Lynden Energy 10-Q 2015 Q2 Quarterly report

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 December 31, 2014

or

¨ 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)

888 Dunsmuir Street Suite 1200 Vancouver, British Columbia	V6C 3K4
(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  ¨    No  x

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  ¨    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):

Large accelerated filer	¨	Accelerated filer	¨
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	Smaller reporting company	x

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 February 12, 2015.

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 December 31, 2014 and June 30, 2014		5
Condensed Consolidated Interim Statements of Income and Comprehensive Income for the Three and Six Months Ended December 31, 2014 and 2013		6
Condensed Consolidated Interim Statement of Changes in Equity for the Six Months Ended December  31, 2014 and 2013		7
Condensed Consolidated Interim Statements of Cash Flows for the Six Months Ended December 31, 2014 and 2013		8
Notes to Consolidated Financial Statements		9
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		16
Item 3. Quantitative and Qualitative Disclosures About Market Risk		25
Item 4. Controls and Procedures		26
PART II. OTHER INFORMATION
Item 1. Legal Proceedings		28
Item 1A. Risk Factors		28
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		28
Item 6. Exhibits		28

GLOSSARY OF CERTAIN TERMS AND CONVENTIONS USED HEREIN

The following are abbreviations and definitions of certain terms used in this Quarterly Report on Form 10-Q:

“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.” One barrel of oil equivalent, 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 natural gas to 1.0 Bbl of oil or NGL.

“Boe/d.” One Boe per day.

“Btu” or “One British Thermal Unit” The quantity of heat required to raise the temperature of a one-pound mass 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 natural gas.” A natural gas containing insufficient quantities of hydrocarbons heavier than methane to allow their commercial extraction or to require their removal in order to render the gas suitable for fuel use.

“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.

“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.

1

“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.

“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 Boe.

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

“Mcf/d.” One Mcf per day.

“MGal.” One thousand gallons of NGL.

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

“MMBoe.” One million Boe.

“MMBtu.” One million British thermal units.

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

“Net acres” or “net wells.” The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres own 50 net acres. All net acre figures in the Quarterly Report on Form 10-Q are approximates and estimated.

“Net production.” Production that is owned by us less royalties and production due others.

“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 natural gas well or lease.

“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 found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

“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.

2

“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 the “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 natural gas production on a completed well. Also called well or borehole.

“West Texas Intermediate Sweet” or “WTI.” 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, natural gas or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis.

The terms “development project,” “development well,” “exploratory well,” “proved developed reserves,” “proved reserves” and “reserves” are defined by the SEC.

3

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 credit facility and the purchasers of the Company’s production;

• 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 Registration Statement on Form 10, initially filed with the SEC on October 29, 2014, (as amended by that certain Amendment No. 1 filed on December 29, 2014 and Amendment No. 2 filed on February 10, 2015, our “Registration Statement on Form 10”) and which is 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.

4

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

Condensed Consolidated Interim Balance Sheets as of December 31, 2014 and June 30, 2014.

(Presented in United States dollars, except where indicated)

(Unaudited)

	Notes	December 31, 2014			June 30, 2014
ASSETS
Current assets
Cash and cash equivalents		$	10,411,112		$	13,955,890
Trade and other receivables, net of allowance for doubtful accounts	3,8		2,170,898			3,143,017
Income taxes receivable			200,000			200,000
Prepaid expenses			95,220			—
Total current assets			12,877,230			17,298,907
Non-current assets
Property, plant and equipment	4		107,242,698			91,812,527
Total assets		$	120,119,928		$	109,111,434
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Trade and other payables	8	$	1,260,015		$	2,971,177
Income taxes payable			505,000			380,000
Total current liabilities			1,765,015			3,351,177
Non-current liabilities
Credit facility	5		27,396,318			17,853,245
Asset retirement liabilities			258,063			240,208
Deferred tax liabilities			16,440,811			14,902,811
			44,095,192			32,996,264
Total liabilities			45,860,207			36,347,441
Shareholders’ equity
Share capital - authorized unlimited common shares, no par value
Issued and outstanding: December 31, 2014 - 130,198,411
June 30, 2014 - 129,275,911			65,622,739			65,160,387
Paid-in capital	6		15,228,868			15,434,128
Accumulated other comprehensive loss			(1,118,957	)		(212,663	)
Deficit			(5,472,929	)		(7,617,859	)
Total shareholders’ equity			74,259,721			72,763,993
Total liabilities and shareholders’ equity		$	120,119,928		$	109,111,434

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

5

Condensed Consolidated Interim Statements of Income and Comprehensive Income for the Three and Six Months Ended December 31, 2014 and 2013.

(Presented in United States dollars, except where indicated)

(Unaudited)

	Notes	Three months ended December 31,						Six months ended December 31,
		2014			2013			2014			2013
Revenue and other income
Petroleum and natural gas sales, net of royalties		$	5,958,672		$	7,191,257		$	13,893,539		$	16,138,740
Derivative financial instruments gain (loss)			—			52,067			—			(73,338	)
Interest income			35,464			11,425			73,290			12,096
Total revenue and other income			5,994,136			7,254,749			13,966,829			16,077,498
Expenses
Production and operating expenses			(1,366,257	)		(1,219,185	)		(2,692,187	)		(2,268,661	)
Depletion, depreciation and accretion			(2,783,429	)		(1,979,395	)		(5,462,449	)		(3,958,291	)
Foreign exchange gain (loss)			(1,675	)		(1,585	)		(1,129	)		(2,780	)
General and administrative			(539,351	)		(377,222	)		(913,635	)		(629,977	)
Impairments			—			—			(449,541	)		—
Interest			(324,963	)		(90,182	)		(514,958	)		(129,768	)
Total expenses			(5,015,675	)		(3,667,569	)		(10,033,899	)		(6,989,477	)
Other income
Gain on disposition of property, plant and equipment			—			9,937,842			—			9,937,842
Income before income taxes			978,461			13,525,022			3,932,930			19,025,863
Income tax expense			469,000			3,917,100			1,788,000			5,780,000
Net income			509,461			9,607,922			2,144,930			13,245,863
Other comprehensive (loss) income
Foreign currency translation adjustment			(369,067	)		(312,287	)		(906,294	)		(299,219	)
Total comprehensive income for the period		$	140,394		$	9,295,635		$	1,238,636		$	12,946,644
Weighted average number of common shares outstanding
Basic	6		130,181,291			125,181,984			129,895,245			118,410,542
Diluted	6		131,022,050			127,863,338			132,889,697			121,315,964
Net earnings per common share
Basic		$	0.00		$	0.08		$	0.02		$	0.11
Diluted		$	0.00		$	0.08		$	0.02		$	0.11

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

6

Condensed Consolidated Interim Statement of Changes in Equity for the Six Months Ended December 31, 2014 and 2013.

(Presented in United States dollars, except where indicated)

(Unaudited)

	Common Shares				Paid-in Capital			Accumulated Other Comprehensive Income (Loss)			Deficit			Total
	Number		Amount
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		—		—		—			(906,294	)		—			(906,294	)
Earnings for the period		—		—		—			—			2,144,930			2,144,930
Balance at December 31, 2014		130,198,411	$	65,622,739	$	15,228,868		$	(1,118,957	)	$	(5,472,929	)	$	74,259,721

	Common Shares				Paid-in Capital			Accumulated Other Comprehensive Income (Loss)			Deficit			Total
	Number		Amount
Balance at June 30, 2013		110,505,520	$	49,279,688	$	18,598,870		$	139,939		$	(23,021,510	)	$	44,996,987
Common shares issued for cash:
Exercise of warrants		18,770,391		15,880,699		(3,220,425	)		—			—			12,660,274
Share-based payments		—		—		53,383			—			—			53,383
Foreign currency translation		—		—		—			(299,219	)		—			(299,219	)
Earnings for the period		—		—		—			—			13,245,863			13,245,863
Balance at December 31, 2013		129,275,911	$	65,160,387	$	15,431,828		$	(159,280	)	$	(9,775,647	)	$	70,657,288

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

7

Condensed Consolidated Interim Statements of Cash Flows for the Six Months Ended December 31, 2014 and 2013.

(Presented in United States dollars, except where indicated)

(Unaudited)

	Notes	Six months ended December 31,
		2014			2013
Operating activities
Net income for the period		$	2,144,930		$	13,245,863
Adjustments for:
Accrued interest			43,073			(19,639	)
Unrealized loss on derivative financial instruments			—			30,316
Depletion, depreciation and accretion			5,462,449			3,958,291
Impairments			449,541			—
Share-based payments			—			53,227
Gain on disposition of property, plant and equipment			—			(9,937,842	)
Deferred income taxes			1,538,000			5,641,000
Unrealized foreign exchange gain			(147,533	)		(171,173	)
Changes in non-cash working capital items:
Trade and other receivables			972,119			(297,094	)
Prepaid expenses			(95,220	)		—
Trade and other payables			180,025			384,402
Income taxes payable			125,000			139,000
Cash generated by operating activities			10,672,384			13,026,351
Investing activities
Proceeds on disposition of property, plant and equipment			—			19,603,125
Acquisition of property, plant and equipment			(23,215,493	)		(18,231,052	)
Cash (used in) generated by investing activities			(23,215,493	)		1,372,073
Financing activities
Drawings (repayments) of credit facility			9,500,000			(14,250,000	)
Common shares issued for cash, net of issue costs	6		257,092			12,660,274
Cash generated (used) by financing activities			9,757,092			(1,589,726	)
Effect of exchange rate on cash held in foreign currency			(758,761	)		(127,890	)
Change in cash and cash equivalents during the period			(3,544,778	)		12,680,808
Cash and cash equivalents, beginning of period			13,955,890			1,874,400
Cash and cash equivalents, end of period		$	10,411,112		$	14,555,208
Cash and cash equivalents are composed of:
Cash		$	665,468		$	2,796,622
Guaranteed investment certificates			9,745,644			11,758,586
		$	10,411,112		$	14,555,208
Supplemental cash flow information	9

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

8

Notes to Consolidated Financial Statements.

1. Description of Business

Lynden Energy Corp. (the “Company”) is a public company continued under theBusiness 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.

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 December 31, 2014 and for the three and six months ended December 31, 2014 and the 2013 comparative period. These condensed consolidated interim financial statements do not include all the necessary annual disclosures as prescribed under U.S. GAAP and should be read in conjunction with the Company’s restated audited consolidated financial statements as of June 30, 2014.

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 December 31, 2014 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, 2014.

c) Recent accounting pronouncements

As of July 1, 2014, 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 consolidated financial statements.

• Accounting Standards Update 2013-04,Obligations resulting from Joint and Several Liability Arrangements

• Accounting Standards Update 2013-05,Parent’s Accounting for Cumulative Translation Adjustments upon Derecognition of Certain Subsidiaries

• Accounting Standards Update 2013-11,Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists

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

• 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)

• Accounting Standards Update 2014-09,Revenue From Contracts With Customers(effective for annual periods beginning after December 15, 2016)

• 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)

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

9

3. Trade and Other Receivables

	December 31, 2014		June 30, 2014
Accounts receivable – trade	$	456	$	2,572,762
Accrued receivables		2,085,094		496,947
Sales taxes receivable		85,348		73,308
	$	2,170,898	$	3,143,017

The Company did not have any allowance for doubtful accounts as at December 31, 2014 and June 30, 2014. As at December 31, 2014, $2,085,094 (June 30, 2014 - $2,991,585) is owing from one counterparty.

4. Property, Plant and Equipment

	December 31, 2014
	Cost		Accumulated Depletion, Depreciation and Impairment			Net Book Value
Petroleum and natural gas properties
Proved	$	115,759,709	$	(18,231,769	)	$	97,527,940
Suspended exploratory well costs		36,949,407		(27,236,093	)		9,713,314
		152,709,116		(45,467,862	)		107,241,254
Computer Equipment		2,240		(796	)		1,444
Total property, plant and equipment	$	152,711,356	$	(45,468,658	)	$	107,242,698

	June 30, 2014
	Cost		Accumulated Depletion, Depreciation and Impairment			Net Book Value
Petroleum and natural gas properties
Proved	$	100,407,384	$	(12,781,939	)	$	87,625,445
Suspended exploratory well costs		30,972,613		(26,786,552	)		4,186,061
		131,379,997		(39,568,491	)		91,811,506
Computer Equipment		4,820		(3,799	)		1,021
Total property, plant and equipment	$	131,384,817	$	(39,572,290	)	$	91,812,527

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.

Suspended Exploratory Well Costs

Suspended exploratory well costs consist of costs of drilling and equipping exploratory wells relating to the Company’s Paradox Basin Project, Mitchell Ranch Project, and two horizontal wells on its Wolcott Lease. 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.

Upon revisiting the criteria for the capitalization of the costs related to the Paradox Basin Project suspended exploratory well costs, including the lack of substantial activities to assess the reserves for more than one year following the drilling of the exploratory wells, and the lack of significant expenditures which are planned in the future, management has corrected the accounting for these costs as they should no longer be capitalized. As a result, the Company has made an immaterial adjustment and has expensed the remaining costs of $449,541 in the three months ended September 30, 2014.

10

5. Credit Facility

The Company has a reducing revolving line of credit (the “Credit Facility”) in an amount up to $100 million. As at December 31, 2014, the Credit Facility has a borrowing base of $40 million, of which $27.3 million has been 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 also apply pursuant to the bank’s re-determinations of the borrowing base. Increases 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 Credit Facility contains certain mandatory covenants, including minimum current ratio and cash flow requirements, and other standard business operating covenants. The Company has complied with all of these covenants as at and during the six months ended December 31, 2014. 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.

6. Shareholders’ Equity

a) Authorized

An unlimited number of common shares without par value.

An unlimited number of preference shares without par value.

b) Warrants:

The changes in warrants outstanding during the six months ended December 31, 2014 and the year ended June 30, 2014 are as follows:

	Six months ended December 31, 2014				Year ended June 30, 2014
	Number of warrants		Weighted average exercise price (CDN$)		Number of warrants			Weighted average exercise price (CDN$)
Balance, beginning of period		7,512,000	$	0.65		27,415,760		$	0.69
Exercised		—	$	—		(18,770,391	)	$	0.70
Expired		—	$	—		(1,133,369	)	$	0.70
Balance, end of period		7,512,000	$	0.65		7,512,000		$	0.65

For warrants exercised during the year ended June 30, 2014, the weighted average share price at the dates of exercise was CDN$0.79.

Warrants exercisable and outstanding as at December 31, 2014 are as follows:

Expiry Date	Exercise Price (CDN$)
May 4, 2015	$	0.65	5,079,500
May 18, 2015	$	0.65	2,432,500
			7,512,000

11

c) Earnings per share:

Diluted earnings per share computation

	Three months ended December 31,				Six months ended December 31,
	2014		2013		2014		2013
Numerator:
Net earnings	$	509,461	$	9,607,922	$	2,144,930	$	13,245,863
Denominator:
Weighted average number of common shares (basic)		130,181,291		125,181,984		129,895,245		118,410,542
Dilutive effect of share options		633,827		1,510,653		1,276,150		1,574,181
Dilutive effect of warrants		206,932		1,170,701		1,718,302		1,331,241
Weighted average number of common shares (diluted)		131,022,050		127,863,338		132,889,697		121,315,964
Diluted earnings per common share	$	0.00	$	0.08	$	0.02	$	0.11

For the three months ended December 31, 2014, there are 2,612,500 (2013 – 2,612,500) share options that are not dilutive and nil (2013 – nil) warrants that are not dilutive.

For the six months ended December 31, 2014, there are nil (2013 – 2,612,500) share options that are not dilutive and nil (2013 – nil) warrants that are not dilutive.

d) 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 six months ended December 31, 2014 and the year ended June 30, 2014 are as follows:

	Six months ended December 31, 2014					Year ended June 30, 2014
	Number of options			Weighted average exercise price (CDN$)		Number of options			Weighted average exercise price (CDN$)
Balance, beginning of period		6,632,500		$	0.61		6,862,500		$	0.81
Exercised		(922,500	)	$	0.31		—		$	—
Expired		—		$	—		(230,000	)	$	0.68
Balance, end of period		5,710,000		$	0.65		6,632,500		$	0.61

For stock options exercised during the six months ended December 31, 2014, the weighted average share price at the dates of exercise was CDN$0.92

The following table summarizes information about stock options outstanding and exercisable at December 31, 2014:

	Options outstanding				Options exercisable
Exercise price (CDN$)	Number of options		Weighted average remaining life (years)		Number of options		Weighted average remaining life (years)
$0.30 to $0.60		3,097,500		1.28		3,097,500		1.28
$0.80		2,612,500		1.56		2,612,500		1.56
		5,710,000		1.41		5,710,000		1.41

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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 December 31,				Six months ended December 31,
	2014		2013		2014		2013
Legal fees	$	13,272	$	15,768	$	28,341	$	25,476
Transportation and marketing costs		9,910		4,293		19,290		12,018
Total	$	23,182	$	20,061	$	47,631	$	37,494

Trade and other payables include $8,091 (June 30, 2014—$47,014) 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 December 31, 2014, 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

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 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 from June 30, 2014.

a) Credit risk

The aging of trade and other receivables are as follows:

	December 31, 2014		June 30, 2014
Trade and other receivables
0 to 60 days	$	2,102,889	$	3,083,365
61 to 120 days		8,357		6,762
> 120 days1		59,652		52,890
	$	2,170,898	$	3,143,017

¹ Utah State withholding taxes on P&NG sales.

13

b) Liquidity Risk

The following table details the Company’s expected remaining contractual maturities for its financial liabilities. 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	$	27,396,318	$	—	$	27,396,318	$	—
Trade and other payables		1,260,015		1,260,015		—		—
	$	28,656,333	$	1,260,015	$	27,396,318	$	—

¹ Includes accrued interest of $146,318.

c) Currency Risk

As at December 31, 2014, 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 $1,009,303, 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 denomination	$	10,088,241	$	14,420	$	(9,630	)	$	10,093,031	$	1,009,303

9. Supplemental Cash Flow Information

	Six months ended December 31,
	2014		2013
Non-cash financing activities:
Fair value of stock options transferred to common shares on exercise of stock options	$	205,260	$	—
Fair value of warrants transferred to common shares on exercise of warrants	$	—	$	3,220,425

10. Segmented Information

At December 31, 2014 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
Revenue and other income
Three months ended December 31, 2014
Interest Income, net of royalties	$	35,464	$	—	$	35,464
Petroleum sales, net of royalties				4,461,778		4,461,778
Natural gas sales, net of royalties				616,750		616,750
Natural gas liquids sales, net of royalties				880,144		880,144
Total	$	35,464	$	5,958,672	$	5,994,136

14

	Canada		USA		Consolidated Total
Three months ended December 31, 2013
Interest Income, net of royalties	$	11,425	$	—	$	11,425
Petroleum sales, net of royalties				5,796,751		5,796,751
Natural gas sales, net of royalties				406,998		406,998
Natural gas liquids sales, net of royalties				987,508		987,508
Total	$	11,425	$	7,191,257	$	7,202,682

	Canada		USA		Consolidated Total
Six months ended December 31, 2014
Interest Income, net of royalties	$	73,290	$	—	$	73,290
Petroleum sales, net of royalties				10,709,854		10,709,854
Natural gas sales, net of royalties				1,300,288		1,300,288
Natural gas liquids sales, net of royalties				1,883,397		1,883,397
Total	$	73,290	$	13,893,539	$	13,966,829

	Canada		USA		Consolidated Total
Six months ended December 31, 2013
Interest Income, net of royalties	$	12,096	$	—	$	12,096
Petroleum sales, net of royalties				13,664,391		13,664,391
Natural gas sales, net of royalties				971,296		971,296
Natural gas liquids sales, net of royalties				1,503,053		1,503,053
Total	$	12,096	$	16,138,740	$	16,150,836

Property, plant and equipment
As at December 31, 2014	$	1,444	$	107,241,254	$	107,242,698
As at June 30, 2014	$	1,021	$	91,811,506	$	91,812,527

15

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 consolidated 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 Registration Statement on Form 10. 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 Registration Statement on Form 10. 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 theBusiness 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 Act of 1934 (the “Securities 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. We have two wholly owned subsidiaries, Lynden Exploration Ltd. and Lynden USA Inc.

Highlights

The Company’s financial and operating performance for the three months ended December 31, 2014 included the following highlights:

• The total number of producing Wolfberry wells increased from 95 gross (38.87 net) to 102 gross (41.68 net);

• Primarily as a result of a significant drop in commodity prices, petroleum and natural gas sales decreased by 17% as compared to the three months ended December 31, 2013;

• Realized prices decreased 32% per Bbl of oil, 11% per Mcf of gas and 9% per Bbl of NGL compared to the three months ended December 31, 2013; and

• Average daily production was 1,392 Boe/d compared to 1,196 Boe/d in the three months ended December 31, 2013.

Recent Developments

During the three months ended December 31, 2014, our average daily production was 750 barrels per day, or Bdls/d, of oil, 1,853 thousand cubic feet per day, or Mcf/d, of natural gas and 333 Bbls/d of NGL, a decrease of 2%, or 32 Boe/d over the three months ended September 30, 2014, consisting of 787 Bbls/d of oil, 1,846 Mcf/d of natural gas and 329 Bbls/d of NGL.

During the three months ended December 31, 2014, we incurred approximately $11.5 million of capital expenditures in connection with our Permian Basin properties. Principal activities undertaken during the three months ended December 31, 2014 included the drilling of three gross (1.5 net) wells on the Mitchell Ranch Project, the drilling of one (0.2 net) horizontal well on the Wolcott leases, and the drilling of eight gross (3.36 net) Wolfberry wells.

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.

16

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 December 31, 2014 and 2013, our revenues derived from oil sales were 75% and 80% respectively. Natural gas sales accounted for approximately 10% and 6% of total sales for the three months ended December 31, 2014 and 2013, respectively. Our revenues from NGL sales for the three months ended December 31, 2014 and 2013 were 15% and 14%, 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 December 31, 2014 and 2013.

	Three Months Ended December 31,				% Change
	2014		2013
Oil (Bbls)		69,013		61,489		12.2	%
Natural gas (Mcf)		170,501		101,887		67.3	%
NGL (Bbls)		30,668		31,598		(2.9	)%
Total (Boe)		128,098		110,068		16.4	%
Average net daily production (Boe/d)		1,392		1,196		16.4	%

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.

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 three months ended December 31, 2014, the West Texas Intermediate posted price had declined from a high of $95.55 per Bbl to $53.45 per Bbl. In addition, the Henry Hub spot market price had declined from a high of $4.41 per MMBtu to $2.74 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. This may 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.

17

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 direct, incremental general and administrative expenses are not included in our historical results of operations prior to our U.S. registration.

Changes in Drilling Activity

Our capital budget for fiscal 2015 is approximately $34 million. Our 2015 capital budget contemplates the participation in the drilling of 15 gross Wolfberry wells, 5 gross horizontal wells in the Midland Basin, and 4 gross vertical wells on the Mitchell Ranch Project. The ultimate amount of capital that we expend may fluctuate materially based on market conditions and our drilling results.

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 six months ended December 31, 2014 and 2013. 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 December 31,						Six Months Ended December 31,
	2014			2013			2014			2013
Net Revenues
Oil	$	4,461,778		$	5,796,751		$	10,709,854		$	13,664,391
Natural gas		616,750			406,998			1,300,288			971,296
NGL		880,144			987,508			1,883,397			1,503,053
		5,958,672			7,191,257			13,893,539			16,138,740
Production and operating expenses		(1,366,257	)		(1,219,185	)		(2,692,187	)		(2,268,661	)
Net back	$	4,592,415		$	5,972,072		$	11,201,352		$	13,870,079
Production
Oil (Bbl)		69,013			61,489			141,415			139,496
Natural gas (Mcf)		170,501			101,887			340,322			219,838
NGL (Bbl)		30,668			31,598			60,973			52,258
Total barrel of oil equivalent (Boe)		128,098			110,068			259,108			228,394
Daily production averages
Oil (Bbls/d)		750			668			769			758
Natural gas (Mcf/d)		1,853			1,107			1,850			1,195
NGL (Bbl/d)		333			343			331			284
Total barrel of oil equivalent (Boe/d)		1,392			1,196			1,408			1,241
Average prices
Oil (per Bbl)	$	64.65		$	94.27		$	75.73		$	97.96
Natural gas (per Mcf)	$	3.62		$	3.99		$	3.82		$	4.42
NGL (per Bbl/d)	$	28.70		$	31.25		$	30.89		$	28.76
Total barrel of oil equivalent (per Boe)	$	46.52		$	65.33		$	53.62		$	70.66
Costs and expenses (per Boe)
Lease operating	$	8.22		$	7.77		$	7.69		$	6.43
Production and ad valorem taxes	$	2.44		$	3.31		$	2.70		$	3.51
Depletion, depreciation and accretion	$	21.73		$	17.98		$	21.08		$	17.33
Impairments	$	—		$	—		$	1.73		$	—
General and administrative	$	4.21		$	3.43		$	3.53		$	2.76

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Three Months Ended December 31, 2014 Compared to Three Months Ended December 31, 2013

Net Income. Net income for the three months ended December 31, 2014 was $509,461 and $0.00 per share and diluted share, compared to net income of $9,607,922 and $0.08 per share and diluted share for the three months ended December 31, 2013. Net income for the three months ended December 31, 2014 decreased primarily because oil and gas revenues were lower by $1,232,585, no gain on disposition of property, plant and equipment in the three months ended December 31, 2014 compared to a gain of $9,937,842 in the three months ended December 31, 2013, higher depletion, depreciation and accretion were higher by $804,034 in the three months ended December 31, 2014, and offset income taxes being lower by $3,448,100.

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 December 31,				Change			% Change
	2014		2013
Revenues
Oil	$	4,461,778	$	5,796,751	$	(1,334,973	)		(23	%)
Natural gas		616,750		406,998		209,752			52	%
NGL		880,144		987,508		(107,364	)		(11	%)
Total revenues	$	5,958,672	$	7,191,257	$	(1,232,585	)		(17	%)
Production
Oil (Bbl)		69,013		61,489		7,524			12	%
Natural gas (Mcf)		170,501		101,887		68,614			67	%
NGL (Bbl)		30,668		31,598		(930	)		(3	%)
Total barrel of oil equivalent (Boe)		128,098		110,068		18,030			16	%
Daily production averages
Oil (Bbls/d)		750		668		82			12	%
Natural gas (Mcf/d)		1,853		1,107		746			67	%
NGL (Bbls/d)		333		343		(10	)		(3	%)
Total barrel of oil equivalent (Boe/d)		1,392		1,196		196			16	%
Average prices
Oil (per Bbl)	$	64.65	$	94.27	$	(29.62	)		(31	%)
Natural gas (per Mcf)	$	3.62	$	3.99	$	(0.37	)		(9	%)
NGL (per Bbl)	$	28.70	$	31.25	$	(2.55	)		(8	%)
Total barrel of oil equivalent (per Boe)	$	46.52	$	65.33	$	(18.81	)		(29	%)

Oil revenues. Oil revenues decreased 23% from $5,796,751 for the three months ended December 31, 2013 to $4,461,778 million for the three months ended December 31, 2014 as a result of a $29.62 per Bbl decrease in our average realized price for oil, offset by an increase in oil production volumes of 7,524 Bbls. Our higher oil production was primarily a result of our ongoing Wolfberry well development program, and the resulting increase in the number of wells tied-in and producing.

Natural gas revenues. Natural gas revenues increased 52% from $406,998 for the three months ended December 31, 2013 to $616,750 for the three months ended December 31, 2014 as a result of an increase in natural gas production volumes of 68,614 Mcf, offset by a decrease of $0.37 per Mcf in our average realized natural gas price. Our increase in natural gas production was primarily a result of ongoing Wolfberry well development program, and the resulting increase in the number of wells tied-in and producing

NGL revenues. NGL revenues decreased 11% from $987,508 for the three months ended December 31, 2013 to $880,144 for the three months ended December 31, 2014 as a result of a $2.55 per Bbl decrease in our average realized NGL price, offset by an increase in NGL production volumes of 18,030 Bbls. Our higher NGL production was primarily due to ongoing Wolfberry well development program, and the resulting increase in the number of wells tied-in and producing.

Effects of derivatives. As at and for the three months ended December 31, 2014, all of the Company’s production was unhedged and will be impacted by fluctuations in the prices of oil and natural gas. For the three months ended December 31, 2013, the Company realized a $13,880 loss on a costless collar oil hedge and reported an unrealized gain of $65,947 on a costless collar oil hedge. As at December 31, 2013, the Company’s outstanding costless collar hedge consisted of 4,750 Bbls of oil per month from January 2014 to June 2014 with a floor of $80/Bbl and a ceiling of $104/Bbl based on NYMEX pricing.

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

	Three months ended December 31,				Change			% Change
	2014		2013
Operating expenses
Lease operating	$	1,053,301	$	854,837	$	198,464			23	%
Production and ad valorem taxes		312,956		364,348		(51,392	)		(14	%)
Depletion, depreciation and accretion		2,783,429		1,979,395		804,034			41	%
General and administrative		539,351		377,222		162,129			43	%
Total operating expenses	$	4,689,037	$	3,575,802	$	1,113,235			31	%

	Three months ended December 31,				Change			% Change
	2014		2013
Operating expenses per boe
Lease operating	$	8.22	$	7.77	$	0.45			6	%
Production and ad valorem taxes		2.44		3.31		(0.87	)		(26	%)
Depletion, depreciation and accretion		21.73		17.98		3.75			21	%
General and administrative		4.21		3.43		0.78			23	%
Total operating expenses	$	36.60	$	32.49	$	4.11			13	%

Lease operating expenses. Lease operating expenses increased 23% from $854,837 for the three months ended December 31, 2013 to $1,053,301 for the three months ended December 31, 2014. 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.

Production and ad valorem taxes. Production and ad valorem taxes decreased 14% from $364,348 for the three months ended December 31, 2013 to $312,956 for the three months ended December 31, 2014. The decrease in our production and ad valorem taxes was attributable to lower revenues from falling commodity prices during the three months ended December 31, 2014.

Depletion, depreciation and accretion. Depletion, depreciation and accretion increased 41% from $1,979,395 for the three months ended December 31, 2013 to $2,783,429 for the three months ended December 31, 2014 as a result of a 16% increase in production of Boe along with $25,297,971 more in capitalized costs subject to depletion and depreciation at December 31, 2014 compared to December 31, 2013.

General and administrative expenses. General and administrative (“G&A”) expenses increased 43% from $377,222 for the three months ended December 31, 2013 to $539,351 for the three months ended December 31, 2014. The increase in G&A was due to (1) higher professional fees incurred for the registration of the Company’s securities with the U.S. Securities and Exchange Commission; (2) higher administrative, consulting, and directors fees incurred in order to manage the Company’s increasing business complexity; and (3) higher promotion and travel as additional efforts were made to introduce the Company to potential new shareholders. The following table summarizes G&A for the period indicated.

	Three months ended December 31,				Change			% Change
	2014		2013
General and administrative expenses
Administrative, consulting, and directors fees	$	198,987	$	171,999	$	26,988			16	%
Office, miscellaneous and other		67,214		61,316		5,898			10	%
Professional fees		203,263		71,090		132,173			186	%
Promotion and travel		69,887		47,739		22,148			46	%
Stock-based compensation		—		25,078		(25,078	)		(100	%)
Total general and administrative expenses	$	539,351	$	377,222	$	162,129			43	%

Foreign exchange gain (loss). Foreign exchange losses included in net income primarily relate to Lynden Energy Corp. translating United States dollar transactions into Canadian dollars at exchange rates prevailing on the transaction dates.

Foreign currency translation adjustment. Foreign currency translation loss was $369,067 included in other comprehensive income for the three months ended December 31, 2014 , compared to $312,287 for the three months ended December 31, 2013. 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.

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Interest expense. During the three months ended December 31, 2013, we recorded $90,182 of interest expense as compared to $324,963 in the three months ended December 31, 2014. The increase is primarily the result of additional borrowings of $3,950,000 under our revolving credit facility along with higher banking fees during the three months ended December 31, 2014 compared to repayments of $16,750,000 to our credit facility during the three months ended December 31, 2013.

Income taxes. Income taxes decreased by $3,448,100 from $3,917,100 for the three months ended December 31, 2013 to $469,000 for the three months ended December 31, 2014. The decrease in income taxes is primarily the result of gain on disposition of property, plant and equipment of $9,937,842 and higher oil, natural gas, and NGL revenues of $1,232,585 reported in the three months ended December 31, 2013.

Results of Operations

Six Months Ended December 31, 2014 Compared to Six Months Ended December 31, 2013

Net Income. Net income for the six months ended December 31, 2014 was $2,144,930 and $0.02 per share and diluted share, compared to net income of $13,245,863 and $0.11 per share and diluted share for the six months ended December 31, 2013. Net income for the three months ended December 31, 2014 decreased primarily because oil and gas revenues were lower by $2,245,201, no gain on disposition of property, plant and equipment in the six months ended December 31, 2014 compared to a gain of $9,937,842 in the six months ended December 31, 2013, depletion, depreciation and accretion were higher by $1,504,158 in the six months ended December 31, 2013, and offset income taxes being lower by $3,992,000.

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.

	Six Months Ended December 31,
	2014		2013		Change			% Change
Revenues
Oil	$	10,709,854	$	13,664,391	$	(2,954,537	)		(22	%)
Natural gas		1,300,288		971,296		328,992			34	%
NGL		1,883,397		1,503,053		380,344			25	%
Total revenues	$	13,893,539	$	16,138,740	$	(2,245,201	)		(14	%)
Production
Oil (Bbl)		141,415		139,496		1,918			1	%
Natural gas (Mcf)		340,322		219,838		120,483			55	%
NGL (Bbl)		60,973		52,258		8,715			17	%
Total barrel of oil equivalent (Boe/d)		259,108		228,394		30,714			13	%
Daily Production Averages
Oil (Bbls/d)		769		758		10			1	%
Natural gas (Mcf/d)		1,850		1,195		655			55	%
NGL (Bbls/d)		331		284		47			17	%
Total barrel of oil equivalent (Boe/d)		1,408		1,241		167			13	%
Average Prices
Oil (per Bbl)	$	75.73	$	97.96	$	22.23			(23	%)
Natural gas (per Mcf)	$	3.82	$	4.42	$	(0.60	)		(14	%)
NGL (per Bbl)	$	30.89	$	28.76	$	2.13			7	%
Total barrel of oil equivalent (per Boe)	$	53.62	$	70.66	$	(17.04	)		(24	%)

Oil revenues. Oil revenues decreased 22% from $13,664,391 for the six months ended December 31, 2013 to $10,709,854 for the six months ended December 31, 2014 as a result of a $22.23 per Bbl decrease in our average realized price of oil only partially offset by an increase in oil production volumes of 1,918 Bbls.

Natural gas revenues. Natural gas revenues increased 34% from $971,296 for the six months ended December 31, 2013 to $1,300,288 for the six months ended December 31, 2014 as a result of an increase in natural gas production volumes of 120,483 Mcf offset by a $0.60 per Mcf decrease our average realized natural gas price.

NGL revenues. NGL revenues increased 25% from $1,503,053 for the six months ended December 31, 2013 to $1,883,397 for the six months ended December 31, 2014 as a result of an increase in NGL production volumes of 8,715 Bbls and partially compounded by a $2.13 per Bbl increase in our average realized NGL price.

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Effects of derivatives. As at and for the six months ended December 31, 2014, all of the Company’s production was unhedged and will be impacted by fluctuations in the prices of oil and natural gas. For the six months ended December 31, 2013, the Company realized a $43,022 loss on a costless collar oil hedge and reported an unrealized loss of $30,316 on a costless collar oil hedge. As at December 31, 2013, the Company’s outstanding costless collar hedge consisted of 4,750 Bbls of oil per month from January 2014 to June 2014 with a floor of $80/Bbl and a ceiling of $104/Bbl based on NYMEX pricing.

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

	Six months ended December 31,				Change			% Change
	2014		2013
Operating expenses
Lease operating	$	1,993,287	$	1,468,000	$	525,287			36	%
Production and ad valorem taxes		698,900		800,661		(101,761	)		(13	%)
Depletion, depreciation and accretion		5,462,449		3,958,291		1,504,158			38	%
Impairments		449,541		—		449,541			n/a
General and administrative		913,635		629,977		283,658			45	%
Total operating expenses	$	9,517,812	$	6,856,929	$	2,660,883			39	%

	Six months ended December 31,				Change			% Change
	2014		2013
Operating expenses per boe
Lease operating	$	7.69	$	6.43	$	1.26			20	%
Production and ad valorem taxes		2.70		3.51		(0.81	)		(23	%)
Depletion, depreciation and accretion		21.08		17.33		3.75			22	%
Impairments		1.73		—		1.73			n/a
General and administrative		3.53		2.76		0.77			28	%
Total operating expenses	$	36.73	$	30.03	$	6.70			22	%

Lease operating expenses. Lease operating expenses increased 36% from $1,468,000 for the six months ended December 31, 2013 to $1,993,287 for the six months ended December 31, 2014. 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.

Production and ad valorem taxes. Production and ad valorem taxes decreased 13% from $800,661 for the three months ended December 31, 2013 to $698,900 for the three months ended December 31, 2014. The decrease in our production and ad valorem taxes was attributable to lower revenues from falling commodity prices during the six months ended December 31, 2014.

Depletion, depreciation and accretion. Depletion, depreciation and accretion increased 38% from $3,958,291 for the three months ended December 31, 2013 to $5,462,449 for the three months ended December 31, 2014 as a result of a 13% increase in production of Boe along with $25,297,971 more in capitalized costs subject to depletion and depreciation at December 31, 2014 compared to December 31, 2013.

Impairments. Impairments increased by $449,541 for the six months ended December 31, 2013 due to the $449,541 write-off of the Paradox Basin Project suspended exploratory well costs. After revisiting the criteria for the capitalization of the costs related to the Paradox Basin Project suspended exploratory well costs, including the lack of substantial activities to assess the reserves for more than one year following the drilling of the exploratory wells, and the lack of significant expenditures which are planned in the future, management has corrected the accounting for these costs as they should no longer be capitalized. These costs were expensed in the three months ended September 30, 2014.

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General and administrative expenses. General and administrative (“G&A”) expenses increased 45% from $629,977 for the six months ended December 31, 2013 to $913,635 for the six months ended December 31, 2014. The increase in G&A was due to (1) higher professional fees incurred for the registration of the Company’s securities with the U.S. Securities and Exchange Commission; (2) higher administrative, consulting, and directors fees incurred in order to manage the Company’s increasing business complexity; and (3) higher promotion and travel as additional efforts were made to introduce the Company to potential new shareholders. The following table summarizes G&A for the period indicated.

	Six months ended December 31,				Change			% Change
	2014		2013
General and administrative expenses
Administrative, consulting, and directors fees	$	382,673	$	304,998	$	77,675			25	%
Office, miscellaneous and other		93,801		83,222		10,579			13	%
Professional fees		323,544		120,468		203,076			169	%
Promotion and travel		113,617		68,062		45,555			67	%
Stock-based compensation		—		53,227		(53,227	)		(100	%)
Total general and administrative expenses	$	913,635	$	629,977	$	283,658			45	%

Foreign exchange gain (loss). Foreign exchange losses included in net income primarily relate to Lynden Energy Corp. translating United States dollar transactions into Canadian dollars at exchange rates prevailing on the transaction dates.

Foreign currency translation adjustment. Foreign currency translation loss was $906,294 included in other comprehensive income for the six months ended December 31, 2014 , compared to $299,219 for the six months ended December 31, 2013. 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.

Interest expense. During the six months ended December 31, 2013, we recorded $129,768 of interest expense as compared to $514,958 in the six months ended December 31, 2014. The increase is primarily the result of additional borrowings of $9,500,000 under our revolving credit facility in the 2014 period along with higher banking fees.

Income taxes. Income taxes decreased by $3,992,000 from $5,780,000 for the six months ended December 31, 2013 to $1,788,000 for the six months ended December 31, 2014. The decrease in income taxes is primarily the result of gain on disposition of property, plant and equipment of $9,937,842 and higher oil, natural gas, and NGL revenues of $2,245,201 reported in the six months ended December 31, 2013.

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, proceeds from asset dispositions. To date, the Company’s primary use of capital has been for the acquisition, development and exploration of oil and natural gas properties.

Our fiscal 2015 (July 1 to June 30, 2015) capital budget for drilling, completion, recompletion and infrastructure is approximately $34 million. Our fiscal 2015 capital budget is comprised of the following:

• $15 million, or 44%, for the participation in the drilling and completion of 15 gross vertical Midland Basin wells;

• $9 million, or 26% for the participation in the drilling and completion of 2 gross horizontal Midland Basin wells;

• $6.3 million, or 19%, for the participation in the drilling and completion of 3 horizontal Wolcott Lease wells; and

• $3.6 million, or 11%, for the participation in the drilling and completion of 4 vertical Mitchell Ranch wells.

Details of the capital budget expenditures are as follows:

• The Company continues to carry out the Wolfberry vertical well development program on its Midland Basin acreage. The Company’s budget contemplates a gross cost of a Wolfberry well of $2.1 million. The Company’s plans call for 15 gross (6.26 net) Wolfberry wells to spud in fiscal 2015 at an estimated cost to the Company of approximately $15.0 million. Pursuant to the terms of the Midland Basin Participation Agreement with CrownRock, the Company’s funding amount for the 6.26 net wells is equivalent to 7.15 wells.

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• Two initial CrownQuest operated horizontal wells are scheduled for the first half of calendar 2015 in Glasscock County. The Company’s budget contemplates a gross cost of a horizontal well of $9.0 million, for an estimated cost to the Company pursuant to the terms of the CrownRock Midland Basin Participation Agreement of approximately $4.5 million per well.

• Subject to proposals made by the operator, the Company’s budget contemplates three horizontal wells will be spud on the Wolcott Lease in fiscal 2015. The gross cost of a horizontal well is budgeted to be $8.5 million, for an estimated cost to the Company of $2.1 million per well. The Company is funding 24.375% of the cost of the wells on the Wolcott lease and will have a 20% working interest in the wells.

• The Company is also participating in drilling and completion of four new vertical wells in fiscal 2015 on the Mitchell Ranch Project at a budgeted total cost to the Company of $3.6 million.

During the three and six months ending December 31, 2014, we spent approximately $11.5 million and $23.2 million on capital expenditures on property, plant and equipment. As at December 31, 2014, six Wolfberry wells, one Wolcott horizontal well and two Glasscock County horizontal wells remain to be spud under the 2015 capital budget.

Based upon current oil and natural gas price expectations for fiscal 2015, we believe that our cash and cash equivalents on hand, our cash flow from operations and additional borrowings under our revolving credit facility will provide us with sufficient liquidity to execute our current capital program excluding any acquisitions we may enter into. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and 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.

Liquidity

We define liquidity as cash and cash equivalents and funds available under our Credit Facility. The table below summarizes our liquidity position at December 31, 2014 and June 30, 2014.

	Liquidity at December 31			Liquidity at June 30
	2014			2014
Borrowing base	$	40,000,000		$	32,000,000
Cash and cash equivalents		10,411,112			13,955,890
Credit facility		(27,396,318	)		(17,853,245	)
Liquidity	$	23,014,794		$	28,102,645

Working Capital

Our working capital, which we define as current assets minus current liabilities, totaled $11,112,215 and $13,947,730 at December 31, 2014 and June 30, 2014, respectively. Our collection of receivables has historically been timely, and we have had no losses associated with uncollectible receivables. Our cash balances totaled $10,411,112 and $13,955,890 at December 31, 2014 and June 30, 2014, 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 revolving credit facility will be sufficient to fund our working capital needs 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 December 31, 2014 includes $10,088,241 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:

	Six Months Ended December 31,
	2014			2013
Net cash generated by operating activities	$	10,672,384		$	13,026,351
Net cash (used in) generated by investing activities	$	(23,215,493	)	$	1,372,073
Net cash generated by (used in) financing activities	$	9,757,092		$	(1,589,726	)

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Net cash generated by operating activities decreased by 18%, or $2,353,967, to $10,672,384 during the six months ended December 31, 2014 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, partially offset by increases in the timing of receipts of working capital items.

Net cash used in investing activities increased by 1792%, or $24,587,566, to $23,215,493 during the six months ended December 31, 2014 compared to the prior period. The increase in our cash flows used in investing activities was primarily due to (1) $19,603,125 of cash generated by disposition of property, plant and equipment during the six months ended December 31, 2013; and (2) $4,984,441 more in cash used in the acquisition of property, plant and equipment during the six months ended December 31, 2014 pursuant to our fiscal 2015 capital budget.

Net cash generated by financing activities increased by 714%, or $11,346,818, to $9,757,092 during the six months ended December 31, 2014 compared to the prior period. The increase in our cash flows generated by financing activities was primarily due to drawings on the Credit Facility of $9,500,000 during the six months ended December 31, 2014 compared to repayments of outstanding Credit Facility borrowings of $14,250,000 offset by $12,660,274 of common shares issued for cash net of issue costs during the six months ended December 31, 2013.

Debt

The Company has a reducing revolving line of credit (the “Credit Facility”) in an amount up to $100 million. As at December 31, 2014, the Credit Facility has a borrowing base of $40 million, of which $27.3 million has been 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 also apply pursuant to the bank’s re-determinations of the borrowing base. Increases or decreases 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 bank’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 March 2015.

The Credit Facility contains certain mandatory covenants, including minimum current ratio and cash flow requirements, and other standard business operating covenants. The Company has complied with all of these covenants as at and during the six months ended December 31, 2014. 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.

Subsequent Events

None.

Critical Accounting Policies and Estimates

Please refer to “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” in our Registration Statement on Form 10 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 such as obligations under guarantee contracts, a retained or contingent interest in assets transferred to an unconsolidated entity, any obligation under derivative instruments or any obligation under a material variable interest in an unconsolidated entity that provides financing, liquidity, market risk or credit risk support to the Company or engages in leasing or hedging services with the Company.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Commodity Price Risk

Our 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. Our cash flow from product sales will therefore be impacted by fluctuations in commodity prices.

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During the three and six months ended December 31, 2014, we did use any derivative contracts to reduce our exposure to the changes in prices of these commodities.

Credit Risk

Credit risk is the risk that one party to a financial instrument will cause a financial loss for the other party by failing to discharge an obligation. Our cash and cash equivalents and trade and other receivables are exposed to credit risk. We believe the credit risk on cash is low because the counterparties are highly rated financial institutions. The majority of our trade and other receivables are with customers in the petroleum and natural gas industry and are subject to normal industry credit risks. We generally extend unsecured credit to these customers and therefore the collection of trade and other receivables may be affected by changes in economic or other conditions. We believe the risk is mitigated by the size and reputation of the companies to which we extend credit. We have not experienced any material credit loss in the collection of trade and other receivables to date and therefore have not made any provision for bad debts. We did not have any allowance for doubtful accounts as at December 31, 2014 and 2013. As at December 31, 2014, $2,085,094 is owing from CrownQuest Operating, LLC.

Interest Rate Risk

Interest rate risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes in market interest rates. Our cash and credit facility are exposed to interest rate risk as we invest cash at floating rates of interest in highly liquid instruments and borrow funds at floating rates of interest. Fluctuations in interest rates impact interest income and expense. As at December 31, 2014, a 1% change in interest rates would have had a negligible impact on our income and comprehensive income for the period ended December 31, 2014.

Currency Risk

Currency risk is the risk that fair value or future cash flows of a financial instrument will fluctuate because of changes in foreign exchange rates. Financial instruments that impact our income or loss due to currency fluctuations include Canadian dollar denominated assets and liabilities. The Company does not use derivative instruments or hedges to manage currency risks. The sensitivity of our income or loss due to changes in the exchange rate between the Canadian dollar and United States dollar is included in the table below:

	Cash		Trade and other receivables		Trade and other payables			Net assets exposure		Effect of +/- 10% change in currency
Canadian dollar denomination	$	10,088,241	$	14,420	$	(9,630	)	$	10,093,031	$	1,009,303

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 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.

In our amended Form 10 filed during the reporting period covered by this Quarterly Report on Form 10-Q, we disclosed that management had identified a material error in the financial statements for the years ended June 30, 2014 and June 30, 2013 with regards to the determination of its deferred income tax expense, discussed below. Because of this material error, our management has concluded that our disclosure controls and procedures were not effective as of December 31, 2014. We believe that the condensed consolidated interim financial statements in this Form 10-Q fairly present, in all material respects, our financial position, results of operations and cash flows as of the dates, and for the periods presented in conformity with generally accepted accounting principles.

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Changes in Internal Control over Financial Reporting

As disclosed and described in our amended Form 10, after the issuance of our consolidated financial statements for the year ended June 30, 2014, management identified a material error with regards to the determination of its deferred income tax expense for the years ended June 30, 2014, and June 30, 2013, which caused us to restate our previously issued annual consolidated financial statements to correct the error. In connection with this restatement, we determined that we had a material weakness as of June 30, 2014, namely that our controls over the evaluation and review of our deferred income taxes were not effective.

As a result of this error, management is enhancing their internal controls over financial reporting to address this deficiency and expects to implement changes to address the error in the third quarter of fiscal 2015.

There has been no change in our internal control over financial reporting during the quarter ended December 31, 2014, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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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.

In addition to the other information set forth in this Quarterly Report on Form 10-Q, you should carefully consider the factors discussed in “Part I, Item 1A. Risk Factors” in our Registration Statement on Form 10, 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 results of operations.

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

Unregistered Sales of Equity Securities

In October, 2014, we issued 450,000 shares of our common stock upon the exercise of stock options by non- U.S. persons pursuant to an employee benefit plan, for an exercise price of CDN$0.30 (US$0.27; CDN$1 = US$0.90) per share of common stock.

In issuing the above-mentioned shares, we relied on the exemption provided by Rule 701 of the Securities Act of 1933.

Item 6. Exhibits.

See Exhibit Index on page 30 of this Quarterly Report on Form 10-Q.

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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.

LYNDEN ENERGY CORP.
By:	/s/ Colin Watt
	Colin Watt
	President, Chief Executive Officer, Corporate Secretary and Director
	Date:	February 17, 2015

By:	/s/ Laurie Sadler
	Laurie Sadler
	Chief Financial Officer (Principal Financial Officer)
Date:	February 17, 2015

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EXHIBIT INDEX

Exhibit No.	Description
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.
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.

* Filed herewith.

** Furnished herewith.

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