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10-Q 1 d190731d10q.htm FORM 10-Q Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark one)

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2016

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 000-55301

Lynden Energy Corp.

(Exact name of registrant as specified in its charter)


British Columbia
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)

666 Burrard Street Suite 500 Vancouver, British Columbia		V6C 3P6
(Address of principal executive offices)		(Zip code)

(604) 629-2991

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Registration S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

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

The registrant had 130,198,411 shares of common stock outstanding at May 13, 2016.

TABLE OF CONTENTS


	Page

Glossary of Certain Terms and Conventions Used Herein		1

Cautionary Statement Concerning Forward-Looking Statements		4

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Condensed Consolidated Interim Balance Sheets as of March 31, 2016 and June 30, 2015		6

Condensed Consolidated Interim Statements of Income (Loss) and Comprehensive Income (Loss) for the Three and Nine Months Ended March 31, 2016 and 2015		7

Condensed Consolidated Interim Statement of Changes in Equity for the Nine Months Ended March 31, 2016 and 2015		8

Condensed Consolidated Interim Statements of Cash Flows for the Nine Months Ended March 31, 2016 and 2015		9

Notes to Condensed Consolidated Interim Financial Statements		10

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		17

Item 3. Quantitative and Qualitative Disclosures About Market Risk		31

Item 4. Controls and Procedures		31

PART II. OTHER INFORMATION

Item 1. Legal Proceedings		33

Item 1A. Risk Factors		33

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		33

Item 6. Exhibits		33

GLOSSARY OF CERTAIN TERMS AND CONVENTIONS USED HEREIN

Within this report, the following terms have these specific meanings:

“Basin.” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

“Bbl.” One stock tank barrel of 42 U.S. gallons liquid volume used herein in reference to crude oil, condensate or NGL.

“Bbls/d.” Bbls per day.

“Boe.” A barrel of oil equivalent and is a standard convention used to express oil, NGL and natural gas volumes on a comparable oil equivalent basis. Natural gas equivalents are determined under the relative energy content method by using the ratio of 6.0 Mcf of gas to 1.0 Bbl of oil or NGL.

“Boe/d.” One Boe per day.

“Btu” or “British Thermal Unit.” The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

“Completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“Differential.” An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.

“Dry hole” or “Dry well.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

“E&P.” Exploration and production of oil, NGL and natural gas.

“Exploitation.” A development or other project that may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

“Enhanced recovery.” The recovery of oil, NGL and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Enhanced recovery methods are often applied when production slows due to depletion of the natural pressure.

“Exploratory well.” A well drilled to find and produce oil, NGL or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil, NGL or natural gas in another reservoir or to extend a known reservoir.

“Field.” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

“Formation.” A layer of rock which has distinct characteristics that differs from nearby rock.

“Gross acres” or “gross wells.” The total acres or wells, as the case may be, in which a working interest is owned. All gross acre figures in this Quarterly Report on Form 10-Q are approximates and estimated.

“Horizontal drilling.” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

“Hydraulic fracturing.” The technique of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to keep the channel open, so that fluids or natural gases may more easily flow through the formation.

“LIBOR.” The London Interbank Offered Rate, which is a market rate of interest.

“MBbl.” One thousand barrels of crude oil, condensate or NGL.

“MBoe.” One thousand Boes.

“Mcf.” One thousand cubic feet of natural gas.

“Mcf/d.” One Mcf per day.

“MGal.” One thousand gallons of NGL or other liquid hydrocarbons.

“MMBbl.” One million barrels of crude oil, condensate or NGL.

“MMBoe.” One million Boes.

“MMBtu.” One million British Thermal Units.

“MMcf.” One million cubic feet of natural gas.

“Net acres” or “net wells.” The number of net wells or acres is the sum of the fractional working interests owned in gross wells or acres expressed as whole numbers and fractions thereof. A net well or acre is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one. All net acre figures in this Quarterly Report on Form 10-Q are approximates and estimated.

“NGL.” Natural gas liquids. Hydrocarbons found in natural gas that may be extracted as liquefied petroleum gas and natural gasoline.

“NYMEX.” The New York Mercantile Exchange.

“Operator.” The individual or company responsible for the exploration and/or production of an oil or well or lease.

“P&NG.” Petroleum and natural gas.

“PDP.” Proved developed producing reserves.

“Plugging.” The sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface.

“Productive well.” A well that is not a dry well.

“Proved developed reserves.” Reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and installed extraction equipment and infrastructure operation at the time of the reserve estimate if the extraction is by means not involving a well.

“Proved reserves.” The quantities of oil, NGL and natural gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

“Proved undeveloped reserves” or “PUDs.” Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

“Realized price.” The cash market price less all expected quality, transportation and demand adjustments.

“Recompletion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of oil, NGL or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible oil, NGL and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

“SEC.” The United States Securities and Exchange Commission.

“Spacing.” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

“Spot market price.” The cash market price without reduction for expected quality, transportation and demand adjustments.

“Standardized measure.” The year-end present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC, without giving effect to non-property related expenses (such as certain general and administrative expenses, debt service and future federal income tax expenses) or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%.

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

“Unit.” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

“We,” “our,” “us” or like terms and “Lynden” and the “Company” refer to Lynden Energy Corp. and its subsidiaries, Lynden Exploration Ltd. and Lynden USA Inc.

“Wellbore.” The hole drilled by the bit that is equipped for oil or natural gas production on a completed well. Also called well or borehole.

“West Texas Intermediate Sweet.” A light, sweet blend of oil produced from the fields in West Texas.

“Working interest.” The right granted to the lessee of a property to explore for and to produce and own oil, NGL, natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

“Workover.” Operations on a producing well to restore or increase production.

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:

•

the volatility of commodity prices, product supply and demand;

•

competition;

•

access to and cost of capital;

•

uncertainties about estimates of reserves and resource potential and the ability to add proved reserves in the future;

•

the assumptions underlying production forecasts;

•

the quality of technical data;

•

environmental and weather risks, including the possible impacts of climate change;

•

the ability to obtain environmental and other permits and the timing thereof;

•

government regulation or action;

•

the costs and results of drilling and operations;

•

the availability of equipment, services, resources and personnel required to complete the Company’s operating activities;

•

access to and availability of transportation, processing and refining facilities;

•

the financial strength of counterparties to the Company’s reducing revolving credit facility and the purchasers of the Company’s production;

•

the ability to obtain shareholder and court approval and to successfully complete the arrangement (the “Transaction”) with Earthstone Energy, Inc. ( “Earthstone”);

•

the ability to complete the proposed acquisition of the Company by Earthstone on anticipated terms and timetable;

•

Earthstone’s ability to successfully integrate the Company after the Earthstone Transaction and to achieve anticipated benefits from the Transaction;

•

the possibility that various closing conditions for the Earthstone Transaction may not be satisfied or waived; and

•

acts of war or terrorism.

For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see “Part I, Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended June 30, 2015, and “Part II, Item 1A. Risk Factors” in our Quarterly Report on Form 10-Q for the quarter ended December 31, 2015, both of which are also available under our profile at the SEDAR website (www.sedar.com).

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Condensed Consolidated Interim Balance Sheets as of March 31, 2016 and June 30, 2015

(Presented in United States dollars, except where indicated)

(Unaudited)


	Notes	March 31, 2016			June 30, 2015
ASSETS
Current assets
Cash and cash equivalents		$	7,542,271		$	8,748,008
Trade and other receivables, net of allowance for doubtful accounts	3,8		1,386,754			1,660,135
Income taxes receivable			347,412			469,434
Prepaid expenses			83,803			50,613

Total current assets			9,360,240			10,928,190

Non-current assets
Property, plant and equipment	4		104,146,787			107,283,684

Total assets		$	113,507,027		$	118,211,874

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Trade and other payables	8	$	1,858,906		$	1,646,846
Credit facility	5,8		36,579,326			—

Total current liabilities			38,438,232			1,646,846

Non-current liabilities
Credit facility	5,8		—			29,908,366
Asset retirement liabilities			310,998			278,790
Deferred tax liabilities			16,120,892			17,497,692

			16,431,890			47,684,848

Total liabilities			54,870,122			49,331,694

Shareholders’ equity
Share capital - authorized unlimited common shares, no par value
Issued and outstanding: March 31, 2016 - 130,198,411 June 30, 2015 - 130,198,411	6		65,622,727			65,622,727
Paid-in capital	6		15,228,879			15,228,879
Accumulated other comprehensive loss			(4,157,907	)		(3,788,414	)
Deficit			(18,056,794	)		(8,183,012	)

Total shareholders’ equity			58,636,905			68,880,180

Total liabilities and shareholders’ equity		$	113,507,027		$	118,211,874

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

Condensed Consolidated Interim Statements of Income (Loss) and Comprehensive Income (Loss) for the Three and Nine Months Ended March 31, 2016 and 2015

(Presented in United States dollars, except where indicated)

(Unaudited)


	Notes	Three months ended March 31,						Nine months ended March 31,
	Notes	2016			2015			2016			2015
Revenue and other income
Oil and natural gas sales, net of royalties		$	2,483,043		$	3,699,751		$	9,570,382		$	17,593,290
Derivative financial instruments gain			120,204			—			901,539			—
Interest income			14,582			30,249			66,403			103,539

Total revenue and other income			2,617,829			3,730,000			10,538,324			17,696,829

Expenses
Production and operating expenses			(2,040,665	)		(1,959,220	)		(5,062,440	)		(4,651,407	)
Depletion, depreciation and accretion			(2,394,500	)		(2,704,024	)		(7,271,729	)		(8,166,473	)
Exploration and impairments			23,701			—			(6,545,578	)		(449,541	)
General and administrative			(783,179	)		(805,744	)		(1,998,466	)		(1,720,508	)
Share of loss in equity investment			—			(431,919	)		—			(431,919	)
Interest			(349,213	)		(279,960	)		(781,384	)		(794,918	)

Total expenses			(5,543,856	)		(6,180,867	)		(21,659,597	)		(16,214,766	)

(Loss) income before income taxes			(2,926,027	)		(2,450,867	)		(11,121,273	)		1,482,063
Income tax recovery (expense)			673,191			339,000			1,247,491			(1,449,000	)

Net (loss) income			(2,252,836	)		(2,111,867	)		(9,873,782	)		33,063

Other comprehensive (loss) income
Foreign currency translation adjustment			430,910			(835,324	)		(369,493	)		(1,741,618	)

Total comprehensive (loss) income for the period		$	(1,821,926	)	$	(2,947,191	)	$	(10,243,275	)	$	(1,708,555	)

Weighted average number of common shares outstanding
Basic	6		130,198,411			130,198,411			130,198,411			129,994,825
Diluted	6		130,198,411			130,198,411			130,198,411			130,967,825
Net earnings per common share
Basic		$	(0.02	)	$	(0.02	)	$	(0.08	)	$	0.00
Diluted		$	(0.02	)	$	(0.02	)	$	(0.08	)	$	0.00

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

Condensed Consolidated Interim Statement of Changes in Equity for the Nine Months Ended March 31, 2016 and 2015

(Presented in United States dollars, except where indicated)

(Unaudited)


	Common Shares				Paid-in Capital		Accumulated Other Comprehensive Loss			Deficit			Total
	Number		Amount		Paid-in Capital		Accumulated Other Comprehensive Loss			Deficit			Total
Balance at June 30, 2015		130,198,411	$	65,622,727	$	15,228,879	$	(3,788,414	)	$	(8,183,012	)	$	68,880,180
Foreign currency translation		—		—		—		(369,493	)		—			(369,493	)
Net loss for the period		—		—		—		—			(9,873,782	)		(9,873,782	)

Balance at March 31, 2016		130,198,411	$	65,622,727	$	15,228,879	$	(4,157,907	)	$	(18,056,794	)	$	58,636,905


	Common Shares				Paid-in Capital			Accumulated Other Comprehensive Loss			Deficit			Total
	Number		Amount		Paid-in Capital			Accumulated Other Comprehensive Loss			Deficit			Total
Balance at June 30, 2014		129,275,911	$	65,160,387	$	15,434,128		$	(212,663	)	$	(7,617,859	)	$	72,763,993
Common shares issued for cash
Exercise of stock options		922,500		462,352		(205,260	)		—			—			257,092
Foreign currency translation		—		—		—			(1,741,618	)		—			(1,741,618	)
Net income for the period		—		—		—			—			33,063			33,063

Balance at March 31, 2015		130,198,411	$	65,622,739	$	15,228,868		$	(1,954,281	)	$	(7,584,796	)	$	71,312,530

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

Condensed Consolidated Interim Statements of Cash Flows for the Nine months Ended March 31, 2016 and 2015

(Presented in United States dollars, except where indicated)

(Unaudited)


	Notes		Nine months ended March 31,
	Notes		2016			2015
Operating activities
Net (loss) income for the period			$	(9,873,782	)	$	33,063
Adjustments for:
Accrued interest				(79,040	)		44,867
Unrealized gain on derivative financial instruments				(426,420	)		—
Depletion, depreciation and accretion				7,271,729			8,166,473
Impairments				6,565,361			449,541
Share of loss in equity investment				—			431,919
Deferred income taxes				(1,376,800	)		1,167,000
Unrealized foreign exchange gain				(156,432	)		(417,337	)
Changes in non-cash working capital items:
Trade and other receivables				559,761			1,693,100
Income taxes receivable				122,022			—
Prepaid expenses				(33,190	)		(86,215	)
Trade and other payables				1,200,781			(38,344	)
Income taxes payable				—			157,000

Cash generated by operating activities				3,773,990			11,601,067

Investing activities
Advances to investment in associate				—			(431,919	)
Acquisition of property, plant and equipment				(11,516,666	)		(24,193,545	)

Cash used in investing activities				(11,516,666	)		(24,625,464	)

Financing activities
Drawings on credit facility				6,750,000			9,500,000
Common shares issued for cash, net of issue costs				—			257,092

Cash generated by financing activities				6,750,000			9,757,092

Effect of exchange rate on cash held in foreign currency				(213,061	)		(1,324,281	)

Change in cash and cash equivalents during the period				(1,205,737	)		(4,591,586	)
Cash and cash equivalents, beginning of period				8,748,008			13,955,890

Cash and cash equivalents, end of period			$	7,542,271		$	9,364,304

Cash and cash equivalents are composed of:
Cash			$	714,328		$	646,239
Guaranteed investment certificates				6,827,943			8,718,065

			$	7,542,271		$	9,364,304

Supplemental cash flow information		9

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

Notes to Condensed Consolidated Interim Financial Statements

1. Description of Business

Lynden Energy Corp. (the “Company” or “Lynden”) is a public company continued under the Business Corporations Act (British Columbia). The Company’s business is to acquire, explore and develop petroleum and natural gas (“P&NG”) properties. The Company’s principal business activities are located in Texas, United States of America. The Company’s common shares trade on the TSX Venture Exchange (“TSX-V”) under the symbol LVL. The head office is located in Vancouver, British Columbia, Canada.

On December 17, 2015, Lynden and Earthstone Energy, Inc. (“Earthstone”) announced a definitive agreement (as amended, the “Earthstone Agreement”) under which Earthstone will acquire Lynden in an all-stock transaction (the “Transaction”) under a plan of arrangement pursuant to the Business Corporations Act (British Columbia). Under the Earthstone Agreement, the terms of which were unanimously approved by the Boards of Directors of both companies, Earthstone will issue approximately 3.7 million shares of common stock to Lynden’s shareholders. On March 29, 2016, the parties to the Earthstone Agreement entered into an amendment to the Earthstone Agreement clarifying certain technical matters related to the mechanics of the plan of arrangement, mainly that a wholly-owned subsidiary of Earthstone will be the entity that (i) acquires all of the outstanding common stock of Lynden and (ii) amalgamates with Lynden to form one corporate entity with Lynden surviving the amalgamation as a wholly-owned subsidiary of Earthstone. The amendment also extended the date by which Lynden must hold its special meeting to May 27, 2016, and makes miscellaneous conforming changes consistent with the foregoing.

Under the Earthstone Agreement, Lynden shareholders will receive 0.02842 of a share of Earthstone stock in exchange for each share of Lynden common stock held, representing consideration to each Lynden shareholder of $0.52 per share based on the closing price of Earthstone common stock on December 16, 2015. Following the Transaction, shareholders of Earthstone and Lynden are expected to own approximately 79% and 21%, respectively, of the combined company on a fully diluted basis.

The parties have made representations, warranties and covenants in the Earthstone Agreement, including (i) that the parties will, subject to certain exceptions, conduct their respective businesses in the ordinary course and will not engage in certain activities between the execution of the Earthstone Agreement and the consummation of the Transaction; and (ii) the agreement of the Company, subject to certain exceptions, not to solicit alternative transactions or provide information in connection with alternative transactions. Completion of the Transaction is subject to: (1) the approval by the shareholders of the Company of the Earthstone Agreement; (2) a final order from the court in British Columbia to approve the Earthstone Agreement and the fairness of the terms and conditions of the Transaction; (3) applicable regulatory approvals, including certain stock exchange approvals; (4) the absence of legal impediments prohibiting the transactions; and (5) other customary closing conditions. A Special Meeting of Shareholders was held on May 12, 2016, at which meeting the Lynden securityholders approved a special resolution in respect of the Transaction. While a joint information statement/circular has been submitted to all Earthstone stockholders, the Transaction has been approved by the requisite majority pursuant to Earthstone’s certificate of incorporation which provides for approval via stockholder action by written consent.

2. Significant Accounting Policies

a) Basis of presentation

These condensed consolidated interim financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“US GAAP”) as at March 31, 2016, and for the three and nine months ended March 31, 2016, and the 2015 comparative period. These condensed consolidated interim financial statements do not include all the necessary annual disclosures as prescribed under US GAAP and should be read in conjunction with the Company’s audited consolidated financial statements as of and for the year ended June 30, 2015.

In management’s opinion, the condensed consolidated financial statements reflect all adjustments (including normal recurring adjustments) which are necessary to present fairly the financial position as at March 31, 2016, and results of operations and cash flows for all periods presented.

b) Use of estimates

The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the amount and timing of recording of assets, liabilities, revenues and expenses since the determination of these amounts may be dependent on future events. Significant estimates made by management include: oil and natural gas reserves and related present value of future cash flows, depreciation, depletion, amortization and accretion (“DDA&A”), impairment, asset retirement obligations, income taxes, and share-based compensation. The Company uses the most current information available and exercises judgment in making these estimates and assumptions. There have been no significant changes in the estimates or judgments between these condensed consolidated interim financial statements and the audited consolidated financial statements for the year ended June 30, 2015.

c) Recent accounting pronouncements

As of July 1, 2015, the Company adopted the following Financial Accounting Standards Board (“FASB”) accounting standards updates. The adoption of these standards did not have a material impact on the Company’s condensed consolidated interim financial statements.

•

Accounting Standards Update 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (effective for annual periods beginning on or after December 15, 2014)

The FASB has issued the following accounting standards updates which are not yet effective:

•

Accounting Standards Update 2014-09, Revenue From Contracts With Customers (effective for annual periods beginning after December 15, 2017)

•

Accounting Standards Update 2014-12, Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could be Achieved After the Requisite Service Period (effective for annual periods beginning after December 15, 2015)

•

Accounting Standards Update 2014-15, Disclosure of Uncertainties About an Entity’s Ability to Continue as a Going Concern (effective for annual periods ending after December 15, 2016)

•

Accounting Standards Update 2015-03, Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs (effective for annual periods beginning after December 15, 2015)

•

Accounting Standards Update 2015-15, Imputation of Interest: Simplifying the Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements (effective for annual periods beginning after December 15, 2015)

•

Accounting Standards Update 2015-16, Business Combinations: Simplifying the Accounting for Measurement – Period Adjustments (effective for annual periods beginning after December 15, 2015)

•

Accounting Standards Update 2016-01, Financial Instruments: Recognition and Measurement of Financial Assets and Financial Liabilities (effective for annual periods beginning after December 15, 2017)

The Company has not early adopted these accounting standards updates and is currently assessing the application of these standards on the results of operations and financial position of the Company.

3. Trade and Other Receivables


	March 31, 2016		June 30, 2015
Accounts receivable – trade	$	76,538	$	1,340,803
Accrued receivables		1,005,351		237,430
Other receivable – derivative financial asset		286,380		—
Sales taxes receivable		18,485		81,902

	$	1,386,754	$	1,660,135

The Company did not have any allowance for doubtful accounts as at March 31, 2016, and June 30, 2015. As at March 31, 2016, $990,842 (June 30, 2015 - $1,532,382) is owing from one counterparty.

Other receivable consists of a fair valued derivative financial instrument (discussed in more detail in note 8).

4. Property, Plant and Equipment


	March 31, 2016
	Cost		Accumulated Depletion, Depreciation and Impairment			Net Book Value
Petroleum and natural gas properties
Proved	$	132,127,614	$	(30,346,363	)	$	101,781,251
Exploratory well costs		37,956,871		(35,591,749	)		2,365,122

		170,084,485		(65,938,112	)		104,146,373
Computer equipment		2,001		(1,587	)		414

Total property, plant and equipment	$	170,086,486	$	(65,939,699	)	$	104,146,787


	June 30, 2015
	Cost		Accumulated Depletion, Depreciation and Impairment			Net Book Value
Petroleum and natural gas properties
Proved	$	122,491,540	$	(23,096,935	)	$	99,394,605
Exploratory well costs		36,938,662		(29,050,534	)		7,888,128

		159,430,202		(52,147,469	)		107,282,733
Computer equipment		2,081		(1,130	)		951

Total property, plant and equipment	$	159,432,283	$	(52,148,599	)	$	107,283,684

Proved petroleum and natural gas assets

Proved petroleum and natural gas assets consist of lease acquisition costs, costs of drilling and equipping development wells, and construction of related production facilities all relating to the Company’s Midland Basin property.

Exploratory well costs

Exploratory well costs consist of costs associated with the drilling and equipping of exploratory wells relating to 1) the Mitchell Ranch Project; and 2) one vertical well location in the Midland Basin. The Company is performing economic evaluations including, but not limited to, results of additional appraisal drilling, well test analysis, additional geological and geophysical data, facilities and infrastructure development options, development plan approval, and permitting.

During the three months ended December 31, 2015, it was determined that test results from four exploratory test wells drilled in fiscal 2015 had not identified significant reserves. Consequently, the costs attributable to these wells and a portion of the Mitchell Ranch Project leasehold costs, totaling $6,565,361, were written off.

5. Credit Facility

The Company has a reducing revolving line of credit (the “Credit Facility”) in an amount up to $100 million. As at March 31, 2016, the Credit Facility has a borrowing base of $40.0 million, of which $36.5 million has been drawn down. The Credit Facility bears interest determined by the percent of the borrowing base utilized and by elections made by the Company. Amounts drawn down under the Credit Facility will bear interest at a rate of LIBOR plus a range of 3.00% to 3.50% or at a rate of U.S. prime plus a range of 2.00% to 2.50%. A minimum interest rate of 3.5% is required on borrowings under the Credit Facility. Payments under the Credit Facility will be required to the extent that outstanding principal and interest exceed the borrowing base. Other fees may also apply pursuant to the bank’s re-determinations of the borrowing base. Changes in borrowing base are made based on the bank’s engineering valuation of the Company’s oil and gas reserves. The borrowing base is re-determined semi-annually; however, the Company may request two additional re-determinations of the borrowing base annually. The lender`s next engineering valuation of the Company’s oil and gas reserves and re-determination of the borrowing base is anticipated to be completed in June 2016.

The Credit Facility contains certain mandatory covenants, including minimum current ratio and cash flow requirements, and other standard business operating covenants. During the three months ended March 31, 2016, the Company did not comply with a mandatory covenant, the interest coverage ratio, which non-compliance has been waived by the lenders. The Company has pledged its interest in its P&NG and other assets as security for liabilities pursuant to the Credit Facility. Amounts owing on the Credit Facility are payable when the Credit Facility expires in August 2016, unless otherwise extended by the parties, or payable on demand on the event of default. As a result of the Credit Facility expiring in less than one year, the amount due under the Credit Facility has been classified as a current liability. As a result of the entry into the Earthstone Agreement, the Company does not currently plan on committing to an extension of the Credit Facility.

6. Shareholders’ Equity

a) Authorized

An unlimited number of common shares without par value.

An unlimited number of preference shares without par value.

b) Earnings per share:

Diluted earnings per share computation


	Three months ended March 31,						Nine months ended March 31,
	2016			2015			2016			2015
Numerator:
Net (loss) income	$	(2,252,836	)	$	(2,111,867	)	$	(9,873,782	)	$	33,063

Denominator:
Weighted average number of common shares (basic)		130,198,411			130,198,411			130,198,411			129,994,825
Dilutive effect of share options		—			—			—			436,429
Dilutive effect of warrants		—			—			—			536,571

Weighted average number of common shares (diluted)		130,198,411			130,198,411			130,198,411			130,967,825

Diluted earnings per common share	$	(0.02	)	$	(0.02	)	$	(0.08	)	$	0.00

For the three months ended March 31, 2016, 4,010,000 (2015 – 4,270,000) share options are not dilutive and have been excluded from the dilutive earnings per share calculation. For the three months ended March 31, 2016, nil (2015 – 7,512,000) warrants are not dilutive and have been excluded from the dilutive earnings per share calculation.

For the nine months ended March 31, 2016, 4,010,000 (2015 – 2,612,500) share options are not dilutive and have been excluded from the dilutive earnings per share calculation. For the nine months ended March 31, 2016, nil (2015 – nil) warrants are not dilutive and have been excluded from the dilutive earnings per share calculation.

c) Stock option plan

The Company has a stock option plan whereby a maximum of 10% of the issued and outstanding common shares of the Company may be reserved for issuance pursuant to the exercise of stock options. The term of the stock options granted are fixed by the board of directors and are not to exceed ten years. The exercise prices of the stock options are determined by the board of directors but shall not be less than the closing price of the Company’s common shares on the day preceding the day on which the directors grant the stock options, less any discount permitted by the TSX-V. Subject to any vesting schedule imposed by the Company’s board of directors in respect of any specific stock option grants, the stock options vest immediately on the date of grant except for stock options granted to investor relations consultants which vest over a twelve month period.

The changes in stock options issued during the nine months ended March 31, 2016, and the year ended June 30, 2015, are as follows:


	Nine months ended March 31, 2016					Year ended June 30, 2015
	Number of options			Weighted average exercise price (CDN$)		Number of options			Weighted average exercise price (CDN$)
Balance, beginning of period		4,270,000		$	0.69		6,632,500		$	0.61
Exercised		—		$	—		(922,500	)	$	0.31
Expired		(260,000	)	$	0.60		(1,440,000	)	$	0.55

Balance, end of period		4,010,000		$	0.70		4,270,000		$	0.69

The following table summarizes information about stock options outstanding and exercisable at March 31, 2016:


	Options outstanding				Options exercisable
Exercise price (CDN$)	Number of options		Weighted average remaining life (years)		Number of options		Weighted average remaining life (years)
$0.50		1,397,500		1.26		1,397,500		1.26
$0.80		2,612,500		0.31		2,612,500		0.31

		4,010,000		0.64		4,010,000		0.64

7. Related Party Transactions

The Company incurred the following fees and expenses in the normal course of operations at amounts agreed upon between the parties to companies owned by key management and directors. The legal fees are paid to a law firm in which a director is a shareholder and the transportation and marketing costs are paid to Abajo Gas Transmission Company, LLC, the Company’s investment in associate.


	Three months ended March 31,				Nine months ended March 31,
	2016		2015		2016		2015
Legal fees	$	38,554	$	14,341	$	87,835	$	42,682
Transportation and marketing costs		9,098		8,569		33,906		27,859

Total	$	47,652	$	22,910	$	121,741	$	70,541

As at March 31, 2016, trade and other payables include $23,281 (June 30, 2015 - $33,320) owing to related parties. Amounts due to or from related parties are unsecured, non-interest bearing and are due on demand.

8. Financial Instruments

As at March 31, 2016, the Company’s financial instruments are cash and cash equivalents, trade and other receivables, credit facility, and trade and other payables. These financial instruments are classified as follows:

Cash and cash equivalents – loans and receivables

Trade and other receivables – loans and receivables

Credit facility – other financial liabilities

Trade and other payables – other financial liabilities

Derivative asset/liability (included in trade and other receivables) – fair value through profit or loss

The following fair value hierarchy is used to categorize and disclose the Company’s financial assets and liabilities held at fair value for which a valuation technique is used:


Level 1:		Unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities.

Level 2:		All inputs which have a significant effect on the fair value are observable, either directly or indirectly, for substantially the full contractual term.

Level 3:		Inputs which have a significant effect on the fair value are not based on observable market data.

The Company’s commodity derivative asset/liability was classified as a level 2 in accordance with the above hierarchy.

The amounts reported in the condensed consolidated interim balance sheet for the Company’s cash and cash equivalents, trade and other receivables, credit facility, and trade and other payables are carrying amounts and approximate their fair values due to their short-term nature.

The Company has exposure to credit risk, liquidity risk, and market risk from its use of financial instruments. There have not been any changes to the Company’s exposure to risks, or the objectives, policies and processes to manage these since June 30, 2015.

a) Credit risk

The aging of trade and other receivables are as follows:


	March 31, 2016		June 30, 2015
Trade and other receivables
0 to 60 days	$	1,381,057	$	1,592,126
61 to 120 days		5,697		8,357
> 120 days¹		—		59,652

	$	1,386,754	$	1,660,135

¹	Utah State withholding taxes on P&NG sales.

b) Liquidity Risk

The following table details the Company’s expected remaining contractual maturities for its financial liabilities and other obligations. The table is based on the undiscounted cash flows of financial liabilities based on the earliest date on which the Company is required to satisfy the liabilities.


	Total		Less than 1 year		One to two years		More than two years
Credit facility¹	$	36,579,326	$	36,579,326	$	—	$	—
Trade and other payables		1,858,906		1,858,906		—		—
Asset retirement liabilities		4,462,000		—		—		4,462,000

	$	42,900,232	$	38,438,232	$	—	$	4,462,000

¹	Includes accrued interest of $79,326.

c) Currency Risk

As at March 31, 2016, a 10% depreciation or appreciation of the Canadian dollar against the United States dollar would result in an increase or decrease, respectively, in the Company’s earnings or loss by $687,806, based on the net exposures presented below:


	Cash		Trade and other receivables		Trade and other payables			Net assets exposure		Effect of +/- 10% change in currency
Canadian dollar denominated	$	6,953,726	$	10,361	$	(86,028	)	$	6,878,059	$	687,806

d) Price Risk

The Company’s P&NG production is marketed and sold on the spot market to area aggregators based on daily spot prices that are adjusted for product quality and transportation costs. The Company’s cash flow from product sales will therefore be impacted by fluctuations in commodity prices.

To protect future cash flows for planned capital expenditures, the Company periodically enters into commodity derivative contracts. In April 2015, the Company entered into a NYMEX based oil price put contract for 9,000 barrels of oil per month from September 2015 until August 2016 (12 months) with a strike price of $50 per barrel. Fair value changes on this contract are recognized in the statement of income. During the nine months ended March 31, 2016, the Company reported a realized gain of $475,119 (2015 - $0) and reported an unrealized gain of $426,420 (2015 - $0). As at March 31, 2016, the contract has a fair value of $286,380 included in accounts receivable-trade.

9. Supplemental Cash Flow Information


	Nine months ended March 31,
	2016		2015
Non-cash financing activities:
Fair value of stock options transferred to common shares on exercise of stock options	$	—	$	205,260

10. Segmented Information

At March 31, 2016, the Company has one reportable operating segment, being the acquisition, exploration and development of petroleum and natural gas properties. The Company operates in two reportable geographic areas, being Canada and the United States of America.

An operating segment is defined as a component of the Company:

•

that engages in business activities from which it may earn revenues and incur expenses;

•

whose operating results are reviewed regularly by the entity’s chief operating decision maker; and

•

for which discrete financial information is available.

The Company’s revenues and capital assets in each of the geographic areas are as follows:


	Canada				USA				Consolidated Total
Three months ended March 31,	2016		2015		2016		2015		2016		2015
Revenue and other income
Interest income, net of royalties	$	14,582	$	30,249	$	—	$	—	$	14,582	$	30,249
Derivative financial instruments gain		—		—		120,204		—		120,204		—
Petroleum sales, net of royalties		—		—		1,849,155		2,975,682		1,849,155		2,975,682
Natural gas sales, net of royalties		—		—		319,844		485,205		319,844		485,205
Natural gas liquids sales, net of royalties		—		—		314,044		238,864		314,044		238,864

	$	14,582	$	30,249	$	2,603,247	$	3,699,751	$	2,617,829	$	3,730,000


	Canada				USA				Consolidated Total
Nine months ended March 31,	2016		2015		2016		2015		2016		2015
Revenue and other income
Interest income, net of royalties	$	66,403	$	103,539	$	—	$	—	$	66,403	$	103,539
Derivative financial instruments gain		—		—		901,539		—		901,539		—
Petroleum sales, net of royalties		—		—		7,504,785		13,685,536		7,504,785		13,685,536
Natural gas sales, net of royalties		—		—		1,086,766		1,785,493		1,086,766		1,785,493
Natural gas liquids sales, net of royalties		—		—		978,831		2,122,261		978,831		2,122,261

	$	66,403	$	103,539	$	10,471,921	$	17,593,290	$	10,538,324	$	17,696,829


	Canada				USA				Consolidated Total
	March 31, 2016		June 30, 2015		March 31, 2016		June 30, 2015		March 31, 2016		June 30 2015
Property, plant and equipment	$	414	$	951	$	104,146,373	$	107,282,733	$	104,146,787	$	107,283,684

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our unaudited condensed consolidated interim financial statements and related notes in “Part I, Item 1. Financial Statements” presented in this Quarterly Report on Form 10-Q, and in conjunction with the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section and audited consolidated financial statements and related notes thereto included in our Annual Report on Form 10-K for the year ended June 30, 2015. The following discussion and analysis contains forward-looking statements, including, without limitation, statements relating to our plans, strategies, objectives, expectations, intentions and resources. Please see “Cautionary Note Regarding Forward-Looking Information” elsewhere in this Quarterly Report on Form 10-Q and “Part I, Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended June 30, 2015. All references to dollar amounts in this section are in U.S. dollars unless expressly stated otherwise.

Overview

We are an independent oil and natural gas company focused on the acquisition, development, exploration and exploitation of petroleum and natural gas (“P&NG”) rights and properties. We have various working interests in the Midland Basin (including the Wolfberry play) and Eastern Shelf (including our Mitchell Ranch Project), located in the Permian Basin in West Texas, U.S.A.

Lynden Energy Corp. is a public company continued under the Business Corporations Act (British Columbia).

The common shares of the Company are listed on the TSX Venture Exchange under the symbol LVL, and the Company is a reporting issuer in British Columbia, Ontario and Alberta. At December 31, 2013, the Company no longer met the definition of a “foreign private issuer” under the U.S. Securities Exchange Act of 1934 (the “Exchange Act”), and as of June 30, 2014 (our fiscal year end), we met the registration requirements under Section 12(g) of the Exchange Act and subsequently became a reporting company in the United States. As at March 31, 2016 we have two wholly owned subsidiaries, Lynden Exploration Ltd. and Lynden USA Inc.

Entry into the Earthstone Agreement

On December 17, 2015, Lynden and Earthstone announced that they had entered into the Earthstone Agreement with respect to the Transaction. On March 29, 2016, the parties to the Earthstone Agreement entered into an amendment to the Earthstone Agreement clarifying certain technical matters related to the mechanics of the plan of arrangement, extending the date by which Lynden must hold its special meeting to May 27, 2016, and making miscellaneous conforming changes. Under the Earthstone Agreement, the terms of which were unanimously approved by the Boards of Directors of both companies, Earthstone will issue approximately 3.7 million shares of common stock to Lynden stockholders.

Under the Earthstone Agreement, Lynden shareholders will receive 0.02842 of a share of Earthstone stock in exchange for each share of Lynden common stock held, representing consideration to each Lynden shareholder of US$0.52 per share based on the closing price of Earthstone common stock on December 16, 2015. Following the Transaction, shareholders of Earthstone and Lynden are expected to own approximately 79% and 21%, respectively, of the combined company on a fully diluted basis.

The Earthstone Agreement contains certain termination rights for both the Company and Earthstone, including, among others, if the Transaction is not completed by September 30, 2016, or if the number of Lynden shares exercising Dissent Rights (as defined in the Earthstone Agreement) exceeds 5% of the outstanding shares of Lynden common stock. In the event of a termination of the Earthstone Agreement under certain circumstances, the Company may be required to pay to Earthstone a termination fee of $0.25 million, plus reasonable out-of-pocket expenses, not to exceed $0.5 million, or Earthstone may be required to pay to the Company a termination fee of the same amount. Under certain circumstances, in the event the Earthstone Agreement is terminated in connection with an acquisition proposal by a third party, the Company may be required to pay to Earthstone a topping fee of $2.25 million, plus reasonable out-of-pocket expenses, not to exceed $0.5 million.

Concurrently with the execution of the Earthstone Agreement, Oak Valley Resources, LLC (“Oak Valley”), which owns approximately 66% of the outstanding shares of Earthstone common stock, executed a written consent in favor of the Transaction. Also with the execution of the Earthstone Agreement, officers and directors of Lynden and affiliates of JVL Advisors, LLC, all in their capacities as shareholders of Lynden, entered into a voting agreement with Earthstone with respect to their shares of Lynden common stock, which constitute approximately 1% and 18%, respectively, of the total issued and outstanding shares of Lynden common stock.

Highlights

The Company’s financial and operating performance for the three months ended March 31, 2016, included the following highlights:

•

Primarily as a result of a significant drop in commodity prices, petroleum and natural gas sales decreased by 33% as compared to the three months ended March 31, 2015;

•

Realized prices decreased 38% per Bbl of oil and 37% per Mcf of gas, but increased 41% per Bbl of NGL compared to the three months ended March 31, 2015; and

•

Average daily production was 1,329 Boe/d in the three months ended March 31, 2016, compared to 1,350 Boe/d in the three months ended March 31, 2015.

Recent Developments

Over the nine months ended March 31, 2016, our average daily production on a quarterly basis has been:

•

During the three months ended March 31, 2016, our average daily production was 706 barrels per day, or Bbls/d, of oil, 1,910 thousand cubic feet per day, or Mcf/d, of natural gas and 304 Bbls/d of NGL, which totaled 1,329 Boe/d; and

•

During the three months ended December 31, 2015, our average daily production was 812 Bbls/d of oil, 1,849 Mcf/d of natural gas and 331 Bbls/d of NGL, which totaled 1,451 Boe/d; and

•

During the three months ended September 30, 2015, our average daily production was 650 Bbls/d of oil, 1,694 Mcf/d of natural gas, and 295 Bbls/d of NGL, which totaled 1,227 Boe/d.

During the three months ended March 31, 2016, we incurred approximately $0.5 million of capital expenditures in connection with our Permian Basin properties. The Company significantly reduced activity levels during the three months ended March 31, 2016, with principal activities being only the drilling of one gross Wolfberry well and one gross Mitchell Ranch well.

How We Evaluate Our Operations

We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:

•

production volumes;

•

realized prices on the sale of oil, natural gas and NGL; and

•

lease operating expenses.

Sources of Our Revenues

Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGL. For the three months ended March 31, 2016 and 2015, our revenues derived from oil sales were 74% and 81% respectively. Natural gas sales accounted for approximately 13% and 13% of total sales for the three months ended March 31, 2016 and 2015, respectively. Our revenues from NGL sales for the three months ended March 31, 2016 and 2015 were 13% and 6%, respectively. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

Production Volumes

The following table presents production volumes for the Company’s properties for the three months ended March 31, 2016 and 2015.


	Three Months Ended March 31,				% Change
	2016		2015		% Change
Oil (Bbls)		64,285		64,017		0	%
Natural gas (Mcf)		173,810		166,531		4	%
NGL (Bbls)		27,667		29,738		(7	%)

Total (Boe)		120,922		121,510		0	%
Average net daily production (Boe/d)		1,329		1,350		(2	%)

The primary factors affecting our production levels are capital availability, the success of our drilling plan, property sales and our inventory of drilling prospects. In addition, as is typical for businesses engaged in the exploration and production of crude oil and natural gas, we face the challenge of natural production declines. As initial reservoir pressures are depleted, crude oil and natural gas production from a given well decreases. We attempt to overcome this natural decline primarily through drilling our existing undeveloped reserves. Our future growth will depend in part on our ability to continue to add reserves in excess of production. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals.

Production increases compared to the period a year-ago are attributable in part to a shift towards horizontal well development and the timing of the drilling of such horizontal wells.

As the Company directs a greater portion of its capital budget towards horizontal well development, the timing of the drilling of the horizontal wells may result in more variable production volumes from quarter to quarter, as compared to the historically smoother pace of less costly vertical Wolfberry well drilling.

In addition, a lower amount of capital expenditures in a given period will generally result in smaller additions to production volumes, which additions may or may not exceed the natural decline of the Company’s existing wells. The comparability of capital expenditures between periods is however an imperfect measure as result of, among other things, changes in well drilling and completion costs (which have decreased over the last 12 months) and the geological and reservoir characteristics in the areas in which wells are being drilled.

Realized Prices on the Sale of Oil, Natural Gas and NGL

Our results of operations are heavily influenced by commodity prices. Factors that may affect commodity prices, including the price of oil, NGL and natural gas, include the level of consumer demand, domestic and worldwide, for oil, NGL and natural gas; the domestic and worldwide supply of oil, NGL and natural gas; inventory levels at Cushing, Oklahoma, the benchmark for WTI oil prices; natural gas inventory levels in the United States; commodity processing, gathering and transportation availability, and the availability of refining capacity; the price and level of imports of foreign oil, NGL and natural gas; the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; domestic and foreign governmental regulations and taxation; the price and availability of alternative fuel sources; weather conditions; political conditions or hostilities in oil, NGL and natural gas producing regions, including the Middle East, Africa and South America; technological advances affecting energy consumption and energy supply; variations between product prices at sales points and applicable index prices; and worldwide economic conditions.

Although we cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices for any commodity that we produce will generally approximate current market prices in the geographic region of the production. From time to time, we expect that we may economically hedge a portion of our commodity price risk to mitigate the effect of price volatility on our business.

Oil and natural gas prices have been subject to significant fluctuations during the past several years. Recently, oil and natural gas prices have declined significantly. During the nine months ended March 31, 2016, the West Texas Intermediate posted price had declined from a high of $56.94 per Bbl to a low of $26.19 per Bbl. In addition, the Henry Hub spot market price had declined from a high of $2.93 per MMBtu to a low of $1.49 per MMBtu. Likewise, NGL prices have recently suffered significant declines in realized prices. NGL are made up of ethane, propane, isobutane, normal butane and natural gasoline, all of which have different uses and different pricing characteristics.

If commodity prices continue to decline, a significant portion of our exploitation, development and exploration projects could become uneconomic. For example, in the quarter ended December 31, 2015, we recognized an $6,567,361 impairment of Mitchell Ranch Project exploratory well costs due in part to the current commodity price environment. Commodity devaluations may also result in our having to make significant downward adjustments to our estimated proved reserves. As a result, a substantial or extended decline in commodity prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. Lower oil and natural gas prices may also reduce the borrowing base under our credit agreement, which is determined at the discretion of the lenders and is based on the collateral value of our proved reserves that have been mortgaged to the lenders.

Factors Affecting the Comparability of Our Financial Condition and Results of Operations

Our historical financial condition and results of operations for the periods presented may not be comparable, either from period to period or going forward, for the following reasons:

Public Company Expenses

We incur direct, incremental general and administrative expenses as a result of being a U.S. registered company, including, but not limited to, increased costs associated with increased reporting and compliance requirements, accounting costs and legal fees. These additional direct, incremental general and administrative expenses are not included in our historical results of operations prior to our U.S. registration, during which time we were only a reporting issuer in certain provinces of Canada.

Changes in Drilling Activity

Our capital budget for fiscal 2016 was originally established at approximately $18.9 million. Our original fiscal 2016 capital budget contemplated the participation in the drilling of 8 gross Wolfberry wells, 3 gross horizontal wells in the Midland Basin, and 3 gross vertical wells on the Mitchell Ranch Project. The Company’s fiscal 2016 capital budget has been revised downwards to approximately $10.4 million principally as a result of a decrease, from 3 to 1, in the number of gross horizontal wells, and a decrease, from 8 to 6, in the number of gross vertical wells, in the Midland Basin currently scheduled in fiscal 2016. The ultimate amount of capital that we expend may fluctuate materially based on market conditions and our drilling results. See “Capital Requirements and Sources of Liquidity” for additional information.

Results of Operations

Oil, natural gas and NGL sales revenues. The following table provides summary information regarding oil, natural gas and NGL revenues, production, average product prices and average production costs and expenses for the three and nine months ended March 31, 2016 and 2015. We determine a barrel of oil equivalent using the ratio of six Mcf of natural gas to one Boe, and one barrel of NGL to one Boe. The ratios of six Mcf of natural gas to one Boe and one barrel NGL to one Boe do not assume price equivalency and, given price differentials, the price for a Boe for natural gas or NGL may differ significantly from the price for a barrel of oil.


	Three Months Ended March 31,						Nine Months Ended March 31,
	2016			2015			2016			2015
Net Revenues
Oil	$	1,849,154		$	2,975,681		$	7,504,784		$	13,685,535
Natural gas		319,844			485,205			1,086,766			1,785,493
NGL		314,044			238,865			978,831			2,122,262

		2,483,042			3,699,751			9,570,381			17,593,290
Production and operating expenses		(2,040,665	)		(1,959,220	)		(5,062,440	)		(4,651,407	)

Net back	$	442,377		$	1,740,531		$	4,507,941		$	12,941,883

Production
Oil (Bbl)		64,285			64,017			198,773			205,432
Natural gas (Mcf)		173,810			166,531			499,817			506,853
NGL (Bbl)		27,667			29,738			85,201			90,711
Total barrel of oil equivalent (Boe)		120,922			121,510			367,278			380,618
Daily production averages
Oil (Bbls/d)		706			711			723			750
Natural gas (Mcf/d)		1,910			1,850			1,818			1,850
NGL (Bbl/d)		304			330			310			331
Total barrel of oil equivalent (Boe/d)		1,329			1,350			1,336			1,389
Average Prices
Oil (per Bbl)	$	28.76		$	46,48		$	37.76		$	66.62
Natural gas (per Mcf)	$	1.84		$	2.91		$	2.17		$	3.52
NGL (per Bbl/d)	$	11.35		$	8.03		$	11.49		$	23.40
Total average barrel of oil equivalent (per Boe)	$	20.53		$	30.45		$	26.08		$	46.28
Costs and Expenses (per Boe)
Lease operating	$	12.76		$	11.48		$	11.44		$	8.90
Production and ad valorem taxes	$	4.11		$	4.64		$	2.34		$	3.32
Depletion, depreciation and accretion	$	19.62		$	22.25		$	19.74		$	21.46
Impairments	$	(0.20	)	$	—		$	17.82		$	1.18
General and administrative	$	6.48		$	6.62		$	5.44		$	4.51

Three Months Ended March 31, 2016 Compared to Three Months Ended March 31, 2015

Net Income. Net loss for the three months ended March 31, 2016 was ($2,252,836) and ($0.02) per basic and diluted share, compared to net loss of ($2,111,867) and ($0.02) per basic and diluted share for the three months ended March 31, 2015 and was primarily due to lower oil and gas revenues of $1,216,708, offset by lower depletion, depreciation and accretion expense of $309,524, and an equity investment loss of $nil (2015 - $431,919) in the three months ended March 31, 2016.

Oil, natural gas and NGL revenues. The following table provides the components of our revenues for the periods indicated, as well as each period’s respective average prices and production volumes.


	Three Months Ended March 31,				Change			% Change
	2016		2015		Change			% Change
Revenues
Oil	$	1,849,154	$	2,975,681	$	(1,126,527	)		(38	%)
Natural gas		319,844		485,205		(165,361	)		(34	%)
NGL		314,044		238,865		75,179			31	%

Total revenues	$	2,483,042	$	3,699,751	$	(1,216,709	)		(33	%)

Production
Oil (Bbl)		64,285		64,017		268			0	%
Natural gas (Mcf)		173,810		166,531		7,279			4	%
NGL (Bbl)		27,667		29,738		(2,071	)		(7	%)
Total barrel of oil equivalent (Boe)		120,922		121,510		(588	)		(0	%)
Daily production averages
Oil (Bbls/d)		706		711		(5	)		(1	%)
Natural gas (Mcf/d)		1,910		1,850		60			3	%
NGL (Bbls/d)		304		330		(26	)		(8	%)
Total barrel of oil equivalent (Boe/d)		1,329		1,350		(21	)		(2	%)
Average prices
Oil (per Bbl)	$	28.76	$	46.48	$	(17.72	)		(38	%)
Natural gas (per Mcf)	$	1.84	$	2.91	$	(1.07	)		(37	%)
NGL (per Bbl)	$	11.35	$	8.03	$	3.32			41	%
Total barrel of oil equivalent (per Boe)	$	20.53	$	30.45	$	9.91			(33	%)

Oil revenues. Oil revenues decreased 38% from $2,975,681 for the three months ended March 31, 2015 to $1,849,154 for the three months ended March 31, 2016, as a result of a $17.72 per Bbl decrease in our average realized price for oil, offset by a slight increase in oil production volumes of 268 Bbls.

Natural gas revenues. Natural gas revenues decreased 34% from $485,205 for the three months ended March 31, 2015 to $319,844 for the three months ended March 31, 2016, as a result of a $1.07 per Mcf decrease in our average realized natural gas price, offset by a slight increase in natural gas production volumes of 7,279 Mcf.

NGL revenues. NGL revenues increased 31% from $238,865 for the three months ended March 31, 2015 to $314,044 for the three months ended March 31, 2016, as a result of a $3.32 per Bbl increase in our average realized NGL price, offset by an decrease in NGL production volumes of 2,071 Bbls.

Effects of derivatives. In April 2015, the Company entered into a NYMEX-based oil price put contract for 9,000 barrels of oil per month from September 2015 until August 2016 (12 months) with a strike price of $50 per barrel. For the three months ended March 31, 2016, we reported an unrealized loss of $230,760 and a realized gain of $350,964. As at and for the three months ended March 31, 2015, all of our production was unhedged.

Operating expenses. The following table summarizes our operating expenses for the periods indicated.


	Three Months Ended March 31,					Change			% Change
	2016			2015		Change			% Change
Operating expenses
Lease operating	$	1,543,232		$	1,395,313	$	147,919			11	%
Production and ad valorem taxes		497,433			563,907		(66,474	)		(12	%)
Depletion, depreciation and accretion		2,394,500			2,704,024		(309,524	)		(11	%)
Exploration and impairments		(23,701	)		—		(23,701	)		N/A
General and administrative		783,179			805,744		(22,565	)		(3	)%

Total operating expenses	$	5,194,643		$	5,468,988	$	(274,345	)		(5	%)


	Three Months Ended March 31,					Change			% Change
	2016			2015		Change			% Change
Operating expenses per Boe
Lease operating	$	12.76		$	11.48	$	1.28			11	%
Production and ad valorem taxes		4.11			4.64		(0.53	)		(11	%)
Depletion, depreciation and accretion		19.80			22.25		(2.45	)		(11	%)
Exploration and impairments		(0.20	)		—		(0.20	)		N/A
General and administrative		6.48			6.63		(0.15	)		(2	%)

Total operating expenses	$	42.95		$	45.00	$	(2.05	)		(5	%)

Lease operating expenses. Lease operating expenses increased 11% from $1,395,313 for the three months ended March 31, 2015, to $1,543,232 for the three months ended March 31, 2016. The increase in our lease operating expenses was primarily attributable to the increased number of operating wells and to the mix of old wells compared to new wells. Older wells generally require more maintenance per Boe produced. Newer wells generally have higher salt water disposal costs per Boe produced.

Production and ad valorem taxes. Production and ad valorem taxes decreased 12% from $563,907 for the three months ended March 31, 2015, to $497,433 for the three months ended March 31, 2016. The decrease in our production and ad valorem taxes was attributable to lower revenues from falling commodity prices during the three months ended March 31, 2016.

Depletion, depreciation and accretion. Depletion, depreciation and accretion decreased 11% from $2,704,024 for the three months ended March 31, 2015, to $2,394,500 for the three months ended March 31, 2016, principally as a result of a smaller percentage of the Company’s reserves being produced.

Exploration and impairments. Exploration and impairments decreased by $23,701 for the three months ended March 31, 2016, due to recoveries of $24,146 of impairment charges of Mitchell Ranch Project exploratory well costs. During the three months ended December 31, 2015, it was determined that test results from four exploratory test wells drilled in fiscal 2015 had not identified significant reserves. Consequently, the costs attributable to these wells and a portion of the Mitchell Ranch Project leasehold costs were written off.

General and administrative expenses. General and administrative (“G&A”) expenses decreased 3% from $805,744 for the three months ended March 31, 2015, to $783,179 for the three months ended March 31, 2016. Administrative, consulting, and directors’ fees decreased by 17% due to lower administrative fees and lower directors’ fees incurred in the three months ended March 31, 2016. Office, miscellaneous and other expenses decreased by 62% primarily due to higher printing costs incurred in order to meet the filing requirements of the U.S. Securities and Exchange Commission in the three months ended March 31, 2015. Professional fees increased by 72% primarily in conjunction with the Earthstone Agreement, including the preparation of the joint proxy and information statement/circular. The following table summarizes G&A for the period indicated.


	Three Months ended March 31,				Change			% Change
	2016		2015		Change			% Change
General and administrative expenses
Administrative, consulting, and directors’ fees	$	211,170	$	253,566	$	(42,396	)		(17	%)
Office, miscellaneous and other		98,116		256,786		(158,670	)		(62	%)
Professional fees		455,125		264,734		190,391			72	%
Promotion and travel		18,768		30,658		(11,890	)		(39	%)

Total general and administrative expenses	$	783,179	$	805,744	$	(22,565	)		(3	%)

Interest expense. During the three months ended March 31, 2016, we recorded $349,213 of interest expense as compared to $279,960 in the three months ended March 31, 2015. The increase is primarily the result of approximately $9 million of additional borrowing during the three months ended March 31, 2016 compared to the same period in 2015.

Income taxes. We reported an income tax recovery of $673,191 for the three months ended March 31, 2016, compared to an income tax recovery of $339,000 for the three months ended March 31, 2015. The higher income tax recovery reported for the three months ended March 31, 2016 is primarily attributed to lower oil and gas sales of $1,216,708.

Foreign currency translation adjustment. Foreign currency translation gain of $430,910 was included in other comprehensive income for the three months ended March 31, 2016, compared to a loss of $835,324 for the three months ended March 31, 2015. Foreign currency translation loss relates primarily to translating Lynden Energy Corp.’s and Lynden Exploration Ltd.’s net assets denominated in Canadian dollars into United States dollars. Lynden Energy Corp.’s and Lynden Exploration Ltd.’s functional currency is the Canadian dollar.

Nine Months Ended March 31, 2016 Compared to Nine Months Ended March 31, 2015

Net Income. Net loss for the nine months ended March 31, 2016, was ($9,873,782) and ($0.08) per share and diluted share, compared to net income of $33,063 and $0.00 per share and diluted share for the nine months ended March 31, 2015. The large decrease in net income was primarily due to: 1) a $8,022,909 decrease in oil and gas revenues; and 2) a $6,096,037 increase in exploration and impairments. The net loss for the nine months ended March 31, 2016, also resulted in an income tax recovery of $1,247,491, compared to income tax expense of $1,449,000 for the nine months ended March 31, 2015.

Oil, natural gas and NGL revenues. The following table provides the components of our revenues for the periods indicated, as well as each period’s respective average prices and production volumes.


	Nine Months Ended March 31,				Change			% Change
	2016		2015		Change			% Change
Revenues
Oil	$	7,504,784	$	13,685,535	$	(6,180,751	)		(45	%)
Natural gas		1,086,766		1,785,493		(698,727	)		(39	%)
NGL		978,831		2,122,262		(1,143,431	)		(54	%)

Total revenues	$	9,570,381	$	17,593,290	$	(8,022,909	)		(46	%)

Production
Oil (Bbl)		198,773		205,432		(6,658	)		(3	%)
Natural gas (Mcf)		499,817		506,853		(7,036	)		(1	%)
NGL (Bbl)		85,201		90,711		(5,509	)		(6	%)
Total barrel of oil equivalent (Boe)		367,278		380,618		(13,340	)		(4	%)
Daily production averages
Oil (Bbls/d)		723		750		(27	)		(4	%)
Natural gas (Mcf/d)		1,818		1,850		(32	)		(2	%)
NGL (Bbls/d)		310		331		(21	)		(6	%)
Total barrel of oil equivalent (Boe/d)		1,336		1,389		(54	)		(4	%)
Average prices
Oil (per Bbl)	$	37.76	$	66.62	$	(28.86	)		(43	%)
Natural gas (per Mcf)	$	2.17	$	3.52	$	(1.35	)		(38	%)
NGL (per Bbl)	$	11.49	$	23.40	$	(11.91	)		(51	%)
Total barrel of oil equivalent (per Boe)	$	26.08	$	46.28	$	(20.19	)		(44	%)

Oil revenues. Oil revenues decreased 45% from $13,685,535 for the nine months ended March 31, 2015, to $7,504,784 for the nine months ended March 31, 2016, as a result of a $28.86 per Bbl decrease in our average realized price of oil and a decrease in oil production volumes of 6,658 Bbls.

Natural gas revenues. Natural gas revenues decreased 39% from $1,785,493 for the nine months ended March 31, 2015, to $1,086,766 for the nine months ended March 31, 2016, as a result of a $1.35 per Mcf decrease in our average realized natural gas price and a decrease in natural gas production volumes of 7,036 Mcf.

NGL revenues. NGL revenues decreased 54% from $2,122,262 for the nine months ended March 31, 2015, to $978,831 for the nine months ended March 31, 2016, as a result of a $11.91 per Bbl decrease in our average realized NGL price and a decrease in NGL production volumes of 5,509 Bbls.

Effects of derivatives. In April 2015, the Company entered into a NYMEX-based oil price put contract for 9,000 barrels of oil per month from September 2015 until August 2016 (12 months) with a strike price of $50 per barrel. For the nine months ended March 31, 2016, we reported an unrealized gain of $426,420 and a realized gain of $475,119. As at and for the nine months ended March 31, 2015, all of our production was unhedged.

Operating expenses. The following table summarizes our expenses for the periods indicated.


	Nine months ended March 31,				Change			% Change
	2016		2015		Change			% Change
Operating expenses
Lease operating	$	4,202,609	$	3,388,600	$	814,009			24	%
Production and ad valorem taxes		859,831		1,262,807		(402,976	)		(32	%)
Depletion, depreciation and accretion		7,271,729		8,166,473		(894,744	)		(11	%)
Exploration and impairments		6,545,578		449,541		6,096,037			1356	%
General and administrative		1,998,466		1,720,508		277,958			16	%

Total operating expenses	$	20,878,213	$	14,987,929	$	5,890,284			39	%


	Nine months ended March 31,				Change			% Change
	2016		2015		Change			% Change
Operating expenses per Boe
Lease operating	$	11.44	$	8.90	$	2.54			29	%
Production and ad valorem taxes		2.34		3.32		(0.98	)		(29	%)
Depletion, depreciation and accretion		19.80		21.46		(1.66	)		(8	%)
Exploration and impairments		17.82		1.18		16.64			1409	%
General and administrative		5.44		4.52		0.92			20	%

Total operating expenses	$	56.85	$	39.38	$	17.47			44	%

Lease operating expenses. Lease operating expenses increased 24% from $3,388,600 for the nine months ended March 31, 2015, to $4,202,609 for the nine months ended March 31, 2016. The increase in our lease operating expenses was primarily attributable to the increased number of operating wells and to the higher mix of old wells compared to new wells. Older wells generally require more maintenance per Boe produced. Newer wells generally have higher salt water disposal costs per Boe produced. During the nine months ended March 31, 2016, there was also a more active program of repair and production optimization work on the Company’s wells, which contributed to higher lease operating expenses per Boe.

Production and ad valorem taxes. Production and ad valorem taxes decreased 32% from $1,262,807 for the nine months ended March 31, 2015, to $859,831 for the nine months ended March 31, 2016. The decrease in our production and ad valorem taxes was attributable to lower revenues from falling commodity prices during the nine months ended March 31, 2016.

Depletion, depreciation and accretion. Depletion, depreciation and accretion decreased 11% from $8,166,473 for the nine months ended March 31, 2015, to $7,271,729 for the nine months ended March 31, 2016, as a result of a 4% decrease in production of Boe and a smaller percentage of the Company’s reserves being produced.

Exploration and impairments. Exploration and impairments increased by $6,096,037 from $449,541 for the nine months ended March 31, 2015, primarily due to the $6,541,215 impairment of Mitchell Ranch Project exploratory well costs. During the three months ended December 31, 2015, it was determined that test results from four exploratory test wells drilled in fiscal 2015 had not identified significant reserves. Consequently, the costs attributable to these wells and a portion of the Mitchell Ranch Project leasehold costs were written off. The $449,541 impairment reported during the nine months ended March 31, 2015 related to the write-off of the Paradox Basin Project suspended exploratory well costs.

General and administrative expenses. General and administrative (“G&A”) expenses increased 16% from $1,720,508 for the nine months ended March 31, 2015, to $1,998,466 for the nine months ended March 31, 2016.

The increase in G&A was primarily due to incurring $350,000 of consulting fees in conjunction with the Earthstone Agreement. Office, miscellaneous and other expenses decreased by 19% primarily due to higher printing costs incurred in order to meet the filing requirements of the U.S. Securities and Exchange Commission in the nine months ended March 31, 2015. Professional fees increased by 21% primarily in conjunction with the Earthstone Agreement, including the preparation of the joint proxy and information statement/circular. The following table summarizes G&A for the period indicated.


	Nine months ended March 31,				Change			% Change
	2016		2015		Change			% Change
General and administrative expenses
Administrative, consulting, and directors’ fees	$	950,484	$	636,239	$	314,245			49	%
Office, miscellaneous and other		281,507		351,716		(70,209	)		(20	%)
Professional fees		710,306		588,278		122,028			21	%
Promotion and travel		56,169		144,275		(88,106	)		(61	%)

Total general and administrative expenses	$	1,998,466	$	1,720,508	$	277,958			16	%

Interest expense. During the nine months ended March 31, 2016, we recorded $781,384 of interest expense compared to $794,918 in the nine months ended March 31, 2015. The decrease is primarily the result of capitalizing $317,026 of interest expense in the nine months ended March 31, 2016, concerning wells under development during the period. We also incurred $62,500 more in banking fees during the nine months ended March 31, 2015.

Income taxes. Income taxes decreased by $2,696,491 from $1,449,000 for the nine months ended March 31, 2015, to a recovery of $1,247,491 for the nine months ended March 31, 2016. The decrease in income taxes is primarily the result of $8,022,908 lower oil and gas sales; $411,033 higher production and operating expenses; and $277,958 higher general and administrative expenses during the nine months ended March 31, 2016, compared to the nine months ended March 31, 2015.

Foreign currency translation adjustment. Foreign currency translation loss was $369,493 included in other comprehensive income for the nine months ended March 31, 2016, compared to $1,741,618 for the nine months ended March 31, 2015. Foreign currency translation loss relates primarily to translating Lynden Energy Corp.’s and Lynden Exploration Ltd.’s net assets denominated in Canadian dollars into United States dollars. Lynden Energy Corp.’s and Lynden Exploration Ltd.’s functional currency is the Canadian dollar.

Capital Requirements and Sources of Liquidity

The Company’s primary sources of liquidity have been available cash on hand, cash generated from operations, borrowings under our Credit Facility and proceeds from asset dispositions. To date, the Company’s primary use of capital in this fiscal year has been for the acquisition, development and exploration of oil and natural gas properties.

During the nine months ended March 31, 2016, we spent approximately $12.0 million on capital expenditures on property, plant and equipment, which amount includes expenditures for activities included in the Company’s fiscal 2015 capital budget.

Our fiscal 2016 (July 1, 2015 to June 30, 2016) capital budget for drilling, completion, recompletion and infrastructure was originally established at approximately $18.9 million, and has since been revised downwards to approximately $10.4 million for the following:

•

$4.7 million, or 45%, for the participation in the drilling and completion of 6 gross (2.44 net) vertical Midland Basin wells;

•

$4.1 million, or 39% for the participation in the drilling and completion of 1 gross (0.43 net) horizontal Midland Basin wells; and

•

$1.6 million, or 16%, for the participation in the drilling and completion of 3 gross (1.50 net) vertical Mitchell Ranch Project wells.

Details of the revised fiscal 2016 capital budget expenditures are as follows:

•

We continue to carry out the Wolfberry vertical well development program on our Midland Basin acreage. Our plans call for 6 gross (2.44 net) Wolfberry wells to spud in fiscal 2016 at an estimated cost to the Company of approximately $4.7 million. Pursuant to the terms of the Midland Basin Participation Agreement with CrownRock L.P. (“CrownRock”), our funding amount for the 2.44 net wells is equivalent to 2.79 wells. As of March 31, 2016, we have drilled, completed and tied into production 5 of the six wells, and have drilled the sixth well.

•

Our revised fiscal 2016 capital budget contemplates one CrownQuest Operating, LLC (“CrownQuest”) operated horizontal well in Glasscock County. The well was budgeted at a gross cost of $8.3 million and has now been drilled, completed and tied-into production. Pursuant to the terms of a Participation Agreement with CrownRock, our primary working interest partner in the acreage operated by CrownQuest, the Company is funding approximately 50% of the cost of the well.

•

Our fiscal 2016 capital budget contemplates 3 gross (1.5 net) vertical wells being spud on the Mitchell Ranch Project. The gross cost of the first of the three wells is expected to be $1.4 million, with subsequent wells expected to be $0.9 million. As of March 31, 2016, 2 of the 3 wells have been drilled.

Based upon current oil and natural gas prices, we believe that our cash and cash equivalents on hand and our cash flow from operations and additional borrowings under our Credit Facility will provide us with sufficient liquidity to complete our fiscal 2016 capital program, excluding any acquisitions we may enter into. The Company is not contractually bound to drill any wells to which it has not first consented. In April 2015, we entered into a NYMEX-based oil price put contract for 9,000 Bbls of oil per month from September 2015 until August 2016 (12 months) with a strike price of $50 per Bbl as a hedge against some of the effects of commodity volatility during the period of the contract.

Future cash flows are subject to a number of variables, including but not limited to the level of oil and natural gas production and prices.Significant additional capital expenditures will be required to more fully develop our properties. We cannot assure that additional capital will be available on acceptable terms or at all. If we require additional capital for that or other reasons, we may seek such capital through traditional reserve base borrowings, joint venture partnerships, production payment financings, asset sales, offerings of debt and equity securities or other means. We cannot assure you that needed capital will be available on acceptable terms or at all. If we are unable to obtain capital when needed or on acceptable terms, we may be required to curtail our current drilling program, which could result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or replace our reserves. See “1A. Risk Factors” for additional information.

A capital budget has not yet been formally established for the first half of fiscal 2017 (July 1, 2016 to December 31, 2016); however, the Company anticipates significantly reduced levels of capital expenditures in the period compared to the prior period. Currently, plans anticipate one gross (0.40 net) horizontal well in Howard County, and one gross (0.50 net) vertical Mitchell Ranch Project well in the first half of fiscal 2017, at an estimated capital cost to the Company of $3.7 million.

Liquidity

We define liquidity as cash and cash equivalents and funds available under our Credit Facility. The table below summarizes our liquidity position at March 31, 2016, and June 30, 2015.


	Liquidity at March 31,			Liquidity at June 30,
	2016			2015
Borrowing base	$	40,000,000		$	37,500,000
Cash and cash equivalents		7,542,271			8,748,008
Credit Facility		(36,579,326	)		(29,908,366	)

Liquidity	$	10,962,945		$	16,339,642

Working Capital

Our working capital, which we define as current assets minus current liabilities, was in a deficit balance of $29,077,992 as at March 31, 2016, compared to $9,281,344 at June 30, 2015. The Credit Facility matures in August 2016 and has been classified as a current liability as at March 31, 2016, compared to a non-current liability as at June 30, 2015. Our collection of receivables has historically been timely, and we have had no losses associated with uncollectible receivables. Our cash balances totaled $7,542,271 and $8,748,008 at March 31, 2016, and June 30, 2015, respectively. Due to the amounts that accrue related to our drilling program, we may incur working capital deficits in the future. We expect that our cash flows from operating activities and availability under our Credit Facility will be sufficient to fund our working capital needs for fiscal 2016 excluding any acquisitions we may enter into. We expect that our pace of development, production volumes and commodity prices will be the largest variables affecting our working capital. The Company’s cash and cash equivalents at March 31, 2016, includes $6,953,726 of cash denominated in Canadian dollars, which is subject to fluctuations in the foreign exchange rates.

The following table summarizes our cash flows for the periods indicated:


	Nine months ended March 31,
	2016			2015
Net cash generated by operating activities	$	3,773,990		$	11,601,067
Net cash used in investing activities	$	(11,516,666	)	$	(24,625,464	)
Net cash generated by financing activities	$	6,750,000		$	9,757,092

Net cash generated by operating activities decreased by 67%, or $7,827,077, to $3,773,990 during the nine months ended March 31, 2016, compared to the prior period. The decrease in our cash flows generated by operating activities was primarily due to decreases in P&NG revenues from lower commodity prices and higher production and operating expenses and higher general and administrative expenses.

Net cash used in investing activities decreased by 53%, or $13,108,798, to $11,516,666 during the nine months ended March 31, 2016, compared to the prior period. The decrease in our cash flows used in investing activities was primarily due to more drilling and completion activity during the nine months ended March 31, 2015.

Net cash generated by financing activities decreased by 31%, or $3,007,092, to $6,750,000 during the nine months ended March 31, 2016, compared to the prior period. The decrease in our cash flows generated by financing activities was due to lower drawings on the Credit Facility of $2,750,000 and no common shares issued for cash during the nine months ended March 31, 2016.

Debt

Our Credit Facility is a reducing revolving line of credit of up to $100 million. As at March 31, 2016, the Credit Facility has a borrowing base of $40.0 million, of which $36.5 million was drawn down. The Credit Facility will bear interest determined by the percent of the borrowing base utilized and by elections made by the Company. Amounts drawn down under the Credit Facility will bear interest at a rate of LIBOR plus a range of 3.00% to 3.50% or at a rate of U.S. prime plus a range of 2.00% to 2.50%. A minimum interest rate of 3.5% is required on borrowings under the Credit Facility. Payments under the Credit Facility will be required to the extent that outstanding principal and interest exceed the borrowing base. Other fees may also apply pursuant to the bank’s re-determinations of the borrowing base. Changes in the borrowing base are made based on the bank’s engineering

valuation of the Company’s oil and gas reserves. The borrowing base is re-determined semi-annually; however, the Company may request two additional re-determinations of the borrowing base annually. The lender`s next engineering valuation of the Company’s oil and gas reserves and re-determination of the borrowing base is anticipated to be completed in June 2016.

Critical Accounting Policies and Estimates

Please refer to “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Estimates” in our Annual Report on Form 10-K for our fiscal year ended June 30, 2015, for a description of the Company’s critical accounting policies.

Off-Balance Sheet Arrangements

The Company has not engaged in any off-balance sheet arrangements.

Subsequent Events

As previously announced in our Current Report on Form 8-K filed on May 12, 2016, the Special Meeting of Shareholders was held on May 12, 2016, at which meeting the Lynden securityholders approved a special resolution in respect of the Transaction with Earthstone Energy, Inc.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

As of March 31, 2016, there was no material change in the information provided under Item 7A in the Company’s Annual Report on Form 10-K for the fiscal year ended June 30, 2015.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management has evaluated, with the participation of our principal executive officer (Chief Executive Officer) and principal financial officer (Chief Financial Officer), as required by Rule 13a-15(b) under the U.S. Securities Exchange Act of 1934 (the “Exchange Act”), the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of the end of the period covered by this quarterly report on Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information we are required to disclose in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission’s rules and forms, and includes, without limitation, controls and procedures designed to ensure that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Based upon the evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were effective as of March 31, 2016, at a reasonable level of assurance.

Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting during the fiscal quarter ended March 31, 2016, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

We are not currently a party to any legal proceedings. From time to time, we may become party to ongoing legal proceedings in the ordinary course of business, including workers’ compensation claims and employment related disputes. While the outcome of these proceedings cannot be predicted with certainty, we do not believe the results of these proceedings, individually or in the aggregate, will have a material adverse effect on our business, financial condition, results of operations or liquidity.

Item 1A. Risk Factors

There have been no material changes in our risk factors as previously disclosed in “Part I, Item 1A. Risk Factors” of our Annual Report on Form 10-K for the fiscal year ended June 30, 2015 and in “Part II, Item 1A. Risk Factors” of our Quarterly Report on Form 10-Q for the quarter ended December 31, 2015. You should carefully consider the risk factors discussed in our 2015 Form 10-K and December 31, 2015 Form 10-Q, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

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

Unregistered sales of equity securities

None

Item 6. Exhibits

See Exhibit Index on page 36 of this Quarterly Report on Form 10-Q.

SIGNATURES

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

EXHIBIT INDEX


Exhibit No.		Description

2.1		Arrangement Agreement, dated December 16, 2015, among Earthstone Energy, Inc., 1058286 B.C. Ltd. and the Company (incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K initially filed on December 17, 2015).

2.2		First Amendment to the Arrangement Agreement, dated March 29, 2016, among Earthstone Energy, Inc., 105-8286 B.C. Ltd. and the Company (incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K initially filed on March 29, 2016.

3.1		Certificate of Continuation of Lynden Ventures, Ltd., dated February 2, 2006 (incorporated by reference to Exhibit 3.1 of our Registration Statement on Form 10-12G initially filed on October 29, 2014).

3.2		Certificate of Change of Name of the Company, dated January 16, 2008 (incorporated by reference to Exhibit 3.2 of our Registration Statement on Form 10-12G initially filed on October 29, 2014).

3.3		Notice of Articles of the Company (incorporated by reference to Exhibit 3.3 of our Registration Statement on Form 10-12G initially filed on October 29, 2014).

3.4		Articles of the Company, dated December 5, 2005 (incorporated by reference to Exhibit 3.4 of our Registration Statement on Form 10-12G initially filed on October 29, 2014).

10.1		Letter Agreement with CFO (incorporated by reference to Exhibit 10.3 of our Quarterly Report on Form 10-Q initially filed on February 16, 2016).

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

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

32.1**		Certification of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002.

32.2**		Certification of Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS+		XBRL Instance Document.

101.SCH+		XBRL Taxonomy Extension Schema Document.

101.CAL+		XBRL Taxonomy Extension Schema Document.

101.DEF+		XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB+		XBRL Taxonomy Extension Label Linkbase Document.

101.PRE+		XBRL Taxonomy Extension Presentation Linkbase Document.

*	Filed herewith.

**	Furnished herewith.

+	Filed electronically herewith.

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