Lynden Energy Corp. - FORM 10-K - September 28, 2015

Lynden Energy Corp. - FORM 10-K - September 28, 2015

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended June 30, 2015

¨	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, Canada
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

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

Securities registered pursuant to Section 12(b) of the Act:

None.

Securities registered pursuant to 12(g) of the Act:

Common shares, no par value.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15 (d) of the Act. Yes ¨ No x

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

On December 31, 2014, the last business day of the registrant’s most recently completed second fiscal quarter, the aggregate market value of the Common Stock held by non-affiliates of the registrant was approximately $52.7 million, based upon the closing price on the TSX Venture Exchange on such date.

As of September 24, 2015, the registrant had 130,198,411 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

(1)	Portions of the Definitive Proxy Statement for the Company’s Annual Meeting of Shareholders to be held during December 2015 are incorporated into Part III of this report.

TABLE OF CONTENTS


Item		Page

	PART I

	Forward-Looking Statements		1

	Definitions		3

Item 1, 2.	Business and Properties		5

Item 1A.	Risk Factors		29

Item 1B.	Unresolved Staff Comments		47

Item 3.	Legal Proceedings		47

Item 4.	Mine Safety Disclosures		47

	PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		48

Item 6.	Selected Financial Data		48

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		49

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		59

Item 8.	Financial Statements and Supplementary Data		61

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		87

Item 9A.	Controls and Procedures		87

Item 9B.	Other Information		88

	PART III

Item 10.	Directors, Executive Officers and Corporate Governance		89

Item 11.	Executive Compensation		89



Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	89

Item 13.	Certain Relationships and Related Transactions, and Director Independence	90

Item 14.	Principal Accounting Fees and Services	90

	PART IV

Item 15.	Exhibits, Financial Statement Schedules	91

	Signatures	92

	Index to exhibits	93

PART I

REFERENCES

As used in this Annual Report on Form 10-K: (i) the terms “we”, “us”, “our”, “Lynden” and the “Company” mean Lynden Energy Corp. and its subsidiaries, if any; (ii) “SEC” refers to the Securities and Exchange Commission; (iii) “Securities Act” refers to the United States Securities Act of 1933; (iv) “Exchange Act” refers to the United States Securities Exchange Act of 1934; (v) “GAAP” refers to generally accepted accounting principles in the United States.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this Annual Report on Form 10-K includes “forward-looking statements.” All statements, other than statements of historical fact included in this Annual Report on Form 10-K, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Annual Report on Form 10-K, the words “will,” “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the section entitled “Item 1A. Risk Factors” included in this Annual Report on Form 10-K.

Forward-looking statements may include statements about our:

•

business strategy;

•

reserves;

•

exploration and development drilling prospects, inventories, projects and programs;

•

ability to replace the reserves we produce through drilling and property acquisitions;

•

financial strategy, liquidity and capital required for our development program;

•

realized oil and natural gas prices;

•

timing and amount of future production of oil and natural gas;

•

hedging strategy and results;

•

future drilling plans;

•

competition and government regulations;

•

ability to obtain permits and governmental approvals;

•

pending legal or environmental matters;

•

marketing of oil and natural gas;

•

leasehold or business acquisitions;

•

costs of developing our properties;

•

general political and economic conditions, including in or affecting other producing countries;

•

credit markets;

•

uncertainty regarding our future operating results; and

•

plans, objectives, expectations and intentions contained in this Annual Report on Form 10-K that are not historical.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of oil and natural gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures and the other risks described under the section entitled “1A. Risk Factors” in this Annual Report on Form 10-K.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.

Should one or more of the risks or uncertainties described in this Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this Annual Report on Form 10-K are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Annual Report on Form 10-K.

GLOSSARY OF OIL AND NATURAL GAS TERMS

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

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

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

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

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

“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.

“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 Annual Report on Form 10-K 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.

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

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

“MBoe.” One thousand Boes.

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

“MGal.” One thousand gallons of NGL.

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

“MMBoe.” One million Boes.

“MMBtu.” One million British Thermal Units.

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

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

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

“NYMEX.” The New York Mercantile Exchange.

“P&NG.” Petroleum and natural gas.

“PDP.” Proved developed producing reserves.

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

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

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

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

“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.

“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.

“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.

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

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

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

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

CURRENCY

Unless otherwise indicated, all currency amounts are expressed in U.S. dollars.

Items 1 and 2. Business and Properties

COMPANY OVERVIEW

We are a company that was formed on June 15, 2000, under the name The InfoUtility Corporation as a result of the amalgamation of InfoUtility Corporation and Black Point Resources Ltd. pursuant to the Business Corporations Act (Ontario). The Company changed its name to Lynden Ventures Ltd., and consolidated its issued and outstanding shares of common stock on a 4:1 basis on January 18, 2005. Lynden then continued into British Columbia under the Business Corporations Act (British Columbia) on February 2, 2006, under the name Lynden Ventures Ltd., which was subsequently changed to Lynden Energy Corp. effective January 16, 2008. We have two wholly owned subsidiaries, Lynden Exploration Ltd. and Lynden USA Inc. We are a reporting issuer in British Columbia, Ontario and Alberta and our common shares are listed on the TSX Venture Exchange under the symbol LVL. We are in the business of acquiring, exploring and developing P&NG rights and properties. We have various working interests in the Midland Basin and Eastern Shelf (Mitchell Ranch), located in the Permian Basin in west Texas, U.S.A. and in the Paradox Basin Project, located in the State of Utah, U.S.A.

Available Information

We file or furnish annual, quarterly and current reports, proxy statements and other documents with the SEC under the Exchange Act. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an Internet website that contains reports, proxy and information statements, and other information regarding issuers, including the Company, that file electronically with the SEC. The public can obtain any documents that we file with the SEC at http://www.sec.gov.

We also make available free of charge through our Internet website (www.lyndenenergy.com) and on the System of Electronic Document Analysis and Retrieval (www.sedar.com) our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. In addition to the reports filed or furnished with the SEC, we publicly disclose material information from time to time in our press releases, at annual meetings of stockholders, in publicly accessible conferences and investor presentations, and through our website.

PROPERTIES AND INTERESTS

The Company’s properties are located within the Permian Basin, West Texas and the Paradox Basin, Utah. The Permian Basin includes both the Midland Basin, the site of the Spraberry and Sugg fields, as well as the Eastern Shelf, where the Mitchell Ranch Project is located.

All of the Company’s reserves are located in the Spraberry and Sugg fields, where the Company is carrying out vertical (Wolfberry) and horizontal well development. No reserves are attributable to the Mitchell Ranch Project or the Paradox Basin Project.

Midland Basin, West Texas

We have been involved in the Midland Basin since October 2009, and hold interests in leases in the West Texas counties of Martin, Midland, Glasscock and Howard as follows:


County	Gross Acres⁽¹⁾		Net Acres⁽²⁾
Martin		2,884		994
Midland		640		280
Glasscock		4,480		1,960
Howard		6,761		2,649

Total		14,765		5,883

⁽¹⁾	A gross acre is an acre in which we own a working interest. The number of gross acres is the total number of acres in which we own a working interest.

⁽²⁾	Net Acres equals the sum of the fractional working interests owned by the Company in gross acres.

Note: All acreage and net interest percentages are approximate and subject to revision. All leases are subject to royalties to the mineral rights owners.

The vast majority of our acreage is operated by CrownQuest Operating LLC (“CrownQuest”), a Midland, Texas based company with extensive knowledge and experience operating in the Permian Basin. Our primary working interest partner in the acreage operated by CrownQuest is CrownRock LP, a party related to CrownQuest. We are party to a Participation Agreement (“Midland Basin Participation Agreement”) with CrownRock, L.P. (“CrownRock”) whereby we will receive 43.75% of CrownRock’s interest in the leases relating to wells drilled after the date of the Participation Agreement by paying 50% of the drilling and completion costs attributable to CrownRock’s interest. A 1,127 acre lease in Martin County, is operated by a separate Midland, Texas based company. We will receive a 20.0% working interest in new wells drilled on the lease by paying 24.375% of the drilling and completion costs.

Midland Basin Vertical Well Development

West Texas has experienced a resurgence in oil-focused exploration and development activity as a result of new completion methods being applied to an unconventional rock package from the Permian Basin, historically one of the most prolific oil basins in North America. The primary objectives in vertical wells are oil (and gas) production from the Spraberry and Wolfcamp formations, which are Permian in age and are informally grouped to form the “Wolfberry” interval or zone. Completions are anticipated over a 2,500 to 3,000 foot gross interval, generally located at a drilling depth of between 7,000 and 11,500 feet. In addition to this main objective, other conventional and unconventional productive zones occur both above and below the Wolfberry assemblage.

We continue to carry out an oil and gas vertical well development program on our Midland Basin acreage, and we had 109 gross (44.69 net) vertical Wolfberry wells tied-in and producing as of June 30, 2015.

In the normal course of business, we evaluate on an ongoing basis the sale of our assets with the objective of generating the best returns for stockholders.

Effective December 30, 2013, we disposed of 12 gross (4.7 net) Wolfberry wells and underlying leases covering approximately 1,000 gross acres (403 net acres) to BreitBurn Energy Partners L.P. of Los Angeles, California for gross proceeds of $19.3 million, subject to customary post–closing adjustments.

Effective February 1, 2014, we reduced our working interest in a 1,127 acre lease in Martin County and the five Wolfberry wells on the lease from 30.625% to 20.0%. As a result of prior obligations on the lease, for any new wells in which we elect to participate, we are required to fund 24.375% of the cost.

The gross cost of a vertical Wolfberry well is currently approximately $1.6 million. Our current plans call for 8 gross (3.25 net) Wolfberry wells to spud in fiscal 2016 (July 1, 2015 to June 30, 2016) at an estimated cost to us of approximately $6.0 million. Pursuant to the terms of the Midland Basin Participation Agreement, Lynden’s funding amount for the 3.25 net wells is equivalent to 3.71 wells.

Our capital budget is subject to change depending upon a number of factors, including but not limited to economic and industry conditions at the time of drilling, prevailing and anticipated prices for oil and gas, the availability of sufficient capital resources for drilling prospects, our financial results and the availability of lease extensions and renewals on reasonable terms.

The following table summarizes the number of Wolfberry wells at the indicated periods.


	March 31, 2014		June 30, 2014		September 30, 2014		December 31, 2014		March 31, 2015		June 30, 2015
Producing Wolfberry wells
Gross		78		91		95		102		105		109
Net		31.72		37.18		38.87		41.68		43.07		44.69
Wells spud or drilled awaiting completion and /or tie in
Gross		7		4		5		2		2		0
Net		2.87		1.68		1.97		0.79		0.81		—

Midland Basin Horizontal Well Development

The Midland Basin acreage also has potential to be developed with horizontal wells. Numerous industry participants are actively testing various formations within the Wolfberry interval for their development potential. CrownQuest, the operator of the vast majority of our acreage, has begun to implement an initial horizontal development plan for the acreage.

An initial CrownQuest operated horizontal well was spud in June 2015, and a second well was spud in July 2015. Both wells were drilled in Glasscock County on a lease block referred to as Wind Farms. Our fiscal 2016 capital budget contemplates an additional three CrownQuest operated horizontal wells on the Wind Farms lease block. The first well has been budgeted at a gross cost of $8.3 million, with the balance of wells budgeted at a gross cost of $7.0 million. Well design, in particular well length and completion approach, will be significant variables in the cost of these wells. The first of these wells has now been drilled and the two remaining wells are not scheduled to be spud until June 2016. Pursuant to the terms of the CrownRock Midland Basin Participation Agreement, the Company is funding 50% of the cost of the wells.

Lynden’s first horizontal well was spud in April 2014 on a 1,127 acre lease in northern Martin County, West Texas. The 1,127 lease (the “Wolcott Lease”) is operated by a separate Midland, Texas based company. A second horizontal well was spud on the Wolcott Lease in early October 2014. Lynden is funding 24.375% of the cost of the wells on the Wolcott Lease and will have a 20% working interest in the wells. Subject to proposals made by the operator, we do not currently anticipate any additional horizontal wells will be spud on the lease in fiscal 2016.

Lynden incurred approximately $27,500,000 of capital expenditures in the Midland Basin during the financial year ended June 30, 2015. Of this amount, approximately $85,500 was for land and lease costs; approximately $22,000 was for the accrual of decommissioning liabilities; and approximately $27,420,000 was for drilling, completion, facilities and tie-in.

Mitchell Ranch Project, West Texas

In 2010, we entered into a Participation Agreement (“Eastern Shelf Participation Agreement”) with CrownRock pertaining to a single P&NG lease covering approximately 104,000 acres of P&NG leases in Coke, Mitchell, and Sterling counties of West Texas, subject to a 22.5% royalty to the mineral rights owners. All acreage is contained within a historical ranch, whose lands were optioned by CrownRock. The ranch lies to the immediate west of the Jameson oil field and is approximately 10 miles south-east of the Iatan oil field. The project is focused on Permo-Pennsylvanian-aged detrital targets along the eastern shelf of the Permian Basin where there are numerous opportunities across several pay zones, all of which are shallower than 8,000 feet in drilling depth.

In July 2011, together with CrownRock, we completed a term assignment with a large, independent exploration and production company, covering approximately 35,000 acres of the 104,000 acre Mitchell Ranch Project, located generally in the southern portion of the ranch. On March 31, 2014, the term assignment acreage was returned to us and CrownRock. We currently have a 50% working interest in the approximately 104,000 acres of the Mitchell Ranch Project.

Several rounds of completions have been carried out at the Company’s original (0.5 net) test well on the Mitchell Ranch Project, the Spade 17 #1, to determine a development plan for the project. The most recent completion was carried out in mid-February 2014. During the three months ended June 30, 2015, it was determined that all principal target zones in the Spade 17 #1 well had been tested and future completion operations were not being planned. Accordingly, expenditures related to the Spade 17 #1 were written off.

A four well test program is currently underway. All four wells were drilled in an area in general proximity to the Spade 17 #1 well. Several rounds of fracture stimulations and production testing have been carried out in the wells. Production testing is ongoing with additional up hole zones remaining to be tested.

Our fiscal 2016 capital budget contemplates 3 gross (1.5 net) vertical wells being spud on the Mitchell Ranch Project. The gross cost of the first of the three wells is expected to be $1.4 million, with subsequent wells expected to be $1.0 million. The Company is funding 50% of the cost of these wells. The first of the 3 wells contemplated in the fiscal 2016 capital budget was spud in early September 2015. The well is targeting features identified through 3D seismic interpretation.

During the year ended June 30, 2015, we received $94,929 in P&NG sales, incurred royalties of $21,359, and incurred production taxes of $3,395 with respect to the Mitchell Ranch Project.

Paradox Basin Project, Utah

The “Paradox Basin Project” is a natural gas focused project located in the Paradox Basin in southwest Utah. The project is separated into two contiguous P&NG prospect areas: the Northern Prospect Area and the Southern Prospect Area. Lynden has a 55% before payout working interest (41.25% after payout working interest) in an 80% net revenue interest in the Northern Prospect Area. Lynden has a 25% before payout working interest (23.75% after payout working interest) in an 85% to 87% net revenue interest in the Southern Prospect Area.

Lynden and its partners have drilled nine gross wells in the Paradox Basin Project as part of the evaluation of the project’s productive potential. Two of the wells have now been plugged and abandoned and several of the wells continue to produce periodically.

Our interest in the gas gathering system, including approximately 25 miles of pipeline, is held though our 48% interest in Abajo Gas Transmission Company, LLC (“Abajo”). Through our interest in Abajo, Lynden is entitled to an effective 55% interest in the Northern Prospect Area gathering system and a 25% effective interest in the Southern Prospect Area gathering system.

During the financial year ended June 30, 2015, we received $136,859 in P&NG sales, incurred royalties of $22,916, incurred transportation costs of $41,607, and incurred production taxes of $3,745 in the Paradox Basin. The transportation and marketing costs were paid to Abajo at market rates. The majority of the P&NG sales were from the sale of natural gas.

As a result of the depressed price of natural gas, we have not undertaken any material development work on the Paradox Basin Project over the past several years and consequently Lynden’s lease holdings continue to expire. Lynden’s lease holdings not held by production will expire in the next three years.

During the three months ended September 30, 2014, management determined that the capitalized costs related to the Paradox Basin Project suspended exploratory well costs should have been expensed in the year ended June 30, 2014, due to 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 expensed the remaining costs of $449,541 in the three months ended September 30, 2014.

In December 2013, the Company disposed of its interest in leases covering approximately 8,400 gross acres in the Paradox Basin Project Southern Prospect Area for proceeds of approximately $307,000. As Lynden’s interest in these leases had been previously written down, Lynden recognized a gain of approximately $288,000 on disposition.

SUMMARY RESERVE INFORMATION

The following chart details our summary reserve information as of June 30, 2015 and 2014. The information is based on a reserve report prepared by our independent consulting petroleum engineers, Cawley, Gillespie and Associates, Inc. (“CGA”). You should refer to “Item 1A. Risk Factors,” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in evaluating the material presented in the following table.


	June 30, 2015
	12-Month Unweighted Average Pricing: Oil $71.68, Natural Gas $3.361
	Oil (Mbbl)		Natural Gas (MMcf)		Natural Gas Liquids (Mbbl)
Proved developed producing		1,893.0		6,254.8		1,117.0
Proved developed non-producing		333.8		468.3		83.6
Proved undeveloped		4,402.5		12,848.2		2,284.5

Total proved		6,629.3		19,571.3		3,485.1
Probable		34.8		123.0		21.9


	June 30, 2014
	12-Month Unweighted Average Pricing: Oil $100.27, Natural Gas $4.104
	Oil (Mbbl)		Natural Gas (MMcf)		Natural Gas Liquids (Mbbl)
Proved developed producing		1,606.9		4,506.8		893.9
Proved developed non-producing		496.0		773.5		153.5
Proved undeveloped		1,847.2		4,438.8		880.7

Total proved		3,950.1		9,719.1		1,928.1
Probable		210.8		275.1		54.6

Proved Reserves

Estimates of proved developed and undeveloped reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. See “Item 1A. Risk Factors” for more information.

The following table provides a rollforward of the total proved reserves for the years ended June 30, 2015 and 2014.


	Oil (Bbls)			Natural Gas (Mcf)			Natural Gas Liquids (Mbbl)			Total (BOE)
Net Proved Reserves
Balance at June 30, 2014		3,950,079			9,719,125			1,928,080			7,498,013
Discoveries and extensions		3,086,400			8,595,200			1,528,700			6,047,633
Revisions of prior estimates		(132,914	)		1,927,264			147,833			336,130
Production		(274,185	)		(670,309	)		(119,513	)		(505,416	)

Balance at June 30, 2015		6,629,380			19,571,280			3,485,100			13,376,360

Net Proved Developed Reserves, included above
Balance at June 30, 2014		2,102,913			5,280,353			1,047,356			4,030,328
Balance at June 30, 2015		2,226,910			6,723,130			1,200,620			4,548,052
Net Proved Undeveloped Reserves, included above
Balance at June 30, 2014		1,847,166			4,438,772			880,724			3,467,685
Balance at June 30, 2015		4,402,470			12,848,150			2,284,480			8,828,308


	Oil (Bbls)			Natural Gas (Mcf)(1)			Total (BOE)
Net Proved Reserves
Balance at June 30, 2013		3,653,262			13,589,316			5,918,148
Discoveries and extensions		1,023,690			1,950,095			1,348,706
Revisions of prior estimates		327,408			9,377,971			1,890,403
Sales of reserves in place		(808,114	)		(2,451,430	)		(1,216,686	)
Production		(246,167	)		(1,178,347	)		(442,558	)

Balance at June 30, 2014		3,950,079			21,287,605			7,498,013

Net Proved Developed Reserves, included above
Balance at June 30, 2013		1,805,485			6,585,058			2,902,995
Balance at June 30, 2014		2,102,913			11,564,489			4,030,328
Net Proved Undeveloped Reserves, included above
Balance at June 30, 2013		1,847,777			7,004,258			3,015,153
Balance at June 30, 2014		1,847,166			9,723,116			3,467,685

(1)

Natural gas reserves for fiscal 2013 are shown in “wet” Mcf, which includes NGL. We receive our production data from third-party operators. Our third-party operators did not and cannot provide complete three-stream data for fiscal 2013 that would allow the Company to break-out NGLs in addition to oil and gas in our reserve and production disclosure.

Proved Undeveloped Reserves

As of June 30, 2015, our PUDs totaled 4,402.5 MBbls of oil, 12,848.2 MMcf of natural gas, and 2,284.5 MBbls of NGL. PUDs will be converted from undeveloped to developed as the applicable wells begin production. During the year ended June 30, 2015, we converted approximately 338 MBoe of proved undeveloped reserves to proved developed reserves by drilling and completing 5 gross (2.18 net) PUD vertical Wolfberry locations.

Changes in PUDs that occurred during the year ended June 30, 2015 were primarily due to (i) the addition of 5,480 MBoe attributable to new PUD locations, principally as a result of an increase in location density, from the strategic drilling of wells to delineate our acreage position, (ii) the conversion of 338 MBoe of reserves categorized as PUD as of June 30, 2014 that were converted to PDP and (iii) negative revisions of previous estimates of 2,075 MBoe, principally as a result of a decrease in oil, natural gas and NGL prices.

During the year ended June 30, 2015, we spent approximately $3.7 million to convert PUDs to proved developed reserves.

All of our PUD drilling locations are scheduled to be drilled within five years of their initial booking.

All of our drilling locations associated with PUDs are scheduled for drilling within the primary term of the associated lease or as a part of the Company’s continuous development plan.

See “Items 1 and 2. Business and Properties—Selected Oil and Natural Gas Information—Leasehold Acreage” for additional discussion of the continuous development provisions of our leasehold acreage.

Probable Reserves

Estimates of probable reserves are inherently imprecise. When producing an estimate of the amount of oil and natural gas that is recoverable from a particular reservoir, an estimated quantity of probable reserves is an estimate that is as likely as not to be achieved. Estimates of probable reserves are also continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.

Deterministic methods to estimate probable reserve quantities are used, and when deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

RESERVE INFORMATION PROCEDURES AND AUDITS

The information included in this Annual Report on Form 10-K about our reserves as of June 30, 2015 and 2014, is based on reports prepared by CGA. The estimates of 100% of our proved reserves at June 30, 2015, and 2014, were prepared by CGA. Reserves were estimated in accordance with guidelines established by the SEC and the Financial Accounting Standards Board (“FASB”) applicable to public reporting companies.

Reserve Estimation Procedures

We have established internal controls over reserve estimation processes and procedures to support the accurate and timely preparation and disclosure of reserve estimates in accordance with SEC and GAAP requirements. These controls include oversight of the reserves estimation reporting processes by members of our senior management team and the preparation of annual reserve reports by CGA.

As part of our reserves estimation report processes, CGA works with our financial, land and accounting personnel to gather accurate and current data in order to prepare reserves estimates. Data gathered include updated production, lease operating expenses, price differentials and ownership interest. The reports are prepared by CGA and reviewed by members of our senior management team. All reserve estimates, material assumptions and inputs used in reserve estimates and significant changes in reserve estimates are reviewed for engineering and financial appropriateness and compliance with SEC and GAAP standards by CGA.

The Company engages a technical consultant to assist in the preparation of all of our reserve estimates. The consultant and Colin Watt, our President and Chief Executive Officer, work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our assets in the Permian Basin. Our Chief Executive Officer and our technical consultant confer with our independent reserve engineers periodically during the period covered by the proved reserve report to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to the independent reserve engineers for our properties, such as ownership interest, oil and natural gas production, well test data, commodity prices and operating and development costs. Colin Watt, our President and Chief Executive Officer, is primarily responsible for overseeing the preparation of all of our reserve estimates. In addition, our technical consultant is a petroleum engineer with approximately 39 years of reservoir and operations experience.

Reserves Report Preparation

CGA follows the general principles set forth in the standards pertaining to estimating and preparing oil and natural gas reserve information promulgated by the Society of Petroleum Engineers (“SPE”).

In conjunction with the preparation of our reserves report, we provided our internal engineering and geosciences technical data and all applicable analyses to CGA. No data was withheld from CGA. CGA accepted without independent verification the accuracy and completeness of the historical information and data furnished by us with respect to ownership interest, oil and natural gas production, well test data, commodity prices, operating and development costs, and any agreements relating to current and future operation of the properties and sale of production. Nevertheless, if in the course of its evaluation something came to its attention that brought into question the validity or sufficiency of any such information or data, CGA did not rely on the information or data until it had satisfactorily resolved its questions relating thereto or had independently verified that information or data.

Qualifications of Reserves Preparers

CGA is a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. CGA was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-693. Within CGA, the technical person primarily responsible for preparing the estimates set forth in the CGA letter dated September 18, 2015 was Mr. Robert D. Ravnaas. Mr. Ravnaas is President of CGA and is a Registered Professional Engineer in the State of Texas (License No. 61304). Mr. Ravnaas has been a Petroleum Consultant for CGA since 1983 and became President in 2011. We understand that he has completed numerous field studies, reserve evaluations and reservoir stimulation, waterflood design and monitoring, unit equity determinations and producing rate studies and that he has testified before the Railroad Commission of Texas (the “TRRC”) in unitization and field rules hearings. Mr. Ravnaas received a B.S. with special honors in Chemical Engineering from the University of Colorado at Boulder, and a M.S. in Petroleum Engineering from the University of Texas at Austin. He is a member of the SPE, the Society of Petroleum Evaluation Engineers, the American Association of Petroleum Geologists and the Society of Professional Well Log Analysts.

Technologies Used in Reserves Estimates

PUDs include those 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 completion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having undeveloped proved reserves only if an ability and intent has been established to drill the reserves within five years, unless specific circumstances justify a longer time period.

In the context of reserves estimations, reasonable certainty means a high degree of confidence that the quantities will be recovered, and reliable technology is a grouping of one or more technologies (including computational methods) that has been field-tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. In estimating proved reserves, we use several traditional methods, such as, performance-based methods, volumetric-based methods and analogy with similar properties. In addition, we use additional technical analyses, such as seismic interpretation, geophysical logs and core data to provide incremental support for more complex reservoirs. Information from this incremental support is combined with the traditional technologies to enhance the certainty of our reserve estimates.

Oil and Natural Gas Reserves under Canadian Law

As a reporting issuer under Alberta, British Columbia and Ontario securities laws, we are required under Canadian law to comply with National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” (“NI 51-101”) implemented by the members of the Canadian Securities Administrators in all of our reserves related disclosures. CGA evaluated the Company’s reserves as of June 30, 2015, in accordance with the reserves definitions of NI 51-101 and the Canadian Oil and Gas Evaluators Handbook (“COGEH”). Our annual oil and natural gas reserves disclosures prepared in accordance with NI 51-101 and COGEH and filed in Canada are available under Lynden’s profile at www.sedar.com.

SELECTED OIL AND NATURAL GAS INFORMATION

The following tables set forth selected oil and natural gas information from our operations as of and for each of the years ended June 30, 2015, 2014 and 2013. Because of normal production declines, increased or decreased drilling activities, and the effects of acquisitions or divestitures, the historical information presented below should not be interpreted as being indicative of future results.

Discrepancies in production volumes reported in tables under the heading Production, Price and Cost Data and in tables under the heading Proved Reserves in this Item 1 and 2. Business and Properties, are a result of the inclusion of production volumes in the Production, Price and Cost Data tables from the Mitchell Ranch Project and the Paradox Basin Project, both of which have no attributable reserves. Production volumes reported under the heading Proved Reserves are based on a reserve report prepared by CGA and match those values provided in the “Supplemental Information on Oil and Gas Exploration and Production Activities” accompanying the audited consolidated financial statements.

Production, Price and Cost Data

The following table sets forth summary production and operating data for the years ended June 30, 2015 and 2014. Unless stated otherwise, revenue and production data with respect to natural gas include NGL revenue and NGL production data, respectively.


	Year Ended June 30, 2015
	Permian Basin		Paradox Basin		Total
Production information:
Annual sales volumes:
Oil (Bbls)		275,461		114		275,575
Natural Gas (Mcf)		670,309		19,285		689,594
Natural Gas Liquids (Bbls)		119,513		1,131		120,644
Total (Boe)		506,692		4,459		511,151
Average daily sales volumes:
Oil (Bbls)		755		0.3		755
Natural Gas (Mcf)		1,836		53		1,889
Natural Gas Liquids (Bbls)		328		3		331
Total (Boe)		1,388		12		1,400
Average prices:
Oil (per Bbl)	$	63.00	$	70.40	$	63.02
Natural Gas (per Mcf)	$	3.18	$	3.41	$	3.19
Natural Gas Liquids (per Bbl)	$	21.37	$	35.48	$	21.50
Total (per Boe)	$	43.51	$	25.55	$	43.40
Average costs (per Boe):
Production costs:
Lease operating expense	$	9.07	$	44.07	$	9.38
Production taxes	$	2.15	$	0.84	$	2.14
	Year Ended June 30, 2014
	Permian Basin		Paradox Basin		Total
Production information:
Annual sales volumes:
Oil (Bbls)		247,075		78		247,153
Natural Gas (Mcf)		496,201		22,536		518,737
Natural Gas Liquids (Bbls)		113,691		1,927		115,618
Total (Boe)		443,467		5,761		449,228
Average daily sales volumes:
Oil (Bbls)		677		0.2		677
Natural Gas (Mcf)		1,359		62		1,421
Natural Gas Liquids (Bbls)		312		5		317
Total (Boe)		1,215		16		1,231
Average prices:
Oil (per Bbl)	$	95.37	$	88.90	$	95.37
Natural Gas (per Mcf)	$	4.26	$	4.44	$	4.26


Natural Gas Liquids (per Bbl)	$	30.99	$	31.24	$	31.00
Total (per Boe)	$	65.84	$	29.02	$	65.37
Average costs (per Boe):
Production costs:
Lease operating expense	$	6.65	$	33.81	$	6.99
Production taxes	$	3.27	$	1.17	$	3.24

	Year Ended June 30, 2013
	Permian Basin		Paradox Basin		Total
Production information:
Annual sales volumes:
Oil (Bbls)		176,341		180		176,521
Natural Gas (Mcf)(1)		706,229		40,237		746,466
Total (Boe)		443,467		6,886		300,932
Average daily sales volumes:
Oil (Bbls)		483		0.5		484
Natural Gas (Mcf)(1)		1,935		110		2,045
Total (Boe)		806		19		825
Average prices:
Oil (per Bbl)	$	88.26	$	70.29	$	88.17
Natural Gas (per Mcf)(1)	$	4.80	$	3.05	$	4.54
Total (per Boe)	$	64.46	$	19.64	$	62.98
Average costs (per Boe):
Production costs:
Lease operating expense	$	5.68	$	22.52	$	6.05
Production taxes	$	3.25	$	1.02	$	3.20

(1)

We had one field that exceeded 15% of our total proved reserves as of June 30, 2015. Our Spraberry play represented approximately 99.5% of our total proved reserves. The following table provides additional information related to the Spraberry play:


	Year Ended June 30, 2015		Year Ended June 30, 2014		Year Ended June 30, 2013
Production information:
Annual sales volumes:
Oil (Bbls)		273,588		245,514		174,417
Natural Gas (Mcf)(1)		666,875		493,720		700,207
Natural Gas Liquids (Bbls)		118,831		113,131		—
Total (Boe)		503,535		440,932		291,118
Average prices:
Oil (per Bbl)	$	63.05	$	95.37	$	88.26
Natural Gas (per Mcf)(1)	$	3.18	$	4.26	$	4.61
Natural Gas Liquids (per Bbl)	$	21.34	$	30.99		—
Total (per Boe)	$	43.53	$	65.84	$	64.00
Average costs (per Boe):
Production costs:
Lease operating expense	$	8.75	$	6.65	$	5.66
Production taxes	$	2.15	$	3.27	$	3.25

(1)

Productive Wells

The following table sets forth information at June 30, 2015, relating to the productive wells in which we owned a working interest as of that date. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we own an interest, and net wells are the sum of our fractional working interests owned in gross wells.


	Gross Productive Wells						Net Productive Wells
	Oil		Natural Gas		Total		Oil		Natural Gas		Total
Total		116		0		116		44.98		0		44.98

Leasehold Acreage

The following table sets forth information relating to our leasehold acreage:

Developed Acreage (a)

Undeveloped Acreage (b)

Gross (c)

Net (d)

Gross (c)

Net (d)

Total

9,200

3,814

120,938

58,898

(a)	Developed acres are acres spaced or assigned to productive wells capable of production.

(b)	Undeveloped acres are acres which are not held by commercially producing wells, regardless of whether such acreage contains proved reserves.

(c)	A gross acre is an acre in which we own a working interest. The number of gross acres is the total number of acres in which we own a working interest.

(d)	A net acre is deemed to exist when the sum of the fractional ownership working interest in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. All of the leases governing our acreage have continuous development clauses that permit us to continue to hold the acreage under such leases after the expiration of the primary term if we initiate additional development within 60 to 180 days of the expiration date, without the requirement of a lease extension payment. Thereafter, the lease is held with additional development every 60 to 180 days until the entire lease is held by production. All of our drilling locations associated with PUDs are scheduled for drilling within the primary term of the associated lease or as a part of our continuous development plan. None of our PUDs as of June 30, 2015 is scheduled to be developed on a date more than five years from the date the reserves were initially booked as PUDs.

The vast majority of the gross and net undeveloped acreage set forth in the table above is held by production or is subject to our continuous development plan. In particular, 104,000 gross undeveloped acres and 52,000 net undeveloped acres are associated with the ongoing Mitchell Ranch project. The entire 104,000 acre Mitchell Ranch project lease can be perpetuated by drilling a well every 90 days. However, approximately 11,400 gross undeveloped acres and approximately 4,800 net undeveloped acres, all associated with the Paradox Basin Project, will expire within the next three years. We believe that the expiring acreage in the Paradox Basin in any given year does not represent a material amount of our total gross or net undeveloped acreage.

The following table sets forth the expiration dates of the leases, excluding leases currently on continuous development, on our gross and net undeveloped acres as of June 30, 2015.


	Acres Expiring (1)
	Paradox
	Gross	Net
Period Ending June 30:
2016	6,146		2,856
2017	4,128		1,726
2018	1,099		247

Total	11,373		4,829

(1)	Acres expiring are based on lease terms.

With respect to the leases subject to expiration during the 2016 fiscal year, we may perpetuate these leases pursuant to their respective continuous drilling clauses, we may sell all or some of these leases, we may allow the leases to expire undrilled or we may extend the leases prior to their expiration based on planned activities for the 2016 fiscal year or for other business reasons. In certain leases, an extension is only subject to our election to extend and the fulfillment of certain capital expenditure commitments. In other cases, the extensions are subject to the consent of third parties, and no assurance can be given that the requested extensions will be granted.

Drilling and Other Exploration and Development Activities.

The following table sets forth the number of gross and net wells drilled by us during the years ended June 30, 2015, 2014 and 2013, that were productive or dry holes. This information should not be considered indicative of future performance, nor should it be assumed that there were any correlations between the number of productive wells drilled and the oil and natural gas reserves generated thereby or the costs to us of productive wells compared to the costs of dry holes.


	Year Ended June 30,
	2015		2014		2013
Gross:
Development
Productive		16		24		40
Dry		0		0		0

Total		16		24		40
Exploratory
Productive		4		0		0
Dry		0		0		0

Total		4		24		40
Net:
Development
Productive		6.23		9.78		16.90
Dry		0		0		0

Total		6.23		9.78		16.90
Exploratory
Productive		2.0		0		0
Dry		0		0		0

Total		2.0		9.78		16.90

Present Activities

The following table sets forth information about our wells that were in the process of being drilled as of June 30, 2015:


	June 30, 2015
Gross:
Development		0
Exploratory		1
Total		1
Net:
Development		0
Exploratory		0.44
Total		0.44

TITLE TO PROPERTIES

We believe we have satisfactory title, in all material respects, to substantially all of our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Our producing properties are subject to royalty interests, standard liens incident to operating agreements, liens for current taxes and other burdens, which we believe do not materially interfere with the use of or affect the value of such properties. Substantially all of our proved producing oil and natural gas properties are pledged as collateral for borrowing under our revolving Credit Facility. As is customary in the industry, in the case of undeveloped properties, we typically rely upon the judgment of oil and natural gas lease brokers or landmen who perform the field work in examining records in the appropriate governmental or county clerk’s office before attempting to acquire a lease or other developed rights in a specific mineral interest. Prior to drilling a well, however, we obtain a preliminary title review of the spacing unit within which the proposed well is to be drilled to ensure there are no obvious deficiencies in title to the well. During the course of this preliminary title review, we may find that individual properties are subject to burdens that we believe do not materially interfere with the use or affect the value of the properties, such as royalty interest, standard liens incident to operating agreements and liens for current taxes.

Our failure to obtain perfect title to our leaseholds may adversely affect our current production and reserves and our ability in the future to increase production and reserves.

MARKETING AND MAJOR PURCHASERS

All revenues from the sale of oil and natural gas production are collected and disbursed on our behalf by CrownQuest. Production from our properties is marketed using methods that are consistent with industry practices. Sales prices for oil, NGL and natural gas production are negotiated based on factors normally considered in the industry, such as an index or spot price, price regulations, distance from the well to the pipeline, commodity quality and prevailing supply and demand conditions. We sell our oil and natural gas production principally to marketers and other purchasers that have access to pipeline facilities. In areas where there is no practical access to pipelines, oil is transported to storage facilities by trucks owned or otherwise arranged by the marketers or purchasers. Our marketing of oil and natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted.

For the year ended June 30, 2015, oil and natural gas production representing approximately 46% of our total revenues was sold to NGL Crude Logistics, LLC (formerly known as High Sierra Crude Oil & Marketing, LLC), oil and natural gas production representing approximately 20% of our total revenues was sold to Targa Pipeline Partners LP, and oil and natural gas production representing approximately 31% of our total revenues was sold to LPC Crude Oil, Inc. The loss of any significant purchaser may result in a temporary decline in our revenues.

While the loss of any of these purchasers may result in a temporary interruption in sales of, or a lower price for, our production, we believe that the loss of any of these purchasers would not have a material adverse effect on our operations because there are other purchasers in our producing regions.

SEASONALITY

Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months, thereby affecting the price we receive for natural gas. Seasonal anomalies, such as mild winters or hotter than normal summers, sometimes lessen this fluctuation. Demand for natural gas and natural gas liquid (“NGL”) can be particularly weak in the fall and spring which, coupled with high inventory levels, could result in the shut-in and deferral of production. Demand for oil has generally not been seasonal.

COMPETITION

The oil and natural gas industry in the regions in which we operate is highly competitive. We encounter strong competition from numerous parties, ranging generally from small independent producers to major integrated companies. We primarily encounter significant competition in acquiring properties, contracting for drilling and workover equipment, and securing trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than ours. As a result, our competitors may be able to pay more for desirable properties, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit.

In addition to the competition for drilling and workover equipment, we are also affected by the availability of related equipment and materials. The oil and natural gas industry periodically experiences shortages of drilling and workover rigs, equipment, pipe, materials and personnel, which can delay developmental drilling, workover and exploration activities and cause significant price increases. Past shortages of personnel made it difficult to attract and retain personnel with experience in the oil and natural gas industry and caused us to increase our general and administrative budget. We are unable to predict the timing or duration of any such shortages

Competition is also strong for attractive oil and natural gas producing properties, undeveloped leases and drilling rights. Although we regularly evaluate acquisition opportunities and submit bids as part of our growth strategy, we do not have any current agreements, understandings or arrangements with respect to any material acquisition.

EMPLOYEES

Our operations and activities are managed by our board of directors (the “Board”) and our executive management personnel. We have no employees. However, pursuant to a management agreement with Colin Watt, the employees of Squall Capital Corp., a company wholly owned by Colin Watt, provide monthly administrative and support services. Mr. Watt currently devotes a minimum of 35 hours per week to the Company’s business. As of June 30, 2015, Squall had 3 full-time employees, all of which worked at our Vancouver, BC office. We also use the services of independent contractors to perform various other services.

We are a non-operator, and as such all of the oil and gas field operations are carried out by an operator. The vast majority of our acreage is operated by CrownQuest Operating, LLC of Midland, Texas. CrownQuest is a company related to CrownRock. CrownQuest operates 94% of our wells in the Midland Basin, and is the operator of both the Mitchell Ranch Project and Paradox Basin Project.

REGULATION OF THE OIL AND NATURAL GAS INDUSTRY

General

The oil and natural gas industry in the U.S. is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burdens on the oil and natural gas industry increase our cost of production and, consequently, affect our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the oil and natural gas industry with similar types, quantities and locations of production.

Activities on Federal Lands

Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires the federal Bureau of Land Management, a division of the U.S. Department of the Interior (the “BLM”) and/or other relevant federal agencies of the U.S. Department of the Interior to evaluate major agency actions having the potential to significantly affect the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative effects of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirement of NEPA. This process has the potential to delay development of some of our oil and natural gas projects. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects.

Our lease operations on these federal leases must also comply with numerous regulatory restrictions, including various non-discrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to specified on-site security regulations and other appropriate federal permits. Our leases upon these federal lands contain relatively standardized terms and require compliance with detailed federal regulation and orders, and contain stipulations limiting activities that may be conducted on the lease. Some stipulations are unique to particular geographic areas and may limit the times during which activities on the lease may be conducted, the manner in which certain activities may be conducted or, in some case, may ban any surface activity. Under certain circumstance, the BLM or other relevant federal agency may require our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect our financial condition and operations.

Regulation of the Development and Production of Oil and Natural Gas

Development and production operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, the posting of bonds in connection with various types of activities and filing reports concerning operations. Most states, and some counties and municipalities, in which we operate, also regulate one or more of the following:

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the location of wells;

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the method of drilling and casing wells;

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the method and ability to fracture and stimulate wells;

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the surface use and restoration of properties upon which wells are drilled;

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the plugging and abandoning of wells; and

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notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, NGLs and natural gas within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but there can be no assurance that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells, or limit the number of locations we can drill.

Regulation of Transportation and Sale of Oil and NGL

The liquids industry is also extensively regulated by numerous federal, state and local authorities. In a number of instances, the ability to transport and sell such products on interstate pipelines is dependent on pipelines whose rates, terms and conditions of service are subject to the Federal Energy Regulatory Commission (“FERC”) jurisdiction under the Interstate Commerce Act (the “ICA”). We do not believe these regulations affect us any differently than other producers.

The ICA requires that pipelines maintain a tariff on file with FERC. The tariff sets forth the established rates as well as the rules and regulations governing the service. The ICA requires, among other things, that rates and terms and conditions of service on interstate common carrier pipelines be “just and reasonable.” Such pipelines must also provide jurisdictional service in a manner that is not unduly discriminatory or unduly preferential. Shippers have the power to challenge new and existing rates and terms and conditions of service before FERC.

Rates of interstate liquids pipelines are currently regulated by FERC primarily through an annual indexing methodology, under which pipelines increase or decrease their rates in accordance with an index adjustment specified by FERC. For the five-year period beginning in 2010, FERC established an annual index adjustment equal to the change in the producer price index for finished goods plus 2.65%. This adjustment is subject to review every five years. Under FERC’s regulations, a liquids pipeline can request a rate increase that exceeds the rate obtained through application of the indexing methodology by using a cost-of-service approach, but only after the pipeline establishes that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing methodology. Increases in liquids transportation rates may result in lower revenue and cash flows for us.

In addition, due to common carrier regulatory obligations of liquids pipelines, capacity must be prorated among shippers in an equitable manner in the event there are nominations in excess of capacity by current shippers or capacity requests are received from a new shipper. Therefore, new shippers or increased volume by existing shippers may reduce the capacity available to us. Any prolonged interruption in the operation or curtailment of available capacity of the pipelines that we rely upon for liquids transportation could have a material adverse effect on our business, financial condition, results of operations and cash flows. However, we believe that access to liquids pipeline transportation services generally will be available to us to the same extent as to our similarly-situated competitors.

Intrastate liquids pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate liquids pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate liquids pipeline rates, varies from state to state. We believe that the regulation of liquids pipeline transportation rates will not affect our operations in any way that is materially different from the effects on our similarly-situated competitors.

In November 2009, the FTC issued regulations pursuant to the Energy Independence and Security Act of 2007 intended to prohibit market manipulation in the petroleum industry. Violators of the regulations face civil penalties of up to $1.0 million per violation per day. In July 2010, the U.S. Congress passed the Act, which incorporated an expansion of the authority of the Commodity Futures Trading Commission (“CFTC”) to prohibit market manipulation in the markets regulated by the CFTC. This authority, with respect to crude oil swaps and futures contracts, is similar to the anti-manipulation authority granted to the FERC with respect to anti-manipulation in the

natural gas industry and the FTC with respect to crude oil purchases and sales. In July 2011, the CFTC issued final rules to implement their new anti-manipulation authority. The rules subject violators to a civil penalty of up to the greater of $1.0 million or triple the monetary gain to the person for each violation.

Sales prices of oil, condensate and NGL are not currently regulated and are made at market prices. Although prices of these energy commodities are currently unregulated, the U.S. Congress historically has been active in their regulation. We cannot predict whether new legislation to regulate the prices charged for these commodities, might be proposed, what proposals, if any, might actually be enacted by the U.S. Congress or the various state legislatures and what effect, if any, the proposals might have on our operations.

Regulation of Transportation and Sale of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by FERC under the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 (“NGPA”) and regulations issued under those statutes. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.

The availability, terms and cost of transportation significantly affect sales of gas. Federal and state regulations govern the price and terms for access to gas pipeline transportation. Intrastate gas pipeline transportation activities are subject to various state laws and regulations, as well as orders of state regulatory bodies, including the TRRC. The interstate transportation and sale of gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by FERC. FERC endeavors to make gas transportation more accessible to gas buyers and sellers on an open-access and non-discriminatory basis. Natural gas transportation has historically been heavily regulated. Therefore, we cannot provide any assurance that the current less stringent regulatory approach will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.

Pursuant to the Energy Policy Act of 2005 (“EPAct 2005”) it is unlawful for “any entity,” including producers such as us, that are otherwise not subject to FERC’s jurisdiction under the NGA to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of gas or the purchase or sale of transportation services subject to regulation by FERC, in contravention of rules prescribed by FERC. FERC’s rules implementing this provision make it unlawful, in connection with the purchase or sale of gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 also gives FERC authority to impose civil penalties up to $1.0 million per day per violation for violations of the NGA and the NGPA. The anti-manipulation rule applies to activities of entities not otherwise subject to FERC’s jurisdiction to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which includes the annual reporting requirements under Order 704 (defined below).

In December 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order 704”). Under Order 704, any market participant that engages in wholesale sales or purchases of gas that equal or exceed 2.2 million MMBtus of physical natural gas in the previous calendar year must annually report such sales and purchases to FERC on Form No. 552 on May 1 of each year. Form No. 552 contains aggregate volumes of natural gas purchased or sold at wholesale prices in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 is intended to increase the transparency of the wholesale gas markets and to assist FERC in monitoring those markets and in detecting market manipulation.

Additional proposals and proceedings that might affect the natural gas industry are considered from time to time by the U.S. Congress, FERC, state regulatory bodies and the courts. We cannot predict when or if any such proposals might become effective or their effect, if any, on our operations. We do not believe that we will be affected by any action taken in a materially different way than other natural gas producers, gatherers and marketers with which we compete.

Gas Gathering

Section 1(b) of the NGA exempts gas gathering facilities from FERC’s jurisdiction. We believe that the gas gathering facilities in which we hold an interest meet the traditional tests FERC has used to establish a pipeline system’s status as a non-jurisdictional gatherer. There is, however, no bright-line test for determining the jurisdictional status of pipeline facilities. Moreover, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of litigation from time to time, so the classification and regulation of some of our gathering facilities may be subject to change based on future determinations by FERC and the courts.

While we hold an interest in some gas gathering facilities, we also depend on gathering facilities owned and operated by third parties to gather production from our properties, and therefore, we are affected by the rates charged by these third parties for gathering services. To the extent that changes in federal or state regulation affect the rates charged for gathering services, we also may be affected by these changes. Accordingly, we do not anticipate that we would be affected any differently than similarly situated gas producers.

Energy Commodity Prices

Sales prices of gas, oil, condensate and NGL are not currently regulated and are made at market prices. Although prices of these energy commodities are currently unregulated, the U.S. Congress historically has been active in their regulation. We cannot predict whether new legislation to regulate oil and gas, or the prices charged for these commodities, might be proposed, what proposals, if any, might actually be enacted by the U.S. Congress or the various state legislatures and what effect, if any, the proposals might have on our operations.

Transportation of Hazardous Materials

The U.S. Department of Transportation has adopted regulations requiring that certain entities transporting designated hazardous materials develop plans to address security risks related to the transportation of hazardous materials. We do not believe that these requirements will have an adverse effect on us or our operations. We cannot provide any assurance that the security plans required under these regulations would protect against all security risks and prevent an attack or other incident related to our transportation of hazardous materials.

Environmental and Occupational Health and Safety Matters

General. Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection, worker health and safety, and the discharge of materials into the environment. These laws and regulations may, among other things:

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require the acquisition of various permits before drilling or other regulated activity commences;

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enjoin some or all of the operations of facilities deemed in noncompliance with environmental regulations or permits;

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restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling and production activities;

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limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas;

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apply specific health and safety criteria addressing worker protection; and

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require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.

A failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory and remedial obligations, and the issuance of orders enjoining performance of some or all of our operations.

These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. While we believe we are in substantial compliance with all existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse effect on our financial condition and results of operations, environmental laws and regulations are subject to frequent change, often resulting in more restrictions and limitations on activities that may affect the environment. Any changes that result in more stringent and costly well construction, drilling, water management or completion activities or waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant effect on our results of operations, financial condition and business as well as the industry in general. We did not incur any material capital expenditures for remediation or pollution control activities for the fiscal year ended June 30, 2015. Additionally, we are not aware of any environmental issues or claims that will require material capital expenditures during the 2016 fiscal year. Nevertheless, accidental spills or releases may occur in the course of our operations, and we cannot give any assurance that we will not incur substantial costs and liabilities as a result of such spills or releases, including those relating to third-party claims for damage to property and persons.

The following is a summary of some of the more significant existing laws and regulations, as amended from time to time, to which our operations are or may be subject.

Hazardous Wastes and Substances. The Resource Conservation and Recovery Act (the “RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the U.S. Environmental Protection Agency (the “EPA”), the individual states administer some or all of the provisions of the RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of crude oil or natural gas, if properly handled, are regulated under the RCRA’s non-hazardous waste provisions rather than the more stringent hazardous waste standards. However, owing to changes in existing laws and regulations, it is possible that certain oil and gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position as well as those of the oil and natural gas industry in general.

Wastes containing naturally occurring radioactive materials (“NORM”) may also be generated in connection with our operations. NORM is subject primarily to individual state radiation control regulations. In addition, NORM handling and management activities are governed by regulations promulgated by the Occupational Safety and Health Administration (“OSHA”). These state and OSHA regulations impose certain requirements concerning worker protection; the treatment, storage and disposal of NORM waste; the management of waste piles, containers and tanks containing NORM; as well as restrictions on the uses of land with NORM contamination. Compliance with these NORM requirements could have a significant adverse effect on our operating costs.

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, and analogous state laws impose joint and several liability, without regard to fault or legality of conduct, on classes of persons considered to be responsible for the release of a “hazardous substance” into the environment. These persons include current and past owners or operators of the site where the release occurred and anyone who transported or disposed, or arranged for the transport or disposal, of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

We currently own, lease, or operate numerous properties that have been used for oil and natural gas development and production for many years. Although we believe that we have used operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or petroleum hydrocarbons may have been spilled or otherwise released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for recycling or disposal. In addition, some of our properties have been operated by previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, the RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property or perform remedial plugging or pit closure operations to prevent future contamination.

Water Discharges and Subsurface Injections. The Clean Water Act and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and hazardous substances, into waters of the United States and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure planning requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of stormwater runoff from certain types of facilities. The Clean Water Act also prohibits the discharge of dredge and fill material into regulated waters, including wetlands, unless authorized by an appropriately issued permit. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for noncompliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

The primary federal law imposing liability for oil spills is the Oil Pollution Act (the “OPA”) which amends the Clean Water Act and sets minimum standards for prevention, containment and cleanup of oil spills. OPA applies to releases from vessels, offshore facilities and onshore facilities, including exploration and production facilities, that may affect waters of the United States. Under OPA, responsible parties, including owners and operators of onshore facilities, may be subject to oil spill cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills. OPA also requires owners and operators of certain onshore facilities to prepare Oil Spill Response Plans for responding to a worst case discharge of oil to waters of the United States.

Operations associated with our properties also produce wastewaters that are disposed via injection in underground wells. These injection wells are regulated by the federal Safe Drinking Water Act (the “SDWA”) and analogous state laws. The underground injection well program under the SDWA requires a permit from the EPA or an analogous state agency for our disposal wells, establishes minimum standards for injection well operations, and restricts the types and quantities of fluids that may be injected. Any leakage from the subsurface portions of the injection wells may cause degradation of freshwater, potentially resulting in cancellation of operations of a well, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource, and imposition of liability by third parties for alternative water supplies, property damages and personal injuries. While we believe that we have obtained the necessary permits from the applicable regulatory agencies for our underground injection wells and that we are in substantial compliance with applicable permit conditions and federal and state rules, any changes in the laws or regulations or the inability to obtain permits for new injection wells in the future may affect our ability to dispose of produced waters and ultimately increase the cost of our operations. In addition, in response to recent seismic events near underground injection wells used for the disposal of oil and gas-related wastewaters, federal and some state agencies, including the TRRC, have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or imposed moratoria on the use of such injection wells. If new regulatory initiatives are implemented that restrict or prohibit the use of underground injection wells in areas where we rely upon the use of such wells in our operations, our costs to operate may significantly increase and our ability to conduct continue production may be delayed or limited, which could have a material adverse effect on our results of operations and financial position.

We also routinely use hydraulic fracturing techniques in many of our drilling and completion programs. The process involves the injection of water, sand and chemical additives under pressure into targeted subsurface formations to stimulate oil and gas production. The process is typically regulated by state oil and gas commissions but the EPA has asserted federal regulatory authority under the SDWA over certain hydraulic fracturing involving the use of diesel fuel and published final permitting guidance in February 2014 for hydraulic fracturing activities using diesel fuels. In May 2014, the EPA issued an Advanced Notice of Proposed Rulemaking seeking comment on its intent to develop regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. In April 2015, the EPA proposed to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. Also, the federal Bureau of Land Management (“BLM”) finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands, including, for example, notice to and pre-approval by the BLM of the proposed hydraulic fracturing activities; development and pre-approval by the BLM of a plan for managing and containing flowback fluids and produced water recovered during the hydraulic fracturing process; implementation of measures designed to protect usable water from hydraulic fracturing activities; and public disclosure of the chemicals used in the hydraulic fracturing fluid. The U.S. District Court of Wyoming has temporarily stayed implementation of this rule. A final decision is pending, however. In addition, Congress has from time to time considered the adoption of legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, a growing number of states, including Texas where we operate, have adopted, or are considering legal requirements that could impose more stringent permitting, disclosure, or well construction requirements on hydraulic fracturing activities. In addition, local governments may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nevertheless, if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

In addition, several governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing activities. In June 2015, the EPA released its draft report on the potential impacts of hydraulic fracturing on drinking water resources, which concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water resources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources. The draft report is expected to be finalized after a public comment period and a formal review by the EPA’s Science Advisory Board. In addition, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. These existing or any future studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.

To our knowledge, there have been no citations, suits or contamination of potable drinking water arising from our fracturing operations. We do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our general liability and excess liability insurance policies would cover third-party claims related to hydraulic fracturing operations and associated legal expenses in accordance with, and subject to, the terms of such policies.

Air Emissions. The federal Clean Air Act (the “CAA”) and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. Such laws and regulations may require a facility to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions; obtain or strictly comply with air permits containing various emissions and operational limitations; or utilize specific emission control technologies to limit emissions of certain air pollutants. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Moreover, states can impose air emissions limitations that are more stringent than the federal standards imposed by the EPA. Federal and state regulatory agencies can also impose administrative, civil and criminal penalties for noncompliance with air permits or other requirements of the CAA and associated state laws and regulations.

Permits and related compliance obligations under the CAA, as well as changes to state implementation plans for controlling air emissions in regional non-attainment areas, may require us to incur future capital expenditures in connection with the addition or modification of existing air emission control equipment and strategies for gas and oil exploration and production operations. For example, in 2012, the EPA published final rules under the CAA that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants programs. With regard to production activities, these final rules require, among other things, the reduction of volatile organic compound emissions from three subcategories of fractured and refractured gas wells for which well completion operations are conducted: wildcat (exploratory) and delineation gas wells; low reservoir pressure non-wildcat and non-delineation gas wells; and all “other” fractured and refractured gas wells. All three subcategories of wells must route flowback emissions to a gathering line or capture and combust flowback emissions using a combustion device, such as a flare. However, the “other” wells must use reduced emission completions, also known as “green completions,” with or without combustion devices, on or after January 1, 2015. These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. In addition, in December 2014, the EPA proposed to reduce the National Ambient Air Quality Standards for ozone from the current standard of 75 ppb to between 65 and 70 ppb and to adopt the new standard by October 1, 2015. If the EPA lowers the ozone standard, states could be required to implement new more stringent regulations, which could apply to our exploration and production operations. Compliance with these requirements could increase our costs of development and production, which costs could be significant.

Climate Change. In December 2009 the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. Based on these findings, the EPA adopted regulations under the existing CAA, establishing construction and operating permitting reviews for GHG emissions from certain large stationary sources that are already major sources of certain principal, or criteria, pollutant emissions. We could become subject to these permitting requirements and be required to install “best available control technology” to limit emissions of GHGs from any new or significantly modified facilities we may seek to construct in the future if they would otherwise emit criteria pollutants in excess of applicable threshold levels. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions on an annual basis from specified large GHG emission sources in the United States, including certain oil and natural gas production facilities, which includes certain of our facilities. On August 18, 2015, the EPA proposed new regulations that set methane emission standards for new and modified oil and natural gas production and natural gas processing and transmission facilities as part of the Administration’s efforts to reduce methane emissions from the oil and natural gas sector by up to 45% from 2012 levels by 2025. The EPA is expected to finalize this proposal in 2016. The BLM is expected to address methane emissions from crude oil and natural gas sources in 2015 as well.

While the U.S. Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of federal climate legislation in the United States, a number of state and regional efforts have emerged that are aimed at tracking or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would affect our business, any such future laws and regulations could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, acquire emissions allowances or comply with new regulatory or reporting requirements including the imposition of a carbon tax. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, oil and gas, which could reduce the demand for the oil and gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations.

Finally, some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

Endangered Species. The federal Endangered Species Act (the “ESA”) and analogous state laws regulate activities that could have an adverse effect on threatened or endangered species. Some of our well drilling operations are conducted in areas where protected species or their habitats are known to exist. In these areas, we may be obligated to develop and implement plans to avoid potential adverse effects to protected species and their habitats, and we may be prohibited from conducting operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on the species. It is also possible that a federal or state agency could order a complete halt to drilling activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The presence of a protected species in areas where we perform activities could result in increased costs or limitations on our ability to perform operations and thus have an adverse effect on our business.

As a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service (the “FWS”) is required to consider listing numerous species as endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year. Additional listings under the ESA and similar state laws could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse effect on our ability to develop and produce reserves.

Occupational Health and Safety. Our operations are subject to the requirements of OSHA and comparable state statutes. These laws and the related regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

LEGAL PROCEEDINGS

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

Item 1A. Risk Factors

Investing in us involves a degree of risk, including the risks described below. Our operating results have been, and will continue to be, affected by a wide variety of risk factors, many of which are beyond our control, that could have adverse effects on profitability during any particular period. You should carefully consider the following risk factors together with all of the other information included in this Annual Report on Form 10-K, including the financial statements and related notes, when deciding to invest in us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may also materially and adversely affect our business operations. If any of the following risks were to actually occur, our business, financial condition or results of operations could be materially and adversely affected.

The headings provided in this Item 1A are for convenience and reference purposes only and shall not affect or limit the extent or interpretation of the risk factors.

Oil and natural gas prices are volatile. A substantial or extended decline in commodity prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The prices we receive for our oil, NGLs and natural gas production heavily influence our revenue, profitability, access to capital and future rate of growth. Oil, NGLs and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the commodities market has been volatile. This market will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include but are not limited to the following:

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worldwide and regional economic conditions affecting the global supply and demand for oil, NGLs and natural gas;

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the price and quantity of foreign imports;

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political and economic conditions in or affecting other producing countries, including the Middle East, Africa, South America and Russia;

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the ability of members of the Organization of the Petroleum Exporting Countries to agree to and maintain oil price and production controls;

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the level of global exploration and production;

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the level of global and domestic inventories;

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prevailing prices on local price indexes in the areas in which we operate;

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the proximity, capacity, cost and availability of gathering and transportation facilities;

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localized and global supply and demand fundamentals and transportation availability;

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the cost of exploring for, developing, producing and transporting reserves;

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refining capacity;

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weather conditions and other natural disasters;

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technological advances affecting energy consumption and energy supply;

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the price and availability of alternative fuels;

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expectations about future commodity prices; and

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domestic, local and foreign governmental regulation and taxes.

Lower commodity prices may reduce our cash flows and borrowing ability. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our reserves as existing reserves are depleted. Lower commodity prices may also reduce the amount of oil, NGLs and natural gas that we can produce economically.

Recently, oil and natural gas prices have declined significantly. The West Texas Intermediate posted price has declined from a high of $107.95 per Bbl on June 20, 2014 to $38.22 per Bbl on August 24, 2015. In addition, the Henry Hub spot market price had declined from a high of $8.15 per MMBtu on February 10, 2014 to $2.65 per MMBtu on August 24, 2015. Likewise, NGL prices have suffered significant declines in realized prices recently. NGLs 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. 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.

Our exploitation, development and exploration projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our ability to access or grow reserves.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures for the exploitation, development and acquisition of oil and natural gas reserves. Our fiscal 2016 capital budget for drilling, completion, recompletion and infrastructure is approximately $19.4 million. Our capital budget excludes acquisitions. We expect to fund 2016 capital expenditures with cash generated by operations, borrowings under our revolving Credit Facility and possibly through asset sales or additional capital market transactions. Our borrowing base under our Credit Facility is currently set at $37.5 million, and we currently have $37.0 million drawn under the Credit Facility. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, lack of availability under our Credit Facility; oil and natural gas prices; actual drilling results; the availability of drilling rigs and other services and equipment; and regulatory, technological and competitive developments. A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures, which would negatively affect our ability to grow production. We intend to finance our near-term capital expenditures primarily through cash flow from operations and through borrowings under our revolving Credit Facility; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. The issuance of additional indebtedness would require that a portion of our cash flow from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flow from operations to fund working capital, capital expenditures and acquisitions.

Our cash flow from operations and access to capital are subject to a number of variables, including but not limited to:

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our proved reserves;

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the level of hydrocarbons we are able to produce from existing wells;

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the prices at which our production is sold;

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our ability to acquire, locate and produce new reserves; and

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our ability to borrow under our revolving Credit Facility.

If our revenues or the borrowing base under our revolving Credit Facility decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available borrowings under our revolving Credit Facility are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and production, and could materially and adversely affect our business, financial condition and results of operations.

Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

Our operations involve utilizing some of the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling horizontal wells include, but are not limited to, the following:

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landing our wellbore in the desired drilling zone;

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staying in the desired drilling zone while drilling horizontally through the formation;

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running our casing the entire length of the wellbore; and

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being able to run tools and other equipment consistently through the horizontal wellbore.

Risks that we face while completing our wells include, but are not limited to, the following:

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the ability to fracture stimulate the planned number of stages;

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the ability to run tools the entire length of the wellbore during completion operations; and

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the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and, consequently, we are more limited in assessing future drilling results in these areas. If our drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our future financial condition and results of operations will depend on the success of our exploitation, development and acquisition activities, which are subject to numerous risks beyond our control, including, but not limited to the risk that drilling will not result in commercially viable oil and natural gas production.

Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “Our reserve estimates depend on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and standardized measure of discounted future net cash flows from our reserves.” In addition, our cost of drilling, completing and operating wells is often uncertain.

Further, many factors may curtail, delay or cancel our scheduled drilling projects, including, but not limited to the following:

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delays imposed by or resulting from compliance with regulatory requirements including limitations resulting from wastewater disposal, discharge of GHGs and limitations on hydraulic fracturing;

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pressure or irregularities in geological formations;

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shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities;

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equipment failures or accidents;

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lack of available gathering facilities or delays in construction of gathering facilities;

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lack of available capacity on interconnecting transmission pipelines;

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adverse weather conditions;

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issues related to compliance with environmental regulations;

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environmental hazards, such as oil and natural gas leaks, oil spills, pipeline and tank ruptures and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

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declines in oil and natural gas prices;

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limited availability of financing at acceptable terms;

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title problems; and

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limitations in the market for oil and natural gas.

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and standardized measure of discounted future net cash flows from our reserves.

This report contains estimates of our proved and probable reserves and the estimated future net revenues from our proved reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, capital expenditures, taxes, and availability of funds. The process of estimating oil and gas reserves is complex. The process involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering, and economic data for each reservoir. Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses, and quantities of recoverable oil and gas reserves will most likely vary from these estimates. Any significant variation of any nature could materially affect the estimated quantities and present value of our proved reserves, and the actual quantities and present value may be significantly less than we have previously estimated. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, prevailing oil and natural gas prices, costs to develop and operate properties, and other factors, many of which are beyond our control. Our properties may also be susceptible to hydrocarbon drainage from production by operators on adjacent properties.

Standardized measure of discounted future net cash flows is a reporting convention that provides a common basis for comparing oil and natural gas companies subject to the rules and regulations of the SEC. The standardized measure of discounted future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated oil and natural gas reserves. We base the standardized measure of discounted future net cash flows from our proved reserves on the average, first-day-of-the-month price during the twelve-month period, in accordance with SEC rules. However, actual future net cash flows from our oil and natural gas properties also will be affected by factors such as but not limited to:

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actual prices we receive for oil and natural gas;

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actual costs of development and production expenditures;

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the amount and timing of actual production;

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supply of and demand for oil and natural gas; and

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changes in governmental regulations or taxation, including severance and excise taxes.

The timing of production from oil and natural gas properties and of related expenses affects the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor required by the SEC to be used to calculate standardized measure for reporting purposes may not be the most appropriate discount factor in view of actual interest rates, costs of capital, and other risks to which our business or the oil and natural gas industry in general are subject. Therefore, the standardized measure of discounted future net cash flows included in this Annual Report on Form 10-K should not be construed as accurate estimates of the current fair value of our proved reserves.

Probable reserves are less certain to be recovered than proved reserves. Reserves and standardized measure of discounted future net cash flows relating to the categories of proved and probable reserves have not been adjusted for risk due to the uncertainty of recovery and thus are not comparable and should not be summed into total amounts.

We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful.

Our ability to make scheduled payments on or to refinance our indebtedness obligations, including our revolving Credit Facility, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.

If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our revolving Credit Facility currently imposes restrictions on our ability to dispose of assets and on our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations.

The borrowing base under our revolving credit facility is currently $37.5 million and we currently have $37.0 million drawn under the facility. Our next scheduled borrowing base redetermination is expected to occur in October, 2015. In the future, we may not be able to access adequate funding under our revolving credit facility as a result of a decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover the defaulting lender’s portion. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.

Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.

Our revolving Credit Facility contains a number of significant covenants (in addition to covenants restricting the incurrence of additional indebtedness), including restrictive covenants that may limit our ability to, among other things:

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incur additional indebtedness;

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make loans to others;

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make investments;

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merge or consolidate with another entity;

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make certain payments;

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hedge future production or interest rates;

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incur liens;

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sell assets; and

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engage in certain other transactions without the prior consent of the lenders.

In addition, our revolving Credit Facility requires us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios. These restrictions may also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our revolving credit facilities impose on us.

A breach of any covenant in our revolving Credit Facility would result in a default under the applicable agreement after any applicable grace periods. A default, if not waived, could result in acceleration of the indebtedness outstanding under our revolving Credit Facility and in a default with respect to, and an acceleration of, the indebtedness outstanding under other debt agreements. The accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us.

Any significant reduction in our borrowing base under our revolving Credit Facility or an inability to access adequate funding may negatively affect our ability to fund our operations.

Our revolving Credit Facility limits the amounts we can borrow up to a borrowing base amount. The borrowing base amount under the Credit Facility is determined from time to time by the lenders, in their sole discretion, on a semi-annual basis based, among other things, upon projected revenues from, and asset values of, the oil and natural gas properties securing our loan. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our revolving Credit Facility. Reductions in estimates of our natural gas and crude oil reserves could result in a reduction in our borrowing base. Reductions in our borrowing base could also arise from other factors, including but not limited to:

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lower commodity prices or production,

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inability to drill or unfavorable drilling results,

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changes in natural gas and crude oil reserve engineering,

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the lenders’ inability to agree to an adequate borrowing base, or

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adverse changes in the lenders’ practices regarding estimation of reserves.

In the event that our borrowing base is lowered, we could be required to repay any indebtedness in excess of the redetermined borrowing base.

In the future, we may not be able to access adequate funding under our revolving Credit Facility as a result of a decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover the defaulting lender’s portion. In the event that we are unable to access adequate funding, we may be unable to implement our respective exploration, drilling and development plan, replace production, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.

If we are unable to comply with the restrictions and covenants in our revolving Credit Facility agreement, there could be an event of default under the terms of our credit facility, which could result in an acceleration of repayment.

If we are unable to comply with the restrictions and covenants in our revolving Credit Facility, there could be an event of default under the terms of this facility. Our ability to comply with these restrictions and covenants, including meeting the financial ratios and tests under our revolving credit facility agreement, may be affected by events beyond our control. If market or other economic conditions deteriorate or if oil and natural gas prices remain at their current level for an extended period of time or continue to decline, our ability to comply with these covenants may be impaired. We cannot assure that we will be able to comply with these restrictions and covenants or meet such financial ratios and tests. In the event of a default under our credit agreement, the lenders could terminate their commitments to lend or accelerate the loans and declare all amounts borrowed due and payable. If any of these events occur, our assets might not be sufficient to repay in full all of our outstanding indebtedness and we may be unable to find alternative financing. Even if we could obtain alternative financing, it might not be on terms that are favorable or acceptable to us. Additionally, we may not be able to amend our revolving credit facility agreement or obtain needed waivers on satisfactory terms.

Our derivative activities could result in financial losses or could reduce our earnings.

We periodically enter into derivative instrument contracts for a portion of our oil production, and our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.

Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:

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production is less than the volume covered by the derivative instruments;

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the counterparty to the derivative instrument defaults on its contractual obligations;

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there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or

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there are issues with regard to legal enforceability of such instruments.

The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of our borrowing base. Future collateral requirements will depend on arrangements with our counterparties, highly volatile oil and natural gas prices and interest rates.

In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for oil and natural gas, which could also have a material adverse effect on our financial condition.

Our hedging transactions may limit our gains and expose us to other risks.

We periodically enter into derivative transactions related to our future production to manage the risks from changes in commodity prices. Hedging instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in commodity prices and provide increased certainty of cash flows for our drilling program and debt service requirements. These instruments provide only partial price protection against declines in commodity prices and, depending on the hedging instrument, may limit our potential gains from future increases in prices. None of our instruments are used for trading purposes. We do not speculate on commodity prices but rather attempt to hedge a portion of our physical production in order to protect our returns.

Depending on market and other conditions, we may continue to use commodity derivative instruments to hedge our price risk in the future. Our hedging strategy and future hedging transactions will be determined at our discretion and may be different than what we have done on a historical basis. We are not under an obligation to hedge a specific portion of our production.

Our identified drilling locations are scheduled out over several months, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such locations.

Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our growth strategy. We are a non-operator with respect to our natural gas and oil properties. Consequently, we have limited ability to exercise influence over, and control the risks associated with the operation of these properties. Our ability to drill and develop these locations depends on a number of uncertainties, including, but not limited to, oil and natural gas prices, the availability and cost of capital, the operator’s expertise and financial resources, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the numerous drilling locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the drilling locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.

As a result of the limitations described above, we may be unable to drill many of our drilling locations. In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations.

Adverse weather conditions may negatively affect our operating results and our ability to conduct drilling activities.

Adverse weather conditions may cause, among other things, increases in the costs of, and delays in, drilling or completing new wells, power failures, temporary shut-in of production and difficulties in the transportation of our oil, NGLs and natural gas. Any decreases in production due to poor weather conditions will have an adverse effect on our revenues, which will in turn negatively affect our cash flow from operations.

Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Drought conditions have persisted in Texas over the past several years. These drought conditions have led governmental authorities to restrict the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supplies. If we are unable to obtain water to use in our operations, we may be unable to economically produce oil and natural gas, which could have a material and adverse effect on our financial condition, results of operations and cash flows.

Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with operating in one major geographic area.

Substantially all of our producing properties are geographically concentrated in the Permian Basin of West Texas. At June 30, 2015, all of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, we may be disproportionately exposed to the effect of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or other drought related conditions or interruption of the processing or transportation of oil, NGLs or natural gas.

The marketability of our production is dependent upon transportation and other facilities, certain of which we do not control. If these facilities are unavailable, our operations could be interrupted and our revenues reduced.

The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of transportation facilities owned by third parties. Our oil production is transported from the wellhead to our tank batteries by owned and third party gathering systems. Our purchasers then transport the oil by truck or pipeline for transportation. Our natural gas production is generally transported by gathering lines from the wellhead to a gas processing facility. We do not control these trucks and other third party transportation facilities and our access to them may be limited or denied. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of our or third party transportation facilities or other production facilities could adversely affect our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, we may be required to shut in or curtail production. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, would materially and adversely affect our financial condition and results of operations.

Failure of third parties to meet contractual obligations could have a material adverse effect on Lynden and its cash flow from operations.

We are or may be exposed to third party credit risk through its contractual arrangements with its current or future joint venture partners, the operators of its joint ventures and other parties. In the event such entities fail to meet their contractual obligations to Lynden, such failures could have a material adverse effect on Lynden and its cash flow from operations.

We may incur losses as a result of title defects in the properties in which we invest.

The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.

The development of our PUDs may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated PUDs may not be ultimately developed or produced.

As of June 30, 2015, approximately 65% of our total estimated proved reserves were classified as proved undeveloped. Development of these undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the value of our estimated PUDs and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our PUDs as unproved reserves. Further, we may be required to write down our PUDs if we do not drill those wells within five years after their respective dates of booking.

If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value for a significant period of time, or if we change our plans about development of our properties, we will be required to take write-downs of the carrying values of our properties.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. A writedown constitutes a non-cash charge to earnings. In fiscal 2015, management recognized an impairment of the suspended exploratory well costs related to the Paradox Basin Project due to the lack of substantial activities to assess the reserves for more than one year following the drilling of exploratory wells, and the lack of significant expenditures planned for the future. We may incur additional impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.

Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploitation, development and exploration activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be materially and adversely affected.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The effect of the changing demand for oil and natural gas may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our operations may be exposed to significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our business activities.

Our operations are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment, health and safety aspects of our operations, or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations including the acquisition of permits before conducting regulated drilling activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them. Such enforcement actions often involve taking difficult and costly compliance measures or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining, or be unable to obtain, required permits, which may delay or interrupt our operations and limit our growth and revenue.

Certain environmental laws impose strict as well as joint and several liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons, or solid wastes have been stored or released. We may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from the consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In connection with certain acquisitions, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety effects of our operations. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.

We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations.

Our exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including but not limited to the possibility of:

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environmental hazards, such as uncontrollable releases of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater, air and shoreline contamination;

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abnormally pressured formations;

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mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;

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fires, explosions and ruptures of pipelines;

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personal injuries and death;

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natural disasters; and

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terrorist attacks targeting oil and natural gas related facilities and infrastructure.

Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:

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injury or loss of life;

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damage to and destruction of property, natural resources and equipment;

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pollution and other environmental damage;

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regulatory investigations and penalties;

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suspension of our operations; and

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repair and remediation costs.

We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

Properties that we decide to drill may not yield oil or natural gas in commercially feasible quantities.

Properties that we decide to drill that do not yield oil or natural gas in commercially viable quantities will adversely affect our results of operations and financial condition. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically feasible. The use of micro-seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further, our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including but not limited to:

•

unexpected drilling conditions;

•

title problems;

•

pressure or lost circulation in formations;

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equipment failure or accidents;

•

adverse weather conditions;

•

compliance with environmental and other governmental or contractual requirements; and

•

increase in the cost of, shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services.

We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.

In the future we may make acquisitions of businesses that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. Competition for acquisitions may also increase the cost of, or cause us to refrain from, completing acquisitions.

The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

In addition, our revolving Credit Facility imposes certain limitations on our ability to enter into mergers or combination transactions. Our revolving Credit Facility also limits our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.

Our oil and natural gas exploration, production and transportation operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, including the assessment of natural resource damages, as well as injunctions limiting or prohibiting our activities. These regulations could change to our detriment. Our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Such costs could have a material adverse effect on our business, financial condition and results of operations.

Certain of our properties are subject to land use restrictions, which could limit the manner in which we conduct our business.

Certain of our properties are subject to land use restrictions, including city ordinances, which could limit the manner in which we conduct our business. These land use restrictions could affect, among other things, our access to and the permissible uses of our facilities as well as the manner in which we produce oil and natural gas and may restrict or prohibit drilling in general. The costs we incur to comply with such restrictions may be significant in nature, and we may experience delays or curtailment in the pursuit of exploration, development or production activities and perhaps even be precluded from the drilling of wells.

Our business is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and the production and transportation of, oil and natural gas. Failure to comply with such laws and regulations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition and results of operations.

Changes to existing or new regulations may unfavorably affect us, could result in increased operating costs and could have a material adverse effect on our financial condition and results of operations. Such potential regulations could increase our operating costs, reduce our liquidity, delay or halt our operations or otherwise alter the way we conduct our business, which could in turn have a material adverse effect on our financial condition, results of operations and cash flows. Further, the discharges of oil, NGLs, natural gas and other pollutants into the air, soil or water may give rise to significant liabilities on our part to the government and third parties. See “Items 1 and 2. Business and Properties—Regulation of the Oil and Natural Gas Industry” for a further description of laws and regulations that affect us.

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling and workover rigs, pipe and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. If we are unable to secure a sufficient number of drilling rigs at reasonable costs, we may not be able to drill all of our acreage before our leases expire. Equipment shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.

Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

Under the EPAct 2005, FERC has civil penalty authority under the Natural Gas Act of 1938 (the “NGA”) and the Natural Gas Policy Act (“NGPA”) to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional operations to FERC annual reporting and posting requirements. We also must comply with the anti-market manipulation rules enforced by FERC. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability, as described in “Items 1 and 2. Business and Properties—Regulation of the Oil and Natural Gas Industry.”

Climate change laws and regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas that we produce while potential physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal CAA that, among other things, require preconstruction and operating permit reviews for GHG emissions from certain large stationary sources that are already major sources of emissions of regulated pollutants. Facilities required to obtain preconstruction permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include certain of our operations. On August 18, 2015, the EPA proposed new regulations that set methane emission standards for new and modified oil and natural gas production and natural gas processing and transmission facilities as part of the Administration’s efforts to reduce methane emissions from the oil and natural gas sector by up to 45% from 2012 levels by 2025. The EPA is expected to finalize this proposal in 2016. The BLM is expected to address methane emissions from crude oil and natural gas sources in 2015 as well.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would affect our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could adversely affect

demand for the oil and natural gas we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have a material adverse effect on our exploration and production operations.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.

Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing is typically regulated by state oil and natural gas commissions. However, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has asserted federal regulator authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities. In May 2014, the EPA issued an Advanced Notice of Proposed Rulemaking, seeking comment on its intent to develop regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. In April 2015, the EPA proposed to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. In addition, the BLM finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands including, for example, notice to and pre-approval by the BLM of the proposed hydraulic fracturing activities; development and pre-approval by the BLM of a plan for managing and containing flowback fluids and produced water recovered during the hydraulic fracturing process; implementation of measures designed to protect usable water from hydraulic fracturing activities; and public disclosure of the chemicals used in the hydraulic fracturing fluid. The U.S. District Court of Wyoming has temporarily stayed implementation of this rule. A final decision is pending, however. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. The adoption of new federal rules or regulations, or changes to existing federal rules or regulations, relating to hydraulic fracturing could lead to increased operating costs, delays and curtailment in the pursuit of exploration, development or production activities, which in turn could materially adversely affect our operations.

Certain governmental reviews have been conducted or are underway that focus on the potential environmental effects of hydraulic fracturing. In June 2015, the EPA released its draft report on the potential impacts of hydraulic fracturing on drinking water resources, which concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water sources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water sources. The draft report is expected to be finalized after a public comment period and a formal review by the EPA’s Science Advisory Board. In addition, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. Other governmental agencies, including the U.S. Department of Energy, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, in May 2013, the TRRC issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down and cementing wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.

Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil or natural gas and secure trained personnel.

Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased over the past three years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.

The loss of senior management or technical personnel could adversely affect operations.

We depend on the services of our senior management. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of our senior management could have a material adverse effect on our business, financial condition and results of operations.

Our management may not be subject to United States legal process, making it more difficult for U.S. investors to sue them.

The enforcement by investors of civil liabilities under the United States federal securities laws may not be possible because most of our officers and some of our directors are neither citizens nor residents of the United States. U.S. shareholders may not be able to effect service of process within the United States upon such persons. U.S. shareholders may not be able to enforce, in United States courts, judgments against such persons obtained in such courts predicated upon the civil liability provisions of United States federal securities laws. Appropriate foreign courts may not be able to enforce judgments of United States courts obtained in actions against such persons predicated upon the civil liability provisions of the federal securities laws. The appropriate foreign courts may not be able to enforce, in original actions, liabilities against such persons predicated solely upon the United States federal securities laws. However, U.S. laws would generally be enforced by a Canadian court provided that those laws are not contrary to Canadian public policy, are not foreign penal laws or laws that deal with taxation or the taking of property by a foreign government, and are in compliance with applicable Canadian legislation regarding the limitation of actions.

We are susceptible to the potential difficulties associated with rapid growth and expansion and have a limited operating history.

We have grown rapidly over the last several years. Our management believes that our future success depends on our ability to manage the rapid growth that we have experienced and the demands from increased responsibility on management personnel. The following factors could present difficulties:

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increased responsibilities for our executive level personnel;

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increased administrative burden;

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increased capital requirements; and

•

increased organizational challenges common to large, expansive operations.

Our operating results could be adversely affected if we do not successfully manage these potential difficulties. The historical financial information incorporated herein is not necessarily indicative of the results that may be realized in the future. In addition, our operating history is limited and the results from our current producing wells are not necessarily indicative of success from our future drilling operations.

Increases in interest rates could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability affecting our ability to finance our operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

We may be subject to risks in connection with acquisitions of properties.

The successful acquisition of producing properties requires an assessment of several factors, including but not limited to:

•

recoverable reserves;

•

future oil and natural gas prices and their applicable differentials;

•

operating costs; and

•

potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.

Income tax returns are subject to reassessment or audit, which may affect current and future taxes.

We intend to file all required income tax returns and believe that we are in full compliance with the provisions of federal (Canada and United States) and all applicable provincial and state tax legislation. However, such returns are subject to reassessment by the applicable taxation authority. In the event of a successful reassessment or tax audit of Lynden whether by re-characterization of exploration and development expenditures or otherwise, such reassessment or audit may have an effect on current and future taxes payable.

Certain federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated, and additional state taxes on oil and natural gas extraction may be imposed, as a result of future legislation.

The Fiscal Year 2016 Budget proposed by the President recommends the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies, and legislation has been introduced in Congress that would implement many of these proposals. Such changes include, but are not limited to: (i) the repeal of the percentage depletion allowance for oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities for oil and natural gas production; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear, however, whether any such changes will be enacted or how soon such changes could be effective.

The passage of this legislation or any other similar change in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could negatively affect our financial condition and results of operations.

Our use of seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.

Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in areas where we operate.

Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations or materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have a material and adverse effect on our ability to develop and produce our reserves.

The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd Frank Act”), enacted on July 21, 2010, established federal oversight and regulation of the over the counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the CFTC and the Securities and Exchange Commission (the “SEC”) to promulgate rules and regulations implementing the Dodd-Frank Act. In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the United States District Court for the District of Columbia in September 2012. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, their impact on the Company is uncertain at this time. The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing. The CFTC has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing. In addition, the Dodd-Frank Act requires that regulators establish margin rules for uncleared swaps. Because such rules are not yet final, their impact on the Company is uncertain at this time. Although we expect to qualify for the end-user exception to the clearing, trade execution and margin requirements for swaps entered to hedge our commercial risks, the application of the such requirements to other market participants, such as swap dealers, may change the cost and availability of our derivatives.

Although the CFTC has finalized certain regulations, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished or what the effect of any such regulations will be on the Company. The full impact of the Dodd-Frank Act and related regulatory requirements upon the Company’s business will not be known until the regulations are implemented and the market for derivatives contracts has adjusted. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks the Company encounters, and reduce the Company’s ability to monetize or restructure its existing derivative contracts. If the Company reduces its use of derivatives as a result of the Dodd-Frank Act and regulations, the Company’s results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect the Company’s ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. The Company’s revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices. Any of these consequences could have a material and adverse effect on the Company and its financial condition.

In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations. At this time, the impact of such regulations is not clear.

We may not be able to keep pace with technological developments in our industry.

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.

Item 1B. Unresolved Staff Comments

We do not have any unresolved staff comments.

Item 3. Legal Proceedings

To the best of our knowledge, there are no material pending legal proceedings, to which we, or any of our subsidiaries, is a party or of which our property is subject.

Item 4. Mine Safety Disclosures

Not Applicable.

PART II

Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market Price

Our common stock trades on the TSX Venture Exchange under the symbol “LVL”. The table below sets forth, for the periods indicated, the high and low sales prices per share of our common stock in Canadian dollars.


Years Ended June 30,	High		Low
2015
Fourth quarter	$	0.58	$	0.34
Third quarter	$	0.57	$	0.34
Second quarter	$	1.01	$	0.38
First quarter	$	1.23	$	0.85
2014
Fourth quarter	$	0.92	$	0.72
Third quarter	$	0.90	$	0.63
Second quarter	$	0.90	$	0.71
First quarter	$	0.98	$	0.66

On June 30, 2015, the closing price of our common stock was $0.47 per share. As of September 23, 2015, we had approximately 248 holders of record of our common stock. This number excludes owners for whom common stock may be held in “street” name.

As at the date of this Annual Report on Form 10-K, 4,010,000 shares of our common stock were subject to outstanding incentive stock options.

Dividend Policy

Lynden has never declared and paid, and it does not anticipate declaring or paying, any cash dividends to holders of its common stock in the foreseeable future. We currently intend to retain future earnings, if any, for the development and growth of our business. Our future dividend policy is within the discretion of the Board and will depend upon then-existing conditions, including our results of operations, financial condition, capital requirements, investment opportunities, statutory restrictions on our ability to pay dividends and other factors the Board may deem relevant. In addition, our revolving Credit Facility places restrictions on our ability to pay cash dividends.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The Company did not make any purchases of its common stock during the three months ended June 30, 2015.

Item 6. Selected Financial Data

As a smaller reporting company, we are not required to provide this information.

Item 7. 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 audited consolidated financial statements and related notes in “Part II, Item 8. Financial Statements and Supplementary Data” presented in this Annual Report on Form 10-K. 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 “Part I, Cautionary Statement Regarding Forward-Looking Statements” and “Part I, Item 1A. Risk Factors” elsewhere in this Annual Report on Form 10-K.

Overview

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

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

The common shares of the Company are listed on the TSX Venture Exchange under the symbol LVL, and the Company is a reporting issuer in British Columbia, Ontario and Alberta. At December 31, 2013, the Company no longer met the definition of a “foreign private issuer” under the 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 year ended June 30, 2015 included the following highlights:

•

The total number of producing Wolfberry wells increased from 91 gross (37.18 net) to 109 gross (44.69 net);

•

Primarily as a result of a significant drop in commodity prices, petroleum and natural gas sales decreased by 25% as compared to the year ended June 30, 2014;

•

Realized prices decreased 34% per Bbl of oil, 25% per Mcf of gas and 31% per Bbl of NGL compared to the year ended June 30, 2014; and

•

Average daily production was 1,400 Boe/d in the year ended June 30, 2015 compared to 1,231 Boe/d in the year ended June 30, 2014.

Recent Developments

Principal activities recently undertaken include the spudding of the Company’s first two CrownQuest operated horizontal wells in Glasscock County.

In June 2015, the Company’s borrowing base under its Credit Facility was reduced from $40.0 million to $37.5 million. The Company currently has $37.0 million drawn under its Credit Facility.

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:

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production volumes;

•

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

•

lease operating expenses.

Sources of Our Revenues

Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGL. For the years ended June 30, 2015 and 2014, our revenues derived from oil sales were 78% and 80% respectively. Natural gas sales accounted for approximately 10% and 8% of total sales for the years ended June 30, 2015 and 2014, respectively. Our revenues from NGL sales for the years ended June 30, 2015 and 2014 were 12% and 12%, 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 years ended June 30, 2015 and 2014.


	Year Ended June 30,
	2015		2014		% Change
Oil (Bbls)		275,575		247,153		11	%
Natural gas (Mcf)		689,594		518,737		33	%
NGL (Bbls)		120,644		115,618		4	%

Total (Boe)		511,151		449,228		14	%
Average net daily production (Boe/d)		1,400		1,231		20	%

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 year ended June 30, 2015, the West Texas Intermediate posted price had declined from a high of $106.06 per Bbl to a low of $43.39 per Bbl. In addition, the Henry Hub spot market price had declined from a high of $4.47 per MMBtu to a low of $2.50 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.

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

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

Public Company Expenses

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

Changes in Drilling Activity

Our capital budget for fiscal 2016 is approximately $18.9 million. Our 2016 capital budget contemplates the participation in the drilling of eight gross Wolfberry wells, three gross horizontal wells in the Midland Basin, and three gross vertical wells on the Mitchell Ranch Project. Well design, in particular well length and completion approach, will be significant variables in the Midland Basin horizontal wells. The ultimate amount of capital that we expend may fluctuate materially based on market conditions and our drilling results. See “Capital Requirements and Sources of Liquidity” for additional information.

Results of Operations

Year Ended June 30, 2015 Compared to Year Ended June 30, 2014

Net Income (Loss). Net loss for the year ended June 30, 2015 was $565,153 and $0.00 per share and diluted share, compared to net income of $15,403,651 and $0.12 per share and diluted share for the year ended June 30, 2014. The $15,968,804 decrease in net income is primarily due to declining oil and gas revenues which were lower by $7,207,097 in 2015. In addition, there was no gain on disposition of property, plant and equipment in the year ended June 30, 2015 compared to a gain of $10,219,755 in the year ended June 30, 2014; depletion, depreciation and accretion was higher by $2,315,502; and production and operating expenses were higher by $1,319,810, which was offset by lower income taxes of $8,933,421.

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.


	Year Ended June 30,
	2015		2014		Change			% Change
Revenues
Oil	$	17,367,615	$	23,570,733	$	(6,203,118	)		(26	%)
Natural gas		2,198,265		2,212,065		(13,800	)		(1	%)
NGL		2,593,618		3,583,797		(990,179	)		(28	%)

Total revenues	$	22,159,498	$	29,366,595	$	(7,207,097	)		(25	%)

Production
Oil (Bbl)		275,575		247,153		28,422			11	%
Natural gas (Mcf)		689,594		518,737		170,857			33	%
NGL (Bbl)		120,644		115,618		5,026			4	%
Total barrel of oil equivalent (Boe/d)		511,151		449,228		61,923			14	%
Daily Production Averages
Oil (Bbls/d)		755		677		78			11	%
Natural gas (Mcf/d)		1,889		1,421		468			28	%
NGL (Bbls/d)		331		317		14			34	%
Total barrel of oil equivalent (Boe/d)		1,400		1,231		169			20	%
Average Prices
Oil (per Bbl)	$	63.02	$	95.37	$	(32.35	)		(34	%)
Natural gas (per Mcf)	$	3.19	$	4.26	$	(1.07	)		(25	%)
NGL (per Bbl)	$	21.50	$	31.00	$	(9.50	)		(31	%)
Total barrel of oil equivalent (per Boe)	$	43.40	$	65.37	$	(21.97	)		(34	%)

Oil revenues. Oil revenues decreased 26% from $23,570,733 for the year ended June 30, 2014 to $17,367,615 for the year ended June 30, 2015 as a result of a $32.35 per Bbl decrease in our average realized price of oil only partially offset by an increase in oil production volumes of 28,422 Bbls.

Natural gas revenues. Natural gas revenues decreased 1% from $2,212,065 for the year ended June 30, 2014 to $2,198,265 for the year ended June 30, 2015 as a result of a $1.07 per Mcf decrease in our average realized natural gas price partially offset by an increase in natural gas production volumes of 170,857 Mcf.

NGL revenues. NGL revenues decreased 28% from $3,583,797 for the year ended June 30, 2014 to $2,593,618 for the year ended June 30, 2015 as a result of a $9.50 per Bbl decrease in our average realized NGL price partially offset by an increase in NGL production volumes of 5,026 Bbls.

Effects of derivatives. In April 2015, the Company entered into a NYMEX–based oil price put contract for 9,000 barrels of oil per month from September 2015 until August 2016 (12 months) with a strike price of $50 per barrel. The Company recognized an unrealized loss on the put contract of $140,040 as at June 30, 2015. For the year ended June 30, 2014, the Company realized a $48,470 loss on a costless collar oil hedge and reported an unrealized loss of $15,163 on a costless collar oil hedge. These costless collar hedges expired as at June 30, 2014.

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


	Year Ended June 30,
	2015		2014		Change			% Change
Operating expenses
Lease operating	$	4,793,999	$	3,142,345	$	1,651,654			53	%
Production and ad valorem taxes		1,475,743		1,807,587		(331,844	)		(18	%)
Depletion, depreciation and accretion		10,232,732		7,917,230		2,315,502			29	%
Exploration and impairments		2,368,110		253,504		2,114,606			834	%
General and administrative		2,384,340		1,390,422		993,918			71	%

Total operating expenses	$	21,254,924	$	14,511,088	$	6,743,836			46	%


	Year Ended June 30,
	2015		2014		Change			% Change
Operating expenses per boe
Lease operating	$	9.38	$	6.99	$	2.38			34	%
Production and ad valorem taxes		2.89		4.02		(1.14	)		(28	%)
Depletion, depreciation and accretion		20.02		17.62		2.39			14	%
Exploration and impairments		4.63		0.56		4.07			721	%
General and administrative		4.66		3.08		1.58			51	%

Total operating expenses	$	41.58	$	32.29	$	9.29			29	%

Lease operating expenses. Lease operating expenses increased 53% from $3,142,345 for the year ended June 30, 2014 to $4,793,999 for the year ended June 30, 2015. 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 18% from $1,807,587 for the year ended June 30, 2014 to $1,475,743 for the year ended June 30, 2015. The decrease in our production and ad valorem taxes was attributable to lower revenues as a result of falling commodity prices during the year ended June 30, 2015.

Depletion, depreciation and accretion. Depletion, depreciation and accretion increased 29% from $7,917,230 for the year ended June 30, 2014 to $10,232,732 for the year ended June 30, 2015 as a result of a 14% increase in production of Boe along with $22,081,417 more in capitalized costs subject to depletion and depreciation at June 30, 2015 compared to June 30, 2014.

General and administrative expenses. General and administrative (“G&A”) expenses increased 71% from $1,390,422 for the year ended June 30, 2014 to $2,384,340 for the year ended June 30, 2015. 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; (3) higher printing costs incurred in order to meet the filing requirements of the U.S. Securities and Exchange Commission; and (4) 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 periods indicated.


	Year Ended June 30,
	2015		2014		Change			% Change
General and administrative expenses
Administrative, consulting, and directors fees	$	795,644	$	656,560	$	139,084			21	%
Office, miscellaneous and other		511,992		223,341		288,651			129	%
Professional fees		868,250		292,634		575,616			197	%
Promotion and travel		208,454		162,204		46,250			29	%
Stock-based compensation		—		55,683		(55,683	)		(100	%)

Total general and administrative expenses	$	2,384,340	$	1,390,422	$	993,918			71	%

Exploration and impairments. Exploration and impairments increased by $2,114,606 for the year ended June 30, 2015 due to the (1) write-off of $1,814,441 for the Mitchell Ranch Project suspended exploratory well costs, of which $1,682,794 is the write-off of the Spade 17 #1 well; and (2) $449,541 write-off of the Paradox Basin Project

suspended exploratory well costs. During the three months ended June 30, 2015, it was determined that all principal target zones in the Spade 17 #1 well had been tested and that no future completion operations were being planned. After revisiting the criteria for the capitalization of the costs related to the Paradox Basin Project 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 future completion operations were not being planned, management determined that the costs should no longer be capitalized. The Company expensed the remaining costs of $449,541 in the three months ended September 30, 2014.

Share of loss in equity investment. In March 2015, we invested a further $431,919 in an investment in associate. This additional investment represents the funding of prior losses up to the amount of the additional investment and was expensed in the three months ended March 31, 2015.

Foreign currency translation adjustment. Foreign currency translation loss was $3,575,751 included in other comprehensive income for the year ended June 30, 2015, compared to $352,602 for the year ended June 30, 2014. 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, as Lynden Energy Corp.’s and Lynden Exploration Ltd.’s functional currency is the Canadian dollar.

Interest expense. During the year ended June 30, 2014, we recorded $283,183 of interest expense as compared to $549,672 in the year ended June 30, 2015. The increase is primarily the result of additional borrowings of $12,000,000 under our Credit Facility in the 2015 period along with higher banking fees and higher interest rates.

Income taxes. Income taxes decreased by $8,933,421 from $9,414,785 for the year ended June 30, 2014 to $481,364 for the year ended June 30, 2015. The decrease in income taxes is primarily the result of gain on disposition of property, plant and equipment of $10,219,755 and higher oil, natural gas, and NGL revenues of $7,207,097 reported in the year ended June 30, 2014.

Capital Requirements and Sources of Liquidity

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

Our fiscal 2015 (July 1, 2014 to June 30, 2015) capital budget for drilling, completion, recompletion and infrastructure was established at approximately $34 million.

During the year ended June 30, 2015, we spent approximately $29.1 million on capital expenditures on property, plant and equipment. Included in our fiscal 2015 capital budget were 1 gross horizontal Midland Basin well and 1 gross vertical Midland Basin well that were not spud by June 30, 2015 and are now incorporated in the fiscal 2016 capital budget. One horizontal Wolcott Lease well included in the fiscal 2015 capital budget was not drilled and has not been rescheduled.

Our fiscal 2016 (July 1, 2015 to June 30, 2016) capital budget for drilling, completion, recompletion and infrastructure is approximately $18.9 million, for the following:

•

$6.0 million, or 32%, for the participation in the drilling and completion of 8 gross vertical Midland Basin wells;

•

$11.2 million, or 59% for the participation in the drilling and completion of 3 gross horizontal Midland Basin wells; and

•

$1.7 million, or 9%, for the participation in the drilling and completion of 3 gross vertical Mitchell Ranch Project wells.

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

•

We continue to carry out the Wolfberry vertical well development program on our Midland Basin acreage. Our fiscal 2016 budget contemplates a gross cost of a Wolfberry well of $1.6 million. Our plans call for 8 gross (3.25 net) Wolfberry wells to spud in fiscal 2016 at an estimated cost to the Company of approximately $6.0 million. Pursuant to the terms of the Midland Basin Participation Agreement with CrownRock, our funding amount for the 3.25 net wells is equivalent to 3.71 wells.

•

Our fiscal 2016 capital budget contemplates 3 CrownQuest operated horizontal wells in Glasscock County. The first well has been budgeted at a gross cost of $8.3 million, with the balance of wells budgeted at a gross cost of $7.0 million. Well design, in particular well length and completion approach, will be significant variables in the cost of these wells. The first of these wells has now been drilled and the balance of wells are not scheduled to be spud until June 2016. Pursuant to the terms of the CrownRock Midland Basin Participation Agreement, the Company is funding 50% of the cost of the wells.

•

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

However, future cash flows are subject to a number of variables, including but not limited to the level of oil and natural gas production and prices, 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. See “1A. Risk Factors” for additional information.

Liquidity

We define liquidity as cash and cash equivalents and funds available under our Credit Facility. The table below summarizes our liquidity position at June 30, 2015 and June 30, 2014.


	Liquidity at June 30			Liquidity at June 30
	2015			2014
Borrowing base	$	37,500,000		$	32,000,000
Cash and cash equivalents		8,748,008			13,955,890
Credit Facility		(29,908,366	)		(17,853,245	)

Liquidity	$	16,339,642		$	28,102,645

Working Capital

Our working capital, which we define as current assets minus current liabilities, totaled $9,281,344 and $13,947,730 at June 30, 2015 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 $8,748,008 and $13,955,890 at June 30, 2015 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 Credit Facility will be sufficient to fund our working capital needs excluding any acquisitions we may enter into. See “Item 1A. Risk Factors – Our exploitation, development and exploration projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our ability to access or grow reserves.” 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 June 30, 2015 includes $8,670,365 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:


	Year Ended June 30,
	2015			2014
Net cash generated by operating activities	$	13,529,718		$	21,758,744
Net cash (used in) generated by investing activities	$	(29,810,609	)	$	(13,431,117	)
Net cash generated by financing activities	$	12,757,091		$	3,910,274

Net cash generated by operating activities decreased by 38%, or $8,229,026, to $13,529,718 during the year ended June 30, 2015 compared to the prior fiscal year. 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 222%, or $16,379,492, to $29,810,609 during the year ended June 30, 2015 compared to the prior fiscal year. The increase in our cash flows used in investing activities was primarily due to (1) $20,803,912 of cash generated by disposition of property, plant and equipment during the year ended June 30, 2014; offset by (2) $4,856,339 more cash used in the acquisition of property, plant and equipment during the year ended June 30, 2014.

Net cash generated by financing activities increased by 313%, or $8,346,817, to $12,257,091 during the year ended June 30, 2015 compared to the prior fiscal year. The increase in our cash flows generated by financing activities was primarily due to drawings on the Credit Facility of $12,000,000 during the year ended June 30, 2015 compared to repayments of outstanding Credit Facility borrowings of $8,750,000 offset by $12,660,274 of common shares issued for cash net of issue costs during the year ended June 30, 2014.

Debt

Our “Credit Facility” is a reducing revolving line of credit of up to $100 million. As at June 30, 2015, the Credit Facility has a borrowing base of $37.5 million, of which $29.75 million was drawn down. The Credit Facility will bear interest determined by the percent of the borrowing base utilized and by elections made by the Company. Amounts drawn down under the Credit Facility will bear interest at a rate of LIBOR plus a range of 3.00% to 3.50% or at a rate of U.S. prime plus a range of 2.00% to 2.50%. A minimum interest rate of 3.5% is required on borrowings under the Credit Facility. Payments under the Credit Facility will be required to the extent that outstanding principal and interest exceed the borrowing base. Other fees may also apply pursuant to the bank’s re-determinations of the borrowing base. Changes in the borrowing base are made based on the bank’s engineering valuation of the Company’s oil and gas reserves. The borrowing base is re-determined semi-annually; however, the Company may request two additional re-determinations of the borrowing base annually. The 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 October 2015.

As of September 24, 2015 $37.0 million has been drawn down on the Credit Facility.

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 year ended June 30, 2015. 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.

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.

Critical Accounting Policies and Practices

Our historical consolidated financial statements and related notes to consolidated financial statements contain information that is pertinent to our management’s discussion and analysis of financial condition and results of operations. Preparation of financial statements in conformity with GAAP requires that our management make estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities.

In management’s opinion, the more significant reporting areas affected by management’s judgments and estimates are the choice of accounting method for oil and natural gas activities, oil and natural gas reserve estimation, asset retirement obligations and impairment of long-lived assets. Management’s judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters. Actual results could differ from the estimates, as additional information becomes known.

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; and

•

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 and which may have an impact on the Company:

•

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, 2017 with early adoption permitted);

•

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); and

•

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.

Successful Efforts Method of Accounting

We use the successful efforts method of accounting for our oil and natural gas exploration and development activities. Under this method, exploration expenses, including geological and geophysical costs, lease rentals and exploratory dry holes, are charged against income as incurred. Costs of successful wells and related production equipment, undeveloped leases and developmental dry holes are capitalized. Exploratory drilling costs are initially capitalized, but are charged to expense if and when the well is determined not to have found proved reserves. Generally, a gain or loss is recognized when producing properties are sold. This accounting method may yield significantly different results than the full cost method of accounting.

The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either developmental or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes. Once a well is drilled, the determination that proved reserves have been discovered may take considerable time, and requires both judgment and application of industry experience. The evaluation of oil and natural gas leasehold acquisition costs included in unproved properties requires management’s judgment to estimate the fair value of such properties. Drilling activities in an area by other companies may also effectively condemn our leasehold positions.

Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain PUDs. Individually significant non-producing properties or projects are periodically assessed for impairment of value by considering future drilling plans, the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such properties.

Depletion of capitalized drilling and development costs of oil and natural gas properties is computed using the unit-of-production method on a field basis based on total estimated proved developed oil and natural gas reserves. Depletion of producing leaseholds is based on the unit-of-production method using our total estimated proved reserves. In arriving at rates under the unit-of-production method, the quantities of recoverable oil and natural gas are established based on estimates made by our geologists and engineers and independent engineers. Equipment and other assets are depreciated using the straight-line method over estimated useful lives ranging from two to six years. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated depreciation and depletion are eliminated from the accounts and the resulting gain or loss is recognized.

Oil and Natural Gas Reserves and Standardized Measure of Discounted Net Future Cash Flows

This Annual Report on Form 10-K presents estimates of our proved reserves as of June 30, 2015, and June 30, 2014 which have been prepared and presented consistent with SEC rules for year-end reporting. These rules require SEC reporting companies to prepare their reserve estimates using revised reserve definitions and revised pricing based on a 12-month unweighted average of the first-day-of-the-month pricing. The pricing used for estimates of our reserves as of June 30, 2015, was based on unweighted average twelve month West Texas Intermediate posted price of $71.68 per Bbl for oil and a Henry Hub spot natural gas price of $3.36 per MMBtu for natural gas. The pricing used for estimates of our reserves as of June 30, 2014, was based on unweighted average twelve month West Texas Intermediate posted price of $100.27 per Bbl for oil and a Henry Hub spot natural gas price of $4.10 per MMBtu for natural gas.

Another effect of the SEC rules is a general requirement that, subject to limited exceptions, PUDs may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This rule has limited and may continue to limit our potential to book additional PUDs as we pursue our drilling program, particularly as we develop our significant acreage in the Permian Basin of West Texas. Moreover, we may be required to write down our PUDs if we do not drill on those reserves within the required five-year time-frame.

CGA, our independent engineer, works with our senior management, our consultants, and our financial, land and accounting personnel to prepare the estimates of our oil and natural gas reserves and associated future net cash flows and also audits them. Even though our senior management, our consultants and independent engineers are knowledgeable and follow authoritative guidelines for estimating reserves, they must make a number of subjective assumptions based on professional judgments in developing the reserve estimates. Reserve estimates are updated at least annually and consider recent production levels and other technical information about each lease. Periodic

revisions to the estimated reserves and future net cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, oil and natural gas prices, cost changes, technological advances, new geological or geophysical data, or other economic factors. We cannot predict the amounts or timing of future reserve revisions. If such revisions are significant, they could significantly alter future depletion and result in impairment of long-lived assets that may be material.

Asset Retirement Obligations

There are legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and the normal operations of a long-lived asset. The primary effect of this relates to oil and natural gas wells on which we have a legal obligation to plug and abandon. We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and, generally, a corresponding increase in the carrying amount of the related long-lived asset. The determination of the fair value of the liability requires us to make numerous judgments and estimates, including judgments and estimates related to future costs to plug and abandon wells, future inflation rates and estimated lives of the related assets.

Impairment of Long-Lived Assets

All of our long-lived assets are monitored for potential impairment when circumstances indicate that the carrying value of an asset may be greater than its future net cash flows, including cash flows from risk adjusted proved reserves. The evaluations involve a significant amount of judgment since the results are based on estimated future events, such as future sales prices for oil and natural gas, future costs to produce these products, estimates of future oil and natural gas reserves to be recovered and the timing thereof, the economic and regulatory climates and other factors. The need to test an asset for impairment may result from significant declines in sales prices or downward revisions in estimated quantities of oil and natural gas reserves. Any assets held for sale are reviewed for impairment when we approve the plan to sell. Estimates of anticipated sales prices are highly judgmental and subject to material revision in future periods. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges will be recorded.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risk, including but not limited to the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil, NGL and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses.

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.

Due to the inherent volatility in commodity prices, we have historically used commodity derivative instruments, such as collars and puts, to hedge price risk associated with portions of our anticipated production. In April 2015, we entered into a NYMEX based oil price put contract for 9,000 bbls of oil per month from September 2015 until August 2016 (12 months) with a strike price of $50 per bbl. Fair value changes on this contract will be recognized in the statement of income.

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 June 30, 2015 and 2014. As at June 30, 2015, $1,532,385 is owing from CrownQuest Operating, LLC.

Financial information on the counterparties is reviewed in order to monitor their financial stability and assess their ongoing ability to honor their commitments under the derivative contracts. We have not experienced, nor do we expect to experience, any difficulty in the counterparties honoring their commitments.

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. For the year ended June 30, 2015, if interest rates had been 1% higher, net loss and comprehensive loss would have been approximately $136,000 higher. If interest rates had been 1% lower, net loss and comprehensive loss would have been approximately $115,000 higher.

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	$	8,670,365	$	8,196	$	(89,370	)	$	8,589,191	$	858,919

Item 8. Financial Statements and Supplementary Data

Index to Consolidated Financial Statements


	Page Reference
Report of Independent Registered Public Accounting Firm		62

Consolidated Balance Sheets at June 30, 2015 and 2014		63

Consolidated Statements of Income and Comprehensive Income for the years ended June 30, 2015 and 2014		64

Consolidated Statements of Cash Flows for the years ended June 30, 2015 and 2014		65

Consolidated Statements of Changes in Shareholders’ Equity for the years ended June 30, 2015 and 2014		66

Notes to Consolidated Financial Statements		67

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Lynden Energy Corp.

We have audited the accompanying consolidated balance sheets of Lynden Energy Corp. and subsidiaries (the “Company”) as of June 30, 2015 and June 30, 2014, and the related consolidated statements of income (loss) and comprehensive income (loss), changes in shareholders’ equity, and cash flows for each of the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Lynden Energy Corp. and subsidiaries as of June 30, 2015 and June 30, 2014, and the results of their operations and their cash flows for each of the years then ended, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte LLP

Chartered Professional Accountants

September 28, 2015

Vancouver, Canada

LYNDEN ENERGY CORP.

CONSOLIDATED BALANCE SHEETS

(Presented in United States dollars)


	Notes		June 30, 2015			June 30, 2014
ASSETS
Current assets
Cash and cash equivalents			$	8,748,008		$	13,955,890
Trade and other receivables, net of allowance for doubtful accounts		3		1,660,135			3,143,017
Income taxes receivable				469,434			200,000
Prepaid expenses				50,613			—

Total current assets				10,928,190			17,298,907

Non-current assets
Property, plant and equipment		5		107,283,684			91,812,527

Total assets			$	118,211,874		$	109,111,434

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Trade and other payables		6,10		1,646,846			2,971,177
Income taxes payable				—			380,000

Total current liabilities				1,646,846			3,351,177

Non-current liabilities
Credit facility		7		29,908,366			17,853,245
Asset retirement liabilities		8		278,790			240,208
Deferred tax liabilities		14		17,497,692			14,902,811

				47,684,848			32,996,264

Total liabilities				49,331,694			36,347,441

Shareholders’ equity
Share capital—authorized unlimited common shares, no par value
Issued and outstanding: June 30, 2015—130,198,411 June 30, 2014—129,275,911		9		65,622,727			65,160,387
Paid-in capital		9		15,228,879			15,434,128
Accumulated other comprehensive loss				(3,788,414	)		(212,663	)
Deficit				(8,183,012	)		(7,617,859	)

Total shareholders’ equity				68,880,180			72,763,993

Total liabilities and shareholders’ equity			$	118,211,874		$	109,111,434

Subsequent events		15

LYNDEN ENERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)

(Presented in United States dollars)


	Notes		Year ended June 30, 2015			Year ended June 30, 2014
Revenue and other income
Petroleum and natural gas sales			$	22,159,498		$	29,366,595
Derivative financial instruments loss		11		(140,040	)		(63,633	)
Interest income				133,268			89,990

Total revenue and other income				22,152,726			29,392,952

Expenses
Production and operating expenses				(6,269,742	)		(4,949,932	)
Depletion, depreciation, and accretion				(10,232,732	)		(7,917,230	)
Exploration and impairments		5		(2,368,110	)		(253,504	)
General and administrative				(2,384,340	)		(1,390,422	)
Loss from equity investment		4		(431,919	)		—
Interest				(549,672	)		(283,183	)

Total expenses				(22,236,515	)		(14,794,271	)

Other income
Gain on disposition of property, plant and equipment		5		—			10,219,755

Net (loss) income before income taxes				(83,789	)		24,818,436
Income tax expense		14		(481,364	)		(9,414,785	)

Net (loss) income				(565,153	)		15,403,651

Other comprehensive income (loss)
Foreign currency translation adjustment				(3,575,751	)		(352,602	)

Total comprehensive income (loss) for the year			$	(4,140,904	)	$	15,051,049

Weighted average number of common shares outstanding
Basic		9		130,045,582			123,798,574
Diluted		9		130,045,582			127,399,949
Net earnings per common share
Basic			$	(0.00	)	$	0.12
Diluted			$	(0.00	)	$	0.12

LYNDEN ENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Presented in United States dollars)


	Notes		Year ended June 30, 2015			Year ended June 30, 2014
Operating activities
Net (loss) income			$	(565,153	)	$	15,403,651
Adjustments for:
Accrued interest				55,121			—
Unrealized loss on derivative financial instruments				140,040			15,163
Depletion, depreciation and accretion				10,232,732			7,917,230
Impairments				2,372,281			—
Loss from equity investment				431,919			—
Share-based payments				—			55,683
Gain on disposition of property, plant and equipment				—			(10,219,755	)
Deferred income taxes		14		627,230			8,554,735
Unrealized foreign exchange loss				(424,018	)		(196,191	)
Changes in non-cash working capital items:
Trade and other receivables				1,482,882			(545,806	)
Current taxes receivable				(269,434	)		(200,000	)
Prepaid expenses				(50,613	)		—
Trade and other payables				(123,269	)		697,956
Income taxes payable				(380,000	)		276,078

Cash generated by operating activities				13,529,718			21,758,744

Investing activities
Advances to investment in associate				(431,919	)		—
Disposition of property, plant and equipment				—			20,803,912
Acquisition of property, plant and equipment				(29,378,690	)		(34,235,029	)

Cash used in investing activities				(29,810,609	)		(13,431,117	)

Financing activities
Drawings (repayments) of credit facility, net				12,000,000			(8,750,000	)
Common shares issued for cash, net of issue costs		9		257,091			12,660,274

Cash generated by financing activities				12,257,091			3,910,274

Effect of exchange rate on cash held in foreign currency				(1,184,082	)		(156,411	)

Change in cash and cash equivalents during the year				(5,207,882	)		12,081,490
Cash and cash equivalents, beginning of year				13,955,890			1,874,400

Cash and cash equivalents, end of year			$	8,748,008		$	13,955,890

Cash and cash equivalents are composed of:
Cash			$	119,385		$	2,628,377
Guaranteed investment certificates				8,628,623			11,327,513

			$	8,748,008		$	13,955,890

Supplemental cash flow information		12

LYNDEN ENERGY CORP.

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Presented in United States dollars)


	Notes	Year ended June 30, 2015			Year ended June 30, 2014
Share capital
Balance, beginning of year		$	65,160,387		$	49,279,688
Common shares issued for cash:
Exercise of stock options			462,340			—
Exercise of warrants			—			15,880,699

Balance, end of year		$	65,622,727		$	65,160,387

Paid-in capital
Balance, beginning of year		$	15,434,128		$	18,598,870
Exercise of stock options			(205,249	)		—
Exercise of warrants			—			(3,220,425	)
Share-based payments			—			55,683

Balance, end of year		$	15,228,879		$	15,434,128

Accumulated other comprehensive income (loss)
Balance, beginning of year		$	(212,663	)	$	139,939
Foreign currency translation			(3,575,751	)		(352,602	)

Balance, end of year		$	(3,788,414	)	$	(212,663	)

Deficit
Balance, beginning of year		$	(7,617,859	)	$	(23,021,510	)
Net (loss) income			(565,153	)		15,403,651

Balance, end of year		$	(8,183,012	)	$	(7,617,859	)

Total shareholders’ equity		$	68,880,180		$	72,763,993

Common shares—number
Balance, beginning of year			129,275,911			110,505,520
Exercise of stock options			922,500			—
Exercise of warrants			—			18,770,391

Balance, end of year			130,198,411			129,275,911

LYNDEN ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Description of Business

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

2. Significant Accounting Policies

Basis of presentation

These consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“US GAAP”). These consolidated financial statements present the Company’s financial position as of June 30, 2015 and 2014 and results of operations for the years ended June 30, 2015 and 2014.

Basis of consolidation

The consolidated financial statements include the financial statements of the Company and its wholly owned subsidiaries, Lynden Exploration Ltd. and Lynden USA Inc.

Investments where the Company has the ability to exercise significant influence are accounted for using the equity method. Under this method, the Company’s share of the associate’s earnings or losses is included in operations with a corresponding change in the carrying value of the investment. Dividends received from these investments are credited to the investment. The Company’s 48% interest in Abajo Gas Transmission Company, LLC is accounted for using the equity method (note 4).

A substantial portion of the Company’s exploration, development and production activities is conducted jointly with others. These consolidated financial statements reflect only the Company’s proportionate interest in such activities.

Inter-company balances and transactions, including income and expenses arising from inter-company transactions, are eliminated in preparing the consolidated financial statements. Unrealized gains arising from transactions with equity accounted investees are eliminated against the investment to the extent of the Company’s interest in the investee.

Foreign currency translation

The consolidated financial statements are presented in United States dollars, except where otherwise indicated, and all values are rounded to the nearest dollar, except where otherwise indicated. The individual financial statements of each entity are prepared in their functional currency, which is the currency of the primary economic environment in which the entity operates. The functional currency of the Company and its wholly owned subsidiary, Lynden Exploration Ltd., is the Canadian dollar. The functional currency of the Company’s wholly owned subsidiary, Lynden USA Inc., is the United States dollar.

Transactions in foreign currencies are initially recorded into the entities’ functional currencies at the exchange rates at the date of the transactions. Monetary assets and liabilities denominated in foreign currencies are translated using exchange rates prevailing at the date of the statement of financial position. Non-monetary items that are measured in terms of historical cost in a foreign currency are translated using the exchange rates as at the dates of the initial transactions. Non-monetary items measured at fair value in a foreign currency are translated using the exchange rates at the date when the fair value is determined. Revenue and expense items are translated at the exchange rates in effect at the date of underlying transaction, except for items related to non-monetary assets and liabilities, which are translated at historical exchange rates. Exchange rate differences are recognized in the statement of income and comprehensive income in the period they arise.

The results of the Company and Lynden Exploration Ltd. are translated to the United States dollar presentation currency as follows: all assets and liabilities are translated at the exchange rate prevailing at the statement of financial position date; equity balances are translated at the rates of exchange at the transaction dates. All items included in the statements of income (loss) and comprehensive income (loss) are translated using the average monthly exchange rates unless there are significant fluctuations in the exchange rate, in which case the rate at the date of transaction is used. All differences arising upon the translation to the presentation currency are recorded in the foreign currency translation reserve.

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 liabilities, income taxes, and share-based compensation. The Company uses the most current information available and exercises judgment in making these estimates and assumptions. In the opinion of management, these consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the Company’s accounting policies.

Cash and cash equivalents

Cash and cash equivalents in the statement of financial position comprise cash at banks and on hand, and short term deposits with an original maturity of three months or less, which are readily convertible into a known amount of cash.

Trade and other receivables and allowance for doubtful accounts

The majority of all revenues from the sale of oil and natural gas production are collected and disbursed on our behalf by CrownQuest Operating LLC (“CrownQuest”), a party related to CrownRock LP’s (“CrownRock”). The Company is party to various participation agreements with CrownRock. Oil and natural gas sales receivables are generally unsecured. Receivables are considered past due if full payment is not received by the contractual due date. Amounts are written off against the allowance for doubtful accounts only after all collection attempts have been exhausted and it is probable that the receivables will not be collected. The Company does not have any off balance sheet credit exposure related to its customers.

Property, plant and equipment (“PPE”)

Property, plant and equipment are recorded at cost.

The Company uses the successful-efforts method to account for its exploration and development activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. Costs of productive wells and development dry holes are capitalized and amortized using the unit-of-production method. The Company capitalizes exploratory well costs as an asset when the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project or when the well has found a sufficient quantity of reserves to justify its completion as a producing well. Other exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred.

Maintenance and repair costs, including planned major maintenance, are expensed as incurred. Improvements that increase or prolong the service life or capacity of an asset are capitalized.

Production involves lifting the oil and gas to the surface and gathering, treating, field processing and field storage of the oil and gas. The production function normally terminates at the outlet valve on the lease or field production storage tank. Production costs are those incurred to operate and maintain the Company’s wells and related equipment and facilities and are expensed as incurred. They become part of the cost of oil and gas produced. These costs, sometimes referred to as lifting costs, include such items as labour cost to operate the wells and related equipment; repair and maintenance costs on the wells and equipment; materials, supplies and energy costs required to operate the wells and related equipment; and administrative expenses related to the production activity.

Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas reserves. Depreciation and depletion for assets associated with producing properties begin at the time when production commences on a regular basis. Depreciation for other assets begins when the asset is in place and ready for its intended use. Assets under construction are not depreciated or depleted. Unit-of-production depreciation is applied to those wells, plant and equipment assets associated with productive depletable properties, and the unit-of-production rates are based on the amount of proved developed reserves of oil and gas. Depreciation of other plant and equipment is calculated using the straight-line method, based on the estimated service life of the asset.

Proved oil and gas properties held and used by the Company are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets.

The Company estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows used in impairment evaluations are developed using annually updated corporate plan investment evaluation assumptions for crude oil and natural gas commodity prices. Annual volumes are based on field production profiles, which are also updated annually.

Impairment analyses are based on reserve estimates used for internal planning and capital investment decisions. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. An asset group would be impaired if the undiscounted cash flows were less than its carrying value. Impairments are measured by the amount the carrying value exceeds fair value.

Significant unproved properties are assessed for impairment individually and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time the company expects to hold the properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period. The valuation allowances are reviewed at least annually.

Gains or losses on assets sold are included in the consolidated statement of income.

Asset retirement liabilities

The Company’s P&NG operating activities give rise to dismantling, decommissioning and site remediation activities. These obligations are initially measured at fair value and discounted to present value. A corresponding amount equal to the initial obligation is added to the capitalized costs of the related asset. Amortization of capitalized decommissioning costs and increases in asset retirement obligations resulting from the passage of time are recorded as amortization and accretion, respectively, which are included in depreciation, depletion, amortization and accretion and charged against net income.

Changes in the estimated liability resulting from revisions to the estimated timing or amount of cash flows, are recognized as a change in the asset retirement obligation and related capitalized asset retirement cost and are measured at fair value and discounted to present value.

Revenue recognition

The Company uses the accrual method of accounting for P&NG revenues. Sales of P&NG are recognized when the delivery to the purchaser has occurred and title has been transferred. This occurs when P&NG has been delivered to a pipeline or oil hauling has occurred. Crude oil is priced on the average monthly settlement price during the calendar month of the delivery month based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. Virtually all of the Company’s natural gas contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas, and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies.

Share-based payments

Employees (including directors and senior executives) of the Company may receive a portion of their remuneration in the form of share-based payment transactions, whereby employees render services as consideration for equity instruments (“equity-settled transactions”).

In situations where equity instruments are issued for goods or services, the transaction is measured at the fair value of the goods or services received by the entity. When the value of the goods or services cannot be specifically identified, they are measured at fair value of the share-based payment.

The costs of equity-settled transactions with employees are measured by reference to the fair value at the date on which they are granted.

The costs of equity-settled transactions are recognized, together with a corresponding increase in equity, over the period in which the performance and/or service conditions are fulfilled, ending on the date on which the relevant employees become fully entitled to the award (“the vesting date”). The cumulative expense is recognized for equity-settled transactions at each reporting date until the vesting date reflects the Company’s best estimate of the number of equity instruments that will ultimately vest. The profit or loss charge or credit for a period represents the movement in cumulative expense recognized as at the beginning and end of that period and the corresponding amount is represented in share option reserve.

No expense is recognized for awards that do not ultimately vest, except for awards where vesting is conditional upon a market condition, which are treated as vesting irrespective of whether or not the market condition is satisfied provided that all other performance and/or service conditions are satisfied.

Where the terms of an equity-settled award are modified, the minimum expense recognized is the expense as if the terms had not been modified. An additional amount is recognized on the same basis as the amount of the original award for any modification which increases the total fair value of the share-based payment arrangement, or is otherwise beneficial to the employee as measured at the date of modification.

The dilutive effect of outstanding options is reflected as additional dilution in the computation of earnings per share.

Income tax

Income tax expense is comprised of current and deferred income tax. Current income tax is the expected tax payable or refund on taxable income or loss for the year, using rates enacted at the reporting date. Deferred income tax is recognized using the liability method of accounting for income taxes. Under this method, deferred tax is recorded on the temporary differences between the accounting and income tax basis of assets and liabilities, using the enacted income tax rates expected to apply when the temporary differences are expected to reverse. Deferred tax is recognized in net income except to the extent that it relates to items recognized directly in shareholders’ equity. Deferred tax is not recognized for taxable temporary differences arising on the initial recognition of goodwill. The Company routinely reviews deferred tax assets and a valuation allowance is provided if, after considering available evidence, it is more likely than not that a deferred tax asset will not be realized.

The Company recognizes the financial statement effects of an uncertain tax position when it is more likely than not, based on technical merits, that the position will be sustained upon examination by a taxation authority. The amount of tax benefit recognized is the largest amount of tax benefit that has a greater than 50 percent likelihood of being realized upon settlement with a taxation authority. The Company recognizes potential penalties and interest related to uncertain tax positions in income tax expense.

The effect of changes in enacted income tax rates or laws, for both current and deferred income tax, is recognized in net income in the period of enactment.

Financial assets

All financial assets are initially recorded at fair value and classified upon inception into one of the following four categories: held to maturity, available-for-sale, loans and receivables or at fair value through profit or loss (“FVTPL”).

Financial assets classified as FVTPL are measured at fair value with unrealized gains and losses recognized through earnings.

Financial assets classified as loans and receivables and held to maturity are measured at amortized cost using the effective interest method less any allowance for impairment. The effective interest method is a method of calculating the amortized cost of a financial asset and of allocating interest income over the relevant period. The effective interest rate is the rate that exactly discounts estimated future cash receipts (including all fees and points paid or received that form an integral part of the effective interest rate, transaction costs and other premiums or discounts) through the expected life of the financial asset, or, where appropriate, a shorter period.

Financial assets classified as available-for-sale are measured at fair value with unrealized gains and losses recognized in other comprehensive income except for losses in value that are considered significant or prolonged decline in the fair value of that investment below its cost which are considered impairments resulting in a reclassification from other comprehensive income to earnings.

Transactions costs associated with FVTPL financial assets are expensed as incurred, while transaction costs associated with all other financial assets are included in the initial carrying amount of the asset.

Financial liabilities

All financial liabilities are initially recorded at fair value and classified upon inception as FVTPL or other financial liabilities.

Financial liabilities classified as other financial liabilities are initially recognized at fair value less directly attributable transaction costs. After initial recognition, other financial liabilities are subsequently measured at amortized cost using the effective interest method. The effective interest method is a method of calculating the amortized cost of a financial liability and of allocating interest expense over the relevant period. The effective interest rate is the rate that exactly discounts estimated future cash payments through the expected life of the financial liability, or, where appropriate, a shorter period.

Financial liabilities classified as FVTPL include financial liabilities held for trading and financial liabilities designated upon initial recognition as FVTPL. Derivatives, including separated embedded derivatives, are also classified as held for trading unless they are designated as effective hedging instruments. Transaction costs on financial liabilities classified as FVTPL are expensed as incurred. Fair value changes on financial liabilities classified as FVTPL are recognized through the statement of income and comprehensive income.

Net income (loss) per share

Basic net income (loss) per common share is computed by dividing net income (loss) by the weighted average number of common shares outstanding during the period.

For the diluted net income (loss) per common share calculation, the weighted average number of shares outstanding is adjusted for the potential number of shares which may have a dilutive effect on net income (loss). The weighted average number of diluted shares is calculated in accordance with the treasury stock method which assumes that the proceeds received from the exercise of all common share equivalents would be used to repurchase common shares at the average market price.

Interest capitalization

The Company capitalizes interest costs which are directly attributable to the acquisition or construction of qualifying assets.

Recent accounting pronouncements

•

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 and which may have an impact on the Company:

•

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, 2017 with early adoption permitted)

•

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.

3. Trade and Other Receivables


	June 30, 2015		June 30, 2014
Accounts receivable – trade	$	1,340,803	$	2,572,762
Accrued receivables		237,430		496,947
Sales taxes receivable		81,902		73,308

	$	1,660,135	$	3,143,017

The Company did not have any allowance for doubtful accounts as at June 30, 2015 and 2014. As at June 30, 2015, $1,532,382 (2014—$2,991,585) is owing from one counterparty.

4. Investment in Associate

The Company has a 48% interest in a Utah, USA based natural gas transmission company, Abajo Gas Transmission Company, LLC (“Abajo”). Abajo holds ownership of the gas gathering systems in the Northern and Southern Prospect Areas of the Company’s Paradox Basin Project (note 5).

The Company exerts significant influence over Abajo as a result of its 48% interest. However, as a result of the Company’s partner holding a greater than 50% interest in Abajo and also acting as manager of Abajo, the Company does not control Abajo. As such, the investment in Abajo is accounted for using the equity method.

At July 1, 2010, the Company wrote down its Abajo investment to $nil. The impairment charge was made after considering, among other things, the estimated future natural gas volumes to be transmitted by Abajo from the wells currently tied into the gas gathering system and the Company’s decision to not incur capital expenditures on the Paradox Basin Project in the near term.

The following is summarized financial information for Abajo as at June 30, 2015 and June 30, 2014 and for the twelve month periods ended June 30, 2015 and 2014:


	June 30, 2015		June 30, 2014
Total assets	$	1,657,330	$	1,682,118
Total liabilities	$	193,019	$	861,934
Revenues	$	75,144	$	88,617
Loss	$	331,017	$	239,804

The Company’s cumulative share of losses attributable to Abajo from July 1, 2010 to June 30, 2015 that have not been recognized amounts to $4,731,583 and $152,285 (2014 – $148,959) for the year ended June 30, 2015. In March 2015, the Company advanced a further $431,919 to Abajo. This additional investment represents the funding of prior losses up to the amount of the additional investment and was expensed during the year ended June 30, 2015.

5. Property, Plant and Equipment


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

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

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


	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
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

The Company has pledged its interest in its property, plant and equipment to the issuer of its Credit Facility as security.

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.

In February 2014, the Company disposed of a 10.625% interest in 5 gross (1.53 net) vertical Midland Basin wells and underlying leases covering approximately 1,127 gross acres (345 acres net) for gross proceeds of $1.23 million, subject to customary post–closing adjustments. The Company recognized a gain of $305,000. The Company will receive a 20% working interest in new wells drilled on the lease by paying 24.375% of the drilling and completion costs.

In December 2013, the Company disposed of 12 gross (4.7 net) vertical Midland Basin wells and underlying leases covering approximately 1,000 gross acres (403 acres net) for gross proceeds of $19.3 million, subject to customary post–closing adjustments. The Company recognized a gain of $10.2 million.

Exploratory Well Costs

Exploratory well costs consist of costs associated with the drilling and equipping of exploratory wells relating to 1) the Mitchell Ranch Project; 2) one vertical well location in the Midland Basin; and 3) one horizontal well location in the Midland Basin.

Exploration activity often involves drilling multiple wells, over a number of years, to fully evaluate a project. Project costs suspended for longer than one year were primarily suspended pending the completion of 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. If additional information becomes available that raises substantial doubt as to the economic or operational viability of any of these projects, the associated costs will be expensed at that time.

The Company continues capitalization of exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.


	Paradox Basin			Mitchell Ranch			Wolfberry			Total
As at June 30, 2013	$	445,706		$	3,584,783		$	—		$	4,030,489
Additions pending the determination of proved reserves		22,652			151,737			—			174,389
Dispositions		(18,817	)		—			—			(18,817	)

As at June 30, 2014		449,541			3,736,520			—			4,186,061
Additions pending the determination of proved reserves		—			5,690,251			2,440,953			8,131,204
Reclassification to proved		—			—			(2,165,155	)		(2,165,155	)
Impairments		(449,541	)		(1,814,441	)		—			(2,263,982	)

As at June 30, 2015	$	—		$	7,612,330		$	275,798		$	7,888,128

The following table provides an aging analysis of exploratory costs as at June 30, 2015 and 2014.


	June 30, 2015		June 30, 2014
Exploratory well costs capitalized for a period of one year or less	$	5,966,049	$	174,389
Exploratory well costs capitalized for a period of one to two years		174,389		224,079
Exploratory well costs capitalized for a period of greater than three years		1,747,690		3,787,593

	$	7,888,128	$	4,186,061

The majority of exploratory well costs capitalized for a period of greater than three years are lease acquisition costs.

During the year ended June 30, 2015, the Company incurred an impairment charge of $1,814,441 for the Mitchell Ranch Project, of which $1,682,794 is for the Spade 17 #1 exploratory well. It was determined that all principal target zones in the Spade 17 #1 well had been tested and that no future completion operations were being planned. The Company had previously recognized cumulative income of $472,000 related to this well (2014: $82,000), which should have been applied to exploratory well costs.

During the three months ended September 30, 2014, management determined that the capitalized costs related to the Paradox Basin Project suspended exploratory well costs should have been expensed in the year ended June 30, 2014, due to 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 expensed the remaining costs as an immaterial out of period adjustment of $449,541 in the three months ended September 30, 2014. Management has determined that no prior period financial statements were materially misstated as a result of these costs.

In December 2013, the Company disposed of its interest in leases covering approximately 8,400 acres in the Southern Prospect Area of the Paradox Basin for proceeds of approximately $307,000. The Company recognized a gain of approximately $288,000.

6. Trade and Other Payables


	June 30, 2015		June 30, 2014
Accounts payable – trade	$	1,526,796	$	2,693,097
Accrued liabilities	$	120,050	$	278,080

	$	1,646,846	$	2,971,177

As at June 30, 2015, $1,253,267 (2014 - $2,486,438) is due to one counterparty.

7. Credit Facility

The Company has a reducing revolving line of credit (the “Credit Facility”) in an amount up to $100 million. As at June 30, 2015, the Credit Facility has a borrowing base of $37.5 million, of which $29.75 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 may also apply pursuant to the bank’s re-determinations of the borrowing base. Changes in the borrowing base are made based on the bank’s engineering valuation of the Company’s oil and gas reserves. The borrowing base is re-determined semi-annually; however, the Company may request two additional re-determinations of the borrowing base annually.

8. Asset Retirement Liabilities

The total decommissioning liabilities were estimated by management based on the Company’s net ownership interest in all wells, estimated costs to reclaim and abandon the wells and the estimated timing of the costs to be incurred in future periods. The total undiscounted amount of the estimated cash flows (adjusted for inflation with weighted-average rate of 2%) to settle the decommissioning liabilities is approximately $4,189,000 as at June 30, 2015 (June 30, 2014—$3,579,000). These payments are expected to be made over the next 10 to 35 years. The Company used a weighted-average credit adjusted risk free rate of 10.2% to calculate the present value of the asset retirement liabilities.


As at June 30, 2013	$	200,531
Liabilities incurred		34,627
Property dispositions		(13,941	)
Accretion		21,190
Revisions in estimated liabilities		(2,199	)

As at June 30, 2014		240,208
Liabilities incurred		22,771
Liabilities settled		(8,870	)
Accretion		25,297
Revisions in estimated liabilities		(616	)

As at June 30, 2015	$	278,790

9. Shareholders’ Equity

Authorized share capital:

An unlimited number of common shares without par value.

An unlimited number of preference shares without par value.

Warrants:

The changes in warrants issued during the years ended June 30, 2015 and 2014 are as follows:


	Number of warrants			Weighted average exercise price (CDN$)
As at June 30, 2013		27,415,760		$	0.69
Exercised		(18,770,391	)	$	0.70
Expired		(1,133,369	)	$	0.70

As at June 30, 2014		7,512,000		$	0.65
Expired		(7,512,000	)	$	0.65

As at June 30, 2015		—		$	—

Earnings per share:

Diluted earnings per share computation


	June 30, 2015			June 30, 2014
Numerator:
Net (loss) income	$	(565,153	)	$	15,403,651

Denominator:
Weighted average number of common shares (basic)		130,045,582			123,798,574
Dilutive effect of share options		—			1,626,501
Dilutive effect of warrants		—			1,974,874

Weighted average number of common shares (diluted)		130,045,582			127,399,949

Diluted (loss) income per common share	$	(0.00	)	$	0.12

For the year ended June 30, 2015, there are nil (2014 – nil) warrants and 4,270,000 (2014 – 2,612,500) stock options that are not dilutive and have been excluded from the dilutive earnings per share calculation.

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 Company did not grant or amend any stock options during the year ended June 30, 2015 and 2014. The Company recognized $55,683 for share-based payments in the year ended June 30, 2014 for stock options granted in prior years.

The changes in stock options issued during the years ended June, 2015 and 2014 are as follows:


	Number of options			Weighted average exercise price (CDN$)
As at June 30, 2013		6,862,500		$	0.61
Expired		(230,000	)	$	0.68

As at June 30, 2014		6,632,500		$	0.61
Exercised		(922,500	)	$	0.31
Expired		(1,440,000	)	$	0.55

As at June 30, 2015		4,270,000		$	0.69

For stock options exercised during the year ended June 30, 2015, 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 June 30, 2015:


	Options outstanding				Options exercisable
Exercise price (CDN$)	Number of options		Weighted average remaining life (years)		Number of options		Weighted average remaining life (years)
$0.50 to $0.60		1,657,500		1.70		1,657,500		1.70
$0.80		2,612,500		1.06		2,612,500		1.06

		4,270,000		1.31		4,270,000		1.31

10. 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.


	June 30, 2015		June 30, 2014
Legal fees	$	42,013	$	38,972
Transportation and marketing costs		41,607		41,322

	$	83,620	$	80,294

Trade and other payables include $33,320 (June 30, 2014—$47,104) owing to related parties. Amounts due to or from related parties are unsecured, non-interest bearing and are due on demand.

11. Financial Instruments

As at June 30, 2015, the Company’s financial instruments are cash and cash equivalents, trade and other receivables, credit facility, trade and other payables, and a commodity derivative liability. These financial instruments are classified as follows:

Cash and cash equivalents – loans and receivables

Trade and other receivables – loans and receivables

Credit facility – other financial liabilities

Trade and other payables – other financial liabilities

Derivative liability – fair value through profit or loss

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

Level 1:

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

Level 2:

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

Level 3:

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

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

The amounts reported in the statement of financial position 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.

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. The Company’s cash and cash equivalents and trade and other receivables are exposed to credit risk. Management believes the credit risk on cash is low because the counterparties are highly rated financial institutions. The majority of the Company’s trade and other receivables are with customers in the petroleum and natural gas industry and are subject to normal industry credit risks. The Company generally extends unsecured credit to these customers and therefore the collection of trade and other receivables may be affected by changes in economic or other conditions. The Company believes the risk is mitigated by the size and reputation of the companies to which they extend credit. The Company has not experienced any material credit loss in the collection of trade and other receivables to date and therefore has not made any provision for bad debts. The Company did not have any allowance for doubtful accounts as at June 30, 2015 and 2014. As at June 30, 2015, $1,532,385 (2014—$2,991,585) is owing from CrownQuest.

The aging of trade and other receivables are as follows:


	June 30, 2015		June 30, 2014
Trade and other receivables
0 to 60 days	$	1,592,126	$	3,083,365
61 to 120 days		8,357		6,762
> 120 days¹		59,652		52,890

	$	1,660,135	$	3,143,017

¹	Utah State withholding taxes on P&NG sales.

Liquidity Risk

Liquidity risk is the risk that the Company will encounter difficulty in meeting obligations associated with financial liabilities. The Company’s trade and other payables are generally payable within 90 days. The Company’s objective is to have sufficient capital to meet short term financial obligations after taking into account its exploration and development obligations, cash on hand, the unused borrowing base amount under its Credit Facility and anticipated changes in the Credit Facility borrowing base amount.

Advances under the Credit Facility can be in the form of Eurodollar loans, which have a maximum period of 90 days, or in the form of floating rate loans, which can remain outstanding to the Credit Facility final maturity date of August 29, 2016. Eurodollar loans can be converted at the Company’s election to floating rate loans, or continued as new Eurodollar loans, provided that the total amount advanced under the Credit Facility does not exceed the borrowing base amount at that time. The Company’s continued investment in developing its property, plant and equipment would generally increase the amount of the borrowing base, however adverse exploration and development results or a decrease in the price of petroleum and natural gas would negatively impact the amount of the borrowing base.

Repayments under the Credit Facility prior to the maturity date will be required only to the extent that outstanding principal and interest exceed the borrowing base.

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	$	29,908,366	$	—	$	29,908,366	$	—
Trade and other payables		1,646,846		1,646,846		—		—
Asset retirement obligation		4,189,000		—		—		4,189,000

	$	35,744,212	$	1,646,846	$	29,908,366	$	4,189,000

¹includes accrued interest of $158,366.

Market Risk

Market risk is the risk of loss that may arise from changes in market factors such as interest rates, foreign exchange rates and commodity and equity prices.

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. The Company’s cash and credit facility are exposed to interest rate risk as the Company invests cash at floating rates of interest in highly liquid instruments and it borrows funds at floating rates of interest. Fluctuations in interest rates impact interest income and expense. For the year ended June 30, 2015, if interest rates had been 1% higher, net loss and comprehensive loss would have been approximately $136,000 higher. If interest rates had been 1% lower, net loss and comprehensive loss would have been approximately $115,000 higher.

ii)

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 the Company’s earnings 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 the Company’s earnings 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	$	8,670,365	$	8,196	$	(89,370	)	$	8,589,191	$	858,919

Based on the above net exposures at June 30, 2015, 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 by $858,919.

iii)

Price Risk

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

To protect future cash flows for planned capital expenditures, the Company periodically enters into commodity derivative contracts. In April 2015, the Company entered into a NYMEX based oil price put contract for 9,000 barrels of oil per month from September 2015 until August 2016 (12 months) with a strike price of $50 per barrel. Fair value changes on this contract are recognized in the statement of income. As at June 30, 2015, the Company has recognized an unrealized loss of $140,040.

During the year ended June 30, 2014, the Company entered into costless collar oil commodity contracts. These costless collar contracts expired during the year ended June 30, 2014. Under the costless collar agreements, the Company would receive a cash payment if the average monthly price of West Texas Intermediate Crude Oil was below $80 and the Company would make a cash payment if the average monthly price of West Texas Intermediate Crude Oil was above $104 or $105. During the year ended June 30, 2014, the Company recognized a loss of $63,633.

12. Supplemental Cash Flow Information


	June 30, 2015		June 30, 2014
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
Additional cash flow information:
Interest paid	$	917,052	$	874,226
Taxes paid	$	503,668	$	783,972

13. Segmented Information

At June 30, 2015 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
Year ended June 30,	2015		2014		2015		2014		2015		2014
Revenue and other income
Interest Income	$	133,268	$	89,990		—		—	$	133,268	$	89,990
Petroleum sales, net of royalties		—		—		17,227,574		23,507,100		17,227,574		23,507,100
Natural gas sales, net of royalties		—		—		2,198,265		2,212,065		2,198,265		2,212,065
Natural gas liquids sales, net of royalties		—		—		2,593,619		3,583,797		2,593,619		3,583,797

	$	133,268	$	89,990	$	22,019,458	$	29,302,962	$	22,152,726	$	29,392,952

	Canada				USA				Consolidated Total
	June 30, 2015		June 30, 2014		June 30, 2015		June 30, 2014		June 30, 2015		June 30, 2014
Property, plant and equipment	$	951	$	1,021	$	107,282,733	$	91,811,506	$	107,283,684	$	91,812,527

14. Income Taxes

Income tax expense differs from the amount computed by applying the combined Canadian federal and provincial income tax rates, applicable to the Company, to the net earnings (loss) before income taxes due to the following:


	June 30, 2015			June 30, 2014
Net (loss) income before income taxes	$	(83,789	)	$	24,818,436
Combined statutory tax rate		26.00	%		26.00	%

Income tax (recovery) expense computed at statutory tax rate		(21,785	)		6,452,793
Increase (decrease) attributable to:
Changes in valuation allowance		3,499			214,513
Change in estimate		9,893			356,201
Non-deductible (taxable) expenditures		378,822			584,411
Effect of different statutory tax rates on earnings in subsidiaries		110,935			2,082,510
Equity investment taxable loss pick-up		—			(275,643	)

Income tax expense	$	481,364		$	9,414,785

Current income tax expense		(145,866	)		860,050
Deferred income tax expense		627,230			8,554,735

Income tax expense	$	481,364		$	9,414,785

Current income tax and deferred income tax for 2015 and 2014 are all US based taxes.

The significant components of the Company’s deferred tax assets and liabilities are as follows:


	June 30, 2015			June 30, 2014
Deferred tax assets:
Asset retirement liabilities	$	94,789		$	81,671
Alternative minimum tax credits		272,830			272,830
Trade and other payables		47,614			—
Credit facility		207,688			—
Capital loss carry forwards		—			17,669
Share issuance costs		2,106			31,315
Excess tax value of intangibles over book value		397			463
Excess tax value of property, plant and equipment over book value		681			1,136
Exploration and evaluation assets		599,091			673,948
Non-capital losses carry forwards		12,334,869			10,149,816

		13,560,065			11,228,848
Valuation allowance		(2,851,490	)		(2,847,991	)

		10,708,575			8,380,857

Deferred tax liabilities:
Credit facility		—			(264,683	)
Unrealized mark-to-market gains		(2,974,446	)		(1,006,795	)
Property, plant and equipment		(25,231,821	)		(22,012,190	)

		(28,206,267	)		(23,283,668	)

Net deferred tax assets (liabilities)	$	(17,497,692	)	$	(14,902,811	)

The Company has income tax loss carry forwards of approximately $29,663,690 (2014 - $14,806,716) for US tax purposes. These recognized tax losses will expire between 2031 and 2035.

The Company has unrecognized income tax loss carry forwards of approximately $8,650,700 (2014 - $7,289,792) for Canadian tax purposes. These unrecognized tax losses will expire between 2026 and 2035.

15. Subsequent Events

Subsequent to June 30, 2015, 260,000 stock options with an exercise price of CDN$0.60 expired unexercised.

LYNDEN ENERGY CORP.

Supplemental Information on Oil and Gas Exploration and Production Activities

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

Costs incurred in oil and natural gas property acquisition and development activities are as follows for the years ended June 30, 2015 and 2014:


	June 30, 2015		June 30, 2014
Property acquisition costs
Proved	$	71,059	$	24,948
Unproved		14,074		12,532
Exploration costs		5,951,975		415,361
Development costs		22,013,097		36,229,566

Total costs incurred	$	28,050,205	$	36,682,407

All of the above costs were incurred in the United States of America.

Exploratory Well Costs

As of June 30, 2015, exploratory well costs consist of costs associated with the drilling and equipping of exploratory wells relating to 1) the Mitchell Ranch Project; 2) one vertical well location in the Midland Basin; and 3) one horizontal well location in the Midland Basin.

On the Mitchell Ranch Project, the Company drilled and fracture stimulated an initial appraisal well, the Spade 17 #1, on the Mitchell Ranch Project in fiscal 2011. Periodic testing and further stimulation of the Spade 17 #1 well has been carried out since that time. In early-fiscal 2012 the Company entered into a 30 month term assignment for a large portion of its Mitchell Ranch Project acreage with a senior oil and gas company. The term assignment provided the Company an opportunity to observe the results of the senior oil and gas company’s drilling and completion activities on the Mitchell Ranch Project term assignment acreage and to incorporate their results in the Company’s testing plan for the Mitchell Ranch Project. On March 31, 2014 the senior oil and gas company elected to not continue with further activities and the term assignment acreage was returned, and the Company and its working interest partner actively resumed scheduling of additional testing activity, as described further below.

In the third quarter of fiscal 2014 the Company and its working interest partner carried out a further round of testing on an uphole zone in the Spade 17 #1 well. During the year ended June 30, 2015, the Company incurred an impairment charge of $1,814,441 for the Mitchell Ranch Project, $1,682,794 of which is for the Spade 17 #1 well. It was determined that all principal target zones in the Spade 17 #1 well had been tested and that no future completion operations were being planned. Seismic interpretation and the initiation of a 3-D seismic program over a portion of the Mitchell Ranch Project acreage not previously covered by seismic was also carried out during fiscal 2014 and 2015 in preparation for drilling additional appraisal wells on the project. The Company and its working interest partner established plans for a four new well program to be carried out on the project. All four wells are in close proximity to the initial Spade 17#1 appraisal well which the Company expects will enhance operational efficiencies in the testing of the project. It is anticipated that the results from these wells will allow the Company to assess the reserves and the further potential development and viability of the project. Positive results would justify further major capital expenditures on the project. The first of the four wells was spud in late May 2014 and a first round of fracture stimulations was carried out in October 2014. The other three wells of the four well program were spud and drilled by October 2014, and several rounds of fracture stimulations and production testing have been carried out in the wells. There are several separate targeted zones that exhibit potential on the Mitchell Ranch Project. These zones will generally be tested by stimulating the lowermost zones in the well, observing flow-back from the stimulated zones, and once the production potential of the zones has been assessed move uphole to systematically test additional zones. Management anticipates that it will be able to determine the commerciality of the Mitchell Ranch Project by December 31, 2015.

Also included in exploratory well costs are the costs incurred in preparation of drilling a vertical well in the Midland Basin that was spud shortly after June 30, 2015 and costs incurred for one horizontal well in the Midland Basin which was spud shortly before June 30, 2015. Both of these wells were drilled to their targeted depths and testing is underway. Management anticipates that it will be able to determine the commerciality of these wells by December 31, 2015.

Standardized Measure of Discounted Future Net Cash Flows

Reserve estimates and discounted future net cash flows are based on the unweighted average market prices for sales of oil and natural gas on the first calendar day of each month during the year. Cash flows are adjusted for transportation fees and regional price differentials, to the estimated future production of proved oil and natural gas reserves less estimated future expenditures to be incurred in developing and producing the proved reserves, discounted using an annual rate of 10% to reflect the estimated timing of the future cash flows. Extensive judgments are involved in estimating the timing of production and the costs that will be incurred throughout the remaining lives of the properties.

Accordingly, the estimates of future net cash flows from proved reserves and the present value may be materially different from subsequent actual results. The standardized measure of discounted net cash flows does not purport to present, nor should it be interpreted to present, the fair value of the properties’ oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, and anticipated future changes in prices and costs.

The table below reflects the standardized measure of discounted future net cash flows related to the Company’s interest in proved reserves at June 30, 2015 and 2014.


	2015			2014
Future cash flows	$	581,163,900		$	488,770,334
Future production costs		(179,031,200	)		(133,828,860	)
Future development costs		(128,842,600	)		(64,661,351	)
Future income taxes		(76,612,819	)		(86,035,972	)

Future net cash flows		196,677,281			204,244,151
Annual discount at 10% for estimated timing of cash flows		(126,706,622	)		(121,768,244	)

Discounted future net cash flows	$	69,970,659		$	82,475,908

Changes in Standardized Measure of Discounted Future Net Cash Flows

The following table provides a rollforward of the standardized measure of discounted future net cash flows for the years ended June 30, 2015 and 2014.


	June 30, 2015			June 30, 2014
Balance, beginning of year	$	82,475,908		$	55,563,510
Changes resulting from:
Sales of oil and gas produced, net of production costs		(15,889,756	)		(24,416,663	)
Sales of reserves in place		—			(16,911,630	)
Discoveries and extensions		23,979,600			19,984,162
Changes in prices and production costs		(42,421,155	)		21,170,364
Changes in estimated future development costs		(8,827,304	)		(26,847,805	)
Development costs incurred during the period		21,809,476			36,229,566
Revisions of previous quantity estimates		(1,557,183	)		15,765,294
Net change in income taxes		6,289,739			(13,484,610	)
Accretion of discount		11,169,119			7,129,418
Changes in production rates and other		(7,057,785	)		8,294,302

Net change		(12,505,249	)		26,912,398

Balance, end of year	$	69,970,659		$	82,475,908

Oil and Gas Reserves

The Company has presented the reserve estimates utilizing an oil price of $71.68 per Bbl and a natural gas price of $3.361 per MMBtu as of June 30, 2015, $100.27 per Bbl and $4.104 per MMBtu as of June 30, 2014, and $91.60 per Bbl and $3.459 per MMBtu as of June 30, 2013.

The Company’s estimated reserves at June 30, 2015, June 30, 2014, and June 30, 2013 were based on reserve reports prepared by a third party engineer, Cawley, Gillespie & Associates, Inc. The proved oil and natural gas reserve estimates of the Company have been prepared in compliance with the Securities and Exchange Commission rules and accounting standards based on the 12-month un-weighted first-day-of-the-month average price.

The reserve disclosures that follow reflect estimates of proved reserves, proved developed reserves and proved undeveloped reserves, net of third-party royalty interests, of natural gas, crude oil and condensate, and NGLs owned at year end. Natural gas volumes are in thousands of cubic feet (Mcf) at a pressure base of 14.73 pounds per square inch and volumes for oil are in barrels (Bbls). Total volumes are presented in barrels of oil equivalent (BOE). For this computation, one barrel is equivalent to 6,000 cubic feet of natural gas.

The Company’s estimates of proved reserves are made using available production performance data, as well as pertinent geologic and reservoir data. These estimates are reviewed annually by an independent third party and revised, either upward or downward as warranted by additional data. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions, as well as changes in the expected recovery associated with infill drilling. All of the Company’s reserves are located in Texas, USA. The following table provides a rollforward of the total proved reserves for the year ended June 30, 2015. Oil volumes are expressed in Bbls, natural gas volumes are expressed in Mcf, natural gas liquids volumes are expressed in Bbls, and total volumes are presented in BOE.


	Oil (Bbls)			Natural Gas (Mcf)			Natural Gas Liquids (Bbls)			Total (BOE)
Net Proved Reserves
Balance at June 30, 2014		3,950,079			9,719,125			1,928,080			7,498,013
Discoveries and extensions		3,086,400			8,595,200			1,528,700			6,047,633
Revisions of prior estimates		(132,914	)		1,927,264			147,833			336,130
Production		(274,185	)		(670,309	)		(119,513	)		(505,416	)

Balance at June 30, 2015		6,629,380			19,571,280			3,485,100			13,376,360

Net Proved Developed Reserves, included above
Balance at June 30, 2014		2,102,913			5,280,353			1,047,356			4,030,328
Balance at June 30, 2015		2,226,910			6,723,130			1,200,620			4,548,052
Net Proved Undeveloped Reserves, included above
Balance at June 30, 2014		1,847,166			4,438,772			880,724			3,467,685
Balance at June 30, 2015		4,402,470			12,848,150			2,284,480			8,828,308

The following table provides a rollforward of the total proved reserves for the year ended June 30, 2014:


	Oil (Bbls)			Natural Gas (Mcf)⁽¹⁾			Total (BOE)
Net Proved Reserves
Balance at June 30, 2013		3,653,262			13,589,316			5,918,148
Discoveries and extensions		1,023,690			1,950,095			1,348,706
Revisions of prior estimates		327,408			9,377,971			1,890,403
Sales of reserves in place		(808,114	)		(2,451,430	)		(1,216,686	)
Production		(246,167	)		(1,178,347	)		(442,558	)

Balance at June 30, 2014		3,950,079			21,287,605			7,498,013

Net Proved Developed Reserves, included above
Balance at June 30, 2013		1,805,485			6,585,058			2,902,995
Balance at June 30, 2014		2,102,913			11,564,489			4,030,328
Net Proved Undeveloped Reserves, included above
Balance at June 30, 2013		1,847,777			7,004,258			3,015,153
Balance at June 30, 2014		1,847,166			9,723,116			3,467,685

(1)

The following is a discussion of the material changes in our proved reserve quantities for the years ended June 30, 2015 and 2014:

Extensions and discoveries for 2015 were 6,047 MBoe, all of which are attributable to the drilling of vertical Midland Basin wells (Wolfberry) in the Permian Basin. During 2015 we produced 505 MBoe from these Wolfberry wells. Through our development drilling we increased the number of producing Wolfberry wells from 91 gross (37.18 net) wells to 109 gross (44.69 net) wells in 2015. We recorded positive revisions of prior estimates of 336 MBoe partially as a result of the better production history, and an overall improvement in average well performance.

Extensions and discoveries for 2014 were 1,349 MBoe, all of which are attributable to the drilling of vertical Midland Basin wells (Wolfberry) in the Permian Basin. During 2014 we produced 442 MBoe from these Wolfberry wells. In December 2013, we sold 1,217 Mboe of proved reserves, including 554 MBoe of proved undeveloped reserves to BreitBurn Energy Partners L.P. After taking into account the sale to BreitBurn, through our development drilling we increased the number of producing Wolfberry wells from 67 gross (27.93 net) wells to 91 gross (37.18 net) wells in 2014. We recorded positive revisions of prior estimates of 1,890 MBoe partially as a result of the better production history, an overall improvement in average well performance, and higher oil and natural gas prices.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

For the fiscal years ended June 30, 2015, and 2014, we did not have any disagreement with our accountants on any matter of accounting principles, practices or financial statement disclosure.

Item 9A. 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 Annual Report on Form 10-K. 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 Registration Statement on Form 10 filed during the reporting period covered by this Annual Report on Form 10-K, 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 the material weakness in our internal controls associated with this error had not been corrected by June 30, 2015, our management has concluded that our disclosure controls and procedures were not effective as of June 30, 2015. We believe that the consolidated audited financial statements in this Form 10-K 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.

Changes in Internal Control Over Financial Reporting

As disclosed and described in our amended Registration Statement on 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, 2015, namely that our controls over the evaluation and review of our deferred income taxes were not effective.

In the first quarter of fiscal 2016, management engaged consultants to assist in the determination of deferred income taxes for the year ended June 30, 2015 and enhanced our internal controls by including those consultants in our review process in order to remediate the material weakness. Management believes that the above changes to our internal controls over financial reporting, implemented in the first quarter of fiscal 2016, correct the material weakness.

There has been no change in our internal control over financial reporting during the fiscal quarter ended June 30, 2015, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

This Annual Report on Form 10-K does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of the Company’s registered public accounting firm due to a transition period established by rules of the SEC for newly public companies and because as a smaller reporting company we are not subject to Section 404(b) of the Sarbanes-Oxley Act of 2002.

Item 9B. Other Information

There have been no events that occurred in the fourth quarter of 2015 that would need to be reported on Form 8-K that have not previously been reported.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The information required in response to this Item will be set forth in the Company’s definitive proxy statement for the annual meeting of shareholders to be held in December 2015 and is incorporated herein by reference.

Item 11. Executive Compensation

We are currently considered an emerging growth company for purposes of the SEC’s executive compensation disclosure rules. In accordance with such rules, we are required to provide a Summary Compensation Table and an Outstanding Equity Awards at Fiscal Year End Table, as well as limited narrative disclosures. Further, our reporting obligations extend only to the individuals serving as our chief executive officer, and our two other most highly compensated executive officers.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

EQUITY COMPENSATION PLAN INFORMATION

During the financial year ended June 30, 2015, the Plan was the only equity compensation plan under which securities were authorized for issuance. The following table sets forth information with respect to our stock option plan as at the fiscal year ended June 30, 2015. You can find descriptions of our equity incentive plan under Note 9 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”


Plan category	Number of securities to be issued upon exercise of outstanding options (a)		Weighted-average exercise price of outstanding options ($) (b)		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity compensation plans approved by security holders		4,270,000	CDN$	0.69		8,749,841	⁽¹⁾
Equity compensation plans not approved by security holders		0		N/A		0
Total		4,270,000	CDN$	0.69		8,749,841	⁽¹⁾

⁽¹⁾

This figure is based on the total number of shares authorized for issuance under our Plan, less the number of stock options issued under the Plan which were outstanding as at the Company’s financial year ended June 30, 2015. As at June 30, 2015, the Company was authorized to issue options for the purchase of a total of 13,019,841 shares of common stock.

The remaining information required in response to this Item will be set forth in the Company’s definitive proxy statement for the annual meeting of shareholders to be held in December 2015 and is incorporated herein by reference.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Item 14. Principal Accounting Fees and Services

PART IV

Item 15. Exhibits, Financial Statement Schedules

(a)	Documents filed as part of this report

Index to Consolidated Financial Statements


	Page Reference
Report of Independent Registered Public Accounting Firm		62

Consolidated Balance Sheets at June 30, 2015 and 2014		63

Consolidated Statements of Income and Comprehensive Income for the years ended June 30, 2015 and 2014		64

Consolidated Statements of Cash Flows for the years ended June 30, 2015 and 2014		65

Consolidated Statements of Changes in Shareholders’ Equity for the years ended June 30, 2015 and 2014		66

Notes to Consolidated Financial Statements		67

Index to Consolidated Financial Statement Schedules

All schedules are omitted since the required information is not present or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in the consolidated financial statements or notes thereto.

Exhibits

The Exhibit Index on pages 96 to 97 of this Annual Report on Form 10-K lists the exhibits that are filed or furnished, as applicable, as part of this Annual Report on Form 10-K.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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.
	(Registrant)

Date: September 28, 2015		/s/ Colin Watt
		Colin Watt
		President, Chief Executive Officer, Corporate Secretary and Director

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and as of the date indicated.


Signature	Capacity	Date
/s/ Colin Watt	President, Chief Executive Officer, Corporate Secretary and Director	September 28, 2015
Colin Watt

/s/ Laurie Sadler	Chief Financial Officer	September 28, 2015
Laurie Sadler

/s/ Robert Bereskin	Director	September 28, 2015
Robert Bereskin

/s/ John McLennan	Director	September 28, 2015
John McLennan

/s/ Derek Michaelis	Director	September 28, 2015
Derek Michaelis

/s/ Ron Paton	Director	September 28, 2015
Ron Paton

LYNDEN ENERGY CORP.

INDEX TO EXHIBITS

Exhibits are numbered to correspond to the exhibit table

in Item 601 of Regulation S-K


Exhibit No.		Description

2.1**#		Purchase and Sale Agreement, dated December 12, 2013, between Lynden USA, Inc. and BreitBurn Operating L.P.

3.1**		Certificate of Continuation of Lynden Ventures, Ltd., dated February 2, 2006.

3.2**		Certificate of Change of Name of the Company, dated January 16, 2008.

3.3**		Notice of Articles of the Company.

3.4**		Articles of the Company, dated December 5, 2005.

10.1**		Credit Agreement, dated August 29, 2011, between Lynden USA, Inc., as borrower, Texas Capital Bank, N.A., as administrative agent, and the lenders party thereto.

10.2**		First Amendment to Credit Agreement, dated February 2, 2012, between Lynden USA, Inc., as borrower, Texas Capital Bank, N.A., as administrative agent, and the lenders party thereto.

10.3**		Second Amendment to Credit Agreement, dated March 31, 2012, between Lynden USA, Inc., as borrower, Texas Capital Bank, N.A., as administrative agent, and the lenders party thereto.

10.4**		Third Amendment to Credit Agreement, dated September 25, 2012, between Lynden USA, Inc., as borrower, Texas Capital Bank, N.A., as administrative agent, and the lenders party thereto.

10.5**		Fourth Amendment to Credit Agreement, dated December 19, 2012, between Lynden USA, Inc., as borrower, Texas Capital Bank, N.A., as administrative agent, and the lenders party thereto.

10.6**		Fifth Amendment to Credit Agreement, dated December 26, 2012, between Lynden USA, Inc., as borrower, Texas Capital Bank, N.A., as administrative agent, and the lenders party thereto.

10.7**		Sixth Amendment to Credit Agreement, dated May 10, 2013, between Lynden USA, Inc., as borrower, Texas Capital Bank, N.A., as administrative agent, and the lenders party thereto.

10.8**		Seventh Amendment to Credit Agreement, dated September 27, 2013, between Lynden USA, Inc., as borrower, Texas Capital Bank, N.A., as administrative agent, and the lenders party thereto.

10.9**		Eighth Amendment to Credit Agreement, dated December 27, 2013, between Lynden USA, Inc., as borrower, Texas Capital Bank, N.A., as administrative agent, and the lenders party thereto.

10.10**		Ninth Amendment to Credit Agreement, dated February 5, 2014, between Lynden USA, Inc., as borrower, Texas Capital Bank, N.A., as administrative agent, and the lenders party thereto.

10.11**		Tenth Amendment to Credit Agreement, dated June 5, 2014, between Lynden USA, Inc., as borrower, Texas Capital Bank, N.A., as administrative agent, and the lenders party thereto.

10.12**		Eleventh Amendment to Credit Agreement, dated November 25, 2014, between Lynden USA, Inc., as borrower, Texas Capital Bank, N.A., as administrative agent, and the lenders party thereto (incorporated herein by reference to Exhibit 10.1 of the Registrant’s report on Form 8-K filed on June 24, 2015 (File No. 000-55301)).

10.13**		Twelfth Amendment to Credit Agreement, dated June 4, 2015, between Lynden USA, Inc., as borrower, Texas Capital Bank, N.A., as administrative agent, and the lenders party thereto (incorporated herein by reference to Exhibit 10.2 of the Registrant’s report on Form 8-K filed on June 24, 2015 (File No. 000-55301)).

10.14**+		Form of Share Purchase Warrant Certificate for share purchase warrants issued on May 4, 2012.

10.15**+		Form of Finder’s Warrant Certificate for finder’s warrants issued on May 4, 2012.

10.16**+		Form of Share Purchase Warrant Certificate for share purchase warrants issued on May 18, 2012.


Exhibit No.		Description

10.17**+		Services Agreement, dated January 1, 2013, between Lynden Energy Corp and Richard Andrews.

10.18**+		Management Agreement, dated January 1, 2013, between Lynden Energy Corp and Colin Watt.

10.19**		Participation Agreement, dated September 24, 2009, between CrownRock, L.P. and Lynden USA, Inc.

10.20**		Participation Agreement, dated May 20, 2010, between CrownRock, L.P. and Lynden USA, Inc.

10.21**+		Lynden Energy Corp. Stock Option Plan, as amended on March 16, 2014 and approved by the TSX Venture Exchange on April 27, 2015 (incorporated herein by reference to Exhibit 10.1 of the Registrant’s Quarterly report on Form 10-Q filed on May 13, 2015 (File No. 000-55301)).

21.1*		List of Subsidiaries.

23.1*		Consent of Deloitte LLP

23.2*		Consent of Cawley, Gillespie & Associates, Inc.

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

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

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

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

99.1*		Report of Cawley, Gillespie & Associates, Inc. as of June 30, 2015.

101.INS*		XBRL Instance Document.

101.SCH*		XBRL Taxonomy Extension Schema.

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB*		XBRL Taxonomy Extension Label Linkbase Document.

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document.

+	Designates a compensation plan or arrangement for directors or executive officers.

*	Filed herewith.

**	Previously filed.

***	This exhibit is being furnished rather than filed and shall not be deemed incorporated by reference into any filing, in accordance with Item 601 of Regulation S-K.

#	The schedules (or similar attachments) referenced in this agreement have been omitted in accordance with Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule (or similar attachment) will be furnished supplementally to the Securities and Exchange Commission upon request.

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