before provision for income tax		(1,729	)		(262	)		(461	)		(256	)		(57	)		91				(1,695	)
Provision for income tax		-			-			-			-			-			-				-
Net loss	$	(1,729	)	$	(262	)	$	(461	)	$	(256	)	$	(57	)	$	91			$	(1,695	)
Net loss per common share - basic and diluted	$	(0.05	)																	$	(0.05	)
Weighted average common shares outstanding -
basic and diluted		31,950,963															3,000,000		f		34,950,963

(1) Represents statement of operations for TEG for the twelve months ended December 31, 2013 less six months ended June 30, 2013, plus six months ended June 30, 2014.

(2) Represents Hawker historical statement of operations for the twelve months ended August 31, 2014 plus TEG historical statement of operations for the twelve months ended June 30, 2014.

See accompanying notes to the Pro Forma Financial Statements.

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NOTES TO THE UNAUDITED PRO FORMA CONDENSED CONSOLIDATED

FINANCIAL STATEMENTS OF HAWKER ENERGY, INC.

1. Basis of presentation

The unaudited pro forma condensed consolidated financial statements are based upon the historical consolidated financial statements of Hawker and the historical financial statements of TEG.

Hawker has utilized TEG’s audited historical financial statements for the year ended December 31, 2014 and 2013, as well as the historical interim consolidated financial statements for the six months ended June 30, 2014 and 2013.

The unaudited pro forma condensed consolidated financial statements present the impact of the TEG Acquisition, which was described in the introduction to the unaudited pro forma condensed consolidated financial statement, on Hawker’s results of operations.  As TEG was already included in Hawker’s interim balance sheet as of February 28, 2015, there is no need to report a pro forma condensed consolidated balance sheet.

The acquisition of TEG is being treated as a business combination for GAAP purposes.

2. Pro forma adjustments

The following adjustments for Hawker have been prepared as if the transaction occurred on September 1, 2013, for the unaudited pro forma condensed consolidated statement of operations for the six months ended February 28, 2015 and the year ended August 31, 2014:

(a) To remove the results of operations of TEG for the month of February 2015 as the historical financials of TEG include six months of results.

(b) To reflect the impact of the TEG Acquisition on depreciation and depletion expense.  The purchase price allocation of the transaction is preliminary pending completion of valuation.

(c) To eliminate transaction costs included in the historical financials statements of Hawker that were directly related to the TEG Acquisition.

(d) To remove equity compensation expense resulting from the closing of the TEG Acquisition.

(e) To eliminate interest income and interest expense recorded by Hawker and TEG in the historical financial statements, respectively, on the loan made by Hawker and its subsidiary to TEG.

(f) To reflect the Hawker shares issued to Sefton to acquire TEG.

5

EX-99.3

Exhibit 99.3

3020 JOYCE WAY SUITE 100 GOLDEN, CO  80401 (303) 279-5686

APPRAISAL REPORT

as of

DECEMBER 31, 2014

for

CERTAIN PROPERTIES

owned by

HAWKER ENERGY, INC.

February 23, 2015

TABLE of CONTENTS

	Page
FOREWORD	1
Scope of Investigation	1
Authority	2
Source of Information	2
DEFINITION of RESERVES	3
ESTIMATION of RESERVES	8
VALUATION of RESERVES	9
SUMMARY and CONCLUSIONS	12
APPENDIX

i

3020 JOYCE WAY SUITE 100 GOLDEN, CO  80401 (303) 279-5686

February 23, 2015

APPRAISAL REPORT

as of

DECEMBER 31, 2014

for

CERTAIN PROPERTIES

owned by

HAWKER ENERGY, INC.

FOREWORD

Scope of Investigation:

This report presents an appraisal, as of December 31, 2014, of the extent and value of the proved developed producing oil reserves of certain properties that Hawker ENERGY, Inc. (Hawker) has represented that it owns. The reserves estimated in this report are located in Los Angeles County, California. The properties appraised are listed in detail in the appendix attached this report.

Estimates of reserves presented in this report have been prepared in compliance with the regulations promulgated by the United States Securities and Exchange Commission (SEC). These reserves definitions are discussed in detail in the Definition of Reserves section of this report.

Reserves estimated in this report are expressed as gross and net reserves. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2014. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Hawker after deduction of all interests owned by others.

This report also presents values for proved reserves using initial prices and costs specified by Hawker. Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). A detailed explanation of the future price and cost assumptions is included in the Valuation of Reserves section of this report.

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REED W. FERRILL & ASSOCIATES

Values for proved reserves in this report are expressed in terms of estimated future gross revenue, future net revenue, and present worth. Future gross revenue is that revenue which will accrue to the appraised interests from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting production and ad valorem taxes, operating expenses, and capital costs from the future gross revenue. Operating expenses include field operating expenses, transportation expenses, compression charges, and an allocation of overhead that directly relates to production activities. Present worth is defined as future net revenue discounted at a specified arbitrary discount rate compounded annually over the expected period of realization. In this report, present worth values using a discount rate of 10 percent are reported in detail and values using discount rates of 5, 9, 12, 15, 20, 25, 30, 60, 80, and 100 percent are reported as totals in the appendix bound with this report.

Estimates of oil reserves and future net revenue should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves and revenue estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Authority This report was prepared at the request of Mr. Darren Katic, CEO of Hawker Energy, Inc.

Source of Information

Data used in the preparation of this report were obtained from Hawker and from public sources. Additionally, this information includes data taken from the online records of the California Division of Oil, Gas & Geothermal Resources (DOGGR). In the preparation of this report we have relied, without independent verification, upon information furnished by Hawker with respect to property interests owned, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.

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REED W. FERRILL & ASSOCIATES

DEFINITION OF RESERVES

Petroleum reserves included in this report are classified by degree of proof as proved. Only proved reserves have been evaluated for this report. Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4-10(a) (1)—(32) of Regulation S—X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

Proved oil and gas reserves — Proved oil and gas reserves are 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. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i)   The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii)   In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or

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data and reliable technology establishes a lower contact with reasonable certainty.

(iii)   Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv)   Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v)   Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Probable reserves — Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i)    When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii)    Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

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(iii)   Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv)   See also guidelines in paragraphs (iv) and (vi) of the definition of possible reserves.

Possible reserves — Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i)     When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii)   Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii)   Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv)   The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v)   Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi)   Pursuant to paragraph (iii) of the proved oil and gas reserves definition, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

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Developed oil and gas reserves — Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i)   Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii)   Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped oil and gas reserves — Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i)   Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii)   Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

(iii)   Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4-10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

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The extent to which probable and possible reserves ultimately may be recategorized as proved reserves is dependent upon future drilling, testing, and well performance. The degree of risk to be applied in evaluating probable and possible reserves is influenced by economic and technological factors as well as the time element. No probable or possible reserves have been evaluated for this report.

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REED W. FERRILL & ASSOCIATES

ESTIMATION of RESERVES

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007)." The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production based on existing economic conditions.

In certain cases, when the previously named methods could not be used, reserves were estimated by analogy with similar wells or reservoirs for which more complete data were available.

Future oil and gas producing rates estimated for this report are based on production rates considering the most recent data available. The rates used for future production are estimated to be within the capacity of a well or reservoir to produce.

Data available from wells drilled on the appraised properties through December 31, 2014, were used to prepare the estimates shown herein. Estimated cumulative production through December 31, 2014, from the appraised properties was deducted from the estimated gross ultimate recovery to arrive at estimates of gross reserves.

The estimated proved reserves, as of December 31, 2014, of the properties appraised are summarized as follows, expressed in thousands of barrels (Mbbl):

	Gross Reserves		Net Reserves
	1000 Barrels		1000 Barrels
Proved Developed Producing		254.933		239.243
Proved Developed Non-Producing		1,038.961		1,031.038
Proved Undeveloped		2,122.863		2,074.514
Total Proved Reserves		3,416.757		3,344.796

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VALUATION of RESERVES

Revenue values in this report were estimated using the initial prices and costs provided by Hawker. Future prices were estimated using guidelines established by the SEC and the FASB. The following assumptions were used for estimating future prices and costs:

Oil Prices

Oil prices were furnished by Hawker for each field and are based on a price, calculated as the unweighted arithmetic average of the first­day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. An oil price of $92.34 per barrel for Tapia Field, and $90.22 per barrel for Eureka Canyon field were used for this evaluation. The prices were held constant thereafter and were not escalated for inflation.

Based on receipts received by Hawker, various oil, price differentials based on product quality and property location were determined by Hawker for each property. These differentials were included in above reference prices, respectively, to reflect the net wellhead prices anticipated to be received by each property.

The volume-weighted average prices attributable to estimated proved reserves over the lives of the properties were $92.278 per barrel of oil.

Operating Expenses and Capital Costs

Current operating expenses and future capital costs were based on historical data and estimates provided by Hawker. These expenses and costs were used in estimating future expenses and costs required to operate the properties. These expenses and costs were held constant for the producing lives of the properties. Future capital expenditures were not adjusted for inflation. Abandonment costs, assumed to equal the salvage value of equipment, were not adjusted for inflation.

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REED W. FERRILL & ASSOCIATES

The estimated future revenue to be derived from the production and sale of Hawker's proved developed producing net reserves, as of December 31, 2014, for the properties appraised is summarized as follows, expressed in thousands of dollars (M$):

	Proved Developed	Proved Developed	Proved	Total
	Producing	Non-Producing	Undeveloped	Proved
	$1000	$1000	$1000	$1000
Future Gross Revenue	22,031.393	95,206.094	191,414.141	308,651.656
Production Taxes	0.000	0.000	0.000	0.000
Ad Valorem Taxes	771.099	3,332.213	6,699.496	10,802.807
Operating Expenses	12,042.018	30,413.955	30,512.607	72,968.578
Capital Costs	0.000	1,138.750	13,210.000	14,348.750
Future Net Revenue *	9,218.273	60,321.172	140,992.031	210,531.453
Present Worth at 10 Percent *	5,982.215	26,635.225	51,527.434	84,144.883
	* Before Federal and State Income Taxes

In our opinion, the information relating to estimated proved reserves, estimated future net revenue from proved reserves, and present worth of estimated future net revenue from proved reserves of oil contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, 932-235-50-9, 932-235-50-30, and 932-235-50-31(a), (b), and (e) of the Accounting Standards Update 932-235-50, Extractive Industries — Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4-10(a) (1)—(32) of Regulation S—X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8)(i), (ii), and (v)—(x), and 1203(a) of Regulation S—K of the Securities and Exchange Commission; provided, however, that estimates of the proved developed and proved undeveloped reserves are not presented at the beginning of the year.

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

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The appendix attached to this report includes (1) projections of proved reserves and revenue summarized by reserves category and lease and (2) summaries of proved reserves and revenue by reserves category and lease, and charts of historic and forecasted future monthly producing rates.

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SUMMARY and CONCLUSIONS

Hawker has represented that it owns interests in certain properties located in California. The estimated net proved developed producing reserves of the properties appraised, as of December 31, 2014, expressed in thousands of barrels (Mbbl), are summarized as follows:

	Gross Reserves		Net Reserves
	1000 Barrels		1000 Barrels
Proved Developed Producing		254.933		239.243
Proved Developed Non-Producing		1,038.961		1,031.038
Proved Undeveloped		2,122.863		2,074.514
Total Proved Reserves		3,416.757		3,344.796

Estimated revenue, as of December 31, 2014, attributable to Hawker's interests in the properties appraised under the aforementioned assumptions concerning future prices and costs is summarized as follows, expressed in thousands of dollars (M$):

	Proved Developed	Proved Developed	Proved	Total
	Producing	Producing	Undeveloped	Proved
	$1000	$1000	$1000	$1000
Future Gross Revenue	22,031.393	95,206.094	191,414.141	308,651.656
Production Taxes	0.000	0.000	0.000	0.000
Ad Valorem Taxes	771.099	3,332.213	6,699.496	10,802.807
Operating Expenses	12,042.018	30,413.955	30,512.607	72,968.578
Capital Costs	0.000	1,138.750	13,210.000	14,348.750
Future Net Revenue *	9,218.273	60,321.172	140,992.031	210,531.453
Present Worth at 10 Percent *	5,982.215	26,635.225	51,527.434	84,144.883
	* Before Federal and State Income Taxes

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant's ability to recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2014, estimated oil and gas reserves. The reserves estimated in this report can be produced under current regulatory guidelines.

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Reed W. Ferrill and Associates, Inc. is an independent petroleum engineering consulting firm that has been providing petroleum consulting services since 1989. Reed W. Ferrill & Associates, Inc. and its principles and employees do not have any financial interest, including stock ownership, in Hawker. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of Hawker. Reed W. Ferrill & Associates, Inc. has used all assumptions, procedures, data, and methods that it considers necessary to prepare this report.

	For and On Behalf of Reed W. Ferrill & Associates, Inc
	Reed W. Ferrill, President
	Licensed Professional Engineer
	State of Colorado #16452