lone-ex992_10.htm

We have audited the accompanying consolidated financial statements of Battlecat Oil and Gas Holdings, LLC and its subsidiaries (collectively, the “Company”) which comprise the consolidated balance sheet as of December 31, 2016 and the related consolidated statements of operations, changes in members’ equity and cash flows for the year then ended, and the related notes to the consolidated financial statements (collectively, 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.

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.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Battlecat Oil and Gas Holdings, LLC and its subsidiaries as of December 31, 2016 and the results of their operations and their cash flows for the year then ended in accordance with accounting principles generally accepted in the United States of America.

	March 31,		December 31,
	2017		2016
	(Unaudited)
Assets
Current assets
Cash and cash equivalents	$	664,219	$	816,451
Restricted cash		25,012		25,012
Joint interest billing receivable		307,799		302,145
Revenue receivable		300,196		396,936
Prepaid expenses and other current assets		65,923		101,069

Total current assets		1,363,149		1,641,613

Property and Equipment
Unproved oil and gas properties, successful efforts method of accounting, not subject to amortization, net of accumulated impairment of $216,175 and $216,175, respectively		4,426,646		1,962,289
Proved oil and gas properties, net of accumulated depletion, depreciation and amortization of $8,004,719 and $6,895,075, respectively		22,729,557		23,834,118
Other, net of accumulated depreciation and amortization		418,299		450,621
Net property and equipment		27,574,502		26,247,028
Other, net		66,507		76,008

Total assets	$	29,004,158	$	27,964,649

Liabilities and Members’ Equity
Current Liabilities
Accounts payable and accrued liabilities		485,761		371,675
Revenues payable		208,691		156,941
Prepayment liability		1,664		1,664
Total current liabilities		696,116		530,280
Long Term Liabilities
Asset retirement obligations		420,390		364,646
Line of credit		1,500,000		1,500,000
Total long term liabilities		1,920,390		1,864,646
Commitments and Contingencies (Notes 6 and 7)
Members’ Equity		26,387,652		25,569,723

Total liabilities and members’ equity	$	29,004,158	$	27,964,649

	Three Months Ended March 31,						Year Ended December 31,
	2017			2016			2016
	(Unaudited)			(Unaudited)
Revenues
Oil and gas revenues	$	1,021,222		$	863,081		$	4,102,993
Management fees		46,920			1,000			151,260

Total revenues		1,068,142			864,081			4,254,253

Operating Expenses
Lease operating expenses		669,791			495,032			1,766,835
Production taxes		45,570			39,858			187,909
Geological and geophysical expenses		2,851			—			456
Dry hole expense		—			—			1,212,540
Depletion, depreciation, and amortization		1,182,640			1,089,113			5,844,727
Impairment of unproved oil and gas properties		—			—			216,175
Accretion of asset retirement obligations		6,273			2,630			15,409
General and administrative expenses		819,333			834,645			3,880,809

Total operating expenses		2,726,458			2,461,278			13,124,860

Loss from operations		(1,658,316	)		(1,597,197	)		(8,870,607	)

Other income (expense)
Interest income		—			239			239
Interest expense		(23,755	)		(11,241	)		(74,580	)

Total other expense, net		(23,755	)		(11,002	)		(74,341	)

Loss before income taxes		(1,682,071	)		(1,608,199	)		(8,944,948	)

Deferred state tax benefit		—			—			43,214

Net loss	$	(1,682,071	)	$	(1,608,199	)	$	(8,901,734	)

Consolidated Statements of Changes in Members’ Equity For the Three months ended march 31, 2017 and the Year Ended December 31, 2016

	Three Months Ended March 31,						Year ended December 31,
	2017			2016			2016
	(Unaudited)			(Unaudited)
Operating activities
Net loss	$	(1,682,071	)	$	(1,608,199	)	$	(8,901,734	)
Adjustments to reconcile net loss to net cash used in operating activities:
Deferred state tax benefit		—			—			(43,214	)
Depletion, depreciation, and amortization		1,182,640			1,089,113			5,844,727
Impairment of unproved oil and gas properties		—			—			216,175
Dry hole expense		—			—			1,212,540
Amortization of loan origination fees		9,501			9,501			38,004
Accretion of asset retirement obligations		6,273			2,630			15,409
Changes in operating assets and liabilities:
Receivables		91,086			268,371			(64,575	)
Prepaid expenses and other assets		35,146			(13,119	)		(56,046	)
Accounts payable and accrued liabilities		114,086			(400,690	)		49,046
Prepayment liability		—			(333,990	)		(519,180	)
Revenues payable		51,750			(200,204	)		(278,938	)
Net cash used in operating activities		(191,589	)		(1,186,587	)		(2,487,786	)

Investing activities
Acquisitions and development of oil and gas properties		(2,419,969	)		(213,294	)		(7,833,881	)
Purchase of other property and equipment		(40,674	)		(130,214	)		(16,375	)
Net cash used in investing activities		(2,460,643	)		(343,508	)		(7,850,256	)

Financing activities
Proceeds from line of credit		—			500,000			1,500,000
Member contributions		2,500,000			—			8,000,000
Loan origination fees		—			(79,012	)		(79,012	)
Net cash provided by financing activities		2,500,000			420,988			9,420,988

Decrease in cash and cash equivalents		(152,232	)		(1,109,107	)		(917,054	)
Cash and cash equivalents, beginning of the period		816,451			1,733,505			1,733,505
Cash and cash equivalents, end of the period	$	664,219		$	624,398		$	816,451

Supplemental information:
Cash paid for interest expense	$	13,053		$	1,327		$	32,764
Non-cash investing activities:
Asset retirement obligations assumed or incurred	$	49,471		$	—		$	188,508

Battlecat Oil and Gas Holdings, LLC and its wholly-owned subsidiaries, Battlecat Oil and Gas, LLC, BCOG GP, LLC and Battlecat Management, LLC (collectively “Battlecat” or the “Company”) was formed on November 13, 2014 as a Delaware Limited Liability Company. The Company is engaged to directly or indirectly through its subsidiaries or joint-ventures, acquire, develop, operate and participate in the business of upstream and midstream oil and gas leasing, acquisition, exploration and production and development activities. The Company’s properties are located in Texas.

Upon formation, the Company entered into a limited liability company agreement which required two of the Company’s members, RocMar Investments, LLC (“RocMar”) and Lightspeed Energy, LLC (“Lightspeed”) to contribute all member interests in Battlecat Oil and Gas, LLC in exchange for a $1,000,000 equity interest in the Company. Battlecat Oil and Gas, LLC thereby became a wholly owned subsidiary of Battlecat Oil and Gas Holdings, LLC.

The Company’s consolidated audited financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts of Battlecat Oil and Gas Holdings, LLC and its wholly-owned subsidiaries, after elimination of all material intercompany balances and transactions.

The Company’s unaudited consolidated financial statements have also been prepared in accordance with GAAP and should be read in conjunction with the audited financial statements and notes thereto contained in this report.

In the opinion of management, all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of financial position and the results of operations for the interim periods presented have been reflected herein. The results of operations for interim periods are not necessarily indicative of the results to be expected for the full year. Notes to the interim financial statements which would substantially duplicate the disclosures contained in the audited financial statements for the year ended December 31, 2016 have been omitted.

The preparation of consolidated financial statements in conformity with GAAP 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. The actual results experienced by the Company may differ materially from the Company’s estimates. To the extent there are material differences between the estimates and the actual results, future results of operations will be affected and the effect could be material.

The Company’s consolidated financial statements are based on a number of significant estimates, including oil and gas reserve quantities, which are the basis for the calculations of depletion, depreciation, and amortization, asset retirement obligations, and impairment of proved and unproved oil and gas properties. The Company’s reserve quantities are determined by an independent petroleum engineering firm. However, management emphasizes that estimated reserve quantities are inherently imprecise and that estimates of more recent discoveries are more imprecise than those for properties with long production histories. In addition to the uncertainties inherent in the reserve estimation process, these amounts are affected by historical and projected prices for oil and natural gas which have typically been volatile. It is reasonably possible that the Company’s oil and gas reserve estimates will materially change in the forthcoming year.

The Company considers all highly-liquid investments purchased with original maturities of three months or less to be cash equivalents, which approximate fair value.

Accounts receivable consist of joint interest billing (“JIB”) receivables from other working interest owners for their share of the respective property costs due within 30 days from invoice date and from oil and gas purchasers generally due within 30 days of production sale. The Company requires no collateral on such receivables. The Company determines an allowance for doubtful accounts primarily based on historical write-off experience. The Company establishes provisions for losses on accounts receivable if it is determined that the collection of all or a part of an outstanding balance is not probable. If an allowance for doubtful accounts is deemed necessary, the carrying amount of receivables is reduced by a valuation allowance that reflects management’s best estimate of the amount that may not be collectible. No allowance for doubtful accounts was established as of March 31, 2017 (unaudited) and December 31, 2016. The Company generally does not charge interest on past due accounts.

Revenue is recognized when persuasive evidence of an arrangement exists, oil and gas products have been delivered or services have been rendered, the sales price is fixed or determinable, and collectability is reasonably assured. The Company recognizes oil and gas revenue from its interests in producing wells as oil and gas is produced and sold from those wells. Production sales for which payment had not been received as of period end are reflected as revenue receivable in the accompanying consolidated financial statements. Production imbalances are recognized as an asset or liability to the extent that the Company has an imbalance on a specific property that is in excess of its remaining proved oil and gas reserves. Oil and gas sales volumes are not significantly different from the Company’s share of production. As of March 31, 2017 (unaudited) and December 31, 2016, the Company had no significant production imbalances.

Property Costs – The Company follows the successful efforts method of accounting for its oil and gas property activities. Costs incurred to acquire leasehold interests such as lease bonuses, options to lease properties, brokers’ fees, recording fees, legal costs and other acquisition costs are capitalized and will be transferred to proved properties upon the determination of proved reserves. The costs of acquiring or constructing support equipment and facilities used in oil and natural gas producing activities are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, delay rentals and costs of carrying and retaining unproved properties are expensed. Costs incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) sufficient progress in assessing the reserves and the economic and operating viability of the project has been made. Due to the capital-intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination on its commercial viability. Costs to drill development wells are capitalized. A gain or loss is recognized when a property is sold or an entire field ceases to produce and is abandoned.

Depletion, Depreciation, and Amortization – Depletion, depreciation, and amortization of proved producing properties is provided using the units-of-production method over the life of the related reserves in the respective well or project. Proved leasehold costs are aggregated on a field-by-field basis and depleted over total proved reserves, while well-related costs are depleted over proved developed reserves. Estimated future abandonment and site restoration costs are included in the cost of proved producing properties and such costs as well as anticipated salvage values are taken into account in the depletion calculation. Depletion of each property or well begins when the relevant wells commence production. The Company recorded depletion, depreciation, and amortization of $5,743,359 during the year ended December 31, 2016. During the three-month periods ended March 31, 2017 and 2016, the Company recorded depletion, depreciation, and amortization of $1,109,644 (unaudited) and $1,003,227 (unaudited), respectively.

Impairments –As of December 31, 2016, the costs incurred related to exploratory wells were expensed as dry hole costs. There are no wells in progress as of December 31, 2016 or March 31, 2017 (unaudited). Unproved oil and gas properties are reviewed at least annually for impairment on a property-by-property basis and a loss is recognized, if any, for the cost of the property that has been impaired. The Company evaluates recoverability of capitalized costs considering many factors, including changes in general economic conditions (including commodity prices) or in the Company’s strategy, changes in the regulatory environment in which the Company operates, the expiration dates of the Company’s leaseholds, analysis of geological and geophysical data, and drilling results of other operators in the area. If it is determined that there has been impairment of the carrying value, any such impairment is expensed in the period, and a valuation allowance is established to reflect the reduction in value.

The Company incurred an impairment loss of $216,175 related to unproved properties for the year ended December 31, 2016.

The Company evaluates impairment of its proved oil and gas properties when triggering events take place. The Company reviews its long lived assets that are held and used by the Company for impairment whenever events or changes in circumstances, such as a downward revision of the reserve estimates or lower commodity prices, indicate that the carrying amount of an asset may not be recoverable. In performing this review, an undiscounted cash flow test is performed on the oil and gas properties. If the sum of these estimated risk-adjusted undiscounted future net cash flows is less than the net book value of the property, an impairment loss is recognized for the excess, if any, of the property’s net book value over its estimated fair value, which is based on estimated risk-adjusted discounted future net cash flows. The Company did not incur an impairment loss on its proved properties during 2016. The Company did not incur an impairment loss (unaudited) on its proved properties during the three months ended March 31, 2017 or 2016.

The Company recognizes the present value of estimated future plugging, site restoration, and abandonment costs of its oil and gas properties in both assets and liabilities. The fair value of the liability for an asset retirement obligation (ARO) is recognized in the period in which the legal obligation to retire an asset is incurred.

The Company determines the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future ARO requires management to make estimates, assumptions, and judgments regarding such factors as plugging and abandonment amounts, timing of settlements, the credit-adjusted risk-free rate to be used and inflation rates. The liability is then accreted each period until it is settled or the asset is sold, at which time the liability is reversed and any gain or loss resulting from the settlement of the obligation is recorded. The initial fair value of the ARO is capitalized and subsequently depreciated or amortized as part of the carrying amount of the related asset. The fair value of the ARO is measured using expected future cash outflows discounted at the Company’s credit-adjusted risk-free interest rate. Fair value, to the extent possible, includes a market risk premium for unforeseeable circumstances. No market risk premium was included in the Company’s ARO fair value estimate since a reasonable estimate could not be made. Given the unobservable nature of inputs, the initial measurement of the obligation is considered to be a Level 3 fair value estimate. To the extent future revisions to these assumptions impact the value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance.

The following table summarizes the Company’s asset retirement obligation transactions recorded for the year ended December 31, 2016:

There was no material activity during the three-month periods ended March 31, 2017 and 2016 (unaudited) impacting asset retirement obligations.

Fair value is 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. The Company categorizes its financial instruments in accordance with the Financial Accounting Standards Board’s (FASB) Accounting Standards Codification (ASC) Topic 820 Fair Value Measurement into the following fair value hierarchy:

The fair value hierarchy gives the highest priority to quoted prices (Level 1) and the lowest priority to unobservable inputs (Level 3). In cases where the inputs used to measure fair value fall in different levels of the fair value hierarchy, the level shall be determined based on the lowest level input that is significant to the fair value measurement in its entirety which requires judgment, considering factors specific to the asset or liability.

The Company’s financial instruments are cash and cash equivalents, restricted cash, joint interest billing receivables, and accounts payable stated at historical value which approximate fair value due to the short-term nature of these instruments. Based on market rates for similar loans, the fair value of long-term debt approximates its carrying value.

Property and equipment are stated at cost. Depreciation is computed using the straight-line method over the estimated service lives of assets. Leasehold improvements are amortized over the shorter of the lease term or the estimated useful life of the improvements. The Company’s depreciation lives ranged from three to seven years. Ordinary maintenance and repairs are charged to expenses. Expenditures which extend the physical or economic life of the assets are capitalized. Gains and losses on the dispositions of assets are recognized in the consolidated statements of operations, and the related assets and accumulated depreciation accounts are adjusted accordingly. The Company’s property and equipment consists of the following as of December 31:

Depreciation and amortization expense was $101,368 for the year ended December 31, 2016. Depreciation and amortization expense was $72,996 (unaudited) and $85,886 (unaudited) for the three months ended March 31, 2017 and 2016, respectively. Property and equipment are reviewed for impairment whenever an event or change in circumstances indicates the carrying amount of an asset or group of assets may not be recoverable. The impairment review includes comparison of future undiscounted cash flows expected to be generated by the asset or group of assets with their associated carrying value. If the carrying value of the asset or group of assets exceeds the expected future cash flows (undiscounted), an impairment loss is recognized to the extent the carrying amount of the assets exceeds its fair value. The Company recorded no impairment of property and equipment during the year ended December 31, 2016. The Company recorded no impairment of property and equipment for the unaudited three months ended March 31, 2017 and 2016.

The Company and its subsidiaries are limited liability companies. Consequently, they are not tax paying entities for federal income tax purposes. Accordingly, a provision for federal income taxes associated with the Company has not been recorded in the accompanying consolidated financial statements. Company income or losses are reflected in the members’ individual or corporate tax returns in accordance with their ownership percentages.

The State of Texas has a margin-based franchise tax law which is commonly referred to as the Texas margin tax and is assessed at a 0.75% rate. The tax is considered an income tax and is determined by applying a tax rate to a base that considers both revenues and expenses. At March 31, 2017 (unaudited) and December 31, 2016, the current liability for Texas margin taxes, if any, was immaterial.

The Company accounts for the Texas margin tax pursuant to the provisions of ASC 740-10, Accounting for Income Taxes, which requires, among other things, an asset and liability approach to calculating deferred income taxes. The asset and liability approach requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the carrying amounts and the tax basis of assets and liabilities. A valuation allowance is provided to offset any net deferred tax assets for which management believes it is more likely than not that the net deferred asset will not be realized.

The Company follows guidance issued by the FASB in accounting for uncertainty in income taxes. This guidance clarifies the accounting for income taxes by prescribing the minimum recognition threshold an income tax position is required to meet before being recognized in the consolidated financial statements and applies to all income tax positions. Each income tax position is assessed using a two-step process. A determination is first made as to whether it is more likely than not that the income tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more likely than not criteria, the benefit recorded in the consolidated financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement. The Company believes its tax positions are all more likely than not of being upheld upon examination. As such, the Company has not recorded a liability for uncertain tax benefits as of March 31, 2017 (unaudited) and December 31, 2016. The Company also has no unrecognized tax benefits as of March 31, 2017 (unaudited) and December 31, 2016. The Company includes interest and penalties related to taxes as a component of income tax expense. During 2016 and the unaudited three months ended March 31, 2017 and 2016, the Company did not incur any interest or penalties.

None of the Company’s income tax returns are currently under examination by taxing authorities. The tax returns for 2016, 2015 and 2014 remain subject to examination by the Internal Revenue Service and state taxing authorities.

The effective income tax rate for the year ended December 31, 2016 differs from the U.S. federal statutory income tax rate due to the entity’s pass-through classification for federal tax purposes and for the Texas margin tax rate of 0.75% and because Texas law does not allow any loss carryforward when a taxpayer has negative margin for the tax year.

The Company recognized a deferred state tax benefit as shown in the accompanying consolidated statement of operations for the year ended December 31, 2016. Deferred state income taxes were immaterial during the unaudited three months ended March 31, 2017 and 2016.

The Company maintains cash and cash equivalent balances with major financial institutions, which at times exceed federally insured limits. The Company monitors the financial condition of the financial institution and has experienced no losses associated with these accounts. Substantially all of the Company’s operating accounts receivable result from joint interest operations and from purchasers of oil and gas in the oil and gas industry. This concentration of joint interest owners and oil and gas purchasers may impact the Company’s overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. The Company has not experienced any credit losses on such receivables. The Company cannot ensure that such losses may not occur in the future.

The Company’s purchaser base includes several United States oil and gas operating and production companies. The Company derived all of its oil and gas revenue from one purchaser during the year ended December 31, 2016. The loss of any one purchaser would not have a material adverse effect on the Company’s ability to sell its production of oil and gas.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. In August 2015, the FASB issued ASU 2015-14 to defer the effective date. This standard provides a five-step approach to be applied to all contracts with customers and requires expanded disclosures about the nature, amount, timing and uncertainty of revenue (and the related cash flows) arising from customer contracts, significant judgments and changes in judgments used in applying the revenue model and the assets recognized from costs incurred to obtain or fulfill a contract. This new standard is effective for the Company beginning in the year 2019. Early application is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method. The Company is evaluating the effect that this new guidance will have on its consolidated financial statements and related disclosures. The Company has neither selected a transition method nor has the Company determined the effect of the standard on its ongoing financial reporting.

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements - Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. The amendments require management to assess an entity’s ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in U.S. auditing standards. Specifically, the amendments (1) provide a definition of the term substantial doubt, (2) require an evaluation every reporting period including interim periods, (3) provide principles for considering the mitigating effect of management’s plans, (4) require certain disclosures when substantial doubt is alleviated as a result of consideration of management’s plans, (5) require an express statement and other disclosures when substantial doubt is not alleviated, and (6) require an assessment for a period of one year after the date that the financial statements are issued (or available to be issued). The amendments in this Update are effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. The Company adopted this accounting standard as of December 31, 2016. It did not have a significant impact on the Company.

In February 2016, the FASB issued Accounting Standards Update (“ASU”) No. 2016-02, Leases. The ASU will require lessees to recognize for all leases, (with the exception of short-term leases) at the commencement date, a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. Lessees and lessors may not apply a full retrospective transition approach. The amendments in this ASU are effective for the Company for fiscal years beginning after December 15, 2019, and interim periods within fiscal years beginning after December 15, 2020. Early application of this ASU is permitted. The Company is currently evaluating its impact on their future consolidated financial statements.

In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments, which addressees eight classification issues related to the statement of cash flows: debt prepayment or debt extinguishment costs, settlement of zero-coupon bonds, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions, and separately identifiable cash flows and application of the predominance principle. ASU 2016-15 is effective for the Company for fiscal years beginning after December 15, 2018 and interim periods beginning after December 15, 2019. Early adoption is permitted. The Company is currently evaluating the impact of this accounting standard.

In January 2017, the FASB issued ASU 2017-01, Business Combinations, to clarify the definition of a business by adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of a business. This ASU provides a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or group of similar identifiable assets, the set is not a business. If the screen is not met, this ASU (1) requires that to be considered a business, a set must include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create output and (2) removes the evaluation of whether a market participant could replace the missing elements. ASU 2017-01 is effective for the Company for fiscal years beginning after December 15, 2018 and interim periods beginning after December 15, 2019. Early adoption is permitted under circumstances as prescribed in this ASU. The Company is currently evaluating the impact of this accounting standard.

On July 19, 2016, the Company acquired working interests in certain proved properties from an unrelated third party for a purchase price of $6.51 million. The effective date of this acquisition was May 1, 2016. The Company accounted for this acquisition pursuant to the acquisition method of accounting whereby all the acquired assets and assumed liabilities are recorded at their estimated fair values. Allocation of the purchase is as follows:

Fair values were determined by discounting (at ten percent annually) future estimated net cash flows (Level 3 fair value measurement) associated with estimated proved reserves and apportioning that value on 80% and 20% basis, respectively, to producing leasehold and lease and well equipment. Transaction related costs were immaterial.

On January 15, 2016, the Company entered into a revolving credit agreement (the “Credit Agreement”) with Comerica Bank (the “Bank”). The Credit Agreement provides the Company with a $100 million revolving credit facility that permits borrowings based on the commitments of the lenders and the available borrowing base as determined in accordance with its terms. The Credit Agreement also allows the Company to use the borrowing base for letters of credit.

The borrowing base under the Credit Agreement is determined semiannually based upon the valuation of the reserves attributable to the Company’s oil and gas properties as of March 1 and September 1 of each year. The new borrowing base becomes effective on April 1 and October 1 of each year. As of December 31, 2016 and March 31, 2017 (unaudited), the borrowing base is $2 million until the next redetermination. The Company may request one additional borrowing base redetermination each year, and the lender may request one additional borrowing base redetermination each year. Each time the borrowing base is to be redetermined, the administrative agent under the Credit Agreement will propose a new borrowing base as deemed appropriate by the lender, as described in more detail in the Credit Agreement.

In addition, the Company pays an unused commitment fee of 0.375% of the borrowing base in the event that less than 50% of the borrowing base is used and an unused commitment fee of 0.5% of the borrowing base in the event that greater than 50% of the borrowing base is used.

The Credit Agreement is secured by a first priority lien and security interest in all assets and equity of the Company.

As of December 31, 2016 the Company had borrowings of $1,500,000 outstanding and $25,000 of letters of credit issued pursuant to the Credit Agreement. As of March 31, 2017 the Company had borrowings of $1,500,000 (unaudited) outstanding and $25,000 (unaudited) of letters of credit issued pursuant to the Credit Agreement.

The initial term of the facility is three years. Base rate advances bear interest at the Base Rate Margin, as defined in the Credit Agreement, plus the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus one-half of one percent and (c) the Daily Adjusting LIBOR Rate plus one percent. Eurodollar-based advances bear interest at the Applicable Margin, as defined in the Credit Agreement, plus the quotient of the LIBOR rate divided by a percentage equal to 100% minus the maximum rate on such date at which the administrative agent is required to maintain reserves on Eurocurrency Liabilities as defined in and pursuant to Regulation D of the Board of Governors of the Federal Reserve System. As of December 31, 2016, the effective interest rate paid on the outstanding debt was 3.505%. As of March 31, 2017, the effective interest rate paid on the outstanding debt was 3.529% (unaudited).

The Company is required to meet certain affirmative and negative covenants that are considered normal and customary in the industry in connection with loans of this kind and size, with customary exceptions and materiality qualifiers, including but not limited to reporting requirements, insurance, maintenance of collateral, ongoing satisfaction with operator of properties, and limitations on additional indebtedness, change of control, transactions with affiliates and distributions, and hedging limitations. The Company is subject to certain

restrictive financial covenants under the Credit Agreement including maintaining a debt to Capitalization ratio, as defined in the Credit Agreement, of not more than 15%, a current ratio of not less than 1.00, and maintaining a debt to EBITDAX ratio, after the Borrowing Base Equalization Date, as defined in the Credit Agreement, of not more than 4.00 to 1.00.

As of March 31, 2017 (unaudited) and December 31, 2016, the Company was in compliance with its financial covenants.

The membership interests in the Company are divided into three series of units, referred to as Series A, Series B, and Series C. The Company is authorized to issue an unlimited number of Series A Units, an aggregate of up to 1,500,000 Series B Units and an aggregate of up to 100,000 Series C Units.

On the date of inception, investors contributed to the Company cash of approximately $15,000,000. In exchange for such contributions, the Company issued a total of approximately 15,000,000 Series A Units. Investors have made total future equity commitments in the amount of approximately $119,000,000.

On the date of inception, RocMar and Lightspeed contributed to the Company their membership interests in Battlecat Oil and Gas, LLC in exchange for 1,000,000 Series A Units.

On April 9, 2015 the Company’s limited liability company agreement was amended and restated in connection with the Company’s issuance of 1,500,000 Series B Units in the aggregate to RocMar and Lightspeed. The owners of RocMar and Lightspeed are co-chief executive officers of the Company.

At December 31, 2016, there were approximately 40,800,000 Series A Units, 1,500,000 Series B Units and approximately 96,000 Series C Units issued and outstanding.

At March 31, 2017, there were approximately 43,280,000 Series A Units (unaudited), 1,500,000 Series B Units (unaudited) and approximately 96,000 Series C Units (unaudited) issued and outstanding.

Series C Units are issued pursuant to equity grant agreements to key employees to incentivize such employees to enhance the profitability and growth of the Company. The value of C Unit grants, which are intended to represent profits interests and have threshold value and initial capital account of $0 for tax, is nominal for financial statement purposes. The Units vest according to schedules determined by the grantee’s individual Restricted Unit Agreement, which approximate 20% annually.

Profits and losses of the Company are allocated to members pursuant to the limited liability company agreement. Distributions are determined by the board of managers.

The Company’s managing directors are also partners in Sentry Technologies, Inc. (“Sentry”), a provider of oil and gas monitoring equipment. During the year ended December 31, 2016, the Company paid Sentry $390,049, of which $230,270 was for the reimbursement of general and administrative expenses and $159,779 for well related expenses. As of December 31, 2016, the Company had outstanding payables of $30,508 due to the related party. During the three months ended March 31, 2017 and 2016, the Company paid Sentry $75,823 (unaudited) and $126,294 (unaudited), respectively, of which $38,780 (unaudited) and $67,707 (unaudited) was for the reimbursement of general and administrative expenses and $37,043 (unaudited) and $58,587 (unaudited), respectively, for well related expenses. As of March 31, 2017, the Company had outstanding payables of $11,399 (unaudited) due to the related party.

The Company entered into a long-term sublease agreement, which expires in March 2020, with Sentry in which it pays 80% of the total rent and any related operational expenses associated with the lease. Sentry invoices the Company monthly. Minimum rental payments under the sublease agreement are recognized on a straight‑line basis over the term of the sublease. Rental expense for the year ended December 31, 2016 was $76,931. Rental expense for the three months ended March 31, 2017 and 2016, respectively, was $31,557 (unaudited) and $25,601 (unaudited). Remaining minimum lease payments under this sublease are as follows:

Due to the nature of the Company’s business, some environmental contamination of its properties owned or leased is a risk factor. However, management of the Company monitors these properties and insures for these risks, which are inherent in the Company’s business. Management of the Company does not believe there is a need for a provision for potential remediation costs to be reflected in the consolidated financial statements as of December 31, 2016 and March 31, 2017 (unaudited).

The Company may be subject to various lawsuits and claims arising in the ordinary course of its business. The Company records accruals for potential losses when, in management’s opinion, such losses are probable and reasonably estimable. The Company believes that resolution of such litigation will not have a material adverse effect on the Company. At March 31, 2017 (unaudited) and December 31, 2016, no provision for any lawsuits and/or claims is included in the consolidated financial statements.

The Company evaluates events and transactions occurring after the balance sheet date which could affect its consolidated financial position and/or results of their operations as of and for the year ended December 31, 2016. The Company evaluated such events and transactions through March 23, 2017, which is the date the consolidated financial statements were available to be issued.

In preparation of the unaudited consolidated financial statements for the three months ended March 31, 2017 and 2016, management has evaluated subsequent events through November 30, 2017. The following information is unaudited.

On June 15, 2017, the Company completed its sale of certain oil and gas properties in DeWitt, Gonzales and Karnes Counties, Texas to Lonestar Resources US, Inc. (“Purchaser). The unadjusted purchase price for the sale was approximately $60 million consisting of (i) $55 million in cash and (ii) 1,184,632 shares of the Purchaser’s Series B Preferred Stock valued at approximately $4.8 million.

The following information has been prepared internally by Lonestar’s petroleum engineers based on a third-party petroleum engineering firm’s reserves estimates as of December 31, 2016. The reserve estimates have been prepared in accordance with SEC rules and accounting standards based on the 12-month unweighted arithmetic average of the first-day-of-the-month prices as of December 31, 2016 with appropriate adjustments for location, quality, gathering and marketing adjustments.

Proved reserves are estimated quantities of natural gas, crude oil and natural gas liquids (NGLs) which 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 which are expected to be recovered through existing wells with existing equipment and operating methods. Below are the net quantities of total proved reserves and proved developed reserves of the Company. An analysis of the change in estimated quantities of reserves, all of which are located within the United States, is presented below.

										Oil Equivalent
	Oil (MBbl)			NGL (MBbl)			Gas (MMcf)			(Mboe)
Proved reserves as of January 1, 2016		813			—			136			836
Revisions of previous estimates (1)		(407	)		1			(117	)		(426	)
Purchases of reserves in place		105			—			53			114
Production		(100	)		(1	)		(5	)		(102	)
Proved reserves as of December 31, 2016		411			—			67			422
Proved developed reserves:
As of December 31, 2016		411			—			67			422
Proved undeveloped reserves:

As of December 31, 2016		—			—			—			—

The standardized measure related to proved oil, gas and NGL reserves for the Company is summarized below. This summary is based on a valuation of proved reserves using discounted cash flows based on SEC pricing applicable for each year, costs and economic conditions and a 10% discount rate. The additions to proved reserves from new discoveries and extensions and the impact of changes in prices and costs associated with proved reserves could vary significantly from year to year. Accordingly, the information presented below is not an estimate of the fair value of the Company’s properties and should not be considered indicative of any trends.

In accordance with SEC and FASB requirements, our estimated net proved reserves and standardized measure at December 31, 2016 utilized prices (adjusted for quality and basis differentials) based on the twelve-month unweighted average of the first-of-the-month prices of West Texas Intermediate (“WTI”) oil price which equates to $42.75 per Bbl, approximately $12.40 per Bbl of NGL calculated as 29% of the WTI oil price per Bbl, and an average Henry Hub spot gas price which equates to $2.48 per MMBtu of gas.

The following table sets forth the changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the period indicated.


Asset retirement obligations, January 1, 2016	$160,729
Liabilities acquired or incurred	188,508
Accretion expense	15,409
Asset retirement obligations, December 31, 2016	$364,646


		2016

Land		$322,062
Leasehold improvements		123,690
Furniture, equipment and software		110,513
Property and equipment		556,265
Less: accumulated depreciation and amortization		(105,644)
Property and equipment, net		$450,621


Producing leasehold		$5,239,767
Lease and well equipment		$1,498,450
Revenue payable		$(38,977)
Asset retirement obligations		$(188,508)


Years Ending December 31,

2017	$55,978
2018	61,965
2019	63,585
2020	15,998

Total	$197,526

	December 31, 2016
	(in thousands)
Future cash inflows	$	16,681
Future Costs:
Production		(8,308	)
Development		—
Future inflows before tax		8,373
Future income tax expense		(63	)
Future net cash flows		8,310
Discount of 10% per annum		(2,581	)
Standardized measure of discounted future net cash flows	$	5,729

Members' equity, January 1, 2016		26,471,457
Cash contributions		8,000,000
Net loss		(8,901,734	)
Members' equity, December 31, 2016		25,569,723
Cash contributions		2,500,000
Net loss		(1,682,071	)
Members' equity, March 31, 2017 (Unaudited)	$	26,387,652

	December 31, 2016
	(in thousands)
Standardized measure, beginning of year	$	10,257
Accretion of discount		1,033
Net change in sales price net of production costs		(5,339	)
Changes in estimated future development costs		5,702
Extensions, discoveries and improved recovery		—
Purchase of minerals in place		1,215
Changes of production rates (timing) and other		4,154
Revision of quantity estimates		(9,179	)
Net change in income taxes		34
Sales of oil and gas produced, net of production costs		(2,148	)
Sales of minerals in place		—
Standardized measure, end of year	$	5,729