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): August 25, 2016

 

 

Lucas Energy, Inc.

(Exact name of registrant as specified in its charter)

 

 

Nevada	001-32508	20-2660243
(State or other jurisdiction of incorporation)	(Commission File Number)	(I.R.S. Employer Identification Number)

 

450 Gears Road, Suite 860
Houston, Texas 77067

(Address of principal executive offices, including zip code)

 

(713) 528-1881

(Registrant’s telephone number, including area code)

 

N/A

(Former name or former address, if changed since last report)

 

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 (see General Instruction A.2 below):

 

☐

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

 

☐

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

 

☐

Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.24d-2(b))

 

☐

Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.23e-4(c))

 

 

 

Explanatory Note

 

Lucas Energy, Inc. (“we”, “us”, “Lucas” and the “Company”) amends and supplements its Current Report on Form 8-K dated August 25, 2016 and filed with the Securities and Exchange Commission (“SEC”) on August 31, 2016 (the “Form 8-K”) as set forth in this Current Report on Form 8-K/A (the “Form 8-K/A”). The Form 8-K was filed to report, among other things, the closing (the “Closing”) of the transactions contemplated by the Asset Purchase Agreement dated December 30, 2015, as amended by the First Amendment to Asset Purchase Agreement dated April 20, 2016 and effective April 1, 2016 and the Second Amendment to Asset Purchase Agreement dated August 25, 2016 (the “Purchase Agreement”). The Purchase Agreement is described in greater detail in our Current Report on Form 8-K filed with the SEC on December 31, 2015, the First Amendment is described in greater detail in our Current Report on Form 8-K filed with the SEC on April 25, 2016 and the Second Amendment is described in greater detail in our Current Report on Form 8-K filed with the SEC on August 31, 2016.

 

In connection with the Closing, we acquired working interests in producing properties and undeveloped acreage in Texas and Oklahoma, including varied interests in two largely contiguous acreage blocks in the liquids-rich Mid-Continent region of the United States, and related wells, leases, records, equipment and agreements associated therewith as well as producing shale properties in Glasscock County, Texas (collectively, the “Assets” or the “Properties”), from the Sellers (the “Acquisition”).

 

In accordance with the requirements of Items 9.01(a)(4) and 9.01(b)(2) of Form 8-K, this Form 8-K/A is being filed within 71 calendar days after August 31, 2016 (the date that the initial Form 8-K was required to be filed), to amend and supplement the Form 8-K to include the financial statements and pro forma financial information required by Item 9.01.

 

Item 9.01.

Financial Statements and Exhibits.

 

(a)    Financial Statements of Businesses Acquired.

 

The following are historical audited statements of revenues and direct operating expenses of the Assets for the years ended March 31, 2016 and 2015 and historical unaudited statements of revenues and direct operating expenses of the Assets for the three months ended June 30, 2016 and 2015. Complete financial and operating information related to the Properties, including balance sheet and cash flow information are not presented because the Properties were maintained as an asset and not a separate company in the accounting records of a predecessors; therefore, the assets, liabilities, indirect operating costs and other expenses applicable to the operations were not allocated to the properties acquired. 

 

The full S-X Rule 3-05 financial statements and other financial information, including balance sheet and cash flow information, are not available and not presented because the Assets were maintained as an asset and not a separate company in the accounting records of the Sellers; therefore, the assets, liabilities, indirect operating costs and other expenses applicable to the operations were not allocated to the Assets being acquired. Separate, audited financial statements of the Assets have never been prepared and the Sellers have not maintained the distinct and separate accounts necessary to present the full financial statements of the Assets. It would be extremely costly and impractical to obtain complete financial statements in accordance with generally accepted accounting principles because separate financial statements were never historically required nor were such statements ever prepared with respect to the Assets. The preparation of such statements would involve many subjective assumptions, unreasonable effort and expense.

 

 

Report of Independent Registered Public Accounting Firm

 

To the Board of Directors 

Lucas Energy, Inc. 

Houston, TX

 

We have audited the accompanying statements of revenues and direct operating expenses of the oil and gas properties acquired from Segundo Resources, LLC (the seller representative for various sellers) for the years ended March 31, 2016 and 2015. These financial statements are the responsibility of Lucas Energy, Inc.’s management. Our responsibility is to express an opinion on the financial statements based on our audits.

 

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits 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 audits 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 includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

The accompanying financial statements were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission and are not intended to be a complete financial presentation of the properties described above.

 

In our opinion, the financial statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of the oil and gas properties acquired from Segundo Resources, LLC (the seller representative for various sellers) for the years ended March 31, 2016 and 2015, in conformity with accounting principles generally accepted in the United States.

 

/s/ GBH CPAs, PC

 

GBH CPAs, PC 

www.gbhcpas.com 

Houston, Texas 

July 19, 2016

 

  

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF 

OIL AND GAS PROPERTIES ACQUIRED FROM SEGUNDO RESOURCES, LLC

		For the Year Ended March 31,
		2016				2015
Revenue		$	4,997,426			$	11,002,075
Direct operating expenses			2,740,575				3,075,327
Revenues in excess of direct operating expenses		$	2,256,851			$	7,926,748

		For the Three Months June 30,
		2016				2015
		(Unaudited)				(Unaudited)
Revenue		$	889,635			$	1,651,307
Direct operating expenses			484,011				683,525
Revenues in excess of direct operating expenses		$	405,624			$	967,782

 

See accompanying notes to the statements of revenues and direct operating expenses.

 

 

NOTES TO THE STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF

OIL AND GAS PROPERTIES ACQUIRED FROM SEGUNDO RESOURCES, LLC

 

1. PROPERTIES ACQUIRED AND RELATED TRANSACTIONS

 

Acquisition of Assets from the Sellers

 

On August 25, 2016, Lucas Energy Inc. (the “Company”) purchased oil and gas properties (“Properties”) from Segundo Resources, LLC (the seller representative for various sellers) (“Sellers”). The Properties currently produce approximately 1,000 net barrels of oil equivalent per day, of which 53% are liquids, from 114 producing wells. The bulk of the production is from the Hunton formation holding approximately 43,000 gross acres (9,900 net acres) in central Oklahoma. Additionally, further, offset development drilling opportunities for at least 40 additional wells have been identified.

 

As consideration for the acquisition, we assumed $31,297,483 of commercial bank debt; issued 552,000 shares of newly designated Series B Preferred Stock to one of the Sellers and its affiliate, which are under common control with the Seller Representative, with a total liquidation value of $13,800,000; issued 13,009,664 shares of Common Stock to certain of the Sellers with a fair value of $21,465,946; and paid $4,975,000 in cash to certain Sellers. Notwithstanding the above, in the event there are any title or other material issues associated with the assets, the parties agreed to work in good faith to address such issues, and if such issues cannot be addressed, to adjust the purchase price, provided that no adjustment will be made unless such issues in aggregate total more than 5% of the aggregate purchase price, and provided further that if such issues in aggregate total more than 20% of the aggregate purchase price, we can terminate the Asset Purchase Agreement. We and the Sellers also agreed to a true-up for certain joint interest billings and authorization for expenditures at and/or after closing, and to effect a true-up in connection with any material agreements, if the rights thereto are not provided by the Sellers at closing.

 

The Series B Preferred Issued

 

The Company issued an aggregate of 552,000 shares of Series B Preferred Stock which Preferred Shares had a total value of $13,800,000 based on the $25 per Series B Preferred Stock share par value. The Preferred Shares were issued to the following parties and in the following amounts on behalf of and for the benefit of RAD2 Minerals:

 

	1.	RAD2 Minerals: 200,000 shares of Series B Preferred Stock; and
	2.	Tex Oak Energy, LLC (an Affiliate of RAD2 Minerals): 352,000 shares of Series B Preferred Stock.

 

The Series B Preferred Stock has a liquidation preference of $25 per share. The Series B Preferred Stock is convertible, at the option of the holder at any time following the original issuance date, into Common Stock at a rate of approximately 7.14:1 (issuable into an aggregate of 3,942,857 shares of Common Stock if fully converted), at the option of the holder thereof, or automatically as to 25% of the Series B Preferred Stock shares if our Common Stock trades above $6.125 per share for at least 20 consecutive trading days, and trades with at least 75,000 shares of average volume per day during such period; an additional 50% of the Series B Preferred Stock shares if our Common Stock trades above $7.00 per share for at least 20 consecutive trading days, and trades with at least 75,000 shares of average volume per day during such period; and as to the remaining Series B Preferred Stock shares, if our Common Stock trades above $7.875 per share for at least 20 consecutive trading days, and trades with at least 75,000 shares of average volume per day during such period. Each outstanding share of Series B Preferred Stock will be entitled to one vote per share on all stockholder matters. The Series B Preferred Stock is redeemable at any time by the Company upon the payment by the Company of the face amount of the Series B Preferred Stock ($25 per share) plus any and all accrued and unpaid dividends thereon.

 

The Company shall have the option, exercisable from time to time after the original issue date, to redeem all or any portion of the outstanding shares of Series B Preferred Stock by paying each applicable holder, an amount equal to the original issue price multiplied by the number of Series B Preferred shares held by each applicable holder plus the accrued dividends.

 

 

The 552,000 shares of Series B Preferred stock issued currently have the following features:

 

	·	a liquidation preference senior to all of the Company’s common stock;
	·	a dividend, payable annually, at an annual rate of six percent (6%) of the original issue price until such Series B Preferred is no longer outstanding either due to conversion, redemption or otherwise; and
	·	voting rights on all matters, with each share having 1 vote.

 

As the Series B Preferred Stock is convertible at any time following the original issuance date into Common Stock at a rate of approximately 7.14:1, the Company recognized a fair value measurement of $6,503,112 for the Series B Preferred Stock, which is based on the 552,000 of preferred shares to be issued times the conversion rate of approximately 7.14 times the price of Lucas’ common stock of $1.65 per share at the date of the Asset Purchase Agreement on December 30, 2015.

 

The Debt Assumed

 

Upon closing, the Company assumed $31,297,483 of debt from the Sellers which will be paid by a new loan from International Bank of Commerce, the current lender of the Sellers, to the Company. The Company also borrowed an additional $4,975,000 at closing in order to fulfill the cash consideration obligation due at closing. The new loan amount is for $40,000,000 and has a three-year term and bears an annual interest rate of NYPR + 2% with a floor of 5.5%. The payment schedule is the greater of 50% of the net monthly income or monthly principal and interest payments of $425,000 with any unpaid principal and accrued interest due at maturity. The Company is required to create a sinking fund with an initial deposit of $3,360,000 to be used for principal reductions. There is also a 1% commitment fee of $400,000 of which $200,000 was paid at closing with the remaining amount to be due six months after closing. Additionally 390,290 shares of common stock with a fair value of $643,979 were issued for an underwriting equity fee.

 

As collateral, International Bank of Commerce has a first lien on various working interest in the acquired properties. The loan is subject to a maximum loan-to-value ratio of 50% at all times with a semiannual test based on semiannual reserve reports using pricing parameters determined by International Bank of Commerce.

 

2. BACKGROUND AND BASIS OF PRESENTATION

 

The statements of revenues and direct operating expenses of the Properties for the years ended March 31, 2016 and 2015 and for the three months ended June 30, 2016 and 2015 have been prepared in conformity with accounting principles generally accepted in the United States and in accordance with the rules of the Securities and Exchange Commission (the “SEC”). Complete financial and operating information related to the properties, including balance sheet and cash flow information, are not presented because the properties were maintained as assets and not separate companies in the accounting records of predecessors; therefore, the assets, liabilities, indirect operating costs and other expenses applicable to the operations were not allocated to the properties acquired.

 

The accompanying financial statements include revenues from oil and gas production and direct operating expenses associated with the Properties. The accompanying statements of revenues and direct operating expenses varies from a complete set of statements of operations in accordance with accounting principles generally accepted in the United States of America in that it does not reflect certain indirect expenses that were incurred in connection with the ownership and operation of the Properties including, but not limited to, general and administrative expenses, interest expense and federal and state income tax expenses. These costs were not separately allocated to the Properties in the accounting records of the Sellers. In addition, these allocations, if made using historical general and administrative structures and tax burdens, would not produce allocations that would be indicative of the historical performance of the Properties had they been part of Lucas due to differing size, structure, operations and accounting policies. The accompanying statements also do not include the provisions for depreciation, depletion, amortization and accretion; as such amounts would not be indicative of the costs that will be incurred upon the allocation of the purchase price paid. Furthermore, no balance sheets have been presented because the acquired properties were not accounted for as a separate subsidiary or division of the Sellers and complete financial statements are not available, nor has information about the Properties, operating, investing and financing cash flows been provided for similar reasons. Accordingly, the historical statements of revenues and direct operating expenses of the Properties are presented in lieu of the full financial statements required under Article 8-04 of Securities and Exchange Commission (“SEC”) Regulation S-X. 

 

 

These statements of revenues and direct operating expenses are not indicative of the results of operations for the Properties on a go forward basis.

 

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

Use of Estimates — The statements of revenues and direct operating expenses were derived from the historical operating statements of the sellers. Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the statements of revenues and direct operating expenses. Actual results could be different from those estimates.

 

Revenue Recognition — Oil, natural gas and natural gas liquids revenues reflect the sales method of accounting. Under the sales method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers. Management believes there were no significant imbalances with other revenue interest owners attributable to the Properties during any of the periods presented in these statements.

 

Direct Operating Expenses — Direct operating expenses are recognized on an accrual basis and consist of direct expenses of operating the Properties. The direct operating expenses include lease operating expenses, severance and ad valorem taxes.

 

4. CONTINGENCIES

 

The Properties may be subject to potential claims and litigation in the normal course of operations. The Company does not believe that any liability resulting from any pending or threatened litigation will have a material adverse effect on the operations or financial results of the Properties.

 

Supplemental Information on Oil and Gas Producing Activities (Unaudited)

 

The following unaudited supplemental reserve information summarizes the net proved reserves of oil and gas and the standardized measure thereof for the years ended March 31, 2016 and 2015 and for the three months ended June 30, 2016 attributable to the Properties. All of the reserves are located in the United States. The reserve disclosures are based on reserve studies prepared in accordance with guidelines established by the SEC.

  

There are numerous uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and the amount and timing of development expenditures, including many factors beyond the property owner’s control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and gas that cannot be measured in an exact manner and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all reserve estimates are to some degree subjective, the quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and gas sales prices may each differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. The standardized measure shown below represents estimates only and should not be construed as the current market value of the estimated oil and gas reserves attributable to the Properties. In this regard, the information set forth in the following tables includes revisions of reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions reflect additional information from subsequent development activities, production history of the Properties and any adjustments in the projected economic life of such property resulting from changes in product prices.

 

Proved reserves, including proved developed and proved undeveloped reserves, at March 31, 2016 were estimated by the independent petroleum consulting firm, Ralph E. Davis Associates, LLC. The proved reserves for the years ended March 31, 2016 and 2015 and for the three months ended June 30, 2016 were calculated by rolling forward the reserves at December 31, 2015 using the actual production for the periods. The future cash flows presented below are based on cost rates and statutory income tax rates in existence as of the date of the projections and average prices based on a 12-month average of first of the month commodity prices for the years ended March 31, 2016 and 2015 and for the three months ended June 30, 2016.

 

 

Estimated Quantities of Proved Oil and Gas Reserves (Unaudited)

 

The following table sets forth certain data pertaining to the Properties’ proved reserves for the three months ended June 30, 2016 and the years ended March 31, 2016 and 2015:  

		Three Months Ended June 30, 2016				Year Ended March 31, 2016				Year Ended March 31, 2015
Oil:
Proved reserves (Bbl):
Beginning of period			234,994				267,200				310,290
Production			(4,720	)			(32,206	)			(43,090	)
Proved reserves, at end of period			230,274				234,994				267,200
Natural Gas:
Proved reserves (Mcf):
Beginning of period			17,428,868				18,606,521				19,708,480
Production			(252,221	)			(1,177,653	)			(1,101,959	)
Proved reserves, at end of period			17,176,647				17,428,868				18,606,521
Natural Gas Liquid (NGL) in Bbls:
Proved reserves (Bbl):
Beginning of period			3,729,512				3,836,848				3,911,730
Production			(27,128	)			(107,336	)			(74,882	)
Proved reserves, at end of period			3,702,384				3,729,512				3,836,848
Total Oil, Natural Gas and NGL
Proved reserves (BOE):
Beginning of period			6,869,317				7,205,135				7,506,767
Production			(73,885	)			(335,818	)			(301,632	)
Proved reserves, at end of period			6,795,432				6,869,317				7,205,135

  

Discounted Future Net Cash Flows (Unaudited)

  

The standardized measure of discounted future net cash flows, in management’s opinion, should be examined with caution. The basis for this table is the reserve studies prepared by independent petroleum engineering consultants, which contain imprecise estimates of quantities and rates of future production of reserves. Revisions of previous year estimates can have a significant impact on these results. Therefore, the standardized measure of discounted future net cash flow is not necessarily indicative of the fair value of the Company’s proved oil and natural gas properties.

 

Future income tax expense was computed by applying statutory rates, less the effects of tax credits for each period presented, to calculate the difference between pre-tax net cash flows relating to the Company’s proved reserves and the tax basis of proved properties, after consideration of available net operating loss and percentage depletion carryovers.

  

 

The following table sets forth the standardized measure of discounted future net cash flows relating to the proved reserves as of June 30, 2016, March 31, 2016 and March 31, 2015 and the related changes for the three months ended June 30, 2016 and years ended March 31, 2016 and 2015:

 

		As of June 30, 2016				As of March 31, 2016				As of March 31, 2015
Future cash inflows		$	105,134,925			$	106,024,560			$	214,295,790
Future production costs			(51,973,389	)			(52,457,400	)			(55,197,980	)
Future development costs			(4,776,250	)			(4,776,250	)			(4,776,250	)
Future tax expense			(16,450,980	)			(16,588,890	)			(52,469,330	)
Future net cash flows			31,934,306				32,202,020				101,852,230
10% annual discount			(16,315,076	)			(16,315,080	)			(53,842,950	)
Standardized measure of discounted future net cash flows		$	15,619,230			$	15,886,940			$	48,009,280

  

Changes in Standardized Measure of Discounted Future Cash Flows (Unaudited)

 

		As of June 30, 2016				As of March 31, 2016				As of March 31, 2015
Beginning of the period		$	15,886,940			$	48,009,280			$	70,869,170
Sales of oil, gas and NGL, net of production costs			(405,624	)			(2,110,670	)			(7,926,747	)
Net changes in prices and production costs			—				(103,419,980	)			(52,252,323	)
Accretion of discount			4				37,527,870				16,858,300
Net change in income taxes			137,910				35,880,440				20,460,880
End of the period		$	15,619,230			$	15,886,940			$	48,009,280

 

Reserves

 

The estimated net proved crude oil and natural gas reserves at January 1, 2016 were approximately 6.9 million Boe (Barrel of Oil Equivalent.) Additionally, there are 9.3 million Boe of probable reserves. Natural gas equivalents are determined using a ratio of 6 Mcf of natural gas to 1 Bbl of crude oil or NGLs based on 42 gallons to 1 Bbl of crude oil.

 

A majority of the reserves are in leases in Lincoln, Logan and Payne Counties Oklahoma. Volumes produced are valued using SEC guidelines in effect on December 31, 2015 and adjusted for pricing differentials resulting in average monthly crude oil price of $45.44 per Bbl, natural gas price of $2.33 per thousand cubic feet (Mcf) and NGL pricing was held constant at $14.57 per Bbl for the life of the property. The estimated discounted future net cash flow (PV-10) before tax expenses for our proved reserves was approximately $24.2 million. The estimated capital costs as of January 1, 2016 to realize the proved undeveloped reserves is approximately $4.8 million. 

 

 

The following table sets forth the proved developed and proved undeveloped reserves at January 1, 2016:

 

Proved Developed Reserves
Crude Oil (Bbls)			195,880
Natural Gas (Mcf)			13,522,930
Natural Gas Liquids (NGL) in BBLs			2,736,230
Oil Equivalents (Boe)			5,185,932
Proved Undeveloped Reserves
Crude Oil (Bbls)			46,454
Natural Gas (Mcf)			4,155,608
Natural Gas Liquids (NGL) in BBLs			1,020,472
Oil Equivalents (Boe)			1,759,527
Proved Reserves
Crude Oil (Bbls)			242,334
Natural Gas (Mcf)			17,678,538
Natural Gas Liquids (NGL) in BBLs			3,756,702
Oil Equivalents (Boe)			6,945,459

  

The following table reconciles the discounted future net cash flow (PV10) with the standardized measure of discounted future net cash flow as of June 30, 3016, March 31, 2016 and 2015:

 

		As of June 30, 2016				As of March 31, 2016				As of March 31, 2015
Non-discounted future cash flow per reserve report		$	48,385,286			$	48,790,910			$	154,321,560
10% annual discount			(24,719,790	)			(24,573,620	)			(74,729,960	)
Discounted future net cash flow (PV10)			23,665,496				24,217,290				79,591,600
Future tax expense			(16,450,980	)			(16,588,890	)			(52,469,330	)
10% annual discount			8,404,714				8,258,540				20,887,010
Discounted future tax expense			(8,046,266	)			(8,330,350	)			(31,582,320	)
Standardized measure of discounted future net cash flow		$	15,619,230			$	15,886,940			$	48,009,280

  

Proved reserves.    Proved reserves are those quantities, 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 and operating methods 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 hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

 

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 twelve-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.

 

Reasonable certainty.    If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

 

 

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 not to be recovered.

 

Booking Undeveloped Reserves

 

Certain undeveloped reserves, such as shale, are booked based on a reasonable certainty standard where companies report undeveloped locations at distances greater than one legal offset from economically producing wells. The Hunton reservoir, of which certain assets being purchased are a part, is considered a conventional or traditional reservoir and subject to the more stringent booking requirements where a proved undeveloped (PUD) drilling location must directly offset or adjacent to a producing well.

 

Booking Hunton reserves is also impacted by a business decision to minimize leasehold and other investment until drilling is imminent. This economic decision is made to preserve capital and made possible by the rules in Oklahoma referred to as forced pooling. Through this process, an operator can create a drilling unit without having leased the entire unit. Any unleased mineral owners will have an election to either participate and become a working interest owner or sign-on as a lessor. From the data available on the acreage being purchased, the operator ultimately leases a minimum of 95% of the acreage in the unit. This allows the operator to more broadly deploy capital across a greater number of units and gain a larger leasehold footprint.

 

However, a downside to this strategy is that reserves for undeveloped locations are booked consistent with the amount of acreage that is owned in a drilling unit at the time of booking. If an operator has leased 160 acres of a 640 acre drilling unit, then it may only book 25% of the value of a future well or wells to be drilled in that unit. Once the well is drilled, the working interest will reflect the total accumulation of interests including through pooling.

 

 

(b)     Pro Forma Financial Information.

 

The unaudited pro forma financial information presented below combine the historical financial information of Lucas and the historical statements of revenues and direct operating expenses of the Assets, giving effect to the Acquisition, as if it had occurred on June 30, 2016. The historical financial information has been adjusted to give effect to pro forma events that are (i) directly attributable to the Acquisition and (ii) factually supportable. With respect to the operational financial information, the pro forma events must be expected to have a continuing impact on the combined results. You should read this information in conjunction with the:

 

·

accompanying notes to the unaudited pro forma financial information;

 

·

separate historical unaudited financial statements (including the notes thereto) of Lucas for the quarterly period ended June 30, 2016 included in our quarterly report on Form 10-Q filed with the SEC on August 12, 2016;

 

·

separate historical audited financial statements (including the notes thereto) of Lucas as of and for the fiscal year ended March 31, 2016 included in our annual report on Form 10-K filed with the SEC on July 13, 2016; and

 

·

separate historical audited statements of revenues and direct operating expenses of the Assets for the years ended March 31, 2016 and 2015, and unaudited statements of revenues and direct operating expenses of the Assets for the three months ended June 30, 2016 and 2015 contained elsewhere in this current report.

 

The pro forma adjustments are described in the notes accompanying the pro forma financial information (the “Notes”).

 

The pro forma financial information has been prepared based on information currently available to us, using assumptions that our management believes are reasonable. The pro forma financial information does not purport to represent the actual results of operations that would have occurred if the Acquisition had taken place on the dates specified. The pro forma financial information is not necessarily indicative of the results of operations that may be achieved in the future. The pro forma financial information includes certain reclassifications to conform the historical results of operations of the Assets to our results of operations.

 

The assumptions used and adjustments made in preparing the pro forma financial information are described in the Notes, which should be read in conjunction with the pro forma financial information. The pro forma financial information and related Notes contained herein should be read in conjunction with our financial statements and related notes included in our Annual Report on Form 10-K for the fiscal year ended March 31, 2016 which was filed with the SEC on July 13, 2016 and in our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2016 filed with the SEC on August 12, 2016, and the separate historical audited statements of revenues and direct operating expenses of the Assets for the years ended March 31, 2016 and 2015, and unaudited statements of revenues and direct operating expenses of the Assets for the three months ended June 30, 2016 and 2015, included in this Form 8-K/A.

 

The unaudited pro forma financial information is presented for informational purposes only.

 

LUCAS ENERGY, INC.

UNAUDITED PRO FORMA COMBINED BALANCE SHEET

AS OF JUNE 30, 2016

 

		Lucas Energy, Inc.				(a) Acquisition				Other Significant Transactions				Pro-Forma Adjustments				(Pro-Forma Combined)
ASSETS
Current Assets
Cash		$	60,010			$	167,517	(b)		$	—			$	4,500,000	(n)		$	9,724,527
			—				—				4,997,000	(l)			—				—
Restricted Cash			—				3,360,000	(c)			—				—				3,360,000
Accounts Receivable			165,458				—				—				—				165,458
Inventories			194,997				—				—				—				194,997
Other Current Assets			166,819				—				—				—				166,819
Total Current Assets			587,284				3,527,517				4,997,000				4,500,000				13,611,801
Property and Equipment
Oil and Gas Properties (Full Cost Method)			48,520,979				64,955,339	(d)			—				—				113,476,318
Other Property and Equipment			425,165				—				—				—				425,165
Total Property and Equipment			48,946,144				64,955,339				—				—				113,901,483
Accumulated Depletion, Depreciation and Amortization			(34,857,673	)			—				—				—				(34,857,673	)
			14,088,471				64,955,339				—				—				79,043,810
Other Assets			58,716				—				—				—				58,716
Total Assets		$	14,734,471			$	68,482,856			$	4,997,000			$	4,500,000			$	92,714,327
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable		$	2,585,035			$	200,000	(e)		$	—			$	—			$	2,785,035
Common Stock Payable			71,882				—				—				—				71,882
Accrued Expenses			557,269				—				—				—				557,269
Convertible Notes Payable - Silver Star, Net of Discount of $9,563			636,732				—				—				—				636,732
Note Payable - Rogers			7,114,734				—				—				—				7,114,734
Convertible Notes Payable - HFT, Net of Discount of $434,542			165,458				—				—				—				165,458
Notes Payable - Dreeben, Net of Discount of $10,000			375,000								—				—				375,000
Total Current Liabilities			11,506,110				200,000				—				—				11,706,110
Long-Term Debt, Net of Deferred Financing Cost of $1,043,979			—				31,297,483	(f)			—				—				38,956,021
							4,975,000	(g)
							3,360,000	(c)
							167,517	(b)
							200,000	(e)
							(643,979)	(h)
							(400,000)	(i)
Convertible Subordinated Debenture, Net of Discount of $511,071			18,929				—				—				—	(o)			18,929
Asset Retirement Obligation			1,206,834				713,798	(d)			—				—				1,920,632
Derivative Liability			182,333				—				—				—				182,333
Total Liabilities			12,914,206				39,869,819				—				—				52,784,025

 

 

LUCAS ENERGY, INC.

UNAUDITED PRO FORMA COMBINED BALANCE SHEET

AS OF JUNE 30, 2016

		Lucas Energy, Inc.				(a) Acquisition				Other Significant Transactions				Pro-Forma Adjustments				(Pro-Forma Combined)
Commitments and Contingencies
Stockholders’ Equity
Preferred Stock Series B, 600,000 Shares Authorized of $0.001 Par, 552,000 Shares Issued and Outstanding			—				552	(j)			—				—				552
Preferred Stock Series C, 500,000 Shares Authorized of $0.001 Par, 527 Shares Issued and Outstanding			—				—				1	(l)			—				1
Common Stock, 100,000,000 Shares Authorized of $0.001 Par, 16,687,044 Shares Issued and Outstanding Shares			1,739				13,010	(k)			—				1,385	(n)			16,687
							390	(h)			—				163	(o)
Additional Paid-in Capital			60,155,673				21,452,936	(k)			5,259,999	(l)			499,837	(o)			98,750,209
							643,589	(h)			(263,000)	(m)			4,498,615	(n)
							6,502,560	(j)			—				—
Accumulated Deficit			(58,337,147	)			—				—				(500,000)	(o)			(58,837,147	)
Total Stockholders’ Equity			1,820,265				28,613,037				4,997,000				4,500,000				39,930,302
Total Liabilities and Stockholders’ Equity		$	14,734,471			$	68,482,856			$	4,997,000			$	4,500,000			$	92,714,327

  

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

 

(a)

To record the allocation of the $64,296,660 purchase price to the net assets acquired.

(b)

To record $167,517 in cash received.

(c)

To record $3,360,000 of cash received which is to be placed in a sinking fund for debt principal reductions.

(d)

To record the $713,798 asset retirement obligation associated with the acquired properties.

(e)

To record a $200,000 payable for half of the 1% debt commitment fee (noted in (j)) due in six months.

(f)

To record the $31,297,483 of long-term debt assumed related to the transaction.

(g)

To record the additional debt to be incurred to provide the $4,975,000 of cash consideration due at closing.

(h)

To record the issuance of 390,290 shares of common stock with a fair value of $643,979 to the lender for an underwriting fee recorded as deferred financing cost.

(i)

To record deferred financing cost of $400,000 for the 1% debt commitment fee due at closing.

(j)

To record the fair value of the issuance of 552,000 shares of Series B Preferred Stock.

(k)

To record the issuance of 13,009,664 shares of common stock with a fair value of $21,465,946 to seller.

(l)

To record the cash proceeds from of the issuance of 527 shares of Series C Preferred Stock.

(m)

To record the 5% discount for the issuance of 527 shares of Series C Preferred Stock.

(n)

To record the exercise of warrants to purchase 1,384,616 shares of common stock at an exercise price of $3.25 per share.

(o)

To record the conversion of the subordinated debenture into 163,077 shares of common stock.

 

 

LUCAS ENERGY, INC.

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS

FOR THE YEAR ENDED MARCH 31, 2016

		Lucas Energy, Inc.				(a) Acquisition				Pro Forma Adjustments				(Pro Forma Combined)
Operating Revenues
Crude Oil		$	968,146			$	2,577,274			$	—			$	3,545,420
Natural Gas			—				1,399,972				—				1,399,972
Natural Gas Liquids			—				1,020,179				—				1,020,179
Total Revenues			968,146				4,997,425				—				5,965,571
Operating Expenses
Lease Operating Expenses			740,756				2,740,575				—				3,481,331
Severance and Property Taxes			122,879				—				—				122,879
Depreciation, Depletion, Amortization, and Accretion			879,850				—				5,172,608	(b)			6,052,458
Impairment of Oil and gas Properties			21,391,490								36,111,471	(c)			70,775,337
											13,272,376	(d)
General and Administrative			2,500,814				—								2,500,814
Total Expenses			25,635,789				2,740,575				54,556,455				82,932,819
Operating Income (Loss)			(24,667,643	)			2,256,850				(54,556,455	)			(76,967,248	)
Other Expense (Income)
Interest Expense			696,506				—				2,200,000	(e)			3,689,506
											530,000	(f)
											263,000	(g)
Other Expense, Net			85,606				—				—				85,606
Total Other Expenses			782,112				—				2,993,000				3,775,112
Net Income (Loss)		$	(25,449,755	)		$	2,256,850			$	(57,549,455	)		$	(80,742,360	)
Net Loss Per Common Share
Basic and Diluted		$	(17.58	)										$	(5.04	)
Weighted Average Number of Common Shares Outstanding
Basic and Diluted			1,448,025								13,029,664	(h)			16,025,382
											163,077	(i)
											1,384,616	(j)
											—	(k)

 

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

 

 

(a)

To record the revenues and operating expenses associated with the acquisition.

(b)

To record depletion expense related to the property acquisition under the full cost method.

(c)

To record impairment expense related to the acquisition per the purchase price allocation at August 25, 2016.

(d)

To record impairment expense related to the property acquisition under the full cost method.

(e)

To record interest expense directly attributable to the acquisition.

(f)

To record interest expense related to the amortization of the discount of the convertible subordinated debenture upon conversion.

(g)

To record interest expense related to the amortization of the discount of the 5% discount related to the issuance of 527 Shares of Series C Preferred Shares.

(h)

To record the issuance 13,009,664 and 20,000 shares of common stock (excludes the dilutive effect of the 552,000 Series B Preferred Shares which are convertible into common stock at 7.14 to 1 or 3,941,280 common shares).

(i)

To record the issuance of 163,077 common shares upon the full conversion of the subordinated debenture outstanding.

(j)

To record the issuance of 1,384,616 common shares upon the exercising the warrants associated with the subordinated debenture.

(k)

Excludes the dilutive effect of the 527 Series C Preferred Shares which are convertible into 1,618,462 shares of common stock.

 

 

LUCAS ENERGY, INC.

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS

FOR THE THREE MONTHS ENDED JUNE 30, 2016

 

		Lucas Energy, Inc.				(a) Acquisition				Pro Forma Adjustments				(Pro Forma Combined)
Operating Revenues
Crude Oil		$	153,244			$	420,666			$	—			$	573,910
Natural Gas			—				191,589				—				191,589
Natural Gas Liquids			—				277,380				—				277,380
Total Revenues			153,244				889,635				—				1,042,879
Operating Expenses
Lease Operating Expenses			276,197				484,011				—				760,208
Severance and Property Taxes			23,862				—				—				23,862
Depreciation, Depletion, Amortization, and Accretion			136,903				—				1,038,228	(b)			1,175,131
General and Administrative			657,770				—				—				657,770
Total Expenses			1,094,732				484,011				1,038,228				2,616,971
Operating Income (Loss)			(941,488	)			405,624				(1,038,228	)			(1,574,092	)
Other Expense (Income)
Interest Expense			338,491				—				550,000	(c)			1,681,491
											530,000	(d)
											263,000	(e)
Other Expense, Net			90,373				—				—				90,373
Total Other Expenses			428,864				—				1,343,000				1,771,864
Net Income (Loss)		$	(1,370,352	)		$	405,624			$	(2,381,228	)		$	(3,345,956	)
Net Loss Per Common Share
Basic and Diluted		$	(0.80	)										$	(0.21	)
Weighted Average Number of Common Shares Outstanding
Basic and Diluted			1,707,416								13,029,664	(f)			16,264,773
											163,077	(g)
											1,384,616	(h)
											—	(i)

 

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

 

 

(a)

To record the revenues and operating expenses associated with the acquisition.

(b)

To record depletion expense related to the property acquisition under the full cost method.

(c)

To record interest expense directly attributable to the acquisition.

(d)

To record interest expense related to the amortization of the discount of the convertible subordinated debenture upon conversion.

(e)

To record interest expense related to the amortization of the discount of the 5% discount related to the issuance of 527 Shares of Series C Preferred Shares.

(f)

To record the issuance 13,009,664 shares of common stock (excludes the dilutive effect of the 552,000 Series B Preferred Shares which are convertible into common stock at 7.14 to 1 or 3,941,280 common shares).

(g)

To record the issuance of 163,077 common shares upon the full conversion of the subordinated debenture outstanding.

(h)

To record the issuance of 1,384,616 common shares upon the exercising the warrants associated with the subordinated debenture.

(i)

Excludes the dilutive effect of the 527 Series C Preferred Shares which are convertible into 1,618,462 shares of common stock.

 

  

LUCAS ENERGY, INC. 

UNAUDITED PRO FORMA COMBINED FINANCIAL INFORMATION

 

1. BASIS OF PRO FORMA PRESENTATION

 

The properties currently produce approximately 1,000 net barrels of oil equivalent (“BOE”) per day, of which 53% are liquids, from 114 producing wells. The bulk of the production is from the Hunton formation holding approximately 43,000 gross acres (9,900 net acres) in central Oklahoma. Additionally, further, offset development drilling opportunities for at least 40 additional wells have been identified.

 

As consideration for the acquisition, we assumed $31,297,483 of commercial bank debt; issued 552,000 shares of newly designated Series B Preferred Stock to one of the Sellers and its affiliate, which are under common control with the Seller Representative, with a total liquidation value of $13,800,000; issued 13,009,664 shares of Common Stock to certain of the Sellers with a fair value of $21,465,946; and paid $4,975,000 in cash to certain Sellers. Notwithstanding the above, in the event there are any title or other material issues associated with the assets, the parties agreed to work in good faith to address such issues, and if such issues cannot be addressed, to adjust the purchase price, provided that no adjustment will be made unless such issues in aggregate total more than 5% of the aggregate purchase price, and provided further that if such issues in aggregate total more than 20% of the aggregate purchase price, we can terminate the Asset Purchase Agreement. We and the Sellers also agreed to a true-up for certain joint interest billings and authorization for expenditures at and/or after closing, and to effect a true-up in connection with any material agreements, if the rights thereto are not provided by the Sellers at closing.

 

Since the Asset Purchase agreement was entered into on December 30, 2015, the Company has entered into the following transactions that have been deemed significant and are included in the Combined Pro Forma financial statements under Other Significant Transactions.

 

Securities Purchase Agreement

 

On April 6, 2016, we entered into a Securities Purchase Agreement (the “Securities Purchase Agreement”) with an accredited institutional investor, pursuant to which we sold and issued a redeemable convertible subordinated debenture, with a face amount of $530,000, convertible into 163,077 shares of common stock at a conversion price equal to $3.25 per share (the “Debenture”) and a warrant to purchase 1,384,616 shares of common stock (subject to adjustment thereunder) at an exercise price equal to $3.25 per share (the “First Warrant”). The accredited institutional investor purchased the Debenture at a 5.0% original issue discount for the sum of $500,000 and agreed that it will exercise the 1,384,616 warrants, upon satisfaction of certain conditions, for the sum of $4.5 million. As a result of the inclusion of the warrants, we recorded the fair value of the warrants as a full discount on the Debenture.

 

As the conversion of the Debenture and the exercise of the warrants are conditions to closing the acquisition, we have recognized the additional 163,077 shares of common stock for conversion of the Debenture and 1,384,661 shares of common stock for the exercise of the First Warrant as adjustments to the pro forma balance sheet as of June 30, 2016 and to the pro forma statements of operations for the period ended June 30, 2016.

 

Stock Purchase Agreement

 

Also on April 6, 2016, we entered into a Stock Purchase Agreement (the “Stock Purchase Agreement”) with the same accredited institutional investor as the Securities Purchase Agreement above, pursuant to which we agreed, subject to certain conditions, to issue 527 shares of Series C redeemable convertible preferred stock (the “Series C Preferred Stock”)(with a face value of $5.26 million) at a 5% original issue discount, convertible into 1,618,462 shares of common stock at a conversion price of $3.25 per share, and a warrant to purchase 1,111,112 shares of common stock at an exercise price of $4.50 per share. Under the terms of the Stock Purchase Agreement, 1,111,112 warrants and 53 shares of Series C Preferred Stock was sold and issued for $500,000 after the closing of the Asset Purchase agreement, and the remaining 474 shares of Series C Preferred Stock will be sold and issued for $4.5 million at such time as there is an effective registration statement in place covering the shares of common stock issuable upon conversion of the Series C Preferred Stock and exercise of the 1,111,112 warrants.

 

As the issuance of the 527 shares of Series C preferred stock for $5,000,000 is a condition of closing, we made adjustments to reflect the sale of the Series C preferred stock as well as recognizing the original issue discount of 5.0% in the amount of $263,000 in the pro forma balance sheet as of June 30, 2016 and to the pro forma statements of operations for the year period June 30, 2016.

 

   

As the exercise of the additional 1,111,112 warrants is not a condition to closing the Acquisition, we have made no adjustments to the in the combined pro forma balance sheet as of June 30, 2016 or to the combined pro forma statements of operations for the period ended June 30, 2016. We obtained shareholder approval for the potential issuance of common shares relating to the conversion of the preferred shares and warrants exceeding 19.99% of our outstanding common stock. If the preferred shares and warrants were converted, 2,729,574 additional common shares would be issued and outstanding.

 

The unaudited Pro Forma Combined Financial Statements are presented for illustrative purposes only and do not purport to represent what our financial position or results of operations would have been if the transactions had occurred as presented, or to project our financial position or results of operations for any future periods. The pro forma adjustments are based on available information and certain assumptions that management believes are reasonable. The pro forma adjustments are directly attributable to the transactions and are expected to have a continuing impact on our results of operations. In the opinion of management, all adjustments necessary to present fairly the unaudited Pro Forma Combined Financial Statements have been made. 

 

2. PRO FORMA COMBINED SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

 

The following unaudited supplemental pro forma oil and natural gas reserve tables present how the combined oil and gas reserves and standardized measure information of the Lucas Energy, Inc. (the “Company”) and the Properties may have appeared had the transaction occurred on April 1, 2015. The Proforma Combined Supplemental Information on Oil and Gas Producing Activities are for illustrative purposes only.

 

All of the reserves are located in the United States. Reserves are based as follows:

 

a)      

For Lucas Energy, Inc. (As Reported) – as reported in the Company’s Annual Report on Form 10-K for the year ended March 31, 2016, upon a reserve report prepared by the independent petroleum engineers of Ralph E. Davis Associates, LLC as of March 31, 2016. For the Acquisition (the Properties), using the reserve report prepared as of April 1, 2016, the Company mathematically “rolled forward” reserve values from April 1, 2016 to June 30, 2016 by using actual sales volumes, prices, severance and production taxes, and lease operating expense realized for each month between April 1, 2016 and June 30, 2016 (the “Rollforward Data”). The source of the Rollforward Data is revenue and lease operating data received from the Seller Representative for the relevant periods.

 

b)   

Acquisition (the Properties) – upon a reserve report prepared by the independent petroleum engineers of Ralph E. Davis Associates, LLC as of January 1, 2016. For the Acquisition (the Properties), using the reserve report prepared as of January 1, 2016, the Company mathematically “rolled forward” reserve values from January 1, 2016 to June 30, 2016 by using actual sales volumes, prices, severance and production taxes, and lease operating expense realized for each month between January 1, 2016 and June 30, 2016 (the “Rollforward Data”). The source of the Rollforward Data is revenue and lease operating data received from the Seller Representative for the relevant periods.

 

 

Pro Forma Combined Estimated Quantities of Proved Oil and Gas Reserves (Unaudited)

 

The following table sets forth certain pro forma data pertaining to the combined proved reserves for the year ended March 31, 2016:

 

		Lucas Energy, Inc.				Acquisition (the Properties)				Pro forma Combined
Crude Oil (Bbls)
Net proved reserves at beginning of year			4,578,535				267,200				4,845,735
Revisions of previous estimates			(444,710	)			—				(444,710	)
Purchases in place			—				—				—
Extensions, discoveries and other additions			—				—				—
Sales in place			(270,273	)			—				(270,273	)
Production			(22,190	)			(32,206	)			(54,396	)
Net proved reserves at end of year			3,841,362				234,994				4,076,356
Natural Gas (Mcf)
Net proved reserves at beginning of year			2,976,780				18,606,521				21,583,301
Revisions of previous estimates			(300,926	)			—				(300,926	)
Purchases in place			—				—				—
Extensions, discoveries and other additions			—				—				—
Sales in place			(162,164	)			—				(162,164	)
Production			—				(1,177,653	)			(1,177,653	)
Net proved reserves at end of year			2,513,690				17,428,868				19,942,558
Natural Gas Liquids (Bbls)
Net proved reserves at beginning of year			—				3,836,848				3,836,848
Revisions of previous estimates			—				—				—
Purchases in place			—				—				—
Extensions, discoveries and other additions			—				—				—
Sales in place			—				—				—
Production			—				(107,336	)			(107,336	)
Net proved reserves at end of year			—				3,729,512				3,729,512
Oil Equivalents (Boe)
Net proved reserves at beginning of year			5,074,665				7,205,135				12,279,800
Revisions of previous estimates			(494,863	)			—				(494,863	)
Purchases in place			—				—				—
Extensions, discoveries and other additions			—				—				—
Sales in place			(297,300	)			—				(297,300	)
Production			(22,190	)			(335,818	)			(358,008	)
Net proved reserves at end of year			4,260,312				6,869,317				11,129,628

 

 

The following table sets forth certain pro forma data pertaining to the combined proved reserves for the three months ended June 30, 2016:

 

		Lucas Energy, Inc.				Acquisition (the Properties)				Pro forma Combined
Crude Oil (Bbls)
Net proved reserves at beginning of year			3,841,363				234,994				4,076,357
Revisions of previous estimates			—				—				—
Purchases in place			—				—				—
Extensions, discoveries and other additions			—				—				—
Sales in place			—				—				—
Production			(2,980	)			(4,720	)			(7,700	)
Net proved reserves at end of year			3,838,383				230,274				4,068,657
Natural Gas (Mcf)
Net proved reserves at beginning of year			2,513,691				17,428,868				19,942,559
Revisions of previous estimates			—				—				—
Purchases in place			—				—				—
Extensions, discoveries and other additions			—				—				—
Sales in place			—				—				—
Production			—				(252,221	)			(252,221	)
Net proved reserves at end of year			2,513,691				17,176,647				19,690,338
Natural Gas Liquids (Bbls)
Net proved reserves at beginning of year			—				3,729,512				3,729,512
Revisions of previous estimates			—				—				—
Purchases in place			—				—				—
Extensions, discoveries and other additions			—				—				—
Sales in place			—				—				—
Production			—				(27,128	)			(27,128	)
Net proved reserves at end of year			—				3,702,384				3,702,384
Oil Equivalents (Boe)
Net proved reserves at beginning of year			4,260,311				6,869,317				11,129,628
Revisions of previous estimates			—				—				—
Purchases in place			—				—				—
Extensions, discoveries and other additions			—				—				—
Sales in place			—				—				—
Production			(2,980	)			(73,885	)			(76,865	)
Net proved reserves at end of year			4,257,332				6,795,432				11,052,763

 

 

The following table sets forth certain pro forma data pertaining to the combined proved developed and proved undeveloped reserves for the year ended March 31, 2016:

 

		Lucas Energy, Inc.				Acquisition (the Properties)				Pro forma Combined
Proved Developed Reserves
Crude Oil (Bbls)			117,778				188,540				306,318
Natural Gas (Mcf)			—				13,273,260				13,273,260
Natural Gas Liquids (NGL) in BBLs			—				2,709,040				2,709,040
Oil Equivalents (Boe)			117,778				5,109,790				5,227,568
Proved Undeveloped Reserves
Crude Oil (Bbls)			3,723,585				46,440				3,770,025
Natural Gas (Mcf)			2,513,691				4,155,620				6,669,311
Natural Gas Liquids (NGL) in BBLs			—				1,020,470				1,020,470
Oil Equivalents (Boe)			4,142,534				1,759,513				5,902,047
Proved Reserves
Crude Oil (Bbls)			3,841,363				234,980				4,076,343
Natural Gas (Mcf)			2,513,691				17,428,880				19,942,571
Natural Gas Liquids (NGL) in BBLs			—				3,729,510				3,729,510
Oil Equivalents (Boe)			4,260,312				6,869,303				11,129,615

  

The following table sets forth certain pro forma data pertaining to the combined proved developed and proved undeveloped reserves as of June 30, 2016:

 

		Lucas Energy, Inc.				Acquisition (the Properties)				Pro forma Combined
Proved Developed Reserves
Crude Oil (Bbls)			114,798				183,834				298,618
Natural Gas (Mcf)			—				13,021,027				13,021,039
Natural Gas Liquids (NGL) in BBLs			—				2,681,914				2,681,925
Oil Equivalents (Boe)			114,798				5,035,918				5,150,716
Proved Undeveloped Reserves
Crude Oil (Bbls)			3,723,585				46,440				3,770,025
Natural Gas (Mcf)			2,513,691				4,155,620				6,669,311
Natural Gas Liquids (NGL) in BBLs			—				1,020,470				1,020,470
Oil Equivalents (Boe)			4,142,534				1,759,513				5,902,047
Proved Reserves
Crude Oil (Bbls)			3,838,383				230,274				4,068,643
Natural Gas (Mcf)			2,513,691				17,176,647				19,690,350
Natural Gas Liquids (NGL) in BBLs			—				3,702,384				3,702,395
Oil Equivalents (Boe)			4,257,332				6,795,432				11,052,763

 

 

Pro Forma Combined Standardized Measure of Discounted Future Net Cash Flows (Unaudited)

 

The following table sets forth the combined standardized measure of discounted future net cash flows relating to the pro forma combined proved reserves as of March 31, 2016:

 

		Lucas Energy, Inc.				Acquisition (the Properties)				Pro forma Combined
Future cash inflows		$	179,710,901			$	106,024,560			$	285,735,461
Future production costs			(48,202,264	)			(52,457,400	)			(100,659,664	)
Future development costs			(78,632,113	)			(4,776,250	)			(83,408,363	)
Future income taxes			(3,437,757	)			(16,588,890	)			(20,026,647	)
Future net cash flows			49,438,767				32,202,020				81,640,787
Discount to present value at 10% annual rate			(36,040,384	)			(16,315,080	)			(52,355,464	)
Standardized measure of discounted future net cash flows		$	13,398,383			$	15,886,940			$	29,285,323

  

The following table sets forth the combined standardized measure of discounted future net cash flows relating to the pro forma combined proved reserves as of June 30, 2016:

 

		Lucas Energy, Inc.				Acquisition (the Properties)				Pro forma Combined
Future cash inflows		$	179,585,861			$	105,134,925			$	284,720,786
Future production costs			(48,094,224	)			(51,973,389	)			(100,067,612	)
Future development costs			(78,632,113	)			(4,776,250	)			(83,408,363	)
Future income taxes			(3,146,246	)			(16,450,980	)			(19,597,226	)
Future net cash flows			49,713,278				31,934,306				81,647,585
Discount to present value at 10% annual rate			(36,257,281	)			(16,315,076	)			(52,572,357	)
Standardized measure of discounted future net cash flows		$	13,455,998			$	15,619,230			$	29,075,228

 

Pro Forma Combined Changes in Standardized Measure of Discounted Future Cash Flows (Unaudited)

 

The following table sets forth the combined changes in standardized measure of discounted future cash flows for the year ended March 31, 2016:

 

		Lucas Energy, Inc.				Acquisition (the Properties)				Pro forma Combined
Standardized measure, beginning of year		$	61,628,716			$	48,009,280			$	109,637,996
Crude oil, natural gas and NGL sales, net of production costs			(104,515	)			—				(104,515	)
Net changes in prices and production costs			(41,178,131	)			(103,419,980	)			(144,598,111	)
Extensions, discoveries, additions and improved recovery			—				—				—
Changes in estimated future development costs			(9,440,684	)			—				(9,440,684	)
Development costs incurred			—				—				—
Revisions of previous quantity estimates			(6,460,172	)			—				(6,460,172	)
Accretion of discount			1,400,887				37,527,870				38,928,757
Net change in income taxes			13,592,568				35,880,440				49,473,008
Purchases of reserves in place			—				—				—
Sales of reserves in place			(6,360,521	)			(2,110,670	)			(8,471,191	)
Change in timing of estimated future production			320,235				—				320,235
Standardized measure, end of year		$	13,398,383			$	15,886,940			$	29,285,323

 

 

The following table sets forth the combined changes in standardized measure of discounted future cash flows for the three months ended June 30, 2016:

 

		Lucas Energy, Inc.				Acquisition (the Properties)				Pro forma Combined
Standardized measure, beginning of year		$	13,471,565			$	15,886,940			$	29,358,505
Crude oil, natural gas and NGL sales, net of production costs			—				—				—
Net changes in prices and production costs			—				—				—
Extensions, discoveries, additions and improved recovery			—				—				—
Changes in estimated future development costs			—				—				—
Development costs incurred			—				—				—
Revisions of previous quantity estimates			—				—				—
Accretion of discount			5,950				4				5,954
Net change in income taxes			(4,518	)			137,910				133,392
Purchases of reserves in place			—				—				—
Sales of reserves in place			(16,999	)			(405,624	)			(422,623	)
Change in timing of estimated future production			—				—				—
Standardized measure, end of year		$	13,455,998			$	15,619,230			$	29,075,228

 

 3. PURCHASE PRICE ALLOCATION

 

The table below summarizes the allocation of the purchase price to the net assets acquired. This allocation is based on the price of our Common Stock as of the acquisition closing date on August 25, 2016 of $3.78 per share:

 

Purchase Price on August 25, 2016:
Fair value of common stock issued		$	49,176,530
Fair value of Series B Preferred stock issued			14,903,999
Assumption of debt			31,297,483
Cash at Closing			4,975,000
Total purchase price		$	100,353,012
Fair value of net assets at December 30, 2015:
Oil and gas properties, subject to amortization		$	64,955,339
Total assets			64,955,339
Asset retirement obligations			(713,798	)
Total liabilities			(713,798	)
Net assets acquired		$	64,241,541
Impairment of oil and gas properties		$	36,111,471
Total Purchase Price		$	100,353,012
Assumption of debt		$	31,297,483
Cash funding (paid at closing)			4,975,000
Loan Commitment fee (paid at closing)			200,000
Restricted cash (received at closing)			3,360,000
Cash (received at closing)			167,517
Debt payable after closing		$	40,000,000

 

 

4. PRO FORMA ADJUSTMENTS

 

As pro forma adjustments related to the pro forma statement of operations are to be computed assuming that the transaction was consummated at the beginning of the fiscal year presented and are to include adjustments which give effect to events that are directly attributable to the transaction, expected to have a continuing impact on the Company, and factually supportable, the Company recognized the following pro forma adjustments to depletion and interest expenses.

 

Depletion Expense

 

The Company uses the full cost method of accounting for oil and natural gas producing activities. Therefore, costs of oil and natural gas properties are amortized using the units of production method, and the amortization base is comprised of the total capitalized costs and total future investment costs associated with all proved reserves.

 

In order to record the effects of the property acquisition under the full cost method, the Company is required to combine its oil and gas properties and the acquired oil and gas properties for each period presented. For the three-month period ended June 30, 2016, the amortization rate for the acquired properties is approximately $10/BOE while the amortization rate for the Company properties is approximately $22/BOE. Calculation of the blended rate of the combined properties is approximately $15/BOE.

 

For the year ended March 31, 2016, the amortization rate for the acquired properties is approximately $10/BOE while the amortization rate for the Company properties is approximately $27/BOE. Calculation of the blended rate of the combined properties is approximately $16/BOE. The higher blended BOE rate is a result of the business mix where the acquired properties are approximately 90% natural gas and liquids compared to the Company properties, which are 100% crude oil.

 

Since the acquired properties also represent approximately 90% of the total production of the combined entities, a pro form adjustment to depletion expense is required for three-month period ended June 30, 2016 with a similar adjustment being necessary for the year ended March 31, 2016.

 

Interest Expense

 

As the Company entered into a new loan agreement for $40,000,000 at the closing of the Acquisition, which has a three-year term and bears an annual interest rate of NYPR + 2% with a floor of 5.5%, the Company recorded an adjustment to recognize interest expense of $550,000 and $2,200,000 in the pro forma statement of operations for three-month period ended June 30, 2016 and for the year ended March 31, 2016, respectively.

 

Impairment of Oil and Gas Properties

 

In order to record the effects of the property acquisition under the full cost method, the Company is required to perform an impairment test (ceiling test) at each reporting date, whereby the carrying value of property and equipment is compared to the “estimated present value,” of its proved reserves discounted at a 10-percent interest rate of future net revenues, based on current economic and operating conditions at the end of the period, plus the cost of properties not being amortized, plus the lower of cost or fair market value of unproved properties included in costs being amortized, less the income tax effects related to book and tax basis differences of the properties. If capitalized costs exceed this limit, the excess is charged as an impairment expense. Therefore, the Company recorded an adjustment to recognize a $13.3 million impairment expense associated with oil and gas properties as of March 31, 2016. There was no additional impairment as of June 30, 2016.

 

  

(c) Not Applicable.

 

(d) Exhibits.

 

23.1

Consent of GBH CPAs, PC, Independent Registered Public Accounting Firm.

 

 

 

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 hereunto duly authorized.

 

Dated: September 27, 2016	By:	/s/ Anthony C. Schnur
		Chief Executive Officer, Interim Chief Financial Officer and Treasurer (Principal Executive Officer and Principal Financial Officer)

 

Dated: September 27, 2016	By:	/s/ Paul Pinkston
		Chief Accounting Officer (Principal Accounting Officer)

 

 

EXHIBIT INDEX

 

Exhibit No.		Description of Exhibit
23.1		Consent of GBH CPAs, PC, Independent Registered Public Accounting Firm.