10-12G/A

As filed with the Securities and Exchange Commission on December 29, 2014

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 1

to

Form 10

GENERAL FORM FOR REGISTRATION OF SECURITIES

Pursuant to Section 12(b) or 12(g) of the Securities Exchange Act of 1934

LYNDEN ENERGY CORP.

(Exact name of registrant as specified in its charter)

British Columbia, Canada
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)
888 Dunsmuir Street, Suite 1200 Vancouver, British Columbia	V6C 3K4
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code:

(604) 629-2991

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

None

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

Title of Each Class to be so Registered

Common shares, no par value

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 Securities Exchange Act of 1934, as amended. (Check one):

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

TABLE OF CONTENTS

REFERENCES		1
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS		1
GLOSSARY OF OIL AND NATURAL GAS TERMS		2
CURRENCY		5
Item 1.	Business.	5
Item 1A.	Risk Factors.	27
Item 2.	Financial Information.	49
Item 3.	Properties.	62
Item 4.	Security Ownership of Certain Beneficial Owners and Management.	63
Item 5.	Directors and Executive Officers.	64
Item 6.	Executive Compensation.	66
Item 7.	Certain Relationships and Related Transactions, and Director Independence.	70
Item 8.	Legal Proceedings.	72
Item 9.	Market Price of and Dividends on the Registrant’s Common Equity and Related Stockholder Matters.	72
Item 10.	Recent Sales of Unregistered Securities.	78
Item 11.	Description of Registrant’s Securities to be Registered.	82
Item 12.	Indemnification of Directors and Officers.	84
Item 13.	Financial Statements.	85
Item 14.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.	85
Item 15.	Financial Statements and Exhibits.	85
WHERE YOU CAN FIND MORE INFORMATION		129
EXPERTS		129
SIGNATURES

REFERENCES

As used in this registration statement on Form 10 (the “Registration Statement”): (i) the terms the “Registrant”, “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, as amended; (iv) “Exchange Act” refers to the United States Securities Exchange Act of 1934, as amended; (v) “GAAP” refers to generally accepted accounting principles in the United States; and (vi)  all dollar amounts refer to United States dollars unless otherwise indicated.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this Registration Statement includes “forward-looking statements.” All statements, other than statements of historical fact included in this Registration Statement, 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 Registration Statement, the words “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 Registration Statement.

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 economic conditions;

• credit markets;

• uncertainty regarding our future operating results; and

• plans, objectives, expectations and intentions contained in this Registration Statement 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 Registration Statement.

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 Registration Statement 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 Registration Statement 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 Registration Statement.

GLOSSARY OF OIL AND NATURAL GAS TERMS

The terms and abbreviations defined in this section are used throughout this Registration Statement:

“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.” 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.

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“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 Registration Statement 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 percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres. All net acre figures in this Registration Statement 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.

“PDP.” Proved developed producing reserves.

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

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“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 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.

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“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.

Item 1. Business.

Our Company

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 petroleum and natural gas (“P&NG”) rights and properties. We have various working interests in the Midland Basin (Wolfberry) 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.

We are filing this Registration Statement because, at December 31, 2013, we no longer met the definition of “foreign private issuer” under the Securities Act (and, thus, lost certain exemptions from registration for “foreign private issuers”) and as of June 30, 2014 (our fiscal year end) we met the registration requirements under Section 12(g) of the Exchange Act and are required to register with the SEC as a domestic registrant.

JOBS Act

The Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”) provides for certain exemptions from various reporting requirements applicable to public companies that are reporting companies and are “emerging growth companies.” We are an “emerging growth company” as defined in section 3(a) of the Exchange Act (as amended by the JOBS Act, enacted on April 5, 2012), and we will continue to qualify as an “emerging growth company” until the earliest to occur of: (a) the last day of the fiscal year during which we have total annual gross revenues of $1 billion (as such amount is indexed for inflation every 5 years by the SEC) or more; (b) the last day of our fiscal year following the fifth anniversary of the date of the first sale of our common equity securities pursuant to an effective registration statement under the Securities Act; (c) the date on which we have, during the previous 3-year period, issued more than $1 billion in non-convertible debt; or (d) the date on which we are deemed to be a “large accelerated filer,” as defined in Exchange Act Rule 12b–2. Therefore, we expect to continue to be an emerging growth company for the foreseeable future.

We also qualify as a “smaller reporting company” and have the advantage of not being required to provide the same level of disclosure as larger companies.

Generally, a registrant that registers any class of its securities under Section 12 of the Exchange Act is required to include in the second and all subsequent annual reports filed by it under the Exchange Act,

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a management report on internal control over financial reporting and, subject to an exemption available to registrants that meet the definition of a “smaller reporting company” in Exchange Act Rule 12b-2, an auditor attestation report on management’s assessment of internal control over financial reporting. However, for so long as we continue to qualify as an emerging growth company, we will be exempt from the requirement to include an auditor attestation report in our annual reports filed under the Exchange Act, even if we do not qualify as a “smaller reporting company”. In addition, section 103(a)(3) of the Sarbanes-Oxley Act of 2002 has been amended by the JOBS Act to provide that, among other things, auditors of an emerging growth company are exempt from the rules of the Public Company Accounting Oversight Board requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the registrant (auditor discussion and analysis). Furthermore, as an emerging growth company, we have availed ourselves of the reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements and to not present to our stockholders a nonbinding advisory vote on executive compensation, obtain approval of any golden parachute payments not previously approved, or present the relationship between executive compensation actually paid and our financial performance. Additionally, we have irrevocably elected to comply with new or revised accounting standards even though we are an emerging growth company.

Properties

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)		Lynden Net Interest			Net Acres(2)
Martin		1,757		43.75	%		769
Martin		1,127		20.00	%		225
Midland		640		43.75	%		280
Glasscock		4,480		43.75	%		1,960
Howard		6,121		40.625	%		2,487
Howard		640		25.39	%		162
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. 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.

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

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Basin, historically one of the most prolific oil basins in North America. The Wolfberry Project’s primary objectives target 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 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 now have 101 gross (41.38 net) vertical Wolfberry wells tied-in and producing.

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, we will be funding 24.375% of the cost of new wells drilled on the lease.

The gross cost of a vertical Wolfberry well is currently approximately $2.1 million. Our current plans call for 15 gross (6.26 net) vertical Wolfberry wells to spud in Fiscal 2015 (July 1, 2014 to June 30, 2015) at an estimated cost to us of approximately $15.0 million. Pursuant to the terms of the Midland Basin Participation Agreement, Lynden’s funding amount for the 6.26 net wells is equivalent to 7.15 wells.

Our capital budget is subject to change depending upon a number of factors, including 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 recent Wolfberry drilling activity.

	For the quarterly period ended:
	September 30, 2013		December 31, 2013		March 31, 2014		June 30, 2014		September 30, 2014
Producing Wolfberry well
Gross		76		72		78		91		95
Net		31.68		29.69		31.72		37.18		38.87
Well spud or drilled awaiting completion and /or tie in
Gross		4		3		7		4		5
Net		1.78		1.27		2.87		1.68		1.97

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 create an initial horizontal development plan for the acreage. Two initial CrownQuest operated horizontal wells are scheduled for the first half of calendar 2015 in Glasscock County. We anticipate a gross cost of a horizontal well to be approximately $9.0 million, for an estimated cost to Lynden pursuant to the terms of the Midland Basin Participation Agreement of approximately $4.5 million per well.

Lynden’s first horizontal well, the Wolcott 253-1H, 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. The well has a lateral length of approximately 6,200 feet and was

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fracture stimulated in late July. In order to continue with development of the Wolcott Lease, a second horizontal well on the lease was spud in early October 2014 and has been drilled with a lateral length of approximately 6,200 feet and was fracture stimulated in November. 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 currently anticipate two additional horizontal wells will be spud on the lease in Fiscal 2015. The gross cost of a horizontal well is estimated to be approximately $8.5 million, for an estimated cost to Lynden of approximately $2.1 million per well.

Lynden incurred $36,741,244 of capital expenditures in the Midland Basin during the financial year ended June 30, 2014. Of this amount, approximately $25,000 was for land and lease costs; approximately $345,000 was for the accrual of decommissioning liabilities; approximately $1,122,000 was for capitalized borrowing costs; and approximately $35,250,000 was for drilling, completion, facilities and tie-in.

The Company incurred approximately $7.3 million of capital expenditures in the Midland Basin during Q1/2015. Of this amount, approximately $4,000 was for land and lease costs; approximately $5,500 was for the accrual of decommissioning liabilities; and approximately $7,300,000 was for drilling, completion, facilities and tie-in.

Mitchell Ranch Project

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) producing 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.

A four new well program is currently underway. All four wells now have been drilled in an area in general proximity to our Spade 17 #1 well. The new well program is incorporating the results of a recent 3D seismic program that has identified multiple pay opportunities. As of the date of this registration statement, only one of the wells has been fracture stimulated.

Assuming completions and subsequent testing across several zones, the gross cost of each well is anticipated to be $1.8 million, for an estimated cost to the Company of approximately $0.9 million per well.

During the financial year ended June 30, 2014, we received $110,081 in P&NG sales, incurred royalties of $24,768, and incurred production taxes of $3,939 with respect to the Mitchell Ranch Project.

The Company incurred $2.7 million of capital expenditures in the Mitchell Ranch Project during Q1/2015. Of this amount, approximately $2.6 million was for drilling, completion, facilities and tie-in.

During Q1/2015, the Company received $30,365 in P&NG sales, incurred royalties of $6,832, and incurred production taxes of $1,085.

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Paradox Basin Project

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 47.99% 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, 2014, we received $202,842 in P&NG sales, incurred royalties of $35,634, incurred transportation costs of $41,322, and incurred production taxes of $6,768 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.

During Q1/2015, the Company received $37,105 in P&NG sales, incurred royalties of $5,958, incurred transportation costs of $9,380, and incurred production taxes of $1,147. 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 for 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 has 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.

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Summary Reserve Information

The following chart details our summary reserve information as of June 30, 2014. The information is based on a reserve report prepared by our independent consulting petroleum engineers, Cawley, Gillespie and Associates, Inc. You should refer to “Item 1A. Risk Factors,” “Item 2. Financial Statements-Management’s Discussion and Analysis of Financial Condition and Results of Operations” in evaluating the material presented in the following table.

	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
			June 30, 2013
			12-Month Unweighted Average Pricing: Oil $91.60, Natural Gas $3.459
			Oil (Mbbl)		Natural Gas (MMcf)(1)
Proved developed producing				1,429.7		5,659.0
Proved developed non-producing				375.8		926.0
Proved undeveloped				1,847.8		7,004.3
Total proved				3,653.3		13,589.3
Probable				121.1		497.7

⁽¹⁾  Natural gas reserves are shown in “wet” Mcf, which includes NGL.

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—Risks Related to Our Business—The development of our estimated proved undeveloped reserves (“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.”

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

Net Proved Reserves	Oil (Bbls)			Natural Gas (Mcf)(1)			Total (BOE)
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		326,509			9,344,145			1,883,867
Sales of reserves in place		(808,114	)		(2,451,430	)		(1,216,686	)
Production		(245,268	)		(1,144,521	)		(436,022	)
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 are shown in “wet” Mcf, which includes NGL.

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Proved undeveloped reserves. As of June 30, 2014, our PUDs totaled 1,847 MBbls of oil and 9,723 MMcf of natural gas, for a total of 3,468 MBoe. PUDs will be converted from undeveloped to developed as the applicable wells begin production. During the year ended June 30, 2014, we converted approximately 342 MMBoe of proved undeveloped reserves to proved developed reserves by drilling and completing 5 gross (2.13 net) PUD vertical Wolfberry locations.

Changes in PUDs that occurred during the year ended June 30, 2014 were primarily due to (i) the sale of 554 MBoe of reserves categorized as PUD to an unrelated party in the BreitBurn Sale, (ii) the addition of 1,171 MBoe attributable to new PUD locations resulting from the strategic drilling of wells to delineate our acreage position and (iii) the conversion of 342 MBoe of reserves categorized as PUD as of June 30, 2013 that were converted to PDP.

During the year ended June 30, 2014, we spent approximately $4.1 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 “Item 1. Business—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 Estimation Procedures and Audits

The information included in this registration statement about our reserves as of June 30, 2014 and 2013, is based on reports prepared by CGA. The estimates of 100% of our proved reserves at June 30, 2014, and 2013, 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

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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 22, 2014 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.

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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.

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, 2014, 2013 and 2012. 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.

Production, Price and Cost Data. The following table sets forth summary production and operating data for the years ended June 30, 2014 and 2013. Unless stated otherwise, revenue and production data with respect to natural gas include NGL revenue and NGL production data, respectively.

	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)(1)		1,178,350		34,098		1,212,448
Total (Boe)		443,467		5,761		449,228
Average daily sales volumes:
Oil (Bbls)		677		0.2		677
Natural Gas (Mcf)(1)		3,228		93		3,321
Total (Boe)		1,215		16		1,231
Average prices:
Oil (per Bbl)	$	95.37	$	88.90
Natural Gas (per Mcf)(1)	$	4.78	$	4.44
Total (per Boe)	$	65.84	$	29.02
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)		294,046		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
Natural Gas (per Mcf)(1)	$	4.80	$	3.05
Total (per Boe)	$	64.46	$	19.64
Average costs (per Boe):
Production costs:
Lease operating expense	$	5.68	$	22.52	$	6.05
Production taxes	$	3.25	$	1.02	$	3.20

(1) Natural gas reserves are shown in “wet” Mcf, which includes NGL.

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Productive Wells. The following table sets forth information at June 30, 2014, 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		91		0		91		37.18		0		37.18

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		8,080		3,346		125,173		60,742

(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, 2014 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 14,500 gross undeveloped acres and approximately 6,200 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.

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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 September 30, 2014.

	Acres Expiring (1)
	Paradox
	Gross		Net
Period Ending December 31:
2015		6,231		2,753
2016		6,060		2,959
2017		2,197		493
Total		14,488		6,205

(1) Acres expiring are based on lease terms.

With respect to the leases subject to expiration during Fiscal 2015, 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 Fiscal 2015 planned activities 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, 2014, 2013 and 2012, 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,
	2014		2013		2012
Gross:
Development
Productive		24		40		23
Dry		0		0		0
Total		24		40		23
Exploratory
Productive		0		0		0
Dry		0		0		0
Total		24		40		23
Net:
Development
Productive		9.78		16.90		9.64
Dry		0		0		0
Total		9.78		16.90		9.64
Exploratory
Productive		0		0		0
Dry		0		0		0
Total		9.78		16.90		9.64

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Present Activities. The following table sets forth information about our wells that were in the process of being drilled as of June 30, 2014:

	June 30, 2014
Gross:
Development		4.0
Exploratory		2.0
Total		6.0
Net:
Development		1.68
Exploratory		0.70
Total		2.38

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 interest, 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, 2014 oil and natural gas production representing approximately 50% of our total revenues was sold to High Sierra Crude Oil & Marketing, LLC, and oil and natural gas production representing approximately 30% 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.

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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.

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. See section entitled “Item 6. Executive Compensation – Colin Watt.” As of June 30, 2014, Squall had 4 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 90% of our wells in the Midland Basin (Wolfberry), and is the operator of both the Mitchell Ranch Project and Paradox Basin Project.

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.

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

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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 statues, 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:

• the location of wells;

• the method of drilling and casing wells;

• the method and ability to fracture stimulate wells;

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

• the plugging and abandoning of wells; and

• 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

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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 it 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.

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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 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 Natural Gas Policy Act of 1978. 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 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.

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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:

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

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

• 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;

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

• 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, 2014. Additionally, we are not aware of any environmental issues or claims that will require material capital expenditures during fiscal 2015. 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 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.

Comprehensive Environmental Response, Compensation and Liability Act (the “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 the current and past owner or operator of the site where the release occurred and anyone who disposed or arranged for the disposal of

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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 permits from the EPA or 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

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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 Texas Railroad Commission, 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 November 2011, the EPA announced its intent to develop and issue regulations under the federal Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and continues to project the issuance of an Advance Notice of Proposed Rulemaking that would seek public input on the design and scope of such disclosure regulations but it does not state a deadline for such issuance. 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 government 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. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a draft report drawing conclusions about hydraulic fracturing on drinking water resources expected to be available for public comment and peer review in 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards for shale gas in 2014. Also, in May 2013, the BLM published a revised supplemental notice of proposed rulemaking governing hydraulic fracturing on federal and Indian oil and gas leases that would require public disclosure of chemicals used in hydraulic fracturing, confirmation that wells used in fracturing operations meet appropriate construction standards, and development of appropriate plans for managing flowback water that returns to the surface. 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.

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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 regards 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. 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 potential 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 GHGs in excess of applicable threshold levels. The EPA has also adopted rules requiring the reporting of GHG emissions on an annual basis from specified GHG emission sources in the United States, including certain oil and natural gas production facilities, which includes certain of our facilities. We are monitoring GHG emissions from our operations in accordance with these GHG emissions reporting rules and believe our monitoring activities are in substantial compliance with applicable reporting obligations.

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

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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. For example, on March 27, 2014, the FWS announced the listing of the lesser prairie chicken, whose habitat is over a five-state region, including Texas, where we conduct our operations, as a threatened species under the ESA. However, the FWS also announced a final rule that will limit regulatory effects on landowners and businesses from the listing if those landowners and businesses have entered into certain range-wide conservation planning agreements, such as those developed by the Western Association of Fish and Wildlife Agencies, pursuant to which such parties agreed to take steps to protect the lesser prairie chicken’s habitat and to pay a mitigation fee if its actions harm the lesser prairie chicken’s habitat. The designation of previously unprotected species, including the lesser prairie chicken, as threatened or endangered in areas where we operate 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 statues 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.

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Item 1A. Risk Factors.

Investing in our common stock involves risks. You should carefully consider the information in this Registration Statement, including the matters addressed under “Cautionary Statement Regarding Forward-Looking Statements,” and the following risks before making an investment decision. The trading price of our common stock could decline due to any of these risks, and you may lose all or part of your investment.

Risks Related to Our Business

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 the following:

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

• the price and quantity of foreign imports;

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

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

• the level of global exploration and production;

• the level of global inventories;

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

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

• localized and global supply and demand fundamentals and transportation availability;

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

• weather conditions and other natural disasters;

• technological advances affecting energy consumption;

• the price and availability of alternative fuels;

• expectations about future commodity prices; and

• 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. Through December 15, 2014, the West Texas Intermediate posted price had declined from a high of $107.95 per Bbl on June 20, 2014 to

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$55.91 per Bbl on December 15, 2014. In addition, the Henry Hub spot market price had declined from a high of $8.15 per MMBtu on February 10, 2014 to $3.719 per MMBtu on December 15, 2014. 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. 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.

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 2015 capital budget for drilling, completion, recompletion and infrastructure is approximately $34 million. Our capital budget excludes acquisitions. We expect to fund 2014 capital expenditures with cash generated by operations, borrowings under our revolving credit facility and possibly through asset sales or additional capital market transactions. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, 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:

• our proved reserves;

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

• the prices at which our production is sold;

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

• 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.

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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:

• landing our wellbore in the desired drilling zone;

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

• running our casing the entire length of the wellbore; and

• 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:

• the ability to fracture stimulate the planned number of stages;

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

• 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 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 “Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of 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 the following:

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

• pressure or irregularities in geological formations;

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

• equipment failures or accidents;

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

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• lack of available capacity on interconnecting transmission pipelines;

• adverse weather conditions;

• issues related to compliance with environmental regulations;

• 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;

• declines in oil and natural gas prices;

• limited availability of financing at acceptable terms;

• title problems; and

• 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:

• actual prices we receive for oil and natural gas;

• actual costs of development and production expenditures;

• the amount and timing of actual production;

• supply of and demand for oil and natural gas; and

• 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

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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 Registration Statement 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 restricts our ability to dispose of assets and 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.

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:

• incur additional indebtedness;

• make loans to others;

• make investments;

• merge or consolidate with another entity;

• make certain payments;

• hedge future production or interest rates;

• incur liens;

• sell assets; and

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

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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 as a result of the periodic borrowing base redeterminations or otherwise 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, which the lenders, in their sole discretion, determine 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.

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 respective 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.

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

We irregularly enter into derivative instrument contracts for a portion of our oil production. We are not currently party to any hedging contracts. To the extent we enter into any hedging contracts in the future, 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:

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

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

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

• 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

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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.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves.

In order to prepare reserve estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. For instance, initial production rates reported by us or other operators may not be indicative of future or long-term production rates, our recovery efficiencies may be worse than expected, and production declines may be greater than we estimate and may be rapid and irregular when compared to initial production rates. In addition, we may adjust reserve estimates to reflect production history, results of exploration and development, existing commodity prices and other factors.

You should not assume that the present value of future net revenues from our reserves is the current market value of our estimated reserves. We generally base the estimated discounted future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate.

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. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, 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.

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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.

All of our producing properties are geographically concentrated in the Permian Basin of West Texas. At June 30, 2014, 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

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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 estimated proved undeveloped reserves (“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, 2014, approximately 46% 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. Management has 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

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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 a permit 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 U.S. Environmental Protection Agency (“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 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.

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Our exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

• 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;

• abnormally pressured formations;

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

• fires, explosions and ruptures of pipelines;

• personal injuries and death;

• natural disasters; and

• 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:

• injury or loss of life;

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

• pollution and other environmental damage;

• regulatory investigations and penalties;

• suspension of our operations; and

• 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:

• unexpected drilling conditions;

• title problems;

• pressure or lost circulation in formations;

• equipment failure or accidents;

• adverse weather conditions;

• compliance with environmental and other governmental or contractual requirements; and

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• 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

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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 “Business—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 “Business—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 permits for certain large stationary sources. 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

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sources in the United States on an annual basis, which include certain of our operations. We are monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule and believe that our monitoring activities are in substantial compliance with applicable reporting obligations.

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. In addition, in 2013 the Obama administration announced its Climate Action Plan, which, among other things, directs federal agencies to develop a strategy for the reduction of methane emissions, including emissions from the oil and natural gas industry. 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, but the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act (“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 using diesel fuels. In May 2014, the EPA issued an Advanced Notice of Proposed Rulemaking, seeking comment on the development of regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Also, in May 2013, the BLM published a revised proposed rule that would impose requirements for hydraulic fracturing activities on federal lands, including new requirements relating to public disclosure, as well as well bore integrity and handling of flowback water. In addition, Congress has from time to time considered 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. It is unclear how any federal disclosure requirements that add to any applicable state disclosure requirements already in effect may affect our operations.

We may be subject to regulations that restrict our ability to discharge water produced as part of our production operations, and the ability to use injection wells as a disposal option not only will depend on federal or state regulations but also on whether available injection wells have sufficient storage capacities. For example, the EPA is developing effluent limitation guidelines that may impose federal pre-treatment standards on all oil and natural gas operators transporting wastewater associated with hydraulic fracturing activities to publicly owned treatment works for disposal. The EPA plans to propose such standards by late 2014.

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Further, in April 2012, the EPA published final rules that subject all oil and natural gas operations (production, processing, transmission, storage and distribution) to regulation under the New Source Performance Standards (“NSPS”) and the National Emission Standards for Hazardous Air Pollutants (“NESHAPS”) programs. These rules became effective in October 2012 and include NSPS standards for completions of hydraulically-fractured gas wells. The standards include the reduced emission completion techniques developed in the EPA’s Natural Gas STAR program along with pit flaring of gas not sent to the gathering line. The standards are applicable to newly drilled and fractured wells and wells that are refractured on or after January 1, 2015. Further, the rules under NESHAPS include Maximum Achievable Control Technology (“MACT”) for glycol dehydrators and storage vessels at major source of hazardous air pollutants not currently subject to MACT standards. The EPA received numerous requests for reconsideration of these rules and court challenges were also filed. The EPA intends to issue revised rules that are likely responsive to some of these requests. For example, in September 2013 the EPA published an amendment extending compliance dates for certain storage vessels. At this point, we cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty.

Certain governmental reviews have been conducted or are underway that focus on the potential environmental effects of hydraulic fracturing. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on water resources and expects to make the final report available for public comment and peer review by late 2014. 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 Texas Railroad Commission 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. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, 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

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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:

• increased responsibilities for our executive level personnel;

• increased administrative burden;

• 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

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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:

• 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 will file all required income tax returns and believes that it will be 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 2015 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

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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 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 CRTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. In its rulemaking under the Dodd-Frank Act, the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide derivative transactions would be exempt from these position limits. The position limits rule was vacated by the United States District Court for the District of Columbia in September of 2012 although the CFTC has stated that it will appeal the District Court’s decision. The CFTC also has finalized other regulations, including critical rulemakings on the definition of “swap,” “security-based swap,” “swap dealer” and “major swap participant.” The Dodd-Frank Act and CFTC rules also will require us in connection with certain derivatives activities to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption to such requirements). In addition, new regulations may require us to comply with margin requirements although these regulations are not finalized and their application to us is uncertain at this time. Other regulations also remain to be finalized, and the CFTC recently has delayed the compliance dates for various regulations already finalized. As a result, it is not possible at this time to predict with certainty the full effects of the Dodd-Frank Act and CFTC rules on us and the timing of such effects. The Dodd-Frank Act also may require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of derivative contracts and reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and CFTC rules, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our 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. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and CFTC rules is to lower commodity

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prices. Any of these consequences could have a material and adverse effect on us, our financial condition or our results of operations.

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.

Risks Related to our Common Stock

The requirements of being a public company, including compliance with the reporting requirements of the Exchange Act and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management.

We will incur significant legal, accounting and other expenses that we did not incur before we were required to register under the Exchange Act. We will also incur costs associated with our U.S. public company reporting requirements and with corporate governance requirements, including requirements under the Sarbanes-Oxley Act of 2002, as well as rules implemented by the SEC and the Financial Industry Regulatory Authority. These rules and regulations will increase our legal and financial compliance costs and make some activities more time-consuming and costly, and we expect that these costs may increase further after we are no longer an “emerging growth company.” These rules and regulations make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our Board or as executive officers.

However, for as long as we remain an “emerging growth company” as defined in the JOBS Act, we intend to take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies, including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and stockholder approval of any golden parachute payments not previously approved. We intend to take advantage of these reporting exemptions until we are no longer an emerging growth company.

We will remain an emerging growth company for up to five years, although if we have more than $1 billion of revenues in a fiscal year, if the market value of our common stock that is held by non-affiliates exceeds $700 million, or if we issue more than $1 billion of non-convertible debt over a three-year period, we would cease to be an “emerging growth company.”

After we are no longer an “emerging growth company,” we expect to incur significant additional expenses and devote substantial management effort toward ensuring compliance with those requirements applicable to companies that are not emerging growth companies.

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If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential stockholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common stock.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We have had to restate our financial statements in the past and may have to do so again in the future if we fail to maintain effective internal controls over financial reporting. For example, after the issuance of our consolidated financial statements for the years 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 financial statements to correct the error. In connection with this restatement, we determined that we had a material weakness as of June 30, 2014, namely that our controls over the evaluation and review of our deferred income taxes were not effective. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common stock.

The market price of our common stock may be volatile.

The market price of our common stock could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock.

The following factors could affect our stock price:

• our operating and financial performance and drilling locations, including reserve estimates;

• quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;

• the public reaction to our press releases, our other public announcements and our filings with the SEC;

• strategic actions by our competitors;

• changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts;

• speculation in the press or investment community;

• the failure of research analysts to cover our common stock;

• sales of our common stock by us, the selling stockholders or other stockholders, or the perception that such sales may occur;

• changes in accounting principles, policies, guidance, interpretations or standards;

• additions or departures of key management personnel;

• actions by our stockholders;

• general market conditions, including fluctuations in commodity prices;

• domestic and international economic, legal and regulatory factors unrelated to our performance; and

• the realization of any risks described under this “Risk Factors” section.

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The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against us, could result in very substantial costs, divert our management’s attention and resources and harm our business, operating results and financial condition.

Certain of our executive officers, directors and principal shareholders may be able to exercise significant influence over matters subject to shareholder approval.

An affiliate of one of our directors, Derek Michaelis, beneficially owned approximately 17.06% of our outstanding common shares as of October 22, 2014. Accordingly, Mr. Michaelis, either alone or in combination with other executive officers and directors, together with their respective affiliates, if they act together, may be able to exercise influence over matters requiring shareholder approval, including the election of directors and approval of corporate transactions, such as a merger or other sale of our company or its assets, for the foreseeable future. This concentration of ownership could have the effect of delaying or preventing a change in our control or otherwise discouraging a potential acquirer from attempting to obtain control of us, which in turn could have a material adverse effect on the market value of our common shares. For information regarding the ownership of our outstanding common shares by our executive officers and directors and their affiliates, please see “Item 4. Security Ownership of Certain Beneficial Owners and Management.”

We do not intend to pay cash dividends on our common stock, and our revolving credit facility places certain restrictions on our ability to do so. Consequently, your only opportunity to achieve a return on your investment is if the price of our common stock appreciates.

We do not plan to declare cash dividends on shares of our common stock in the foreseeable future. Additionally, our revolving credit facility places certain restrictions on our ability to pay cash dividends. Consequently, your only opportunity to achieve a return on your investment in us will be if you sell your common stock at a price greater than you paid for it.

Future sales of our common stock in the public market could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

We may sell additional shares of common stock in public offerings. We may also issue additional shares of common stock or convertible securities. We have 130,198,411 shares of common stock outstanding, 5,710,000 shares of common stock reserved for issuance upon the exercise of stock options, 7,500,000 shares of common stock reserved for issuance upon the exercise of share purchase warrants, and 12,000 shares of common stock reserved for issuance upon the exercise of finder’s warrants.

We cannot predict the size of future issuances of our common stock or securities convertible into common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.

We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.

Our notice of articles authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as the Board may determine. The terms of one or more classes or series of preferred stock could adversely affect the voting power or value of our common stock. For example, we might grant holders of

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preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock. However, we are not permitted to issue any preferred stock without the approval of the TSX Venture Exchange on which our common stock is listed.

For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.

In April 2012, President Obama signed into law the JOBS Act. We are classified as an “emerging growth company” under the JOBS Act. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things: (i) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act; (ii) comply with any new requirements adopted by the Public Company Accounting Oversight Board requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; (iii) provide certain disclosure regarding executive compensation required of larger public companies; or (iv) hold nonbinding advisory votes on executive compensation. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1 billion of revenues in a fiscal year, have more than $700 million in market value of our common stock held by non-affiliates, or issue more than $1 billion of non-convertible debt over a three-year period.

To the extent that we rely on any of the exemptions available to emerging growth companies, you will receive less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies. If some investors find our common stock to be less attractive as a result, there may be a less active trading market for our common stock and our stock price may be more volatile.

If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our common stock or if our operating results do not meet their expectations, our stock price could decline.

The trading market for our common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our common stock or if our operating results do not meet their expectations, our stock price could decline.

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Item 2. Financial Information.

Selected Historical Consolidated Financial Information

The selected historical consolidated financial information set forth below as of and for each of the three months ended September 30, 2014 and 2013 and the years ended June 30, 2014 and 2013 has been derived from our condensed consolidated interim financial statements and our audited consolidated financial statements, respectively. As discussed in note 17 in the Notes to the Consolidated Financial Statements for the Year Ended June 30, 2014, included in this Amendment No. 1 to the Registration Statement, we are amending and restating our audited financial statements and related disclosures for the years ended June 30, 2014 and June 30, 2013. The discussion and analysis of the financial condition and results of operations incorporates the restated amounts. For this reason, the data set forth in this section and in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” may not be comparable to discussion and data in the previously filed, un-amended Registration Statement. The selected historical consolidated financial information is qualified in its entirety by, and should be read in conjunction with, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes and other financial information included in this Registration Statement. Historical results are not necessarily indicative of results that may be expected for any future period.

	Three Months Ended September 30,						Year Ended June 30,
	2014			2013			2014 (Restated)			2013 (Restated)
Revenue
Petroleum and natural gas sales, net of royalties	$	7,934,867		$	8,947,483		$	29,366,595		$	18,953,732
Derivative financial instruments gain (loss)		—			(125,405	)		(63,633	)		15,163
Interest income		37,826			671			89,990			12,573
Total revenues		7,972,693			8,822,749			29,392,952			18,981,468
Expenses
Production and operating expenses		(1,324,362	)		(1,048,414	)		(4,949,932	)		(3,019,360	)
Depletion, depreciation and accretion		(2,679,020	)		(1,978,896	)		(7,917,230	)		(5,931,851	)
Exploration		(1,568	)		(1,062	)		(253,504	)		(278,457	)
Foreign exchange gain (loss)		546			(1,195	)		(5,835	)		(52,030	)
General and administrative		(374,284	)		(252,755	)		(1,384,587	)		(1,689,720	)
Impairments		(449,541	)		—			—			—
Interest		(189,995	)		(39,586	)		(283,183	)		(260,974	)
Total expenses		(5,018,224	)		(3,321,908	)		(14,794,271	)		(11,232,392	)
Other Income
Gain on disposition of property, plant and equipment		—			—			10,219,755			11,255,320
Income before income taxes		2,954,469			5,500,841			24,818,436			19,004,396
Income tax expense (recovery)		1,319,000			1,862,900			9,414,785			7,269,852
Net income		1,635,469			3,637,941			15,403,651			11,734,544
Other comprehensive income (loss)
Foreign currency translation reserve		(537,227	)		13,068			(352,602	)		128,387
Total comprehensive income for the year	$	1,098,242		$	3,651,009		$	15,051,049		$	11,862,931
Weighted average number of Common shares outstanding
Basic		129,609,199			111,639,100			123,798,574			110,138,794
Diluted		134,674,198			117,342,007			126,814,887			113,483,138
Net earnings per common share
Basic	$	0.01		$	0.03		$	0.12		$	0.11
Diluted	$	0.01		$	0.03		$	0.12		$	0.10

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	As of September 30,		As of June 30,
	2014		2014		2013
Balance Sheet Data:
Cash and cash equivalents	$	13,469,859	$	13,955,890	$	1,874,400
Property, plant and equipment		98,661,271		91,812,527		73,984,820
Total assets		115,268,713		109,111,434		78,471,594
Shareholders’ equity		73,998,433		72,763,993		44,996,987

	Three Months Ended September 30,				Year Ended June 30,
	2014		2013		2014		2013
Statement of Cash Flows Data:
Capital expenditures	$	11,724,501	$	10,145,218	$	34,235,029	$	56,167,297
Net cash provided by (used in):
Operating activities	$	6,035,016	$	6,143,786	$	21,758,744	$	11,096,363
Investing activities		11,724,501		10,145,218		13,431,117		31,088,315
Financing activities		5,686,198		4,981,202		3,910,274		12,403,233

Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our results of operations and financial condition should be read in conjunction with (i) our audited financial statements for the fiscal years ended June 30, 2014 and 2013, and the notes thereto and (ii) the section entitled “Item 1. Business”, included elsewhere in this Registration Statement. Our consolidated financial statements are prepared in accordance with U.S. GAAP. All references to dollar amounts in this section are in U.S. dollars unless expressly stated otherwise. The following discussion contains forward-looking statements that involve numerous risks and uncertainties. Our actual results could differ materially from the forward-looking statements as a result of these risks and uncertainties. See “Cautionary Statement Regarding Forward-Looking Statements” for additional cautionary information.

Overview

We are an independent oil and natural gas partnership engaged in the acquisition, development, exploitation and exploration of oil and natural gas properties. Our operations are primarily focused in Texas and Utah. We intend to grow our reserves and production through development drilling, and exploitation and exploration activities on our lease holdings.

Our core properties are in the Wolfberry play in the Midland Basin of the Permian Basin, West Texas. The Permian Basin of West Texas is characterized by an extensive production history, predominately oil-focused drilling targets, abundant infrastructure, wells with long reserve lives and multiple oil and natural gas producing stratigraphic horizons. The Wolfberry play is a modification and extension of the Spraberry play, the majority of which is designated in the Spraberry Trend Area field. According to the Energy Information Administration of the U.S. Department of Energy, as of 2009, the Spraberry Trend Area ranked as the second largest oilfield in the United States by proved reserves and the fourth for estimated oil production. Based on the results of our drilling to date and our observation of the activity and results of other operators in this area, we believe the Wolfberry play represents one of the premier oil and gas development opportunities in North America.

Our other properties are located in other parts of the Permian Basin of West Texas and the Paradox Basin of Utah.

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Outlook

We have taken advantage of a robust market for proved reserves and sold portions of our held-by-production Wolfberry play acreage during Fiscal 2013 and 2014. See “—Selected Factors that Affect our Operating Results—Significant Divestitures” for more information on divestitures that we made during Fiscal 2013 and 2014. In the near term, we will be focused on perpetuating leases by satisfying the continuous development provisions of such leases. A major strategy for our sales of the producing acreage is to maintain adequate capital that, along with cash flows from operations and borrowing capacity under our credit facility, ensures that we have the financial resources to drill enough wells to perpetuate substantially all of the net acres scheduled in our latest reserve report. We currently own or hold more than 30% of our Midland Basin acreage by production. See “Item 1. Business—Properties—Selected Oil and Natural Gas Information—Leasehold Acreage” for additional discussion of the continuous development provisions of our leases.

Selected Factors That Affect Our Operating Results

Our revenue, cash flow from operations and future growth depend substantially upon (i) the prices and demand for crude oil, NGL and natural gas, (ii) the quantity of our oil, NGL and natural gas production, and (iii) the level of our operating expenses. All of the Company’s production is unhedged.

(a) Commodity Prices

Our results of operations are heavily influenced by commodity prices. Factors that may affect commodity prices, including the price of oil 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

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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. The following table sets forth the average NYMEX oil and natural gas prices for the nine months ended September 30, 2014, and the years ended December 31, 2013, 2012 and 2011, as well as the high and low NYMEX price for the same periods:

	Nine Months Ended September 30, 2014		Year Ended December 31,
			2013		2012		2011
Average NYMEX prices:
Oil (Bbl)	$	99.62	$	98.05	$	94.15	$	95.11
Natural gas (MMBtu)	$	4.41	$	3.73	$	2.83	$	4.03
High and low NYMEX prices:
Oil (Bbl):
High	$	107.26	$	110.53	$	109.77	$	113.93
Low	$	91.16	$	86.68	$	77.69	$	75.67
Natural gas (MMBtu):
High	$	6.15	$	4.46	$	3.90	$	4.85
Low	$	3.75	$	3.11	$	1.91	$	2.99

Recently, oil and natural gas prices have declined significantly. Through December 15, 2014, the West Texas Intermediate posted price had declined from a high of $107.95 per Bbl on June 20, 2014 to $55.91 per Bbl on December 15, 2014. In addition, the Henry Hub spot market price had declined from a high of $8.15 per MMBtu on February 10, 2014 to $3.719 per MMBtu on December 15, 2014. 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. 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.

Please see “Item 1A. 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,” “—Any significant reduction in our borrowing base under our revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively affect our ability to fund our operations,” and “—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, we will be required to take write-downs of the carrying values of our properties” for more information.

(b) Reserves

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

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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.

(c) Operating Expenses

Operating expenses are the costs incurred in the operation of producing properties. Expenses for utilities, direct labor, water injection and disposal, production taxes, repairs and materials and supplies comprise the most significant portion of our operating expenses. A majority of our operating cost components are variable and increase or decrease as the level of production increases or decreases. Certain items, however, such as direct labor and materials and supplies, generally remain relatively fixed and do not fluctuate with changes in production volumes, but can fluctuate depending on activities performed during a specific period. In evaluating our operations, we monitor and assess our operating expenses, in terms of absolute dollars and on a per Boe basis. We believe that this measure allows us to better evaluate our operating efficiency, and we use it in reviewing the economic feasibility of a potential acquisition or development project

(d) Significant Divestitures

We regularly review our asset base to assess the market value versus holding value of existing assets, with a view to optimizing deployed capital. While we generally do not dispose of assets solely for the purpose of reducing debt, such dispositions can have the result of furthering our objective of increasing financial flexibility through reduced debt levels.

Effective December 1, 2012 we disposed of 16 gross (7.0 net) Wolfberry Project wells and underlying leases covering approximately 1,440 gross acres (630 acres net) to BreitBurn Energy Partners L.P. of Los Angeles, California for gross proceeds of $25.1 million.

Effective December 30, 2013 the Company 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. for gross proceeds of $19.3 million (the “BreitBurn Sale”).

Three Months Ended September 30, 2014 (“Q1/2015”) Compared to Three Months Ended September 30, 2013 (“Q1/2014”)

Results of Operations

The Company reported net earnings of $1,635,469 (Q1/2014 - $3,637,941) and total comprehensive income of $1,098,242 (Q1/2014 - $3,651,009) for Q1/2015. Significant components of Q1/2015 net earnings were revenues of $7,972,693, depletion and depreciation of $2,679,020, and income tax expense of $1,319,000. The Company’s net earnings per common share were $0.01 (Q1/2014 - $0.03).

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P&NG Revenue

The Company reported net P&NG revenues of $7,934,867 (Q1/2014 - $8,947,483) for Q1/2015. The Company incurred production and operating expenses of $1,324,362 (Q1/2014 - $1,048,414) for Q1/2015. The Company also incurred $2,679,020 (Q1/2014 - $1,978,896) of depletion and depreciation for Q1/2015.

	Three Months ended September 30,
	2014			2013
Net Revenues
Petroleum revenue	$	6,248,076		$	7,867,640
Natural gas revenue		683,538			564,298
Natural gas liquids revenue		1,003,253			515,545
		7,934,867			8,947,483
Production and operating expenses		(1,324,362	)		(1,048,414	)
Net back	$	6,610,505		$	7,899,069
Production Volumes and Pricing
Net volumes
Petroleum production (bbl)		72,402			78,256
Natural gas production (mcf)		169,821			174,022
Natural gas liquids production (bbl)		30,305			16,058
Barrel of oil equivalent (boe)		131,010			123,317
Daily production averages
Petroleum (bblpd)		787			851
Natural gas (mcfpd)		1,846			1,892
Natural gas liquids (bblpd)		329			175
Barrel of oil equivalent (boepd)		1,424			1,340
Average prices
Petroleum selling price ($/bbl)	$	86.30		$	100.54
Natural gas selling price ($/mcf)	$	4.03		$	3.24
Natural gas liquids selling price ($/bbl)	$	33.11		$	32.11
Barrel of oil equivalent selling price ($/boe)	$	60.57		$	72.56
Average costs
Lease operating expense ($/boe)	$	7.16		$	4.96
Production taxes ($/boe)	$	2.95		$	3.54

Petroleum and natural gas net revenues decreased $1,012,616 in Q1/2015 compared to Q1/2014 as result of a $1,619,564 decrease in petroleum revenue, partially offset by a $119,240 increase in natural gas revenue and a $487,708 increase in natural gas liquids revenue. On a percentage of revenue basis, Q1/2015 petroleum revenue accounted for 79% of total petroleum and natural gas revenues, with natural gas accounting for 9% and natural gas liquids accounting for 12%.

The $1,619,564 decrease in petroleum revenue was the result of a 7% decrease in the volume of petroleum production and a 14% decrease in the petroleum selling price.

The $119,240 increase in natural gas revenue was the result of a 24% increase in the natural gas selling price, offset by a 2% decrease in the volume of natural gas production.

The $487,708 increase in natural gas liquids revenue was the result of an 189% increase in the volume of natural gas liquids production and a 3% increase in the natural gas liquids selling price.

The selling price received for oil decreased in the most recent quarter as the price has generally tracked the changes in the price of West Texas Intermediate.

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Production volumes, on a boepd basis, increased by 6% in the current quarter.

As at September 30, 2014, all of the Company’s production is unhedged and will be impacted by fluctuations in the prices of oil and natural gas. The Company did not have any derivative financial instrument gain or losses in Q1/2015 as a result of being unhedged. Oil price hedging in Q1/2014 resulted in a $125,405 loss in that period.

Production and operating expenses were $275,948 (26%) higher in Q1/2015 compared to Q1/2014. Approximately 29% of production and operating expenses in Q1/2015 are related to production and ad valorem taxes which are directly related to production volumes and commodity prices, as compared to 42% in Q1/2014. The balance of production and operating expenses relate to lease operating costs, which costs include workovers and salt water disposal costs. The increase in these expenses was due to the increase in the numbers of wells in service in Q1/2015 (95 gross wells at September 30, 2014) compared to the number of wells in service in Q1/2014 (76 gross wells at September 30, 2013).

Depletion

Depletion of proved oil and natural gas properties was $2,672,872 for Q1/2015, an increase of $698,989 (35%) from $1,973,883 for Q1/2014. The increase in depletion expense was primarily due to the capitalized costs associated with new vertical wells that were successfully drilled and completed in 2013 and 2014 offset by the sale of producing oil and natural gas properties in December 2013 and increases in the oil and natural gas prices between the periods utilized to determine proved reserves.

Impairments

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 during 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 has expensed the remaining costs of $449,541 in Q1/2015.

General and Administrative

The Company’s general and administrative expenditures are related to the level of financing and exploration, development, and production activities that are being conducted, which may in turn depend on the Company’s recent exploration, development, and production activities and prospects, as well as general market conditions relating to the availability of funding for early stage exploration and development natural resource companies. Thus, there may not be predictable or observable trends in the Company’s business activities and comparisons of financial operating results with prior years may not be meaningful.

General and administrative expenses were $374,284 (Q1/2014 - $252,755) during Q1/2015. Some of the differences in expenditures were as follows:

• Administrative and management fees have increased by $30,618 during Q1/2015 over Q1/2014 primarily due to the growth and increased complexity of the Company’s business activities.

• Consulting fees have increased by $19,903 during Q1/2015 over Q1/2014 primarily due to the timing of costs incurred for the Company’s reserve engineering.

• Professional fees have increased by $70,903 during Q1/2015 over Q1/2014 primarily due to additional legal fees incurred for the registration of the Company’s securities with U.S. Securities and Exchange Commission.

• Promotion and travel increased by $14,298 and $9,107 respectively during Q1/2015 as additional efforts were made to introduce the Company to potential new shareholders.

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• Share-based payments were $nil (Q1/2014 - $28,149) in Q1/2015. The Company granted nil (Q1/2014 - nil) stock options in Q1/2015. The Company uses the Black-Scholes method to determine fair value for all share-based awards. The Company grants share options on a periodic basis in order to provide non-cash compensation to its directors, officers, employees and consultants and to align the interests of the directors, officers, employees and consultants with the interests of shareholders.

The Company anticipates significant increases in its general and administrative costs for the registration of the Company’s securities with the SEC, and for subsequent ongoing reporting obligations with the SEC. In particular, the Company anticipates higher legal, accounting and consulting fees.

Foreign Currency Translation

The foreign exchange gain of $546 (Q1/2014 – loss of $1,195) included in net earnings for Q1/2015 primarily relates to Lynden Energy Corp. translating United States dollar transactions into Canadian dollars at exchange rates prevailing on the transaction dates.

The foreign currency translation loss of $537,227 (Q1/2014 – gain of $13,068) included in other comprehensive income for Q1/2015 relates primarily to translating Lynden Energy Corp.’s and Lynden Exploration Ltd.’s net assets denominated in Canadian dollars into the United States dollar. Lynden Energy Corp.’s and Lynden Exploration Ltd.’s functional currency is the Canadian dollar.

Income taxes

The Company has estimated income tax expense of $1,319,000 (Q1/2014 - $1,862,900) for Q1/2015. Of this amount, $1,123,000 represents deferred tax expense (Q1/2014 - $1,783,900). The deferred tax liabilities are mainly due to the lower tax carrying values for the Company’s property, plant and equipment compared to the accounting carrying values. This is due to recognizing more depreciation for tax purposes compared to depreciation for accounting purposes.

Year Ended June 30, 2014 (“Fiscal 2014”) Compared to Year Ended June 30, 2013 (“Fiscal 2013”)

Results of Operations

The Company reported net income of $15,403,651 (Fiscal 2013 - $11,734,544) and total comprehensive income of $15,051,049 (Fiscal 2013 - $11,862,931) for Fiscal 2014. Significant components of Fiscal 2014 net earnings were revenues of $29,392,952, gain on disposition of property, plant and equipment of $10,219,755 and depletion, depreciation and accretion of $7,917,230 and income tax expense of $9,414,785. The Company’s net earnings per common share for Fiscal 2014 were $0.12 (Fiscal 2013 - $0.11).

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P&NG Revenue

The Company reported petroleum and natural gas sales, net of royalties of $29,366,595 (Fiscal 2013 - $18,953,732) for Fiscal 2014, the vast majority from its Wolfberry wells. The Company paid production and operating expenses of $4,949,932 (Fiscal 2013 - $3,019,361) for Fiscal 2014. The Company also incurred $7,917,230 (Fiscal 2013 - $5,931,851) of depletion, depreciation and accretion for Fiscal 2014.

	Year ended June 30,
	2014			2013
Net Revenues
Petroleum revenues	$	23,570,733		$	15,563,507
Natural gas revenues		5,795,862			3,390,225
		29,366,595			18,953,732
Production and operating expenses		(4,949,932	)		(3,019,360	)
Net back	$	24,416,663		$	15,934,372
Production Volumes and Pricing(1)
Net volumes
Petroleum production (bbl)		246,167			174,969
Natural gas production (mcf)(2)		1,178,350			706,229
Barrel of oil equivalent (boe)		442,559			292,674
Daily production averages
Petroleum (bblpd)		674			479
Natural gas (mcfpd)(2)		3,228			1,935
Barrel of oil equivalent (boepd)		1,212			802
Average prices
Petroleum selling price ($/bbl)	$	95.75		$	88.95
Natural gas selling price ($/mcf)(3)	$	4.92		$	4.80
Barrel of oil equivalent selling price ($/boe)	$	66.36		$	64.76
Average costs
Lease operating expense ($/boe)	$	7.10		$	6.22
Production taxes ($/boe)	$	3.29		$	3.29

⁽¹⁾ Unless stated otherwise, revenue and production data with respect to natural gas include NGL revenue and NGL production data, respectively.

⁽²⁾ Natural gas reserves are shown in “wet” Mcf, which includes NGL.

⁽³⁾ The natural gas selling price is reflective of the thermal value of the gas and associated products sold.

Petroleum and natural gas net revenues increased $10,412,863 in Fiscal 2014 compared to Fiscal 2013 as result of an $8,007,226 increase in petroleum revenue and a $2,405,637 increase in natural gas revenue. On a percentage of revenue basis, in Fiscal 2014 petroleum revenue accounted for 80% of total petroleum and natural gas revenues, with natural gas accounting for 20%.

The $8,007,226 increase in petroleum revenue was the result of a 41% increase in the volume of petroleum production and a 8% increase in the petroleum selling price.

The $2,405,637 increase in natural gas revenue was the result of a 67% increase in the volume of natural gas production and a 3% increase in the natural gas selling price.

The natural gas selling price realized has remained relatively stable over the past year. The selling price received for oil has increased in Fiscal 2014 as the price has generally tracked the changes in the price of West Texas Intermediate. Production volumes increased significantly in Fiscal 2014 as a result of the tie-in of new Wolfberry wells.

All of the Company’s commodity contracts expired at June 30, 2014. During Fiscal 2014, the Company reported realized losses on derivative financial instruments of $63,633 (Fiscal 2013 - $15,163 gain).

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As at June 30, 2014, all of the Company’s production is unhedged and will be impacted by fluctuations in the prices of oil and natural gas.

Production and operating expenses were $1,930,572 (64%) higher in Fiscal 2014 compared to Fiscal 2013. Approximately 37% of production and operating expenses in Fiscal 2014 are related to production and ad valorem taxes which are directly related to production volumes and commodity prices, as compared to 40% in Fiscal 2013. The balance of production and operating expenses relate to lease operating costs, which costs include workovers and salt water disposal costs. The increase in these expenses was due to the increase in the numbers of wells in service in Fiscal 2014 (91 gross wells at June 30, 2014) compared to the number of wells in Fiscal 2013 (67 gross wells at June 30, 2013).

General and Administrative

The Company’s general and administrative expenditures are related to the level of financing and exploration, development, and production activities that are being conducted, which may in turn depend on the Company’s recent exploration, development, and production activities and prospects, as well as general market conditions relating to the availability of funding for early stage exploration and development natural resource companies. Thus, there may not be predictable or observable trends in the Company’s business activities, and comparisons of financial operating results with prior years may not be meaningful.

General and administrative expenses were $1,384,587 (Fiscal 2013 – $1,689,720) during Fiscal 2014. The Company’s cash general and administrative expenses were higher in Fiscal 2014 than Fiscal 2013, however overall expenses were higher in Fiscal 2013 as a result of significantly greater stock based compensation costs of $650,089 in Fiscal 2013. Stock based compensation costs were $55,683 in Fiscal 2014. The Company did not grant any stock options in Fiscal 2014 (Fiscal 2013 – 1,397,500). The Company uses the Black-Scholes method to determine fair value for all share-based awards. The Company grants share options on an irregular basis in order to provide non-cash compensation to its directors, officers, employees and consultants and to align the interests of the directors, officers, employees and consultants with the interests of shareholders.

The Company anticipates significant increases in its general and administrative costs for the registration of the Company’s securities with the SEC, and for subsequent ongoing reporting obligations with the SEC. In particular, the Company anticipates higher legal, accounting and consulting fees.

Foreign Currency Translation

The foreign exchange loss of $5,835 (Fiscal 2013 - $52,030) included in net earnings for Fiscal 2014 primarily relates to the effect of exchanging Canadian dollars, held by Lynden Energy Corp., to United States dollars and transferring those funds to Lynden USA Inc. The Company exchanged and transferred $100,000 in Fiscal 2014 (Fiscal 2013 - $7,580,000).

The foreign currency translation loss of $352,602 (Fiscal 2013 – gain of $128,387) included in other comprehensive income for Fiscal 2014 relates primarily to translating Lynden Energy Corp.’s and Lynden Exploration Ltd.’s net assets denominated in Canadian dollars into the United States dollar. Lynden Energy Corp.’s and Lynden Exploration Ltd.’s functional currency is the Canadian dollar.

Other Items

During Fiscal 2014, the Company recognized a gain of approximately $9.6 million on the BreitBurn Sale, $288,000 on the sale of Paradox Basin leases, and $305,000 on the disposition of a 10.625% interest in certain Midland Basin wells and leases. During the Fiscal 2013, the Company recognized a gain of approximately $11.3 million on a separate sale of assets to BreitBurn.

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Income taxes

The Company has estimated income tax expense of $9,414,785 (Fiscal 2013 – $7,269,852) for Fiscal 2014. A significant portion of these amounts represent deferred tax expense. The deferred tax liabilities are mainly the result of the lower tax carrying values for the Company’s property, plant and equipment compared to the accounting carrying values, due to recognizing more depreciation for tax purposes compared to depreciation for accounting purposes.

Depletion

Depletion of proved oil and natural gas properties was $7,917,230 for Fiscal 2014, an increase of $1,985,379 (33%) from $5,931,851 for Fiscal 2013. The increase in depletion expense was primarily due to the capitalized costs associated with new vertical wells that were successfully drilled and completed in 2013 and 2014 offset by the sale of producing oil and natural gas properties in December 2013 and increases in the oil and natural gas prices between the periods utilized to determine proved reserves.

Financial Condition, Liquidity and Capital Resources

For the three months ended September 30, 2014

As at September 30, 2014, the Company had working capital of $15,030,074 compared to working capital of $13,947,730 at June 30, 2014. The major component of working capital is cash and cash equivalents of approximately $13.5 million, which includes $11 million of cash and cash equivalents denominated in Canadian dollars.

Major sources of cash during the three months ended September 30, 2014 were 1) $6,035,016 from operating activities; 2) $136,198 from the exercise of 472,500 stock options; and 3) $49,595 of recoveries of exploration and evaluation assets from the Paradox Basin and Mitchell Ranch sales of P&NG.

The major use of cash during the three months ended September 30, 2014 was $11,724,501 spent on exploration and evaluation assets, and development and production assets.

For the year ended June 30, 2014

As at June 30, 2014, the Company had working capital of $13,947,730 compared to a working capital deficiency of $22,439,226 at June 30, 2013. The significant change in working capital is primarily the result of the Credit Facility being classified as a long-term liability as at June 30, 2014 as the Credit Facility was extended to August 2016 during 2014. The major component of working capital is cash and cash equivalents of approximately $14 million, which includes $12 million of cash and cash equivalents denominated in Canadian dollars.

Major sources of cash during fiscal 2014 were 1) $21,758,744 from operating activities; 2) gross proceeds of $20,803,912 from the dispositions of property, plant and equipment; and 3) $12,660,274 from the exercise of 18,770,391 share purchase warrants.

The major uses of cash during fiscal 2014 were 1) $34,235,029 spent on exploration and evaluation assets, and development and production assets; and 2) $8,750,000 of the Credit Facility repaid.

The Company’s wholly owned subsidiary, Lynden USA Inc., has a reducing revolving line of credit (the “Credit Facility”) in an amount up to $100 million (increased from $50 million on February 5, 2014). As at June 30, 2014, and September 30, 2014 the Credit Facility provided a borrowing base of $32 million of which $17.75 million had been drawn at June 30, 2014 and $23.3 million had been drawn at September 30, 2014. There is currently $27.3 million drawn on the Credit Facility. Subsequent to September 30, 2014, the borrowing base was increased to $40 million.

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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, 2014. The Company has pledged its interest in its P&NG and other assets as security for liabilities pursuant to the Credit Facility. Further to amendments to the Credit Facility during the year, 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. The Credit Facility also includes a covenant restricting the payment of dividends and certain other payments from Lynden USA Inc. to the parent company. The restricted net assets of Lynden USA Inc. represent the majority of the Company’s total net assets.

The Company anticipates total capital expenditures in fiscal 2015 (July 1, 2014 to June 30, 2015) of approximately $34 million. Included in the capital budget is the Company’s participation in fifteen Wolfberry wells, five Midland Basin horizontal wells, and four vertical wells on the Mitchell Ranch Project.

The Company continues to carry out an oil and gas vertical well development program on its Midland Basin acreage. The gross cost of a Wolfberry well is currently approximately $2.1 million. The Company’s current plans call for 15 gross (6.26 net) Wolfberry wells to spud in fiscal 2015

(July 1 to June 30, 2015) at an estimated cost to the Company of approximately $15.0 million. Pursuant to the terms of the Midland Basin Participation Agreement with CrownRock, the Company’s funding amount for the 6.26 net wells is equivalent to 7.15 wells.

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

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

The Company is also participating in four new vertical wells over the next several months on the Mitchell Ranch at an estimated total cost to the Company of $3.6 million.

There are currently no major capital expenditures planned for the Paradox Basin Project.

The Company anticipates financing the majority of its capital expenditures through operating revenues, draw downs on the line of credit, and cash on hand.

The Company’s capital budget is subject to change depending upon a number of factors, including 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 and the Company’s financial results.

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

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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.

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 registration statement presents estimates of our proved reserves as of June 30, 2014, and June 30, 2013 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, 2014, was based on unweighted average twelve month West Texas Intermediate posted price of $100.27 per Bbl for oil and a Henry

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Hub spot natural gas price of $4.10 per MMBtu for natural gas. The pricing used for estimates of our reserves as of June 30, 2013, was based on unweighted average twelve month West Texas Intermediate posted price of $91.60 per Bbl for oil and a Henry Hub spot natural gas price of $3.50 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 3. Properties.

For a description of our properties, please see “Item 1. Business—Properties.”

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Item 4. Security Ownership of Certain Beneficial Owners and Management.

The table below presents, as of December 23, 2014, information regarding the beneficial ownership of our common stock with respect to each of our executive officers, each of our directors, each person known by us to own beneficially more than 5% of the common stock, and all of our directors and executive officers as a group. Beneficial ownership is determined under the rules of the Securities and Exchange Commission and generally includes voting or investment power over securities. Each individual or entity named has sole investment and voting power with respect to the common shares indicated as beneficially owned by them, subject to community property laws, where applicable, except where otherwise noted.

Shares of common stock subject to options or warrants that are currently exercisable within 60 days from December 23, 2014 are considered outstanding and beneficially owned by the person holding the options or warrants for the purpose of computing the percentage ownership of that person but are not treated as outstanding for the purpose of computing percentage ownership of any other person.

Name of Beneficial Owner	Amount and Nature of Beneficial Ownership			Percent of Class
Richard Andrews		5,596,500	(1)		4.23	%
Colin Watt		2,917,699	(2)		2.21	%
Robert Bereskin		200,000	(3)		0.15	%
John McLennan		281,250	(4)		0.22	%
Ron Paton		681,250	(5)		0.52	%
Laurie Sadler		83,600	(6)		0.06	%
All Officers and Directors as a Group		9,760,299			7.21	%
John Lovoi		27,387,600	(7)		20.47	%

⁽¹⁾ Includes 2,237,500 stock options held of record by Richard Andrews which are vested and are exercisable into 2,237,500 shares of common stock. The address for Mr. Andrews is Suite 1200, 888 Dunsmuir St., Vancouver, BC V6C 3K4.

⁽²⁾  Includes 2,110,000 stock options held of record by Colin Watt which are vested and are exercisable into 2,110,000 shares of common stock. The address for Mr. Watt is Suite 1200, 888 Dunsmuir St., Vancouver, BC V6C 3K4.

⁽³⁾  Includes 175,000 stock options held of record by Robert Bereskin which are vested and are exercisable into 175,000 shares of common stock. The address for Mr. Bereskin is Suite 1200, 888 Dunsmuir St., Vancouver, BC V6C 3K4.

⁽⁴⁾  Includes 281,250 stock options held of record by John McLennan which are vested and are exercisable into 281,250 shares of common stock. The address for Mr. McLennan is Suite 1200, 888 Dunsmuir St., Vancouver, BC V6C 3K4.

⁽⁵⁾  Includes 581,250 stock options held of record by Ron Paton which are vested and are exercisable into 581,250 shares of common stock. The address for Mr. Paton is 29th Floor, 595 Burrard Street, Vancouver, BC V7X 1J5.

⁽⁶⁾  Includes 75,000 stock options held of record by Laurie Sadler which are vested and are exercisable into 75,000 shares of common stock. The address for Mr. Sadler is Suite 1200, 888 Dunsmuir St., Vancouver, BC V6C 3K4.

⁽⁷⁾  Includes the following limited partnerships which are indirectly controlled by JVL Advisors, LLC, the membership interests of which are substantially owned by John Lovoi, (i) 1,630,627 common stock owned by Asklepios Energy Fund, LP, (ii) 4,597,822 shares of common stock owned by Hephaestus Energy Fund LP, (iii) 9,670,948 shares of common stock owned by Luxiver, LP, (iv) 4,931,449 common shares owned by Navitas Fund, LP, (v) 1,884,574 shares of common stock owned by Panakeia Energy Fund, LP, (vi) 336,658 shares of common stock owned by TJS Energy Fund, LP, (vii) 414,973 shares of common stock owned by Urga, (viii) 235,301 shares of common stock owned by Children’s Energy, LP, (ix) 113,748 shares of common stock owned by LVPV, LP, (x) 1,482,600 warrants which are exercisable into 1,482,600 shares of common stock owned

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by Luxiver, LP and (xi) 2,142,900 warrants which are exercisable into 2,142,900 shares of common stock owned by Navitas Fund, LP. The address for Mr. Lovoi is Suite 550, 10000 Memorial Dr., Houston, Texas 77024.

Item 5. Directors and Executive Officers.

The following table sets forth the names, ages and titles of our directors and executive officers. Richard Andrews has informed the Company of his intention to resign as chairman and as a director effective December 31, 2014. Mr. Andrews does not serve as one of the Company’s independent directors. Following his resignation, Mr. Andrews has agreed to continue to provide the Company with business consulting services.

Name	Age		Position
Richard Andrews		66	Chairman of the Board and Director
Colin Watt		43	President, Chief Executive Officer, Corporate Secretary and Director
Laurie Sadler		70	Chief Financial Officer
Robert Bereskin		72	Director
John McLennan		62	Director
Derek Michaelis		36	Director
Ron Paton		51	Director

Richard Andrews, Chairman of the Board and Director, has served as a member of the Board and as our chairman of the board since April 2008, and as chief executive officer of our subsidiary, Lynden USA Inc., since April, 2008. Mr. Andrews has over 30 years of experience in fundraising and building resource companies, including acting as a consultant to Silver Standard Resources Inc., Conquistador Mines Ltd., Canadian Spirit Resources Inc., Western Copper and Gold Corp. and Victoria Gold Corp.

Colin Watt, President, Chief Executive Officer, Corporate Secretary and Director, has served as a member of the Board and as our president since January 2005, as our chief executive officer since February 2007 and as our corporate secretary since January 2010. Mr. Watt has been the president of Squall Capital Corp., a private Canadian based company which specializes in financing, restructuring and providing management service to early stage public companies, since 1997. Mr. Watt is currently a director of Donnybrook Energy Inc., Donnycreek Energy Inc., Emerita Resources Corp. and Oakham Capital Corp., all of which are listed on the TSX Venture Exchange.

Laurie Sadler, Chief Financial Officer, has served as our chief financial officer since July 2005. Mr. Sadler is a retired Chartered Accountant with extensive experience as a business advisor to public and private companies. Mr. Sadler was a founder and managing partner of the firm Sadler, Weismiller, Spencer, Chartered Accountants (1984-2001) and has a Masters of Business Administration from the University of Western Ontario.

Robert Bereskin, Director, has served as a member of the Board since July 2007. Dr. Bereskin has over 30 years experience in the oil and gas industry, and is currently an Adjunct Professor at the University of Utah. His consulting work over the last dozen years has focused on unconventional gas-bearing shale reservoirs in both the United States and Canada, where he has assisted with several international and domestic exploration/exploitation efforts. Before that, Dr. Bereskin was a manager / scientist with TerraTek Inc. for approximately twelve years, where he was able to investigate reservoirs around the world. Dr. Bereskin began his work in the oil and gas industry with a large, Denver based, exploration and production company, where he was involved in both frontier work in Nevada, Utah and Wyoming, and development efforts in Utah and Wyoming.

John McLennan, Director, has served as a member of the Board since May 2005. Dr. McLennan has worked in geomechanics and petroleum technology companies since receiving his Ph.D. in 1980 (Civil Engineering, University of Toronto). Since then, while with Dowell and Schlumberger Dowell, one focus of his has been on improving stimulation effectiveness by applying rock mechanics principles and new-generation frac simulators. While at TerraTek, and later with Advantek International, he

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became involved with produced water and drill cuttings reinjection, fracpack design, as well as casing design issues related to compaction. Dr. McLennan has authored or co-authored technical manuals on coalbed methane exploitation, underbalanced drilling and underbalanced completions as well as numerous technical papers. He is currently Technical Director of ASRC Energy Service E&P Technology Inc. with its main office in Anchorage, Alaska. Dr. McLennan is currently an associate professor at University of Utah, Department of Chemical Engineering and senior research scientist at Energy & Geoscience Institute, University of Utah.

Derek Michaelis, Director, has served as a member of the Board since September 2013. Since 2005, Mr. Michaelis has been an equity oil & gas analyst with JVL Advisors, LLC, a private energy investment company based in Houston, Texas, and related entities. JVL Advisors, LLC and related entities are significant shareholders of Lynden. Mr. Michaelis holds a B.A. in Economics from Rice University.

Ron Paton, Director, has served as a member of the Board since January 2005. Mr. Paton practices business and securities law as a shareholder with the law firm of Owen Bird Law Corporation based in Vancouver, British Columbia. His clients include private and public companies with domestic and international business interests in a variety of industries. His experience includes advising on equity and debt financings, stock exchange listings, mergers and acquisitions, regulatory compliance, corporate governance and general corporate, commercial and securities law matters. Prior to joining Owen Bird Law Corporation in 2013, Mr. Paton carried on practice with the Vancouver law firm of Maitland & Company for 24 years. He has also served as a director or officer of several junior public and private companies in the resource and other sectors. Mr. Paton received his law degree from the University of British Columbia (LL.B. 1988) and was called to the British Columbia bar in 1989.

Director Qualifications

The board of directors seeks to ensure that the board is composed of members whose particular experience, qualifications, attributes and skills, when taken together, will allow the board to satisfy its oversight responsibilities effectively. More specifically, in identifying candidates for membership on the board, takes into account (1) individual qualifications, such as strength of character, mature judgment and industry knowledge or business experience, and (2) all other factors it considers appropriate, including alignment with our shareholders.

When determining whether our current directors have the experience, qualifications, attributes and skills, taken as a whole, to enable our board to satisfy its oversight responsibilities effectively in light of our business and structure, our board focused primarily on our directors’ contributions to our success in recent years and on the information discussed in the biographies set forth above. With respect to Mr. Colin Watt, our board considered in particular his current role as our president and chief executive officer, his familiarity with our business operations, and his management expertise. With respect to Mr. Richard Andrews, our board considered his familiarity with our business operations, and his experience advising and raising funds for natural resource companies. With respect to Dr. Robert Bereskin, our board considered in particular his general oil gas industry experience and his geological knowledge of the Permian Basin and other oil and gas basins in North America. With respect to Dr. John McLennan, our board considered in particular his general oil and gas industry experience and his knowledge of well completion practices. With respect to Mr. Ron Paton, our board considered in particular his extensive knowledge of Canadian securities matters. With respect to Mr. Derek Michaelis, our board considered in particular his knowledge of capital markets and of oil and gas activities in the Permian Basin.

Other U.S. Directorships

None of our directors are currently, or have been within the past five years, also directors of other issuers with a class of securities registered under Section 12 of the Exchange Act (or which otherwise are required to file periodic reports under the Exchange Act).

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Involvement in Certain Legal Proceedings

On or about April 25, 2013, Functional Technologies Corp. (“FEB”), a British Columbia company, of which Ron Paton was a director, filed a notice of intention to make a proposal to its creditors under the Canada Bankruptcy and Insolvency Act. The initial 30 day creditor protection period was extended by court order on or about May 24, 2013. On June 12, 2013, Mr. Paton resigned as a director with immediate effect. It is Mr. Paton’s understanding that following his resignation, FEB was placed into bankruptcy.

Significant Employees

We have no employees and our officers and directors provide their services on a consulting basis.

Item 6. 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. For the fiscal year ending June 30, 2014, our named executive officers were:

Named Executive Officer	Title
Richard Andrews	Chairman
Colin Watt	Chief Executive Officer
Laurie Sadler	Chief Financial Officer

Summary of Compensation

The following table sets forth all annual and long term compensation for services paid to or earned by the Named Executive Officers during the most recently completed financial year.

Summary Compensation Table

Name and Principal Position During the Financial Year Ended June 30, 2014	Financial Year Ended June 30		Salary ($)		Bonus ($)		Stock Awards ($)		Option Awards ($)		All other compens- ation ($)			Total compens- ation ($)
Richard Andrews		2014		0	$	70,000		0		0	$	182,115	(1)	$	252,115
Chairman
Colin Watt		2014		0		0		0		0		226,059	(2)		226,059
Chief Executive Officer
Laurie Sadler		2014		0		0		0		0		14,946	(3)		14,946
Chief Financial Officer

⁽¹⁾  Paid to Richard Andrews pursuant to the Andrews Agreement, as described in greater detail below.

⁽²⁾  Paid, pursuant to the Watt Agreement as described in greater detail below, to Squall Capital Corp., a company controlled by Colin Watt, for the services provided by Colin Watt and for administrative services provided by several employees of Squall Capital Corp. The amount paid to Squall Capital Corp. was paid in Canadian dollars and is presented in U.S. dollars. This amount was translated at CDN$1= US$0.9341 for the fiscal year ended June 30, 2014.

⁽³⁾  Paid to Timeout Holdings Inc., a private company owned by Mr. Sadler, for fees for acting as the Company’s Chief Financial Officer. The amount was paid to Timeout Holdings Inc. in Canadian dollars and is presented in U.S. dollars. This amount was translated at CDN$1=US$0.9341 for the fiscal year ended June 30, 2014.

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Compensation Discussion and Analysis

Compensation paid to our Named Executive Officers is determined solely based on discussions by the Board. The Board follows a compensation philosophy that aligns the Named Executive Officers’ interests with those of our stockholders and seeks to provide incentives designed to ensure that we attract, retain and motivate key talents in this highly specialized and technical public junior natural resource industry.

The Board believes that a total compensation package including consulting fees and stock options is appropriate in achieving its objectives. We do not have any predetermined performance goals for our Named Executive Officers, but expect each Named Executive Officer to serve the Company and its stockholders to the best of his abilities, putting stockholder interests and value first in his decision making.

Each of the Named Executive Officers is compensated primarily by a consulting fee that is negotiated between the Company and the Named Executive Officer. Stock options are granted to Named Executive Officers to align the Named Executive Officers’ interests with those of the stockholders. The number of stock options granted to each Named Executive Officer is determined solely by the Board and is based on the Named Executive Officer’s performance, his consulting fee, if any, and the Company’s share price at the time these stock options are granted.

The services of Richard Andrews, the chairman of the Board, are provided pursuant to a services agreement (the “Andrews Agreement”) dated January 1, 2013 between Mr. Andrews and the Company. Pursuant to the terms of the Andrews Agreement, Mr. Andrews is paid $15,000 per month, and provided Mr. Andrews has been continuously engaged by the Company during the calendar year, an annual bonus in the amount of $70,000.

The services of Colin Watt, the president, chief executive officer and corporate secretary of the Company, are provided pursuant to a management agreement (the “Watt Agreement”) dated January 1, 2013 between Mr. Watt and the Company. Pursuant to the terms of the Watt Agreement, Squall Capital Corp. is paid up to CDN$20,000 per month, for the services of Colin Watt and for the administrative services provided by several employees of Squall Capital Corp.

The Company pays Timeout Holdings Inc., a private company owned by Laurie Sadler, CDN$1,333.33 per month for providing the services of Laurie Sadler as the Company’s Chief Financial Officer.

Option-based Awards

The Company currently has in place a “rolling” stock option plan. The purpose of granting stock options is to assist the Company in compensating, attracting, retaining and motivating its executive officers and to closely align the personal interests of such persons to that of the stockholders. In determining the number of options to be granted to the executive officers, the Board will take into account the number of options, if any, previously granted to each executive officer and the exercise price of any outstanding options to ensure that such grants are in accordance with the policies of the TSX Venture Exchange.

See “Incentive Plan Awards” below for details of the option-based awards outstanding as at June 30, 2014.

Compensation Governance

The Company does not have a compensation committee. The Board has not adopted any specific policies or practices to determine the compensation for the Company’s directors and executive officers other than as disclosed above.

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Incentive Plan Awards

During the financial year ended June 30, 2014, the Company did not grant any stock options and there were no re-pricings of stock options under the stock option plan or otherwise.

The following table discloses the particulars of the option-based awards granted to the Named Executive Officers under the Company’s stock option plan which were outstanding as at June 30, 2014.

Outstanding Equity Awards At Fiscal Year-End

Name	Number of Securities Underlying Unexercised Options (#) Exercisable		Option Exercise Price (CDN$)		Option Expiration Date
Richard Andrews		350,000 475,000 1,150,000 612,500		0.30 0.55 0.80 0.50	Oct. 7, 2014 Mar. 16, 2015 July 21, 2016 July 2, 2017
Colin Watt		350,000 475,000 97,500 925,000 612,500		0.30 0.55 0.60 0.80 0.50	Oct. 7, 2014 Mar. 16, 2015 July 20, 2015 July 21, 2016 July 2, 2017
Laurie Sadler		50,000 25,000 50,000		0.30 0.55 0.80	Oct. 7, 2014 Mar. 16, 2015 July 21, 2016

The Company currently has in place a 10% “rolling” stock option plan for the purpose of attracting and motivating directors, officers, employees and consultants of the Company and advancing interests of the Company by affording such person with the opportunity to acquire an equity interest in the Company through rights granted under the stock option plan to purchase common stock of the Company. The Board may, at the time an option is awarded or upon renegotiation of the same, attach restrictions relating to the exercise of the option, including but not limited to vesting provisions. Any such restrictions are indicated on the applicable option certificate. Notwithstanding the foregoing, options issued to consultants performing investor relations activities must vest in stages over at least twelve months with not more than one-quarter of the options vesting in any three month period. See the section entitled “Item 9. Market Price of and Dividends on the Registrant’s Common Equity and Related Stockholder Matters” for more details regarding the Company’s stock option plan.

Pension Plan Benefits

The Company does not maintain or sponsor any pension or retirement plans.

Potential Payments Upon Termination Or Change-In-Control

Except as disclosed below, the Company does not have any compensatory plans, contracts or arrangements that provide for payments to a Named Executive Officer at, following or in connection with any termination, resignation, retirement, a change in control of the Company or a change in a Named Executive Officer’s responsibilities.

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Richard Andrews

The services of Richard Andrews, the chairman of the Board, are provided pursuant to a services agreement (the “Andrews Agreement”) dated January 1, 2013 between Mr. Andrews and the Company. Mr. Andrews may terminate the Andrews Agreement on two weeks’ written notice for Good Cause (as defined below), in which case the Company is obligated to pay Mr. Andrews $500,000 on the termination date.

Good Cause means the occurrence of one of the following events without Mr. Andrews’ express written consent:

• the assignment by the Company to Mr. Andrews, without Mr. Andrews’ consent, of any substantial new or different duties inconsistent with the his positions, duties, responsibilities and status with the Company immediately prior to such change in assigned duties;

• a material reduction in Mr. Andrews’ responsibilities, without the his consent, except as a result of his death or disability;

• a reduction by the Company in Mr. Andrews’ compensation not agreed to by him;

• the requirement by the Company that Mr. Andrews be based anywhere other than within a 50 kilometer radius of his then current location; or

• the failure by the Company to continue in effect, or a material change in the terms of Mr. Andrews’ participation in benefits under any incentive program in place for the Company’s executives, including, without limiting the generality of the foregoing, share option plans, share purchase plans, stock appreciation rights, profit-sharing or bonus plans (collectively, the “Incentive Plans”), the effect of which would be to materially reduce the total value, in the aggregate, of the benefit to him under the Incentive Plan.

The Company may terminate the Andrews Agreement without cause at any time by notice in writing stating the effective date of termination, in which case the Company is obligated to pay Mr. Andrews $500,000 on the termination date.

If the Andrews Agreement is terminated by the Company within 12 months of a Change of Control (as defined in the Andrews Agreement) other than for cause, or the Andrews Agreement is terminated by Mr. Andrews at any time within six months after a Change of Control, Mr. Andrews will receive a termination payment of $500,000.

Colin Watt

The services of Colin Watt, the president, chief executive officer and corporate secretary of the Company, are provided pursuant to a management agreement (the “Watt Agreement”) dated January 1, 2013 between Mr. Watt and the Company. Mr. Watt may terminate the Watt Agreement on two weeks’ written notice for Good Cause (as defined below), in which case the Company is obligated to pay Mr. Watt CDN$500,000 on the termination date.

Good Cause means the occurrence of one of the following events without Mr. Watt’s express written consent:

• the assignment by the Company to Mr. Watt, without Mr. Watt’s consent, of any substantial new or different duties inconsistent with the his positions, duties, responsibilities and status with the Company immediately prior to such change in assigned duties;

• a material reduction in Mr. Watt’s responsibilities, without the his consent, except as a result of his death or disability;

• a reduction by the Company in Mr. Watt’s compensation not agreed to by him;

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• the requirement by the Company that Mr. Watt be based anywhere other than within a 50 kilometer radius of his then current location; or

• the failure by the Company to continue in effect, or a material change in the terms of Mr. Watt’s participation in benefits under the Incentive Plans, the effect of which would be to materially reduce the total value, in the aggregate, of the benefit to him under the Incentive Plan.

The Company may terminate the Watt Agreement without cause at any time by notice in writing stating the effective date of termination, in which case the Company is obligated to pay Mr. Watt CDN$500,000 on the termination date.

If the Watt Agreement is terminated within 12 months of a Change of Control (as defined in the Watt Agreement) by the Company other than for cause, or the Watt Agreement is terminated by Mr. Watt at any time within six months after a change of control, Mr. Watt will receive a termination payment of CDN$500,000.

Compensation of Directors

Compensation for the Named Executive Officers has been disclosed in the “Summary Compensation Table” above. The Company pays its independent directors for acting as such and is determined solely based on discussions by the Board. Directors are also eligible to receive stock option grants.

The Company has a stock option plan for the granting of incentive stock options to certain persons including directors. The purpose of granting such options is to assist the Company in compensating, attracting, retaining and motivating the directors of the Company and to closely align the personal interests of such persons to that of the stockholders. See “Incentive Plan Awards” above.

The following table discloses the particulars of the compensation provided to the directors of the Company (excluding the Named Executive Officers) for the financial year ended June 30, 2014.

Director Compensation

Director Name	Fees Earned or Paid in Cash ($)		All Other Compensation ($)		Total ($)
Robert Bereskin		48,000		Nil	$	48,000
John McLennan		24,000		Nil	$	24,000
Derek Michaelis		Nil		Nil		Nil
Ron Paton		Nil		Nil		Nil

Mr. Robert Bereskin is paid $2,000 per month for acting as a director of the Company, and is paid $2,000 per month for acting as the Chair of the Company’s Technical Committee.

Mr. John McLennan is paid $2,000 per month for acting as a director of the Company.

Item 7. Certain Relationships and Related Transactions, and Director Independence.

Certain Relationships and Related Transactions

We do not maintain a policy for approval of Related Party Transactions. A “Related Party Transaction” is a transaction, arrangement or relationship in which we or any of our subsidiaries was, is or will be a participant, the amount of which involved exceeds the lesser of (a) $120,000 or (b) one percent of the average of our total assets at year end for the last two completed fiscal years, and in

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which any Related Person had, has or will have a direct or indirect material interest. A “Related Person” means:

• any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors;

• any person who is known by us to be the beneficial owner of more than 5% of our common stock;

• any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of a director, executive officer or a beneficial owner of more than 5% of our common stock, and any person (other than a tenant or employee) sharing the household of such director, executive officer or beneficial owner of more than 5% of our common stock; and

• any firm, corporation or other entity in which any of the foregoing persons is a partner or principal or in a similar position or in which such person has a 10% or greater beneficial ownership interest.

The Board periodically reviews all Related Party Transactions that the rules of the SEC require be disclosed in the Company’s annual report or proxy statement, as applicable, and makes a determination regarding the initial authorization or ratification of any such transaction.

In determining whether to approve or disapprove entry into a Related Party Transaction, the Board will take into account, among other factors, the following: (1) whether the Related Party Transaction is on terms no less favorable than terms generally available to an unaffiliated third-party under the same or similar circumstances and (2) the extent of the Related Person’s interest in the transaction.

Except as described in this section, there has not been any transaction or series of similar transactions (aside from compensation for services rendered) during the last three completed financial years or any proposed transaction or series of similar transactions to which the Company was or is a party in which the amount involved exceeded or exceeds the lesser of (a) $120,000 or (b) one percent of the average of our total assets at year end for the last two completed fiscal years and in which any of the Company’s directors, executive officers, holders of more than 5% of any class of its voting securities, or any member of the immediate family of any of the foregoing persons, had or will have a direct or indirect material interest.

See “Executive Compensation” for details regarding compensation arrangements with our directors and executive officers.

Director Independence

The Board currently consists of six members, Richard Andrews, Robert Bereskin, John McLennan, Derek Michaelis, Ron Paton and Colin Watt. Although we are not listed on any U.S. securities exchange and therefore are not subject to the listing requirements of the NYSE MKT LLC, the Board has determined that Robert Bereskin, John McLennan and Derek Michaelis are independent as defined by the rules of the NYSE MKT LLC. Colin Watt is an executive officer of the Company and Ron Paton is the Company’s legal counsel, and accordingly, they are not considered to be independent. Due to his position as chairman of the Board involving a policy making function, Richard Andrews is also considered to be non-independent.

Committees of the Board of Directors

We have an audit committee and a technical committee of the Board, and may have such other committees as the Board shall determine from time to time.

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Audit Committee

Our audit committee consists of John McLennan, Ron Paton and Colin Watt (Chair). Colin Watt is an executive officer of the Company and Ron Paton is the Company’s legal counsel, and accordingly, they are not considered to be independent as defined by the rules of the NYSE MKT LLC or Rule 10A-3 of the Exchange Act. However, we are not required to meeting these independence rules because our securities are not listed on a national securities exchange in the United States.

Item 8. 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 9. Market Price of and Dividends on the Registrant’s Common Equity and Related Stockholder Matters.

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.

QUARTER	HIGH		LOW
July 1, 2012 to September 30, 2012	$	0.750	$	0.450
October 1, 2012 to December 31, 2012	$	1.070	$	0.640
January 1, 2013 to March 31, 2013	$	1.030	$	0.750
April 1, 2013 to June 30, 2013	$	0.860	$	0.600
July 1, 2013 to September 30, 2013	$	0.980	$	0.660
October 1, 2013 to December 31, 2013	$	0.900	$	0.710
January 1, 2014 to March 31, 2014	$	0.900	$	0.630
April 1, 2014 to June 30, 2014	$	0.920	$	0.720
July 1, 2014 to September 30, 2014	$	1.230	$	0.850
October 1, 2014 to December 23, 2014	$	1.010	$	0.400

On December 23, 2014, the closing price of our common stock was CDN$0.59 per share. As of December 23, 2014, we had approximately 251 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 Registration Statement, 5,710,000 shares of our common stock were subject to outstanding incentive stock options, 7,500,000 shares of our common stock were subject to shares purchase warrants, and 12,000 shares of our common stock were subject to finder’s warrants.

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.

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Securities Authorized for Issuance Under Equity Compensation Plans

During the financial year ended June 30, 2014, our stock option 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, 2014.

Plan category	Number of securities to be issued upon exercise of outstanding options (a)		Weighted-average exercise price of outstanding options ($) (b)		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity compensation plans approved by security holders		6,632,500	CDN$	0.61		6,295,091	(1)
Equity compensation plans not approved by security holders		Nil		N/A		Nil
Total		6,632,500	CDN$	0.61		6,295,091	(1)

⁽¹⁾  This figure is based on the total number of shares authorized for issuance under our stock option plan, less the number of stock options issued under such plan which were outstanding as at the Company’s financial year ended June 30, 2014. As at June 30, 2014, the Company was authorized to issue options for the purchase of a total of 12,927,591 shares of common stock.

Warrants

As at the date of this Registration Statement, we have a total of 7,500,000 share purchase warrants outstanding. The holders of 5,067,500 share purchase warrants are entitled to purchase one share of our common stock at a price of CDN$0.65 per share until May 4, 2015, and the holders of 2,432,500 share purchase warrants are entitled to purchase one share of our common stock at a price of CDN$0.65 per share until May 18, 2015.

If, during the term of the share purchase warrants, we: (i) subdivide the outstanding shares of common stock into a greater number of common stock, (ii) consolidate the outstanding shares of our common stock into a lesser number of common stock, or (iii) make any distribution, other than by way of a dividend paid in the ordinary course, to the holders of all or substantially all of the outstanding shares of common stock payable in shares of common stock, (any of such events being called a “Common Share Reorganization”), the exercise price of the share purchase warrants shall be adjusted effective immediately after the effective date or record date, as the case may be, on which the holders of common stock are determined for the purpose of the Common Share Reorganization by multiplying the exercise price in effect immediately prior to such effective date or record date by a fraction, the numerator of which shall be the number of shares of common stock outstanding on such effective date or record date before giving effect to such Common Share Reorganization and the denominator of which shall be the number of shares of common stock outstanding immediately after giving effect to such Common Share Reorganization occurring on the effective date or record date as the case may be.

If, during the term of the warrants, we fix a record date for the issue or distribution to all or substantially all the holders of:

(i) securities of the Company including any rights, options or warrants to acquire shares of common stock or securities convertible into or exchangeable for shares of common stock or property or assets at a price per common stock or having a conversion or exchange price per common stock less than 75% of the current market price per common stock on such record date; or

(ii) any property or other assets,

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and if such issuance or distribution is not by way of a dividend paid in the ordinary course or a Common Share Reorganization then, in each such case, the exercise price shall be adjusted immediately after such record date so that it shall equal the price determined by multiplying the exercise price in effect on such record date by a fraction, of which the numerator shall be the product of the number of shares of common stock outstanding on such record date and the current market price on such record date, less the aggregate fair market value (as determined by us) of such securities, property or other assets so issued or distributed, and of which the denominator shall be the product of the number of shares of common stock outstanding on such record date and such current market price.

As at the date of this Registration Statement, we have a total of 12,000 finder’s warrants outstanding. The holders of the finder’s warrants are entitled to purchase one share of our common stock at a price of CDN$0.65 per share until May 4, 2015. The terms of the warrants finder’s warrants have the same terms regarding adjustment of the exercise price as the share purchase warrants described above.

Stock Options

As at the date of this Registration Statement, we have a total of 5,710,000 incentive stock options outstanding.

The Company currently has in place a “rolling” stock option plan (the “SOP”), whereby a maximum of 10% of the issued common stock from time to time may be reserved for issuance pursuant to the exercise of options. The purpose of the SOP is to attract and motivating directors, officers, employees and consultants and our advancing interests by affording such person with the opportunity to acquire an equity interest in Lynden through rights granted under the SOP to purchase our common stock. The Board may, at the time an option is awarded or upon renegotiation of the same, attach restrictions relating to the exercise of the option, including but not limited to vesting provisions. Any such restrictions are indicated on the applicable option certificate. Notwithstanding the foregoing, options issued to consultants performing investor relations activities must vest in stages over at least twelve months with not more than one-quarter of the options vesting in any three month period.

The material terms of the SOP are as follows:

1. Directors, officers, employees and consultants are eligible to be granted stock options under the SOP.

2. The term of any options granted under the SOP will be fixed by the board at the time such options are granted, provided that options will not be permitted to exceed a term of ten years.

3. The exercise price of any options granted under the SOP will be determined by the Board, in its sole discretion, but shall not be less than the closing trading price of the our common stock preceding the grant of such options, less any discount permitted by the regulatory authorities.

4. Subject to any required regulatory approvals, any existing option or the SOP or the terms and conditions of any option thereafter to be granted may from time to time be amended provided that where such amendment relates to an existing option and it would:

(a) materially decrease the rights or benefits accruing to an option holder; or

(b) materially increase the obligations of an option holder;

then the written consent of the option holder in question to such amendment must be obtained. If at the time the exercise price of an option is reduced the option holder is an insider, the insider must not exercise the option at the reduced exercise price until the reduction in exercise price has been approved by disinterested shareholders, if required by the TSX Venture Exchange.

5. If there is a material alteration in the capital structure and the shares of common stock are consolidated, subdivided, converted, exchanged, reclassified or in any way substituted for, the

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Board or a committee of the Board shall make such adjustments to the SOP and to the options then outstanding under the SOP they determine to be appropriate and equitable under the circumstances, so that the proportionate interest of each option holder shall, to the extent practicable, be maintained as before the occurrence of such event. Such adjustments may include, without limitation:

(a) a change in the number or kind of share covered by such options; and

(b) a change in the exercise price payable per share provided, however, that the aggregate exercise price applicable to the unexercised portion of existing options shall not be altered, it being intended that any adjustments made with respect to such options shall apply only to the exercise price payable per share and the number of shares of common stock subject thereto.

6. Unless otherwise imposed by the Board or a committee of the Board, no vesting requirements will apply to options granted under the SOP. A four month hold period, commencing from the date of grant of an option, will apply to all shares issued under an option only if the exercise price of the stock options is based on less than market price.

7. All options will be non-assignable and non-transferable.

8. If the option holder ceases to be a director or ceases to be employed by us (other than by reason of death), as the case may be, then the option granted shall expire on no later than the 30th day following the date that the option holder ceases to be a director or ceases to be employed us, subject to the terms and conditions set out in the SOP.

9. The aggregate number of options which may be granted to any one option holder under the SOP within any 12 month period must not exceed 5% of the number of issued and outstanding common shares of the Company (unless the we have obtained disinterested shareholder approval as required by the TSX Venture Exchange).

10. Disinterested shareholder approval (in accordance with TSX Venture Exchange requirements) is required to the grant to insiders (as a group), within a 12 month period, of an aggregate number of options which, when added to the number of outstanding incentive stock options granted to insiders within the previous 12 months (calculated at the date an option is granted to an insider), exceed 10% of the number of issued and outstanding shares of common stock.

11. The aggregate number of options which may be granted to any one consultant within any 12 month period must not exceed 2% of the number of issued and outstanding shares of common stock, calculated at the date an option is granted to a consultant.

12. The aggregate number of options which may be granted within any 12 month period to employees or consultants engaged in investor relations activities must not exceed 2% of the number of issued and outstanding shares of common stock, calculated at the date an option is granted to any such employee or consultant, and such options must vest in stages over a period of not less than 12 months with no more than 25% of the options vesting in any three month period.

13. The aggregate number of options which may be granted to eligible charitable organizations must not at any time exceed 1% of the number of issued and outstanding common shares, calculated immediately subsequent to the grant of an option to an eligible charitable organization.

Below is a table setting out details of the current outstanding stock options.

Grant Date	Number of Options		Exercise Price (CDN$)		Expiry Date
March 17, 2010		1,440,000	$	0.55		March 16, 2015
July 21, 2010		260,000	$	0.60		July 20, 2015
July 22, 2011		2,537,500	$	0.80		July 21, 2016
September 2, 2011		75,000	$	0.80		September 1, 2016
July 3, 2012		1,397,500	$	0.50		July 2, 2017

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Exchange Controls

There are no government laws, decrees or regulations in Canada which restrict the export or import of capital or which affect the remittance of dividends, interest or other payments to non-resident holders of our common stock. Any remittances of dividends to United States residents and to other non-residents are, however, subject to withholding tax. See “Taxation” below.

The Investment Canada Act generally prohibits implementation of a reviewable investment by an individual, government or agency thereof, corporation, partnership, trust or joint venture (each an “entity”) that is not a “Canadian” as defined in the Investment Canada Act (a “non-Canadian”), unless after review, the minister responsible for the Investment Canada Act is satisfied or deemed to be satisfied that the investment is likely to be of net benefit to Canada.

An investment in the common stock by a non-Canadian entity other than a “WTO Investor” (as that term is defined by the Investment Canada Act, and which term includes entities which are nationals of or are controlled by nationals of member states of the World Trade Organization) when we were not controlled by a WTO Investor, would be reviewable under the Investment Canada Act if it was an investment to acquire control of Lynden and the value of our assets, as determined in accordance with the regulations promulgated under the Investment Canada Act, was $5,000,000 or more, or if an order for review was made by the federal cabinet on the grounds that the investment related to Canada’s cultural heritage or national identity, regardless of the value of our assets. An investment in the common stock by a WTO Investor, or by a non-Canadian entity when we were controlled by a WTO Investor, would be reviewable under the Investment Canada Act if it was an investment to acquire control of Lynden and the value of our assets, as determined in accordance with the regulations promulgated under the Investment Canada Act, was not less than a specified amount, which for the year 2014 is $354,000,000. A non-Canadian entity would be deemed to acquire control of Lynden for the purposes of the Investment Canada Act if the non-Canadian entity acquired a majority of our common stock. The acquisition of one-third or more, but less than a majority of our common stock, would be presumed to be an acquisition of control of Lynden unless it could be established that, on the acquisition, we were not controlled in fact by the acquirer through the ownership of our common stock. The acquisition of less than one-third of our common stock is deemed not to be an acquisition of control of Lynden.

Certain transactions relating to the common stock would be exempt from the Investment Canada Act, including: (a) an acquisition of the common stock by a person in the ordinary course of that person’s business as a trader or dealer in securities; (b) an acquisition of control of Lynden in connection with the realization of security granted for a loan or other financial assistance and not for a purpose related to the provisions of the Investment Canada Act; and (c) an acquisition of control of Lynden by reason of an amalgamation, merger, consolidation or corporate reorganization following which the ultimate direct or indirect control in fact of Lynden, through the ownership of the common stock, remained unchanged.

Taxation

Certain Canadian Federal Income Taxation

We consider that the following general summary fairly describes the principal Canadian federal income tax consequences applicable to a holder of our common stock who is a resident of the United States, who is not, will not be and will not be deemed to be a resident of Canada for purposes of the Income Tax Act (Canada) and any applicable tax treaty and who does not use or hold, and is not deemed to use or hold, his, her or its common stock in the capital of Lynden in connection with carrying on a business in Canada (a “non-resident holder”).

This summary is based upon the current provisions of the Income Tax Act (Canada), the regulations thereunder (the “Regulations”), the current publicly announced administrative and assessing policies of the Canada Revenue Agency and the Canada-United States Tax Convention as amended by the Protocols thereto (the “Treaty”). This summary also takes into account the amendments to the Income

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Tax Act (Canada) and the Regulations publicly announced by the Minister of Finance (Canada) prior to the date hereof (the “Tax Proposals”) and assumes that all such Tax Proposals will be enacted in their present form. However, no assurances can be given that the Tax Proposals will be enacted in the form proposed, or at all. This summary is not exhaustive of all possible Canadian federal income tax consequences applicable to a holder of our common stock and, except for the foregoing, this summary does not take into account or anticipate any changes in law, whether by legislative, administrative or judicial decision or action, nor does it take into account provincial, territorial or foreign income tax legislation or considerations, which may differ from the Canadian federal income tax consequences described herein.

This summary is of a general nature only and is not intended to be, and should not be construed to be, legal, business or tax advice to any particular holder or prospective holder of our common stock, and no opinion or representation with respect to the tax consequences to any holder or prospective holder of our common stock is made. Accordingly, holders and prospective holders of our common stock should consult their own tax advisors with respect to the income tax consequences of purchasing, owning and disposing of our common stock in their particular circumstances.

Dividends

Dividends paid on our common stock to a non-resident holder will be subject under the Income Tax Act (Canada) to withholding tax at a rate of 25% subject to a reduction under the provisions of an applicable tax treaty, which tax is deducted at source by Lynden. The Treaty provides that the Income Tax Act (Canada) standard 25% withholding tax rate is reduced to 15% on dividends paid on shares of a corporation resident in Canada (such as our company) to residents of the United States, and also provides for a further reduction of this rate to 5% where the beneficial owner of the dividends is a corporation resident in the United States that owns at least 10% of the voting stock of the corporation paying the dividend.

Capital Gains

A non-resident holder is not subject to tax under the Income Tax Act (Canada) in respect of a capital gain realized upon the disposition of a share of our common stock unless such share represents “taxable Canadian property”, as defined in the Income Tax Act (Canada), to the holder thereof. Our common stock generally will be considered taxable Canadian property to a non-resident holder if:

• the non-resident holder;

• persons with whom the non-resident holder did not deal at arm’s length; or

• the non-resident holder and persons with whom such non-resident holder did not deal at arm’s length,

owned, or had an interest in an option in respect of, not less than 25% of the issued shares of any class of our capital stock at any time during the 60 month period immediately preceding the disposition of such shares. In the case of a non-resident holder to whom shares of our common stock represent taxable Canadian property and who is resident in the United States, no Canadian taxes will generally be payable on a capital gain realized on such shares by reason of the Treaty unless the value of such shares is derived principally from real property situated in Canada.

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Item 10. Recent Sales of Unregistered Securities.

Information concerning the issuance or sale of unregistered securities during the last three years is set out below.

DATE OF SALE	TYPE OF SECURITY	NUMBER	CONSIDERATION	EXEMPTION FROM REGISTRATION
September 2, 2011	Stock Options issued to non-U.S. Person exercisable into common stock until September 1, 2016(1)	75,000	Exercise price of CDN$0.80 (US$0.81;CDN$1 =US$1.0161) per common stock	Regulation S
April 24, 2012	Common Stock issued upon exercise of warrants by non-U.S. Person	100,000	Exercise price of CDN$0.50 (US$0.51; CDN$1 =US$1.0121) per common stock	Regulation S
May 1, 2012	Common Stock issued upon exercise of warrants by U.S. Person	17,000	Exercise price of CDN$0.50 (US$0.51; CDN$1 =US$1.0144) per common stock	Rule 506 of Regulation D
May 4, 2012	Units issued to U.S.	8,023,000	CDN$0.42	Rule 506 of Regulation D
	Persons(2)		(US$0.42;CDN$1 =US$1.0045) per Unit
May 4, 2012	Units issued to non-U.S. Persons(2)	2,112,000	CDN$0.42 (US$0.42;CDN$1 =US$1.0045) per Unit	Regulation S
May 4, 2012	Finder’s Units(2)	30,000	Finder’s fees for the introduction of non-U.S. investors in the May 4, 2012 tranche of the private placement. A total cash payment of CDN$12,600 (US$12,657; CDN$1=US$1.0045) was also paid to finders for the introduction of non- U.S. investors in the May 4, 2012 tranche of the private placement.	Regulation S

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DATE OF SALE	TYPE OF SECURITY	NUMBER	CONSIDERATION	EXEMPTION FROM REGISTRATION
May 7, 2012	Common Stock issued upon exercise of warrants by non-U.S. Persons	108,000	Exercise price of CDN $0.50 (US$0.50; CDN$1=US$1.0070) per common stock	Regulation S
May 18, 2012	Units issued to non-U.S. Persons(3)	4,865,000	CDN$0.42 (US$0.41; CDN$1=US$0.9796) per Unit. No finder’s fee or commissions were paid in connection with this tranche of the private placement.	Regulation S
July 3, 2012	Stock Options issued to non-U.S. persons exercisable into common stock until July 2, 2017(4)	785,000	Exercise price of CDN$0.50 (US$0.52; CDN$1=US$1.0408) per common stock	Regulation S
July 3, 2012	Stock Options issued to U.S. persons exercisable into common stock until July 2, 2017(2)	612,500	Exercise price of CDN$0.50 (US$0.52; CDN$1=US$1.0408) per common stock	Rule 506 of Regulation D
December 2013	Common Stock issued upon exercise of warrants by non-U.S. Persons	250,000	Exercise price of CDN$0.70 (US$0.71;CDN$1 =US$1.0133) per common stock	Regulation S
January 17, 2013	Common Stock issued upon exercise of stock options by U.S. Person	25,000	Exercise price of CDN$0.55 (US$0.56; CDN$1=US$1.0149) per common stock	Rule 506 of Regulation D
January 25, 2013	Common Stock issued upon exercise of stock options by U.S. Person	100,000	Exercise price of CDN$0.30 (US$0.30; CDN$1=US$0.9923) per common stock	Rule 506 of Regulation D
February 2013	Common Stock issued upon exercise of warrants by non-U.S. Persons	80,000	Exercise price of CDN$0.70 (US$0.70;CDN$1 =US$0.9985) per common stock	Regulation S

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DATE OF SALE	TYPE OF SECURITY	NUMBER	CONSIDERATION	EXEMPTION FROM REGISTRATION
March 2013	Common Stock issued upon exercise of warrants by non-U.S. Persons	130,000	Exercise price of CDN$0.70 (US$0.68;CDN$1 =US$0.9723) per common stock	Regulation S
April 2013	Common Stock issued upon exercise of warrants by non-U.S. Persons	55,000	Exercise price of CDN$0.70 (US$0.69;CDN$1 =US$0.9818) per common stock	Regulation S
July 2013	Common Stock issued upon exercise of warrants by non-U.S. Persons	602,500	Exercise price of CDN$0.70 (US$0.68;CDN$1 =US$0.9737) per common stock	Regulation S
August 2013	Common Stock issued upon exercise of warrants by non-U.S. Persons	141,498	Exercise price of CDN$0.70 (US$0.67;CDN$1 =US$0.9605) per common stock	Regulation S
September 2013	Common Stock issued upon exercise of warrants by non-U.S. Persons	2,916,000	Exercise price of CDN$0.70 (US$0.68;CDN$1 =US$0.9676) per common stock	Regulation S
September 2013	Common Stock issued upon exercise of finder’s warrants by non-U.S. Person	3,000	Exercise price of CDN$0.65 (US$0.62;CDN$1 =US$0.9497) per common stock	Regulation S
October 2013	Common Stock issued upon exercise of warrants by non-U.S. Persons	10,191,393	Exercise price of CDN$0.70 (US$0.68;CDN$1 =US$0.9662) per common stock	Regulation S
October 2013	Common Stock issued upon exercise of warrants by U.S. Persons	450,000	Exercise price of CDN$0.70 (US$0.68;CDN$1 =US$0.9662) per common stock	Rule 506 of Regulation D
November 2013	Common Stock issued upon exercise of warrants by non-U.S. Persons	4,466,000	Exercise price of CDN$0.70 (US$0.67;CDN$1 =US$0.9539) per common stock	Regulation S

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DATE OF SALE	TYPE OF SECURITY	NUMBER	CONSIDERATION	EXEMPTION FROM REGISTRATION
July 14, 2014	Common Stock issued upon exercise of stock options by U.S. Person pursuant to an employee benefit plan	50,000	Exercise price of CDN$0.30 (US$0.28; CDN$1=US$0.9333) per common stock	Rule 701 of the Securities Act
July 14, 2014	Common Stock issued upon exercise of stock options by U.S. Person pursuant to an employee benefit plan	25,000	Exercise price of CDN$0.55 (US$0.51; CDN$1=US$0.9333) per common stock	Rule 701 of the Securities Act
July 30, 2014	Common Stock issued upon exercise of stock options by U.S. Person pursuant to an employee benefit plan	350,000	Exercise price of CDN$0.30 (US$0.28; CDN$1=US$0.9173) per common stock	Rule 701 of the Securities Act
August 1, 2014	Common Stock issued upon exercise of stock options by non-U.S. Persons pursuant to an employee benefit plan	12,500	Exercise price of CDN$0.30 (US$0.27; CDN$1=US$0.9152) per common stock	Rule 701 of the Securities Act
August 7, 2014	Common Stock issued upon exercise of stock options by non-U.S. Person pursuant to an employee benefit plan	35,000	Exercise price of CDN$0.30 (US$0.27; CDN$1=US$0.9157) per common stock	Rule 701 of the Securities Act
October 2, 2014	Common Stock issued upon exercise of stock options by non-U.S. Person pursuant to an employee benefit plan	225,000	Exercise price of CDN$0.30 (US$0.27; CDN$1=US$0.8958) per common stock	Rule 701 of the Securities Act
October 7, 2014	Common Stock issued upon exercise of stock options by non-U.S. Persons pursuant to an employee benefit plan	225,000	Exercise price of CDN$0.30 (US$0.27; CDN$1= US$0.8952) per common stock	Rule 701 of the Securities Act

^1.  These options vested as to 1/3 (33.33%) on March 2, 2012, as to an additional 1/3 (33.3%) on September 2, 2012, and as to an additional 1/3 (33.33%) on March 2, 2013.

^2.  Each unit consisting of one share of common stock and one-half of one share purchase warrant. Each whole share purchase warrant entitles the holder to purchase one share of our common stock at a price of $0.65 per share until May 4, 2015.

^3.  Each unit consisting of one share of common stock and one-half of one share purchase warrant. Each whole share purchase warrant entitles the holder to purchase one share of our common stock at a price of $0.65 per share until May 18, 2015.

^4.  These options vested as to 1/3 (33.33%) on January 3, 2013, as to an additional 1/3 (33.3%) on July 3, 2013, and as to an additional 1/3 (33.33%) on January 3, 2014.

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Item 11. Description of Registrant’s Securities to be Registered.

The authorized capital stock of Lynden is an unlimited number of common shares, with no par value, of which 130,198,411 are issued and outstanding, and an unlimited number of preference shares, with no par value, of which no shares are issued and outstanding.

The following summary of the capital stock and articles of Lynden does not purport to be complete and is qualified in its entirety by reference to the provisions of applicable law and to our notice of articles and articles, which are filed as exhibits to the registration statement.

Common Stock

Each share of common stock entitles the holder thereof to one vote per share at all meetings of stockholders, except meetings at which only holders of a specified class of shares are entitled to vote, and do not have cumulative voting rights. Subject to prior rights and preferences that may be applicable to any outstanding shares or series of preferred stock, holders of common stock are entitled to receive ratably in proportion to the shares of common stock held by them such dividends (payable in cash, stock or otherwise), if any, as may be declared from time to time by the Board out of funds legally available for dividend payments. All outstanding shares of common stock are fully paid and non-assessable.

The holders of common stock have no preferences or rights of conversion, exchange, preemptive or other subscription rights. There are no redemption or sinking fund provisions applicable to common stock. There are no existing indentures or agreements affecting the rights of stockholders other than the notice of articles and articles of the Company. In the event of any voluntary or involuntary liquidation, dissolution or winding-up of our affairs, holders of common stock will be entitled to share ratably in our assets in proportion to the shares of common stock held by them that are remaining after payment or provision for payment of all of our debts and obligations and after distribution in full of preferential amounts to be distributed to holders of outstanding shares of preferred stock, if any. However, the holders of common stock are entitled to receive the remaining property of Lynden upon dissolution, subject to the rights, restrictions and conditions attached to any other class of stock.

Preferred Stock

Our articles authorizes the Board, subject to any limitations prescribed by law, without further stockholder approval, to establish and to issue from time to time one or more classes or series of preferred stock. Each class or series of preferred stock will cover the number of shares and will have the powers, preferences, rights, qualifications, limitations and restrictions determined by the Board, which may include, among others, dividend rights, liquidation preferences, voting rights, conversion rights, redemption rights and the terms and conditions of any sinking fund. The shares of preferred stock of any series may be converted into shares of common stock. Except as provided by law or in a preferred stock designation, the holders of shares of preferred stock have such rights to attend and vote at meetings of stockholders by restrictions on attendances or voting rights thereat as may be determined by resolution of the Board. Holders of shares of a class or series of preferred stock are not entitled to vote separately as a class or series or to dissent in certain circumstances.

In the event of any voluntary or involuntary liquidation, dissolution or winding-up of our affairs, the holders of shares of each series of preferred stock rank in parity with the preferred stock of every other series of the same class and have preference over the shares of common stock and any shares ranking junior to the shares of preferred stock. The directors may also give the shares of preferred stock additional preferences over the shares of common stock and other shares ranking junior to such preferred stock. If any cumulative dividends, whether or not earned or declared, declared non-cumulative dividends, or amounts payable on the return of capital in respect of a series of shares of preferred stock are not paid in full, all shares of preferred stock of other series of the same class are

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entitled to participate rateably in respect of accumulated cumulative dividends, declared non-cumulative dividends, and amounts payable on return of capital.

Anti-Takeover Effects of Provisions of our Articles

Our articles contain an advance notice provision (the “Advance Notice Provision”) which is designed to: (i) facilitate orderly and efficient stockholder meetings at which directors are to be elected; (ii) ensure that all stockholders, including those participating in a stockholders’ meeting by proxy rather than in person, receive adequate notice of all director nominations and sufficient information with respect to all nominees; and (iii) allow stockholders to register an informed vote.

Nominations of persons for election to the board may be made at an annual general meeting of stockholders, or at any other general meeting of stockholders (an “extraordinary meeting”) if one of the purposes for which the extraordinary meeting was called was the election of directors) in one of the following ways: (a) by or at the direction of the board, including pursuant to a notice of meeting; (b) by or at the direction or request of one or more stockholders pursuant to a proposal made in accordance with the provisions of the British Columbia Business Corporations Act (the “BCA”), or a requisition of the stockholders made in accordance with the provisions of the BCA; or (c) by any person (a “Nominating Stockholder”): (A) who, at the close of business on the date of the giving of the notice provided for below in the Advance Notice Provision and on the record date for notice of such meeting, is entered in the central securities register as a holder of one or more shares carrying the right to vote at such meeting or who beneficially owns shares that are entitled to be voted at such meeting; and (B) who complies with the notice procedures set forth below in the Advance Notice Provision.

In addition to any other applicable requirements, for a nomination to be made by a Nominating Stockholder, the Nominating Stockholder must have given timely notice thereof in proper written form to our corporate secretary at our head office.

To be timely, a Nominating Stockholder’s notice to our secretary must be made: (a) in the case of an annual general meeting of stockholders, not less than 30 nor more than 65 days prior to the date of the annual general meeting of stockholders; provided, however, that in the event that the annual general meeting of stockholders is to be held on a date that is less than 50 days after the date (the “Notice Date”) on which the first public announcement of the date of the annual general meeting was made, notice by the Nominating Stockholder may be made not later than the close of business on the 10th day following the Notice Date; and (b) in the case of an extraordinary meeting (which is not also an annual general meeting) of stockholders called for the purpose of electing directors (whether or not called for other purposes), not later than the close of business on the 15th day following the day on which the first public announcement of the date of the extraordinary meeting of stockholders was made. In no event shall any adjournment or postponement of a meeting of stockholder or the announcement thereof commence a new time period for the giving of a Nominating Stockholder’s notice as described above.

To be in proper written form, a Nominating Stockholder’s notice to our corporate secretary must set forth: (a) as to each person whom the Nominating Stockholder proposes to nominate for election as a director: (A) the name, age, business address and residential address of the person; (B) the principal occupation or employment of the person; (C) the class or series and number of shares in our capital stock which are controlled or which are owned beneficially or of record by the person as of the record date for the meeting of stockholder (if such date shall then have been made publicly available and shall have occurred) and as of the date of such notice; and (D) any other information relating to the person that would be required to be disclosed in a dissident’s proxy circular in connection with solicitations of proxies for election of directors pursuant to the BCA and Applicable Securities Laws (as defined below); and (b) as to the Nominating Stockholder giving the notice, any proxy, contract, arrangement, understanding or relationship pursuant to which such Nominating Stockholder has a right to vote any our stock and any other information relating to such Nominating Stockholder that would be required to be made in a dissident’s proxy circular in connection with solicitations of proxies for election of directors pursuant to the BCA and Applicable

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Securities Laws (as defined below). We may require any proposed nominee to furnish such other information as may reasonably be required by us to determine the eligibility of such proposed nominee to serve as an independent director of the Board or that could be material to a reasonable stockholder’s understanding of the independence, or lack thereof, of such proposed nominee.

No person will be eligible for election as a director unless nominated in one of the three ways described above; provided, however, that nothing in the Advance Notice Provision shall be deemed to preclude discussion by a stockholder (as distinct from the nomination of directors) at a meeting of stockholders of any matter in respect of which it would have been entitled to submit a proposal pursuant to the provisions of the BCA. The chairman of the meeting shall have the power and duty to determine whether a nomination was made in accordance with the procedures set forth in the foregoing provisions and, if any proposed nomination is not in compliance with such foregoing provisions, to declare that such defective nomination shall be disregarded.

For purposes of the Advance Notice Provision: (a) “public announcement” shall mean disclosure in a press release reported by a national news service in Canada, or in a document publicly filed by the Company under its profile on the System of Electronic Document Analysis and Retrieval at www.sedar.com; and (b) “Applicable Securities Laws” means the applicable securities legislation of each relevant province and territory of Canada, as amended from time to time, the rules, regulations and forms made or promulgated under any such statute and the published national instruments, multilateral instruments, policies, bulletins and notices of the securities commission and similar regulatory authority of each province and territory of Canada.

Notwithstanding any other provision of the Advance Notice Provision, notice given to our corporate secretary pursuant to the Advance Notice Provision may only be given by personal delivery or fax transmission and shall be deemed to have been given and made only at the time it is served by personal delivery or sent by fax transmission (provided that receipt of confirmation of such transmission has been received) to our corporate secretary at the address of our head office; provided that if such delivery or fax transmission is made on a day which is a not a business day or later than 5:00 p.m. (Vancouver time) on a day which is a business day, then such delivery or fax transmission shall be deemed to have been made on the next business day.

Actions Requiring a Special Majority

Under the Business Corporations Act (British Columbia), unless otherwise stated in the Articles, certain corporate actions require the approval of a special majority of shareholders, meaning holders of shares representing two-thirds of those votes cast in respect of a shareholder vote addressing such matter. Those items requiring the approval of a special majority generally relate to fundamental changes with respect to our business, and include amongst others, resolutions: (i) removing a director prior to the expiry of his or her term; (ii) altering the Articles, (iii) approving an amalgamation; (iv) approving a plan of arrangement; and (v) providing for a sale of all or substantially all of our assets.

Foreign Governmental Laws and Taxes

See the section entitled “Item 9. Market Price of and Dividend on the Registrant’s Common Equity and Related Stockholder Matters – Exchange Controls, Taxation” for a discussion regarding the rights of nonresident or foreign owners.

Item 12. Indemnification of Directors and Officers.

Subject to the Business Corporations Act (British Columbia), our articles require that we indemnify a director, former director or alternate director and his or her heirs and legal personal representatives against all eligible penalties to which such person is or may be liable and each director or alternate

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director is deemed to have contracted with us on the terms of the indemnity contained in our articles. Our articles also provide that we may indemnify any person, subject to any restrictions in the Business Corporations Act (British Columbia). The Business Corporations Act (British Columbia) prohibits indemnification if any of the following circumstances apply:

(a) if the indemnity or payment is made under an earlier agreement to indemnify or pay expenses and, at the time that the agreement to indemnify or pay expenses was made, the company was prohibited from giving the indemnity or paying the expenses by its memorandum or articles;

(b) if the indemnity or payment is made otherwise than under an earlier agreement to indemnify or pay expenses and, at the time that the indemnity or payment is made, the company is prohibited from giving the indemnity or paying the expenses by its memorandum or articles;

(c) if, in relation to the subject matter of the eligible proceeding, the eligible party did not act honestly and in good faith with a view to the best interests of the company or the associated corporation, as the case may be;

(d) in the case of an eligible proceeding other than a civil proceeding, if the eligible party did not have reasonable grounds for believing that the eligible party’s conduct in respect of which the proceeding was brought was lawful.

The Business Corporations Act (British Columbia) also prohibits indemnification and payment of expenses of an eligible party if an eligible proceeding is brought against an eligible party by us or on our behalf or by or on behalf of an associated corporation.

Our articles permit us to purchase insurance on behalf of any officer, director, employee or other agent for any liability arising out of that person’s actions as our officer, director, alternate director, employee or agent or person who holds or held such equivalent position. We have entered into indemnification agreements with each of our current directors and officers. These agreements require us to indemnify these individuals to the fullest extent permitted under laws of British Columbia and the laws of Canada applicable therein against liability that may arise by reason of their service to us, and to advance expenses incurred as a result of any proceeding against them as to which they could be indemnified. We believe that the indemnification agreements facilitate our ability to continue to attract and retain qualified individuals to serve as directors and officers.

Item 13. Financial Statements.

Please see the section entitled “Item 15. Financial Statements and Exhibits” for information on financial statements filed with this Registration Statement.

Item 14. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

For the fiscal years ended June 30, 2013, and 2014, we did not have any disagreement with our accountants on any matter of accounting principles, practices or financial statement disclosure.

Item 15. Financial Statements and Exhibits.

The following Consolidated Financial Statements and Exhibits are filed or furnished as part of this Registration Statement.

(a) Consolidated Financial Statements.

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INDEX TO FINANCIAL STATEMENTS

	Page
Condensed Consolidated Interim Financial Statements for the Three Months Ended September 30, 2014 and 2013 (Unaudited)
Condensed Consolidated Interim Balance Sheets		87
Condensed Consolidated Interim Statements of Income and Comprehensive Income		88
Condensed Consolidated Interim Statement of Changes in Shareholders’ Equity		89
Condensed Consolidated Interim Statements of Cash Flows		90
Notes to the Condensed Consolidated Interim Financial Statements		91
Report of Independent Registered Public Accounting Firm		100
Consolidated Balance Sheets as of June 30, 2014 and June 30, 2013 (Restated)		101
Consolidated Statements of Income and Comprehensive Income for the years ended June  30, 2014 and June 30, 2013 (Restated)		102
Consolidated Statement of Changes in Shareholders’ Equity for the years ended June  30, 2014 and June 30, 2013 (Restated)		103
Consolidated Statements of Cash Flows for the years ended June 30, 2014 and June 30, 2013 (Restated)		104
Notes to the Consolidated Financial Statements		105
Supplemental Information on Oil and Gas Exploration and Production Activities		126

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LYNDEN ENERGY CORP.

Condensed Consolidated Interim Balance Sheets

(Presented in United States dollars, except where indicated)

(Unaudited)

	Notes		September 30, 2014			June 30, 2014
ASSETS
Current assets
Cash and cash equivalents			$	13,469,859		$	13,955,890
Trade and other receivables, net of allowance for doubtful accounts		3,9		2,937,583			3,143,017
Income taxes receivable				200,000			200,000
Total current assets				16,607,442			17,298,907
Non-current assets
Property, plant and equipment		5		98,661,271			91,812,527
Total assets			$	115,268,713		$	109,111,434
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Trade and other payables		9	$	1,126,368		$	2,971,177
Income taxes payable				451,000			380,000
Total current liabilities				1,577,368			3,351,177
Non-current liabilities
Credit facility		6		23,412,645			17,853,245
Asset retirement liabilities				254,456			240,208
Deferred tax liabilities				16,025,811			14,902,811
				39,692,912			32,996,264
Total liabilities				41,270,280			36,347,441
Shareholders’ equity
Share capital—authorized unlimited common shares, no par value
Issued and outstanding: September 30, 2014—129,748,411
June 30, 2014—129,275,911		7		65,404,111			65,160,387
Paid-in capital		7		15,326,602			15,434,128
Accumulated other comprehensive loss				(749,890	)		(212,663	)
Deficit				(5,982,390	)		(7,617,859	)
Total shareholders’ equity				73,998,433			72,763,993
Total liabilities and shareholders’ equity			$	115,268,713		$	109,111,434
Subsequent events		6

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LYNDEN ENERGY CORP.

Condensed Consolidated Interim Statements of Income and Comprehensive Income

(Presented in United States dollars, except where indicated)

(Unaudited)

			Three months ended September 30,
	Notes		2014			2013
Revenue and other income
Petroleum and natural gas sales, net of royalties			$	7,934,867		$	8,947,483
Derivative financial instruments loss				—			(125,405	)
Interest income				37,826			671
Total revenue and other income				7,972,693			8,822,749
Expenses
Production and operating expenses				(1,324,362	)		(1,048,414	)
Depletion, depreciation and accretion				(2,679,020	)		(1,978,896	)
Exploration				(1,568	)		(1,062	)
Foreign exchange gain (loss)				546			(1,195	)
General and administrative				(374,284	)		(252,755	)
Impairments				(449,541	)		—
Interest				(189,995	)		(39,586	)
Total expenses				(5,018,224	)		(3,321,908	)
Income before income taxes				2,954,469			5,500,841
Income tax expense				1,319,000			1,862,900
Net income				1,635,469			3,637,941
Other comprehensive (loss) income
Foreign currency translation adjustment				(537,227	)		13,068
Total comprehensive income for the period			$	1,098,242		$	3,651,009
Weighted average number of common shares outstanding
Basic		7		129,609,199			111,639,100
Diluted		7		134,674,198			117,342,007
Net earnings per common share
Basic			$	0.01		$	0.03
Diluted			$	0.01		$	0.03

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LYNDEN ENERGY CORP.

Condensed Consolidated Interim Statement of Changes in Shareholders’ Equity

(Presented in United States dollars, except where indicated)

(Unaudited)

		Three months ended September 30,
	Notes	2014			2013
Share capital
Balance, beginning of period		$	65,160,387		$	49,279,688
Common shares issued for cash:
Exercise of stock options			243,724			—
Exercise of warrants			—			3,111,397
Balance, end of period		$	65,404,111		$	52,391,085
Paid-in capital
Balance, beginning of period		$	15,434,128		$	18,598,870
Exercise of stock options			(107,526	)		—
Exercise of warrants			—			(630,195	)
Share-based payments			—			28,149
Balance, end of period		$	15,326,602		$	17,996,824
Accumulated other comprehensive income (loss)
Balance, beginning of period		$	(212,663	)	$	139,939
Foreign currency translation			(537,227	)		13,068
Balance, end of period		$	(749,890	)	$	153,007
Deficit
Balance, beginning of period		$	(7,617,859	)	$	(23,021,510	)
Net income			1,635,469			3,637,941
Balance, end of period		$	(5,982,390	)	$	(19,383,569	)
Total shareholders’ equity		$	73,998,433		$	51,157,347
Common shares—number
Balance, beginning of period			129,275,911			110,505,520
Exercise of stock options			472,500			—
Exercise of warrants			—			3,662,998
Balance, end of period			129,748,411			114,168,518

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LYNDEN ENERGY CORP.

Condensed Consolidated Interim Statements of Cash Flows

(Presented in United States dollars, except where indicated)

(Unaudited)

			Three months ended September 30,
	Notes		2014			2013
Operating activities
Earnings for the period			$	1,635,469		$	3,637,941
Adjustments for:
Unrealized loss (gain) on derivative financial instruments				—			96,263
Depletion, depreciation and accretion				2,679,020			1,978,896
Impairments				449,541
Share-based payments				—			28,149
Deferred income taxes				1,123,000			1,783,900
Unrealized foreign exchange gain				(54,483	)		(39,477	)
Changes in non-cash working capital items:
Trade and other receivables				205,434			(1,863,058	)
Trade and other payables				(73,965	)		442,172
Income taxes payable				71,000			79,000
Cash generated by operating activities				6,035,016			6,143,786
Investing activities
Acquisition of property, plant and equipment				(11,724,501	)		(10,145,218	)
Cash used in investing activities				(11,724,501	)		(10,145,218	)
Financing activities
Drawings of credit facility				5,550,000			2,500,000
Common shares issued for cash, net of issue costs		7		136,198			2,481,202
Cash generated by financing activities				5,686,198			4,981,202
Effect of exchange rate on cash held in foreign currency				(482,744	)		52,545
Change in cash and cash equivalents during the period				(486,031	)		1,032,315
Cash and cash equivalents, beginning of period				13,955,890			1,874,400
Cash and cash equivalents, end of period			$	13,469,859		$	2,906,715
Cash and cash equivalents are composed of:
Cash			$	2,641,321		$	2,906,715
Guaranteed investment certificates				10,828,538			—
			$	13,469,859		$	2,906,715
Supplemental cash flow information		10

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LYNDEN ENERGY CORP.

Notes to the Condensed Consolidated Interim Financial Statements

September 30, 2014

(Presented in United States dollars, except where indicated)

(Unaudited)

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

a) Basis of presentation

These condensed consolidated interim financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“US GAAP”) as at September 30, 2014 and for the three months ended September 30, 2014 and the 2013 comparative period and to the preparation requirements of the SEC for interim financial reporting which permits the omission and/or condensing of certain information. In the opinion of management, all adjustments (which include only normal recurring adjustments) necessary to present fairly the financial position, results of operations and cash flows have been made. These condensed consolidated interim financial statements do not include all the necessary annual disclosures as prescribed under U.S. GAAP and should be read in conjunction with the Company’s audited consolidated financial statements as of June 30, 2014.

b) Use of estimates

The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the amount and timing of recording of assets, liabilities, revenues and expenses since the determination of these amounts may be dependent on future events. Significant estimates made by management include: oil and natural gas reserves and related present value of future cash flows, depreciation, depletion, amortization and accretion (“DDA&A”), impairment, asset retirement obligations, income taxes, and share-based compensation. The Company uses the most current information available and exercises judgment in making these estimates and assumptions. 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. There have been no significant changes in the estimates or judgments between these condensed consolidated interim financial statements and the audited consolidated financial statements for the year ended June 30, 2014.

c) Recent accounting pronouncements

As of July 1, 2014, the Company adopted the following FASB accounting standards updates. The adoption of these standards did have a material impact on the Company’s consolidated financial statements.

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

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

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

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LYNDEN ENERGY CORP.

Notes to the Condensed Consolidated Interim Financial Statements

September 30, 2014

(Presented in United States dollars, except where indicated)

(Unaudited)

2. Significant Accounting Policies  (cont’d)

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

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

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

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

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

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

3. Trade and Other Receivables

	September 30, 2014		June 30, 2014
Accounts receivable—trade	$	2,368,955	$	2,572,762
Accrued receivables		492,700		496,947
Sales taxes receivable		75,928		73,308
	$	2,937,583	$	3,143,017

The Company did not have any allowance for doubtful accounts as at September 30, 2014 and June 30, 2014. As at June 30, 2014, $2,829,430 (June 30, 2014—$2,991,585) is owing from one counterparty.

4. Investment in Associate

The Company has a 47.99% interest in Abajo Gas Transmission Company, LLC (“Abajo”), which holds ownership of the gas gathering systems in the Northern and Southern Prospect Areas of the Company’s Paradox Basin Project. The investment in Abajo is accounted for using the equity method and has been written down to $nil in prior periods.

The following is summarized financial information for Abajo as at September 30 and June 30, 2014, and for the three months ended September 30, 2014 and the year ended June 30, 2014:

	September 30, 2014		June 30, 2014
Total assets	$	1,643,712	$	1,682,118
Total liabilities	$	892,384	$	861,934
Revenues	$	12,442	$	88,617
Loss	$	68,857	$	239,804

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LYNDEN ENERGY CORP.

Notes to the Condensed Consolidated Interim Financial Statements

September 30, 2014

(Presented in United States dollars, except where indicated)

(Unaudited)

4. Investment in Associate  (cont’d)

The Company’s cumulative share of losses attributable to Abajo from July 1, 2010 to September 30, 2014 that have not been recognized amounts to $4,620,657 and $41,360 for the three months ended September 30, 2014 (note 8).

5. Property, Plant and Equipment

	September 30, 2014
	Cost		Accumulated Depletion, Depreciation and Impairment			Net Book Value
Petroleum and natural gas properties
Proved	$	112,801,771	$	(20,512,636	)	$	92,289,135
Suspended exploratory well costs		33,607,378		(27,236,093	)		6,371,285
		146,409,149		(47,748,729	)		99,660,420
Computer equipment		4,593		(3,742	)		851
Total property, plant and equipment	$	146,413,742	$	(47,752,471	)	$	98,661,271

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

Proved Petroleum and Natural Gas Assets

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

Suspended Exploratory Well Costs

Suspended exploratory well costs consist of costs of drilling and equipping exploratory wells relating to the Company’s Paradox Basin Project and Mitchell Ranch Project. The Company is performing economic evaluations including, but not limited to, results of additional appraisal drilling, well test analysis, additional geological and geophysical data, facilities and infrastructure development options, development plan approval, and permitting.

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LYNDEN ENERGY CORP.

Notes to the Condensed Consolidated Interim Financial Statements

September 30, 2014

(Presented in United States dollars, except where indicated)

(Unaudited)

5. Property, Plant and Equipment  (cont’d)

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 for the year ended June 30, 2014, due to a lack of substantial activities to assess the reserves for more than one year following the drilling of the exploratory wells, and the lack of significant expenditures which are planned in the future. Management has corrected the accounting for these costs as they should no longer be capitalized and, as a result, the Company has 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.

6. Credit Facility

The Company has a reducing revolving line of credit (the “Credit Facility”) in an amount up to $100 million. As at September 30, 2014, the Credit Facility has a borrowing base of $32 million, of which $23.3 million has been drawn down. Subsequent to September 30, 2014, the borrowing base was increased to $40 million. The Credit Facility will bear interest determined by the percent of the borrowing base utilized and by elections made by the Company. Amounts drawn down under the Credit Facility will bear interest at a rate of LIBOR plus a range of 3.00% to 3.50% or at a rate of U.S. prime plus a range of 2.00% to 2.50%. A minimum interest rate of 3.5% is required on borrowings under the Credit Facility. Payments under the Credit Facility will be required to the extent that outstanding principal and interest exceed the borrowing base. Other fees also apply pursuant to the bank’s re-determinations of the borrowing base. Increases in the borrowing base are made based on the bank’s engineering valuation of the Company’s oil and gas reserves. The borrowing base is re-determined semi-annually; however, the Company may request two additional re-determinations of the borrowing base annually.

The Credit Facility contains certain mandatory covenants, including minimum current ratio and cash flow requirements, and other standard business operating covenants. The Company has complied with all of these covenants as at and during the three months ended September 30, 2014. The Company has pledged its interest in its P&NG and other assets as security for liabilities pursuant to the Credit Facility. Amounts owing on the Credit Facility are payable when the Credit Facility expires in August 2016, unless otherwise extended by the parties, or payable on demand on the event of default.

7. Shareholders’ Equity

a) Authorized

An unlimited number of common shares without par value.

An unlimited number of preference shares without par value.

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LYNDEN ENERGY CORP.

Notes to the Condensed Consolidated Interim Financial Statements

September 30, 2014

(Presented in United States dollars, except where indicated)

(Unaudited)

7. Shareholders’ Equity  (cont’d)

b) Warrants:

The changes in warrants outstanding during the three months ended September 30, 2014 and the year ended June 30, 2014 are as follows:

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

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

Warrants exercisable and outstanding as at September 30, 2014 are as follows:

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

c) Earnings per share:

Diluted earnings per share computation

	Three months ended September 30,
	2014		2013
Numerator:
Net earnings	$	1,635,469	$	3,637,941
Denominator:
Weighted average number of common shares (basic)		129,609,199		111,639,100
Dilutive effect of share options		2,353,504		1,719,097
Dilutive effect of warrants		2,711,494		3,983,810
Weighted average number of common shares (diluted)		134,674,198		117,342,007
Diluted earnings per common share	$	0.01	$	0.03

- 95 -

LYNDEN ENERGY CORP.

Notes to the Condensed Consolidated Interim Financial Statements

September 30, 2014

(Presented in United States dollars, except where indicated)

(Unaudited)

7. Shareholders’ Equity  (cont’d)

There are nil (2013 – nil) warrants and nil (2013 – nil) stock options that are not dilutive as at September 30, 2014.

d) Stock option plan

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

The changes in stock options issued during the three months ended September 30, 2014 and the year ended June 30, 2014 are as follows:

	Three months ended September 30, 2014					Year ended June 30, 2014
	Number of options			Weighted average exercise price (CDN$)		Number of options			Weighted average exercise price (CDN$)
Balance, beginning of period		6,632,500		$	0.61		6,862,500		$	0.81
Exercised		(472,500	)	$	0.31		—		$	—
Expired		—		$	—		(230,000	)	$	0.68
Balance, end of period		6,160,000		$	0.61		6,632,500		$	0.61

For stock options exercised during the three months ended September 30, 2014, the weighted average share price at the dates of exercise was CDN$0.94

The following table summarizes information about stock options outstanding and exercisable at September 30, 2014:

	Options outstanding				Options exercisable
Exercise price (CDN$)	Number of options		Weighted average remaining life (years)		Number of options		Weighted average remaining life (years)
$0.30 to $0.60		3,547,500		1.33		3,547,500		1.32
$0.80		2,612,500		1.81		2,612,500		1.81
		6,160,000		1.54		6,160,000		1.54

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LYNDEN ENERGY CORP.

Notes to the Condensed Consolidated Interim Financial Statements

September 30, 2014

(Presented in United States dollars, except where indicated)

(Unaudited)

8. 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.

	September 30, 2014		September 30, 2013
Legal fees	$	15,069	$	9,708
Transportation and marketing costs with Abajo		9,380		7,725
	$	24,449	$	17,433

Trade and other payables include $13,594 (June 30, 2014 - $47,014) owing to related parties. Amounts due to or from related parties are unsecured, non-interest bearing and are due on demand.

9. Financial Instruments

As at September 30, 2014, the Company’s financial instruments are cash and cash equivalents, trade and other receivables, credit facility, and trade and other payables.

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. There have not been any changes to the Company’s exposure to risks, or the objectives, policies and processes to manage these risks from June 30, 2014.

a) Credit risk

The aging of trade and other receivables are as follows:

	September 30, 2014		June 30, 2014
Trade and other receivables
0 to 60 days	$	2,869,574	$	3,083,365
61 to 120 days		8,357		6,762
> 120 days1		59,652		52,890
	$	2,937,583	$	3,143,017

¹ Utah State withholding taxes on P&NG sales.

- 97 -

LYNDEN ENERGY CORP.

Notes to the Condensed Consolidated Interim Financial Statements

September 30, 2014

(Presented in United States dollars, except where indicated)

(Unaudited)

9. Financial Instruments (cont’d)

b) Liquidity Risk

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

	Total		Less than 1 year		One to two years		More than two years
Credit facility1	$	23,412,645	$	—	$	23,412,645	$	—
Trade and other payables		1,126,368		1,126,368		—		—
	$	24,539,013	$	1,126,368	$	23,412,645	$	—

¹ Includes accrued interest of $112,645.

c) Currency Risk

As at September 30, 2014, a 10% depreciation or appreciation of the Canadian dollar against the United States dollar would result in an increase or decrease, respectively, in the Company’s earnings or loss by $1,074,084, based on the net exposures presented below:

	Cash		Trade and other receivables		Trade and other payables			Net assets exposure		Effect of +/- 10% change in currency
Canadian dollar denomination	$	10,884,867	$	11,904	$	(155,931	)	$	10,740,840	$	1,074,084

10. Supplemental Cash Flow Information

	September 30, 2014		September 30, 2013
Non-cash financing activities:
Fair value of stock options transferred to common shares on exercise of stock options	$	107,526	$	—
Fair value of warrants transferred to common shares on exercise of warrants	$	—	$	630,195

11. Segmented Information

At September 30, 2014 the Company has one reportable operating segment, being the acquisition, exploration and development of petroleum and natural gas properties. The Company operates in two reportable geographic areas, being Canada and the United States of America.

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

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

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

• for which discrete financial information is available.

- 98 -

LYNDEN ENERGY CORP.

Notes to the Condensed Consolidated Interim Financial Statements

September 30, 2014

(Presented in United States dollars, except where indicated)

(Unaudited)

11. Segmented Information (cont’d)

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

	Canada		USA		Consolidated Total
Revenue and other income
Three months ended September 30, 2014	$	37,826	$	7,934,867	$	7,972,693
Three months ended September 30, 2013	$	671	$	8,822,078	$	8,822,749
Property, plant and equipment
As at June 30, 2014	$	851	$	98,660,420	$	98,661,271
As at June 30, 2014	$	1,021	$	91,811,506	$	91,812,527

- 99 -

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, 2014 and June 30, 2013, and the related consolidated statements of income and comprehensive income, 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 the Company as of June 30, 2014 and June 30, 2013, and the results of its operations and its cash flows for each of the years then ended, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 17 to the consolidated financial statements, the accompanying consolidated financial statements have been restated to correct a misstatement.

/s/ Deloitte LLP

Chartered Accountants

Vancouver, Canada

October 28, 2014 (December 29, 2014 as to the effects of the restatement discussed in Note 17)

- 100 -

LYNDEN ENERGY CORP.

Consolidated Balance Sheets

(Presented in United States dollars, except where indicated)

	Notes		June 30, 2014			June 30, 2013 (Restated-Note 17)
ASSETS
Current assets
Cash and cash equivalents			$	13,955,890		$	1,874,400
Trade and other receivables, net of allowance for doubtful accounts		4		3,143,017			2,612,374
Income taxes receivable				200,000			—
Total current assets				17,298,907			4,486,774
Non-current assets
Property, plant and equipment		6		91,812,527			73,984,820
Total assets			$	109,111,434		$	78,471,594
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Credit facility		9	$	—		$	26,601,653
Trade and other payables		8,12		2,971,177			220,425
Income taxes payable				380,000			103,922
Total current liabilities				3,351,177			26,926,000
Non-current liabilities
Credit facility		9		17,853,245			—
Asset retirement liabilities		10		240,208			200,531
Deferred tax liabilities		16		14,902,811			6,348,076
				32,996,264			6,548,607
Total liabilities				36,347,441			33,474,607
Shareholders’ equity
Share capital—authorized unlimited common shares, no par value
Issued and outstanding: June 30, 2014—129,275,911
June 30, 2013—110,505,520		11		65,160,387			49,279,688
Paid-in capital		11		15,434,128			18,598,870
Accumulated other comprehensive income (loss)				(212,663	)		139,939
Retained earnings (Deficit)				(7,617,859	)		(23,021,510	)
Total shareholders’ equity				72,763,993			44,996,987
Total liabilities and shareholders’ equity			$	109,111,434		$	78,471,594
Subsequent events		18

- 101 -

LYNDEN ENERGY CORP.

Consolidated Statements of Income and Comprehensive Income

(Presented in United States dollars, except where indicated)

	Notes		Year ended June 30, 2014 (Restated-Note 17)			Year ended June 30, 2013 (Restated-Note 17)
Revenue and other income
Petroleum and natural gas sales, net of royalties			$	29,366,595		$	18,953,732
Derivative financial instruments gain (loss)		13		(63,633	)		15,163
Interest income				89,990			12,573
Total revenue and other income				29,392,952			18,981,468
Expenses
Production and operating expenses				(4,949,932	)		(3,019,360	)
Depletion, depreciation and accretion				(7,917,230	)		(5,931,851	)
Exploration				(253,504	)		(278,457	)
Foreign exchange gain (loss)				(5,835	)		(52,030	)
General and administrative				(1,384,587	)		(1,689,720	)
Interest				(283,183	)		(260,974	)
Total expenses				(14,794,271	)		(11,232,392	)
Other income
Gain on disposition of property, plant and equipment		6,7		10,219,755			11,255,320
Income before income taxes				24,818,436			19,004,396
Income tax expense (recovery)		16		9,414,785			7,269,852
Net income				15,403,651			11,734,544
Other comprehensive income (loss)
Foreign currency translation adjustment				(352,602	)		128,387
Total comprehensive income for the year			$	15,051,049		$	11,862,931
Weighted average number of common shares outstanding
Basic		11		123,798,574			110,138,794
Diluted		11		127,399,949			113,824,479
Net earnings per common share
Basic			$	0.12		$	0.11
Diluted			$	0.12		$	0.10

- 102 -

LYNDEN ENERGY CORP.

Consolidated Statement of Changes in Shareholders’ Equity

(Presented in United States dollars, except where indicated)

	Notes	Year ended June 30, 2014			Year ended June 30, 2013
Share capital
Balance, beginning of year		$	49,279,688		$	48,755,838
Common shares issued for cash:
Private placement			—			—
Share issue costs on private placement			—			—
Exercise of stock options			—			75,808
Exercise of warrants			15,880,699			448,042
Balance, end of year		$	65,160,387		$	49,279,688
Paid-in capital
Balance, beginning of year		$	18,598,870		$	18,063,623
Private placement			—			—
Share issue costs on private placement			—			—
Exercise of stock options			—			(32,085	)
Exercise of warrants			(3,220,425	)		(88,532	)
Share-based payments			55,683			655,864
Balance, end of year		$	15,434,128		$	18,598,870
Accumulated other comprehensive income (loss)
Balance, beginning of year		$	139,939		$	11,552
Foreign currency translation			(352,602	)		128,387
Balance, end of year		$	(212,663	)	$	139,939
Deficit (Restated-Note 17)
Balance, beginning of year		$	(23,021,510	)	$	(34,756,054	)
Net income			15,403,651			11,734,544
Balance, end of year		$	(7,617,859	)	$	(23,021,510	)
Total shareholders’ equity		$	72,763,993		$	44,996,987
Common shares—number
Balance, beginning of year			110,505,520			109,865,520
Private placement			—			—
Share issue costs on private placement			—			—
Exercise of stock options			—			125,000
Exercise of warrants			18,770,391			515,000
Balance, end of year			129,275,911			110,505,520

- 103 -

LYNDEN ENERGY CORP.

Consolidated Statements of Cash Flows

(Presented in United States dollars, except where indicated)

	Notes		Year ended June 30, 2014 (Restated-Note 17)			Year ended June 30, 2013 (Restated-Note 17)
Operating activities
Earnings for the year			$	15,403,651		$	11,734,544
Adjustments for:
Unrealized loss (gain) on derivative financial instruments				15,163			(15,163	)
Depletion, depreciation, accretion and impairment				7,917,230			5,931,851
Share-based payments				55,683			650,089
Gain on disposition of property, plant and equipment				(10,219,755	)		(11,255,320	)
Deferred income taxes				8,554,735			7,229,852
Unrealized foreign exchange loss (gain)				(196,191	)		149,868
Changes in non-cash working capital items:
Trade and other receivables				(545,806	)		(1,163,033	)
Current taxes receivable				(200,000	)		—
Trade and other payables				697,956			(2,180,247	)
Income taxes payable				276,078			13,922
Cash generated by operating activities				21,758,744			11,096,363
Investing activities
Disposition of property, plant and equipment				20,803,912			25,078,982
Acquisition of property, plant and equipment				(34,235,029	)		(56,167,297	)
Cash used in investing activities				(13,431,117	)		(31,088,315	)
Financing activities
Credit facility				(8,750,000	)		12,000,000
Common shares issued for cash, net of issue costs		11		12,660,274			403,233
Cash generated by financing activities				3,910,274			12,403,233
Effect of exchange rate on cash held in foreign currency				(156,411	)		(15,706	)
Change in cash and cash equivalents during the year				12,081,490			(7,604,425	)
Cash and cash equivalents, beginning of year				1,874,400			9,478,825
Cash and cash equivalents, end of year			$	13,955,890		$	1,874,400
Cash and cash equivalents are composed of:
Cash			$	2,628,377		$	1,874,400
Guaranteed investment certificates				11,327,513			—
			$	13,955,890		$	1,874,400
Supplemental cash flow information		14

- 104 -

LYNDEN ENERGY CORP.

Notes to the Consolidated Financial Statements

For the Year Ended June 30, 2014 and 2013

(Presented in United States dollars, except where indicated)

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

a) Basis of presentation

These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“US GAAP”). These consolidated financial statements present the Company’s financial position as at June 30, 2014 and 2013 and results of operations for the year ended June 30, 2014, and the 2013 and 2012 comparative periods.

b) 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.

The results of subsidiaries acquired or disposed of during the year are included in the consolidated statement of income and comprehensive income from the effective date of acquisition or up to the effective date of disposal, as appropriate.

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 47.99% interest in Abajo Gas Transmission Company, LLC is accounted for using the equity method (note 5).

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.

c) 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.

- 105 -

LYNDEN ENERGY CORP.

Notes to the Consolidated Financial Statements

For the Year Ended June 30, 2014 and 2013

(Presented in United States dollars, except where indicated)

2. Significant Accounting Policies (cont’d)

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.

d) Use of estimates

The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the amount and timing of recording of assets, liabilities, revenues and expenses since the determination of these amounts may be dependent on future events. Significant estimates made by management include: oil and natural gas reserves and related present value of future cash flows, depreciation, depletion, amortization and accretion (“DDA&A”), impairment, asset retirement obligations, income taxes, and share-based compensation. The Company uses the most current information available and exercises judgment in making these estimates and assumptions. 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.

e) 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. The Company had $11,327,513 (2013—$nil) in cash equivalents at June 30, 2014.

f) Trade and other receivables and allowance for doubtful accounts

CrownQuest Operating LLC (“CrownQuest”) markets CrownRock LP’s (“CrownRock”), and by extension, the Company’s, oil and natural gas to various customers. As discussed in note 6, the Company is party to various participation agreements with CrownRock. Oil and natural gas sales receivables are generally unsecured. CrownQuest monitors exposure to these customers primarily by reviewing credit ratings, financial statements and payment history. CrownQuest extends credit terms based on their evaluation of each customer’s creditworthiness. Receivables are considered past due if

- 106 -

LYNDEN ENERGY CORP.

Notes to the Consolidated Financial Statements

For the Year Ended June 30, 2014 and 2013

(Presented in United States dollars, except where indicated)

2. Significant Accounting Policies (cont’d)

full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. The Company does not have any off balance sheet credit exposure related to its customers.

g) 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 carries as an asset exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where the company is making sufficient progress assessing the reserves and the economic and operating viability of the project. 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

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LYNDEN ENERGY CORP.

Notes to the Consolidated Financial Statements

For the Year Ended June 30, 2014 and 2013

(Presented in United States dollars, except where indicated)

2. Significant Accounting Policies (cont’d)

commodity prices. Annual volumes are based on field production profiles, which are also updated annually.

Impairment analyses are generally 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.

h) Asset retirement obligations

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.

i) 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.

j) 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”).

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LYNDEN ENERGY CORP.

Notes to the Consolidated Financial Statements

For the Year Ended June 30, 2014 and 2013

(Presented in United States dollars, except where indicated)

2. Significant Accounting Policies (cont’d)

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.

k) 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.

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LYNDEN ENERGY CORP.

Notes to the Consolidated Financial Statements

For the Year Ended June 30, 2014 and 2013

(Presented in United States dollars, except where indicated)

2. Significant Accounting Policies (cont’d)

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.

l) 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.

m) 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.

o) Net income per share

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

- 110 -

LYNDEN ENERGY CORP.

Notes to the Consolidated Financial Statements

For the Year Ended June 30, 2014 and 2013

(Presented in United States dollars, except where indicated)

2. Significant Accounting Policies (cont’d)

For the diluted net income 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. 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.

p) Interest capitalization

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

q) Recent accounting pronouncements

As of July 1, 2014, the Company will adopt the following FASB accounting standards updates, which have been issued but are not yet effective. The adoption of these standards is not expected to have any material impact on the Company’s consolidated financial statements.

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

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

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

• Accounting Standards Update 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity

• Accounting Standards Update 2014-09, Revenue From Contracts With Customers

• Accounting Standards Update 2014-15, Disclosure of Uncertainties About an Entity’s Ability to Continue as a Going Concern

4. Trade and Other Receivables

	June 30, 2014		June 30, 2013
Accounts receivable—trade	$	2,572,761	$	1,729,691
Accrued receivables		496,947		817,727
Sales taxes receivable		73,308		64,956
	$	3,143,016	$	2,612,374

The Company did not have any allowance for doubtful accounts as at June 30, 2014 and 2013. As at June 30, 2014, $2,991,585 (2013—$2,376,774) is owing from one counterparty.

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LYNDEN ENERGY CORP.

Notes to the Consolidated Financial Statements

For the Year Ended June 30, 2014 and 2013

(Presented in United States dollars, except where indicated)

5. Investment in Associate

In October 2007, the Company participated, along with its Paradox Basin partners, in the formation of a Utah, USA based natural gas transmission company, Abajo Gas Transmission Company, LLC (“Abajo”). The Company purchased a 47.99% interest in Abajo through capital contributions totaling $5,135,000. Abajo holds ownership of the gas gathering systems in the Northern and Southern Prospect Areas of the Company’s Paradox Basin Project (note 7). Through its interest in Abajo, the Company is entitled to 55% of the revenues and expenses attributable to the construction, operation, maintenance and expansion of the gas gathering system in the Northern Prospect Area and 25% in the Southern Prospect Area.

The Company exerts significant influence over Abajo as a result of its 47.99% interest. However, as a result of the Company’s partner holding a 50.60% 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, 2014 and June 30, 2013 and for the twelve month periods ended June 30, 2014 and 2013:

	June 30, 2014		June 30, 2013
Total assets	$	1,682,118	$	1,883,384
Total liabilities	$	861,934	$	823,393
Revenues	$	88,617	$	101,363
Loss	$	239,804	$	219,422

The Company’s cumulative share of losses attributable to Abajo from July 1, 2010 to June 30, 2013 that have not been recognized amounts to $4,579,298 and $148,959 for the year ended June 30, 2014.

6. Property, Plant and Equipment

	June 30, 2014
	Cost		Accumulated Depletion, Depreciation and Impairment			Net Book Value
Petroleum and natural gas properties
Proved	$	100,407,384	$	(12,781,939	)	$	87,625,445
Suspended exploratory well costs		30,972,613		(26,786,552	)		4,186,061
		131,379,998		(39,568,491	)		91,811,506
Computer equipment		4,820		(3,799	)		1,021
Total property, plant and equipment	$	131,384,818	$	(39,572,290	)	$	91,812,527

- 112 -

LYNDEN ENERGY CORP.

Notes to the Consolidated Financial Statements

For the Year Ended June 30, 2014 and 2013

(Presented in United States dollars, except where indicated)

6. Property, Plant and Equipment (cont’d)

	June 30, 2013
	Cost		Accumulated Depletion, Depreciation and Impairment			Net Book Value
Petroleum and natural gas properties
Proved	$	76,891,477	$	(6,937,146	)	$	69,954,331
Suspended exploratory well costs		30,817,041		(26,786,552	)		4,030,489
		107,708,518		(33,723,698	)		73,984,820
Computer equipment		3,337		(3,337	)		-
Total property, plant and equipment	$	107,711,855	$	(33,727,035	)	$	73,984,820

The Company has capitalized $840,320 (2013—$885,779) of interest expense during 2014 to proved assets. The Company has pledged its interest in its property, plant and equipment to the issuer of its Credit Facility as security.

Development and Production Assets – Midland Basin

The Company is party to a Participation Agreement with CrownRock to acquire interests up to 43.75% in P&NG leases located in the Glasscock, Howard, Martin, Midland and Sterling counties of West Texas, USA.

The Company will receive 43.75% of the vendor’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 the vendor’s interest.

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 $9.62 million.

In December 2012, the Company disposed of 16 gross (7.0 net) vertical Midland Basin wells and underlying leases covering approximately 1,440 gross acres (630 acres net) for gross proceeds of $25.1 million, subject to customary post–closing adjustments. The Company recognized a gain of $11.3 million.

7. Suspended Exploratory Well Costs

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.

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LYNDEN ENERGY CORP.

Notes to the Consolidated Financial Statements

For the Year Ended June 30, 2014 and 2013

(Presented in United States dollars, except where indicated)

7. Suspended Exploratory Well Costs (cont’d)

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.

	Paradox Basin			Mitchell Ranch		Total
As at June 30, 2012	$	445,706		$	3,360,704	$	3,806,410
Additions pending the determination of proved reserves		—			224,079		224,079
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

a) Paradox Basin

The Company has a 55% before payout working interest (41.25% after payout) in an 80% net revenue interest in the Paradox Basin Project – Northern Prospect Area consisting of P&NG leases located in the Paradox Basin, Utah.

The Company has a 25% before payout working interest (23.75% after payout working interest) in an 85% to 87% net revenue interest in the Paradox Basin Project – Southern Prospect Area consisting of P&NG leases located in the Paradox Basin, Utah.

During the year ended June 30, 2014, the Company received $119,118 (2013—$99,892) of sales of P&NG net of royalties and production costs from its Paradox Basin Project.

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

b) Mitchell Ranch

The Company is party to a Participation Agreement with CrownRock LP (“CrownRock”) pertaining to a 50% working interest in 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. Pursuant to the Participation Agreement, the Company is required to make an additional $1,500,000 payment to CrownRock upon the achievement of a drilling milestone.

In July 2011, the Company and CrownRock completed a term assignment with a large, independent exploration and production company, covering approximately 35,000 acres (“Term Assignment Acreage”) of the 104,000 acre Mitchell Ranch Project. On March 31, 2014 the Term Assignment Acreage was returned to the Company and CrownRock.

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LYNDEN ENERGY CORP.

Notes to the Consolidated Financial Statements

For the Year Ended June 30, 2014 and 2013

(Presented in United States dollars, except where indicated)

7. Suspended Exploratory Well Costs (cont’d)

The Company has a 50% working interest in the approximately 104,000 acres of the Mitchell Ranch Project.

During the year ended June 30, 2014, the Company received $81,374 (2013—$87,808) of sales of P&NG net of royalties and production costs from its Mitchell Ranch Project.

8. Trade and Other Payables

	June 30, 2014		June 30, 2013
Accounts payable—trade	$	2,693,097	$	163,377
Accrued liabilities		278,080		57,048
	$	2,971,177	$	220,425

As at June 30, 2014, $2,486,438 (2013—$68,261) is due to one counterparty.

9. Credit Facility

The Company has a reducing revolving line of credit (the “Credit Facility”) in an amount up to $100 million. As of June 30, 2014, the Credit Facility has a borrowing base of $32 million, of which $17.75 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 also apply. Increases in the borrowing base will be made based on the bank’s engineering valuation of the Company’s oil and gas reserves. The borrowing base will be re-determined semi-annually; however, the Company may request two additional re-determinations of the borrowing base annually.

The Credit Facility contains certain mandatory covenants, including minimum current ratio and cash flow requirements, and other standard business operating covenants. The terms of the Credit Facility also require the Company to seek written consent from the bank prior to paying any dividends. The Company has complied with all of these covenants as at and during the year ended June 30, 2014. The Company has pledged its interest in its P&NG and other assets as security for liabilities pursuant to the Credit Facility. All 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.

10. Asset Retirement Obligations

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 $3,565,671 as at June 30, 2014 (June 30, 2013—$2,803,000). These payments are expected to be made over the next 11 to 35 years. The Company used a weighted-average credit adjusted risk free rate of 10.2% to calculate the present value of the decommissioning liabilities.

- 115 -

LYNDEN ENERGY CORP.

Notes to the Consolidated Financial Statements

For the Year Ended June 30, 2014 and 2013

(Presented in United States dollars, except where indicated)

10. Asset Retirement Obligations (cont’d)

As at June 30, 2012	$	149,664
Liabilities incurred		52,205
Property dispositions		(16,890	)
Accretion		15,709
Revisions in estimated liabilities		(157	)
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

11. Shareholders’ Equity

a) Authorized share capital:

An unlimited number of common shares without par value.

An unlimited number of preference shares without par value.

b) The Company completed the following private placements during the years ended June 30, 2014, 2013, and 2012:

In May 2012, the Company closed a non-brokered private placement for gross proceeds of CDN$6,300,000. These funds were raised through the issuance of 15,000,000 units at a price of CDN$0.42 per unit. Each unit is comprised of one common share and one-half of one common share purchase warrant. The total proceeds were allocated to common shares in the amount of CDN$5,200,360 and to warrants in the amount of CDN$1,099,640 based on their relative fair values on the dates of closing.

The private placement closed in two stages and therefore 5,067,500 warrants expire on May 4, 2015 and 2,432,500 warrants expire on May 18, 2015. Each share purchase warrant entitles the holder to purchase one additional common share at a price of CDN$0.65 per common share.

The Company incurred total share issue costs on the private placement of CDN$50,601 which were allocated to common shares in the amount of CDN$41,769 and to warrants in the amount of CDN$8,832 based on their relative fair values. Of these costs, CDN$38,001 was incurred in cash and CDN$12,600 was incurred through the issuance of 30,000 units with the same terms as those issued in the private placement.

c) Warrants:

The changes in warrants issued during the years ended June 30, 2014, 2013, and 2012 are as follows:

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LYNDEN ENERGY CORP.

Notes to the Consolidated Financial Statements

For the Year Ended June 30, 2014 and 2013

(Presented in United States dollars, except where indicated)

11. Shareholders’ Equity (cont’d)

	Number of warrants			Weighted average exercise price (CDN$)
As at June 30, 2012		27,930,760		$	0.69
Exercised		(515,000	)	$	0.70
Expired		—		$	—
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

Warrants exercisable and outstanding as at June 30, 2014 are as follows:

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

d) Earnings per share:

Diluted earnings per share computation

	June 30, 2014 (Restated-Note 17)		June 30, 2013 (Restated-Note 17)
Numerator:
Net earnings	$	15,403,651	$	11,734,544
Denominator:
Weighted average number of common shares (basic)		123,798,574		110,138,794
Dilutive effect of share options		1,626,501		1,221,626
Dilutive effect of warrants		1,974,874		2,464,059
Weighted average number of common shares (diluted)		127,399,949		113,824,479
Diluted earnings per common share	$	0.12	$	0.10

There are nil (2013 – nil) warrants and 2,612,500 (2013 – 2,620,000) stock options that are not dilutive as at June 30, 2014 and are not included in the calculation of diluted earnings per share.

- 117 -

LYNDEN ENERGY CORP.

Notes to the Consolidated Financial Statements

For the Year Ended June 30, 2014 and 2013

(Presented in United States dollars, except where indicated)

11. Shareholders’ Equity (cont’d)

e) 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, 2014. The Company recognized $55,683 for share-based payments for stock options granted in prior years.

During the year ended June 30, 2013, the Company granted 1,397,500 stock options to officers, directors and employees. The Company recognized $650,089 for share-based payments.

The fair value of stock options granted is estimated using the Black-Scholes Option Pricing Model with the following details and assumptions:

	June 30, 2014		June 30, 2013
Weighted average fair value at grant date (CDN$)		n/a	$	0.35
Average risk-free interest rate		n/a		1.31	%
Expected life		n/a		5 years
Expected volatility		n/a		97	%
Expected dividend yield		n/a		0	%
Forfeiture rate		n/a		1	%

The expected volatility assumption is based on the historical volatility of the Company’s common share price on the TSX Venture Exchange. The risk-free interest rate is based on yield curves on the Canadian government zero-coupon bonds or Canadian government treasury bills with a remaining term equal to the stock options’ expected life.

The changes in stock options issued during the years ended June, 2014, 2013, and 2012 are as follows:

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LYNDEN ENERGY CORP.

Notes to the Consolidated Financial Statements

For the Year Ended June 30, 2014 and 2013

(Presented in United States dollars, except where indicated)

11. Shareholders’ Equity (cont’d)

	Number of options			Weighted average exercise price (CDN$)
As at June 30, 2012		7,600,000		$	0.81
Granted		1,397,500		$	0.50
Exercised		(125,000	)	$	0.35
Expired		(2,005,000	)	$	1.31
Forfeited		(5,000	)	$	0.80
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

The following table summarizes information about stock options outstanding and exercisable at June 30, 2014:

	Options outstanding				Options exercisable
Exercise price (CDN$)	Number of options		Weighted average remaining life (years)		Number of options		Weighted average remaining life (years)
$0.30 to $0.60		4,020,000		1.43		4,020,000		1.43
$0.70 to $0.80		2,612,500		2.06		2,612,500		2.06
		6,632,500		1.68		6,632,500		1.68

12. 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.

	June 30, 2014		June 30, 2013
Legal fees		38,972		22,201
Transportation and marketing costs with Abajo		41,322		31,239
	$	80,294	$	53,440

Trade and other payables include $47,014 (June 30, 2013—$21,058) owing to related parties. Amounts due to or from related parties are unsecured, non-interest bearing and are due on demand.

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LYNDEN ENERGY CORP.

Notes to the Consolidated Financial Statements

For the Year Ended June 30, 2014 and 2013

(Presented in United States dollars, except where indicated)

13. Financial Instruments

As at June 30, 2014, 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 commodity derivative liability expired during the year ended June 30, 2014.

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.

a) 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, 2014 and 2013. As at June 30, 2014, $2,991,585 (2013—$2,376,774) is owing from CrownQuest.

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LYNDEN ENERGY CORP.

Notes to the Consolidated Financial Statements

For the Year Ended June 30, 2014 and 2013

(Presented in United States dollars, except where indicated)

13. Financial Instruments  (cont’d)

b) 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.

Re-payments 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	$	17,853,245	$	—	$	—	$	17,853,245
Trade and other payables		2,971,177		2,971,177		—		—
Income taxes payable		380,000		380,000		—		—
	$	21,204,422	$	3,351,177	$	—	$	17,853,245

¹includes accrued interest of $103,245.

c) 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.

i) 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. As at June 30, 2014, a 1% change in interest rates would have had a negligible impact on the Company’s earnings and comprehensive earnings for the year ended June 30, 2014.

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LYNDEN ENERGY CORP.

Notes to the Consolidated Financial Statements

For the Year Ended June 30, 2014 and 2013

(Presented in United States dollars, except where indicated)

13. Financial Instruments  (cont’d)

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	$	11,548,317	$	5,300	$	(87,501	)	$	11,466,116	$	1,146,612

Based on the above net exposures at June 30, 2014, a 10% depreciation or appreciation of the Canadian dollar against the United States dollar would result in an increase or decrease, respectively, in the Company’s earnings by $1,146,612.

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 entered into costless collar oil commodity contracts during the years ended June 30, 2014 and 2013. There are no commodity contracts outstanding as at 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 (2013 – gain of $15,163).

14. Supplemental Cash Flow Information

	June 30, 2014		June 30, 2013
Non-cash financing activities:
Fair value of warrants transferred to common shares on exercise of warrants	$	3,220,425	$	88,532
Fair value of options transferred to common shares on exercise of options	$	—	$	32,085
Additional cash flow information:
Interest paid	$	874,226	$	820,353
Taxes paid	$	783,972	$	26,028

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LYNDEN ENERGY CORP.

Notes to the Consolidated Financial Statements

For the Year Ended June 30, 2014 and 2013

(Presented in United States dollars, except where indicated)

15. Segmented Information

At June 30, 2014 the Company has one reportable operating segment, being the acquisition, exploration and development of petroleum and natural gas properties. The Company operates in two reportable geographic areas, being Canada and the United States of America.

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

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

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

• for which discrete financial information is available.

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

	Canada		USA		Consolidated Total
Revenue and other income
Year ended June 30, 2014	$	89,990	$	29,302,962	$	29,392,952
Year ended June 30, 2013	$	12,573	$	18,968,895	$	18,981,468
Property, plant and equipment
As at June 30, 2014	$	1,021	$	91,811,506	$	91,812,527
As at June 30, 2013	$	—	$	73,984,820	$	73,984,820

16. 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, 2014 (Restated-Note 17)			June 30, 2013 (Restated-Note 17)
Net earnings before income taxes	$	24,818,436		$	19,004,395
Combined statutory tax rate		26.00	%		25.25	%
Income tax expense computed at statutory tax rate		6,452,793			4,798,610
Increase (decrease) attributable to:
Changes in valuation allowance		214,513			349,481
Change in estimate		356,201			123,940
Non-deductible (taxable) expenditures		584,411			430,402
Effect of different statutory tax rates on earnings in subsidiaries		2,082,510			1,810,507
Equity investment taxable loss pick-up		(275,643	)		(243,088	)
Income tax expense	$	9,414,785		$	7,269,852
Current income tax expense		860,050			40,000
Deferred income tax expense		8,554,735			7,229,852
Income tax expense	$	9,414,785		$	7,269,852

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LYNDEN ENERGY CORP.

Notes to the Consolidated Financial Statements

For the Year Ended June 30, 2014 and 2013

(Presented in United States dollars, except where indicated)

16. Income Taxes  (cont’d)

Current income tax and deferred income tax for 2014 and 2013 are all US based taxes.

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

	June 30, 2014			June 30, 2013 (Restated-Note 17)
Deferred tax assets:
Decommissioning liabilities	$	81,671		$	68,181
Alternative minimum tax credits		272,830			—
Capital loss carry forwards		17,669			18,347
Share issuance costs		31,315			62,477
Excess tax value of intangibles over book value		463			517
Excess tax value of property, plant and equipment over book value		1,136			1,043
Exploration and evaluation assets		673,948			699,801
Non-capital losses carry forwards		10,149,816			7,175,566
		11,228,848			8,025,932
Valuation allowance		(2,847,991	)		(2,633,478	)
		8,380,857			5,392,454
Deferred tax liabilities:
Credit facility		(264,683	)		(97,236	)
Unrealized mark-to-market gains		(1,006,795	)		(985,159	)
Property, plant and equipment		(22,012,190	)		(10,658,135	)
		(23,283,668	)		(11,740,530	)
Net deferred tax assets (liabilities)	$	(14,902,811	)	$	(6,348,076	)

The Company has income tax loss carry forwards of approximately $23,558,458 (2013—$15,659,628) for US tax purposes. These recognized tax losses will expire between 2031 and 2032.

The Company has unrecognized income tax loss carry forwards of approximately $8,167,152 (2013—$7,331,852) for Canadian tax purposes. These unrecognized tax losses will expire between 2015 and 2034.

The British Columbia provincial corporate tax rate changed effective April 1, 2013, resulting in a change in the Company’s statutory tax rate from 25.25% to 26%.

17. Restatement of deferred income taxes

Subsequent to the issuance of these consolidated financial statements, management identified a material error with regards to the tax bases which were used in the calculation of its deferred income tax expense for

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LYNDEN ENERGY CORP.

Notes to the Consolidated Financial Statements

For the Year Ended June 30, 2014 and 2013

(Presented in United States dollars, except where indicated)

17. Restatement of deferred income taxes  (cont’d)

the years ended June 30, 2014 and June 30, 2013. The correction of the material error results in a decrease in deferred tax expense in the year ended June 30, 2014 of $1,673,866 and a corresponding increase in the deferred tax expense in the year ended June 30, 2013. The deferred tax liabilities at June 30, 2013 increased by $1,673,866 to $6,348,076. There was no change to the consolidated balance sheet at June 30, 2014. There is no impact on cash flows for the years presented. Basic and diluted earnings per share increased by $0.01 per share to $0.12 per share for the year ended June 30, 2014 and decreased by $0.02 per share and $0.03 per share to $0.11 per share and $0.10 per share, respectively for the year ended June 30, 2013.

18. Subsequent Events

Subsequent to June 30, 2014, 447,500 stock options with an exercise price of CDN$0.30 were exercised for gross proceeds of CDN$134,250 and 25,000 stock options with an exercise price of CDN$0.55 were exercised for gross proceeds of CDN$13,750.

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LYNDEN ENERGY CORP.

Supplemental Information on Oil and Gas Exploration and Production Activities

(Presented in United States dollars, except where indicated)

(Unaudited)

Costs Incurred in Oil and 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, 2014 and 2013:

	June 30, 2014		June 30, 2013
Property acquisition costs
Proved	$	24,948	$	293,140
Unproved		12,532		80,673
Exploration costs		415,361		421,863
Development costs		36,229,566		49,982,737
Total costs incurred	$	36,682,407	$	50,778,413

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

Suspended Exploratory Well Costs

The following table summarizes an aging of suspended exploratory well costs as at June 30, 2014:

	Year Costs Incurred
Total	June 30, 2014	June 30, 2013		June 30, 2012 and prior
$4,186,061	$174,389	$	224,079	$	3,787,593

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 and less estimated future income taxes, 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.

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LYNDEN ENERGY CORP.

Supplemental Information on Oil and Gas Exploration and Production Activities

(Presented in United States dollars, except where indicated)

(Unaudited)

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, 2014 and 2013.

	June 30, 2014			June 30, 2013
Future cash flows	$	488,770,334		$	395,565,265
Future production costs		(133,828,860	)		(137,221,987	)
Future development costs		(64,661,351	)		(62,447,810	)
Future income taxes		(86,035,972	)		(52,905,441	)
Future net cash flows		204,244,151			142,990,027
Annual discount at 10% for estimated timing of cash flows		(121,768,244	)		(87,426,517	)
Discounted future net cash flows	$	82,475,908		$	55,563,510

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 year ended June 30, 2014.

	June 30, 2014
Balance, beginning of year	$	55,563,510
Changes resulting from:
Sales of oil and gas produced, net of production costs		(24,416,663	)
Sales of reserves in place		(16,911,630	)
Discoveries and extensions		19,984,162
Changes in prices and production costs		21,170,364
Changes in estimated future development costs		(26,847,805	)
Development costs incurred during the period		36,229,566
Revisions of previous quantity estimates		15,716,557
Net change in income taxes		(13,484,610	)
Accretion of discount		7,129,418
Changes in production rates and other		8,343,039
Net change		26,912,398
Balance, end of year	$	82,475,908

Oil and Gas Reserves

The Company has presented the reserve estimates utilizing an oil price of $100.27 per Bbl and a natural gas price of $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, 2014 were based on reserve reports prepared by a third party engineer. 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.

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LYNDEN ENERGY CORP.

Supplemental Information on Oil and Gas Exploration and Production Activities

(Presented in United States dollars, except where indicated)

(Unaudited)

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, 2014. Oil volumes are expressed in Bbls, natural gas volumes are expressed in Mcf, and total volumes are presented in BOE.

	Oil			Natural Gas			Total
Net Proved Reserves	(Bbls)			(Mcf)			(BOE)
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		326,509			9,344,145			1,883,867
Sales of reserves in place		(808,114	)		(2,451,430	)		(1,216,686	)
Production		(245,268	)		(1,144,521	)		(436,022	)
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

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(b) Exhibits.

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.
4.1**+	Stock Option Plan, dated March 6, 2014.
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**+	Form of Share Purchase Warrant Certificate for share purchase warrants issued on May 4, 2012.
10.13**+	Form of Finder’s Warrant Certificate for finder’s warrants issued on May 4, 2012.
10.14**+	Form of Share Purchase Warrant Certificate for share purchase warrants issued on May 18, 2012.
10.15**+	Services Agreement, dated January 1, 2013, between Lynden Energy Corp and Richard Andrews.
10.16**+	Management Agreement, dated January 1, 2013, between Lynden Energy Corp and Colin Watt.
21.1**	List of Subsidiaries.
23.1*	Consent of Cawley, Gillespie & Associates, Inc.
99.1*	Report of Cawley, Gillespie & Associates, Inc. as of June 30, 2014.
99.2*	Report of Cawley, Gillespic & Associates, Inc. as of June 30, 2013.

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

* Filed herewith.

** Previously filed.

# 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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WHERE YOU CAN FIND MORE INFORMATION

We will be required to file annual and quarterly reports and other information with the SEC. You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C., 20549. Please call 1-800-SEC-0330 for further information on the operation of the Public Reference Room. Our filings will also be available to the public from commercial document retrieval services and at the web site maintained by the SEC at http://www.sec.gov.

EXPERTS

The letter reports of Cawley, Gillespie and Associates, Inc., independent consulting petroleum engineers, and information with respect to our oil and natural gas reserves derived from such reports, have been referred to in this Registration Statement upon the authority of each such firm as experts with respect to such matters covered in such reports and in giving such reports.

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SIGNATURES

Pursuant to the requirements of Section 12 of the Securities Exchange Act of 1934, the registrant has duly caused this Amendment No. 1 to the Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized.

		LYNDEN ENERGY CORP.
Date: December 29, 2014	By:	/s/ Colin Watt
		Colin Watt
		President, Chief Executive Officer, Corporate   Secretary and Director

LYNDEN ENERGY CORP.

Exhibit Index

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.
4.1**+	Stock Option Plan, dated March 6, 2014.
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**+	Form of Share Purchase Warrant Certificate for share purchase warrants issued on May 4, 2012.
10.13**+	Form of Finder’s Warrant Certificate for finder’s warrants issued on May 4, 2012.
10.14**+	Form of Share Purchase Warrant Certificate for share purchase warrants issued on May 18, 2012.
10.15**+	Services Agreement, dated January 1, 2013, between Lynden Energy Corp and Richard Andrews.
10.16**+	Management Agreement, dated January 1, 2013, between Lynden Energy Corp and Colin Watt.
21.1**	List of Subsidiaries.
23.1*	Consent of Cawley, Gillespie & Associates, Inc.
99.1*	Report of Cawley, Gillespie & Associates, Inc. as of June 30, 2014.
99.2*	Report of Cawley, Gillespie & Associates, Inc. as of June 30, 2013.

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

* Filed herewith.

** Previously filed.

# 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.

EX-2.1

Exhibit 2.1

PURCHASE AND SALE AGREEMENT

BETWEEN

LYNDEN USA INC.,

a Utah corporation,

AS SELLER

AND

BREITBURN OPERATING L.P.,

a Delaware limited partnership

AS BUYER

TABLE OF CONTENTS

Article I Assets		1
Section 1.01	Agreement to Sell and Purchase	1
Section 1.02	Assets	1
Section 1.03	Excluded Assets	3
Article II Purchase Price		4
Section 2.01	Purchase Price	4
Section 2.02	Intentionally Omitted	4
Section 2.03	Allocated Values	4
Section 2.04	Effective Time	4
Article III Title Matters		4
Section 3.01	Examination Period	4
Section 3.02	Defensible Title and Permitted Encumbrances	4
Section 3.03	Title Defect	7
Section 3.04	Notice of Title Defects	7
Section 3.05	Remedies for Title Defects	9
Section 3.06	Intentionally Omitted	9
Section 3.07	Preferential Rights To Purchase	9
Section 3.08	Consents to Assignment	9
Section 3.09	Remedies for Title Benefits	10
Section 3.10	Intentionally Omitted	11
Article IV Environmental Matters		11
Section 4.01	Environmental Review	11
Section 4.02	Environmental Definitions	12
Section 4.03	Notice of Environmental Defects	14
Section 4.04	Remedies for Environmental Defects	14
Article V Representations and Warranties of Seller		15
Section 5.01	Seller’s Existence	15
Section 5.02	Legal Power	15
Section 5.03	Execution	16
Section 5.04	Brokers	16
Section 5.05	Bankruptcy	16
Section 5.06	Suits	16
Section 5.07	Royalties	16
Section 5.08	Taxes	16
Section 5.09	Contracts	17
Section 5.10	No Conflict or Violation	17
Section 5.11	Consents; Preferential Rights	17
Section 5.12	Compliance with Laws	17

(i)

Section 5.13	Wells	18
Section 5.14	Proposed Operations or Expenditures	18
Section 5.15	Status of Seller	18
Section 5.16	Intentionally Omitted	18
Section 5.17	Imbalances	18
Section 5.18	Seller’s Knowledge	18
Section 5.19	Affiliate Transactions	18
Section 5.20	Intentionally Omitted	18
Section 5.21	Intentionally Omitted	18
Article VI Representations and Warranties of Buyer		19
Section 6.01	Buyer’s Existence	19
Section 6.02	Legal Power	19
Section 6.03	Execution	19
Section 6.04	Brokers	19
Section 6.05	Bankruptcy	19
Section 6.06	Suits	19
Section 6.07	Qualifications	20
Section 6.08	Investment	20
Section 6.09	Funds	20
Article VII Seller’s Conditions to Close		20
Section 7.01	Representations	20
Section 7.02	Performance	20
Section 7.03	Pending Matters	20
Section 7.04	Purchase Price	20
Section 7.05	Title and Environmental	20
Section 7.06	Execution and Delivery of the Closing Documents	21
Section 7.07	Intentionally Omitted	21
Article VIII Buyer’s Conditions to Close		21
Section 8.01	Representations	21
Section 8.02	Performance	21
Section 8.03	Pending Matters	21
Section 8.04	Execution and Delivery of the Closing Documents	21
Section 8.05	Title and Environmental	21
Section 8.06	Letter Regarding Financial Statements	21
Section 8.07	Intentionally Omitted	21
Section 8.08	Intentionally Omitted	21
Section 8.09	Intentionally Omitted	21
Article IX Tax Matters		22
Section 9.01	Transfer Taxes	22
Section 9.02	Asset Taxes	22
Section 9.03	Purchase Price Allocation	22

(ii)

Section 9.04	Tax Cooperation	23
Section 9.05	754 Elections	23
Section 9.06	Tax Definitions	23
Article X The Closing		24
Section 10.01	Time and Place of the Closing	24
Section 10.02	Adjustments to Purchase Price at the Closing	24
Section 10.03	Closing Statement	26
Section 10.04	Actions of Seller at the Closing	26
Section 10.05	Actions of Buyer at the Closing	27
Article XI Termination		27
Section 11.01	Right of Termination	27
Section 11.02	Effect of Termination	28
Section 11.03	Termination Remedies	28
Section 11.04	Attorneys’ Fees, Etc	28
Article XII Post Closing Obligations		29
Section 12.01	Gas Imbalances	29
Section 12.02	Final Statement	29
Section 12.03	Intentionally Omitted	30
Section 12.04	Financial Statements	30
Section 12.05	Further Cooperation	30
Article XIII Operation of the Assets		30
Section 13.01	Operations after Effective Time	30
Section 13.02	Limitations on the Operational Obligations and Liabilities of Seller	31
Section 13.03	No Liability of Seller	31
Section 13.04	Intentionally Omitted	32
Section 13.05	Casualty Loss	32
Section 13.06	Operatorship	33
Section 13.07	Records	33
Section 13.08	Intentionally Omitted	33
Section 13.09	Intentionally Omitted	33
Article XIV Obligations and Indemnification		33
Section 14.01	Retained Obligations	33
Section 14.02	Assumed Obligations	34
Section 14.03	Buyer’s Indemnification	34
Section 14.04	Seller’s Indemnification	35
Section 14.05	Notices and Defense of Indemnified Matters	35
Section 14.06	Exclusive Remedies	35

(iii)

Article XV Limitations on Representations and Warranties		35
Section 15.01	Disclaimers of Representations and Warranties	35
Section 15.02	Independent Investigation	36
Section 15.03	Survival	37
Article XVI Dispute Resolution		37
Section 16.01	General	37
Section 16.02	Senior Management	37
Section 16.03	Dispute by Independent Expert	37
Section 16.04	Limitation on Arbitration	38
Article XVII Miscellaneous		38
Section 17.01	Names	38
Section 17.02	Expenses	38
Section 17.03	Document Retention	38
Section 17.04	Entire Agreement	39
Section 17.05	Waiver	39
Section 17.06	Publicity	39
Section 17.07	Construction	39
Section 17.08	No Third Party Beneficiaries	39
Section 17.09	Assignment	39
Section 17.10	Governing Law	39
Section 17.11	Notices	40
Section 17.12	Severability	40
Section 17.13	Time of the Essence	40
Section 17.14	Counterpart Execution	40
Section 17.15	Jury Trial Waiver	40
Section 17.16	Financial Statements	41

EXHIBITS AND SCHEDULES

Exhibit A – Subject Interests (Listing of Leases)

Exhibit B – Wells and Interests

Exhibit C – Allocated Values

Exhibit D – Assignment and Bill of Sale

Schedule 1.02(d) – Well Equipment

Schedule 3.02(d)(i) – Permitted Contracts

Schedule 3.07 – Preferential Rights

Schedule 5.06 – Suits

Schedule 5.07 – Royalties in Suspense

Schedule 5.08(b) – Tax Partnerships

Schedule 5.08(c) – Tax Liens

Schedule 5.09 – Material Contracts

Schedule 5.11 – Consents

Schedule 5.12 – Compliance with Laws

(iv)

Schedule 5.13 – Wells

Schedule 5.14 – Proposed Operations or Expenditures

Schedule 12.01 – Imbalances

(v)

DEFINITIONS

TERM	SECTION
Agreed Imbalance	12.01
Agreement	Preamble
Allocated Values	2.02
Asset Taxes	9.06(a)
Assets	1.02
Assignment	10.04(a)
Assumed Obligations	14.02
Audit Firm	17.16(b)
Breaching Party	11.03
Buyer	Preamble
Buyer Indemnitees	14.04
Buyer’s Environmental Consultant	4.01(a)
Buyer’s Environmental Review	4.01(a)
CERCLA	4.02(c)
Closing	10.01
Closing Date	10.01
Contracts	1.02(e)
Defensible Title	3.02
Disputes	16.01
Documents	17.03
Easements	1.02(c)
Effective Time	2.03
Environmental Defect	4.02(a)
Environmental Defect Value	4.02(d)
Environmental Information	4.01(b)
Environmental Laws	4.02(c)
Examination Period	3.01
Exchange Act	17.16(a)
Excluded Assets	1.03
Final Settlement Date	12.02(a)
Final Statement	12.02(a)
Financial Statements	17.16(a)
Governmental Authority	4.02(b)
Hydrocarbons	1.02(d)
Independent Expert	16.03(a)
Leases	1.02(a)
Losses	14.03
Material Contracts	5.09
Net Revenue Interest	3.02(a)
NORM	4.01(c)
Notice of Disagreement	12.02(a)

(i)

TERM	SECTION
Party or Parties	Preamble
Performing Party	11.03
Permitted Encumbrances	3.02(d)
Person	5.09
Personal Property	1.02(d)
Preference Rights	3.07
Property Expenses	10.02(c)
Purchase Price	2.01
Purchase Price Adjustments	10.02(d)
Purchase Price Allocation	9.03
Records	1.02(f)
Retained Obligations	14.01
SEC	17.16(a)
Securities Act	17.16(a)
Seller	Preamble
Seller Indemnitees	14.03
Seller Permits	5.20
Seller’s knowledge	5.18
Specified Retained Obligations	14.01
Statement	10.03
Straddle Period	9.06(b)
Subject Interest(s)	1.02(a)
Tax or Taxes	9.06(c)
Tax Return	9.06(d)
Termination of Participation Agreement	3.06
Third Party	1.02(g)
Third Party Confidential Data	1.03
Title Benefit	3.09(a)
Title Defect	3.03
Title Defect Value	3.04(c)
Transfer Taxes	9.01
Wells	1.02(d)
Working Interest	3.02(b)

(ii)

PURCHASE AND SALE AGREEMENT

This Purchase and Sale Agreement (this “Agreement”) is made and entered into this 12^th day of December, 2013, by and between Lynden USA Inc., a Utah corporation (the “Seller”), and BreitBurn Operating L.P., a Delaware limited partnership (the “Buyer”). Buyer and Seller are collectively referred to herein as the “Parties” and are sometimes referred to individually as a “Party.”

W I T N E S S E T H:

WHEREAS, Seller is willing to sell to Buyer, and Buyer is willing to purchase from Seller, the Assets (as defined in Section 1.02), all upon the terms and conditions hereinafter set forth;

NOW, THEREFORE, in consideration of the mutual benefits derived and to be derived from this Agreement by each Party, Seller and Buyer hereby agree as follows:

Article I

Assets

Section 1.01 Agreement to Sell and Purchase. Subject to and in accordance with the terms and conditions of this Agreement, Buyer agrees to purchase the Assets from Seller, and Seller agrees to sell the Assets to Buyer, effective as of the Effective Time (as defined in Section 2.03).

Section 1.02 Assets. Subject to Section 1.03, the term “Assets” shall mean the following (less and except the Excluded Assets, as hereinafter defined):

(a) all of Seller’s right, title and interest in and to the leasehold estates in and to the oil, gas and mineral leases described or referred to in Exhibit A (the “Leases”) and any overriding royalty interests in and to the lands covered by the Leases, assignments and other documents of title described or referred to in Exhibit A, all as more specifically described in Exhibit A, provided that all of the foregoing are subject to the limitations described in Exhibit A, (as so limited, collectively, the “Subject Interests,” or singularly, a “Subject Interest”);

(b) all of Seller’s right, title and interest in and to all rights incident to the Subject Interests, including, without limitation, all rights with respect to any pooled, communitized or unitized acreage by virtue of any Subject Interest being a part thereof, including all Hydrocarbon (as defined in Subsection (d) of this Section 1.02) production after the Effective Time attributable to the Subject Interests or any such pool or unit allocated to any such Subject Interest;

(c) all of Seller’s right, title and interest in and to all easements, rights-of-way, surface leases, servitudes, permits, licenses, franchises and other

(1)

estates or similar rights and privileges directly related to or used solely in connection with the Subject Interests (the “Easements”), including, without limitation, the Easements described or referred to in Exhibit A;

(d) all of Seller’s (and its affiliates’) right, title and interest in and to all personal property, equipment, fixtures, inventory and improvements located on or used in connection with the Subject Interests and the Easements or with the production, treatment, sale, or disposal of oil, gas or other hydrocarbons (collectively, “Hydrocarbons”), byproducts or waste produced therefrom or attributable thereto, including, without limitation, all wells located on the lands covered by the Subject Interests or on lands with which the Subject Interests may have been pooled, communitized or unitized (whether producing, shut in or abandoned, and whether for production, injection or disposal), including, without limitation, the wells described in Exhibit B (the “Wells”), wellhead equipment, pumps, pumping units, flowlines, gathering systems, piping, tanks, buildings, treatment facilities, injection facilities, disposal facilities, compression facilities, and other materials, supplies, equipment, facilities and machinery, including (i) the central or individual batteries, (ii) the remote tanks, (iii) the pump-off controllers, (iv) radios to transmit pump-off controller and tank information located on or about the Wells and (v) cellular modems, accounts and associated phone numbers specifically installed for electronic alarms (the foregoing (i) through (v) as shown on Schedule 1.02(d)) (collectively, “Personal Property”);

(e) all of Seller’s (and its affiliates’) right, title and interest in and to the extent assignable (provided that Seller shall use commercially reasonable efforts to obtain consent to assignment to Buyer), all contracts, agreements and other arrangements that directly relate to the Subject Interests, the Leases, the Personal Property or the Easements, insofar only as applicable thereto, including, without limitation, production sales contracts, farmout agreements, operating agreements, service agreements, wireless contracts and similar arrangements, excluding the Leases (collectively, the “Contracts”);

(f) all of Seller’s and its affiliates’ books, records, files, all of Seller’s right, title and interest in and to all books muniments of title, reports and similar documents and materials, including, without limitation, lease records, well records, and division order records, well files, title records (including abstracts of title, title opinions and memoranda, and title curative documents related to the Assets), contracts and contract files, and correspondence that relates to the foregoing interests in the possession of, and maintained by, Seller (or its affiliates) (collectively, the “Records”);

(g) all of Seller’s (and its affiliates’) right, title and interest in and to all geological and geophysical data relating to the Subject Interests, other

(2)

than such data which cannot be transferred without the consent of (provided that Seller shall use commercially reasonable efforts to obtain such consent) or payment to any Third Party (unless paid by Buyer). For purposes of this Agreement, “Third Party” means any person or entity, governmental or otherwise, other than Seller or Buyer, and their respective affiliates; the term includes, but is not limited to, working interest owners, royalty owners, lease operators, landowners, service contractors and governmental agencies; and

(h) any other improvements, fixtures, and tangible personal property presently located on the Subject Interests and Wells and utilized in connection with the ownership or operation thereof.

Section 1.03 Excluded Assets. Notwithstanding the foregoing, the Assets shall not include, and there are excepted, reserved and excluded from the sale contemplated hereby (the following, collectively, the “Excluded Assets”): (a) all trade credits and refunds (other than those relating to Taxes, which are governed by (e) below) and all accounts, instruments and general intangibles (as such terms are defined in the Texas Uniform Commercial Code), attributable to the Assets with respect to any period of time prior to the Effective Time, except to the extent relating to pre-Effective Time obligations or liabilities assumed by Buyer under this Agreement; (b) all claims and causes of action of Seller arising from acts, omissions or events occurring prior to the Effective Time, except to the extent relating to pre-Effective Time obligations or liabilities assumed by Buyer under this Agreement; (c) all rights and interests of Seller (i) under any policy or agreement of insurance or indemnity, (ii) under any bond or deposit or (iii) to any insurance or condemnation proceeds or awards arising, in each case, from acts, omissions or events, or damage to or destruction of property, occurring prior to the Effective Time; (d) all Hydrocarbons produced from or attributable to the Subject Interests with respect to all periods prior to the Effective Time, together with all proceeds from the sale of such Hydrocarbons; (e) all claims of Seller for refunds of or loss carry forwards with respect to any Taxes, and refunds for amounts paid in connection with the Assets, attributable to any period prior to the Effective Time; (f) all amounts due or payable to Seller as adjustments to insurance premiums related to the Assets with respect to any period prior to the Effective Time; (g) all proceeds, income or revenues (and any security or other deposits made) attributable to the Assets for any period prior to the Effective Time; (h) all data and other information that cannot be disclosed or assigned to Buyer without the consent of or payment to any Third Party (the “Third Party Confidential Data”); provided that, prior to the Closing, Seller shall use its reasonable efforts to obtain waivers or consents from such Third Parties to the transfer or use of the Third Party Confidential Data to or by Buyer, provided that Buyer pays any fees or other sums of Third Parties requisite to such transfer; (i) all vehicles, vessels, trailers, software, computers and associated peripherals and all radio, telephone and other communications equipment, except for any such items shown on attached Schedule 1.02(d) and/or physically attached to a Well; and (j) any Contracts with respect to which consent to assignment is required but has not been obtained.

(3)

Article II

Purchase Price

Section 2.01 Purchase Price. The total consideration for the purchase, sale and conveyance of the Assets to Buyer is Buyer’s payment to Seller of the sum of Nineteen Million, Two Hundred Ninety-Six Thousand, Four Hundred Sixteen Dollars and No Cents ($19,296,416.00) (the “Purchase Price”), as allocated and as adjusted in accordance with the provisions of this Agreement. The adjusted Purchase Price shall be paid to Seller at the Closing (as defined in Section 10.01) by means of a completed federal funds transfer to an account designated in writing by Seller.

Section 2.02 Intentionally Omitted.

Section 2.03 Allocated Values. Buyer and Seller have agreed on the allocation of values among the Assets as set forth in Exhibit C attached hereto (the “Allocated Values”). Seller and Buyer agree that the Allocated Values shall be used for federal income tax purposes, for computation of any adjustments pursuant to the provisions of Article III and Article IV, and for all other purposes incident to this Agreement.

Section 2.04 Effective Time. If the transactions contemplated hereby are consummated in accordance with the terms and provisions hereof, the ownership of the Assets shall be transferred from Seller to Buyer on the Closing Date, but effective as of 7:00 a.m. local time where the Assets are located on December 30, 2013 (the “Effective Time”).

Article III

Title Matters

Section 3.01 Examination Period. Following the execution date of this Agreement until 5:00 P.M., local time in Midland, Texas on December 20, 2013 (the “Examination Period”), Seller shall permit Buyer and/or its representatives (including Buyer’s Environmental Consultant) to examine, at all reasonable times, in Seller’s offices, all abstracts of title, title opinions, title files, ownership maps, lease files, contract files, assignments, division orders, operating and accounting records and agreements pertaining to the Assets insofar as same may now be in existence and in the possession of Seller, subject to such restrictions on disclosure as may exist under confidentiality agreements or other agreements binding on Seller or such data.

Section 3.02 Defensible Title and Permitted Encumbrances. For purposes of this Agreement, the term “Defensible Title” means, with respect to a given Asset, such ownership by Seller in such Asset during the productive life of that Asset, that, subject to and except for the Permitted Encumbrances (as defined in Subsection (d) of this Section 3.02):

(a) entitles Seller to receive not less than the percentage set forth in Exhibit B as Seller’s “Net Revenue Interest” of all Hydrocarbons produced, saved and marketed from each Well or unit as set forth in Exhibit B, all without reduction, suspension or termination of such interest throughout the productive life of such Well except as specifically set forth in Exhibit B;

(4)

(b) obligates Seller to bear not greater than the percentage set forth in Exhibit B as Seller’s “Working Interest” of the costs and expenses relating to the maintenance, development and operation of each Well or unit as set forth in Exhibit B, all without increase (unless accompanied by a corresponding increase in Seller’s Net Revenue Interest) throughout the productive life of such Well except as specifically set forth in Exhibit B;

(c) is free and clear of all liens, encumbrances and defects in title.

(d) The term “Permitted Encumbrances” shall mean any of the following matters to the extent the same are valid and subsisting and affect the Assets:

(i) The contracts listed on Schedule 3.02(d)(i);

(ii) any (A) undetermined or inchoate liens or charges constituting or securing the payment of expenses that were incurred incidental to the maintenance, development, production or operation of the Assets or for the purpose of developing, producing or processing Hydrocarbons therefrom or therein and (B) materialman’s, mechanics’, repairman’s, employees’, contractors’, operators’ liens under joint operating agreements or other similar liens or charges for liquidated amounts arising in the ordinary course of business which Seller has agreed to pay pursuant to the terms thereof and that are not yet due and payable or are being contested in good faith in the ordinary course of business;

(iii) any liens for Taxes not yet delinquent or, if delinquent, that are being contested in good faith in the ordinary course of business and which Seller has agreed to pay pursuant to the terms hereof;

(iv) the terms, conditions, restrictions, exceptions, reservations, limitations and other matters contained in (including any liens or security interests created by law or reserved in oil and gas leases for royalty, bonus or rental, or created to secure compliance with the terms of) the Leases and any other recorded agreements, instruments and documents that create or reserve to Seller its interest in the Assets, to the extent the same do not reduce the Net Revenue Interests of Seller below those set forth in Exhibit B or increase the Working Interests of Seller above those set forth in Exhibit B without a corresponding increase in the Net Revenue Interest;

(v) any obligations or duties affecting the Assets to any municipality or public authority with respect to any franchise, grant, license or permit and all applicable laws, rules, regulations and orders of any Governmental Authority (as defined in Section 4.02(b));

(5)

(vi) any (A) easements, rights-of-way, servitudes, permits, surface leases and other rights in respect of surface operations, pipelines, grazing, hunting, lodging, canals, ditches, reservoirs or the like and (B) easements for streets, alleys, highways, pipelines, telephone lines, power lines, railways and other similar rights-of-way on, over or in respect of property owned or leased by Seller or over which Seller owns rights-of-way, easements, permits or licenses, to the extent that same do not materially interfere with the ownership of, or oil and gas operations to be conducted on, the Assets;

(vii) all lessors’ royalties, overriding royalties, net profits interests, carried interests, production payments, reversionary interests and other burdens on or deductions from the proceeds of production created or in existence as of the Effective Time, whether recorded or unrecorded, provided that such matters do not operate to reduce the Net Revenue Interests of Seller below those set forth in Exhibit B or increase the Working Interests of Seller above those set forth in Exhibit B without a corresponding increase in the Net Revenue Interests;

(viii) preferential rights to purchase or similar agreements with respect to which (A) waivers or consents are obtained from the appropriate parties for the transaction contemplated hereby or (B) required notices have been given for the transaction contemplated hereby to the holders of such rights and the appropriate period for asserting such rights has expired without an exercise of such rights;

(ix) required Third Party consents to assignments or similar agreements with respect to which (A) waivers or consents are obtained from the appropriate parties for the transaction contemplated hereby, (B) required notices have been given for the transaction contemplated hereby to the holders of such rights and the appropriate period for asserting such rights has expired without an exercise of such rights, or (C) failure to obtain the same does not (i) expressly render the transfer of the applicable Assets void or voidable, (ii) result in lease termination, or (iii) result in liquidated damages.

(x) all rights to consent by, required notices to, filings with, or other actions by Governmental Authorities in connection with the sale or conveyance of oil and gas leases or interests therein that are customarily obtained subsequent to such sale or conveyance;

(xi) division orders to the extent the same do not reduce the Net Revenue Interests of Seller below those set forth in Exhibit B or increase the Working Interests of Seller above those set forth in Exhibit B without a corresponding increase in the Net Revenue Interest;

(6)

(xii) rights reserved to or vested in any Governmental Authority to control or regulate any of the Assets and the applicable laws, rules, and regulations of such Governmental Authorities;

(xiii) any liens of record to be released by Seller at the Closing;

(xiv) all defects and irregularities affecting the Assets which in the aggregate (A) do not operate to (1) reduce the Net Revenue Interest of Seller, (2) increase the proportionate share of costs and expenses of leasehold operations attributable to or to be borne by the Working Interests of Seller, (3) otherwise interfere materially with the operation, value or use of the Assets or (4) that would not be considered material when applying general industry standards or (B) operate to increase the proportionate share of costs and expenses of leasehold operations attributable to or to be borne by the Working Interest of Seller, so long as there is a proportionate increase in Seller’s Net Revenue Interest.

Section 3.03 Title Defect. The term “Title Defect,” as used in this Agreement, shall mean: (a) any encumbrance, encroachment, irregularity, defect in or objection to Seller’s ownership of any Asset (expressly excluding Permitted Encumbrances) that causes Seller not to have Defensible Title to such Asset or (b) any default by Seller under a lease, farmout agreement or other contract or agreement that would (i) have a material adverse affect on the operation, value or use of such Asset, (ii) prevent Seller from receiving the proceeds of production attributable to Seller’s interest therein or (iii) result in cancellation of Seller’s interest therein.

Section 3.04 Notice of Title Defects.

(a) If Buyer discovers any Title Defect affecting any Asset, Buyer shall notify Seller as promptly as possible, but no later than the expiration of the Examination Period of such alleged Title Defect. To be effective, such notice must (i) be in writing, (ii) be received by Seller by 5:00 p.m. Central Standard Time on the expiration date of the Examination Period and (iii) describe the Title Defect in reasonable detail, to the extent then reasonably known by Buyer (including the estimated value of such Title Defect as determined by Buyer). Any matters that may otherwise constitute Title Defects, but of which Seller has not been notified by Buyer in accordance with the foregoing, shall be deemed to have been waived by Buyer for all purposes and shall constitute Permitted Encumbrances.

(b) Upon the receipt of such effective notice from Buyer, Seller, at Seller’s option, shall (i) subject to Section 3.05(a), attempt to cure such Title Defect at any time prior to the Closing or (ii) exclude the affected Asset from the sale and reduce the Purchase Price by the Allocated Value of such affected Asset as set forth on Exhibit C.

(7)

(c) The value attributable to each Title Defect (the “Title Defect Value”) that is asserted by Buyer in the Title Defect notices shall be determined based upon the criteria set forth below:

(i) If the Title Defect is a lien upon any Asset, the Title Defect Value is the amount reasonably expected to be necessary to be paid to remove the lien from the affected Asset.

(ii) If the Title Defect asserted is that the Net Revenue Interest attributable to any Well or unit or Well location is less than that stated in Exhibit C or the Working Interest attributable to any Well or unit or Well location is greater than that stated in Exhibit C, then the Title Defect Value shall take into account the relative change in the interest from Exhibit C and the appropriate Allocated Value attributed to such Asset.

(iii) If the Title Defect represents an obligation, encumbrance, burden or charge upon the affected Asset (including any increase in Working Interest for which there is not a proportionate increase in Net Revenue Interest) for which the economic detriment to Buyer is unliquidated, the amount of the Title Defect Value shall be determined by taking into account the Allocated Value of the affected Asset, the portion of the Asset affected by the Title Defect, the legal effect of the Title Defect, the potential discounted economic effect of the Title Defect over the life of the affected Asset.

(iv) If a Title Defect is not in effect or does not adversely affect an Asset throughout the entire productive life of such Asset, such fact shall be taken into account in determining the Title Defect Value.

(v) The Title Defect Value shall be determined without duplication of any costs or losses included in another Title Defect Value hereunder.

(vi) Notwithstanding anything herein to the contrary, in no event shall a Title Defect Value exceed the Allocated Value of the Wells, units or other Assets affected thereby.

(vii) Such other factors as are reasonably necessary to make a proper evaluation.

(8)

Section 3.05 Remedies for Title Defects.

(a) With respect to each Title Defect that Seller does not cure on or before the Closing, except as otherwise provided in this Section 3.05, the Purchase Price shall be reduced by an amount equal to the Title Defect Value agreed upon in writing by Buyer and Seller or, if Buyer agrees, Seller shall indemnify Buyer pursuant to Section 14.04 against all costs which Buyer may incur in connection with such Title Defect. If any Title Defect is in the nature of an unobtained consent to assignment or other restriction on assignability, the provisions of Section 3.08 shall apply.

(b) Except for those affected Assets which Seller elects to exclude from this transaction pursuant to Section 3.04(b)(ii), if on or before Closing the Parties have not agreed upon the validity of any asserted Title Defect or have not agreed on the Title Defect Value attributable thereto, either Party shall have the right to elect to have the validity of such Title Defect and/or such Title Defect Value determined by an Independent Expert pursuant to Section 16.03; provided that if the validity of any asserted Title Defect, or the Title Defect Value attributable thereto, is not determined before Closing, the affected Asset shall be excluded from the sale and the Purchase Price shall be reduced by the Allocated Value of such affected Asset as set forth on Exhibit C. In no event shall Buyer be required to purchase any such excluded Asset after Closing.

(c) Notwithstanding anything to the contrary in this Agreement, (i) if the value of a given individual Title Defect (or individual Title Benefit (as defined in Section 3.09(a)) does not exceed $50,000 then no adjustment to the Purchase Price shall be made for such Title Defect (or Title Benefit), (ii) if the aggregate adjustment to the Purchase Price determined in accordance with this Agreement for Title Defects and Environmental Defects (as hereinafter defined) does not exceed three percent (3%) of the Purchase Price prior to any adjustments thereto, then no adjustment of the Purchase Price shall be made therefor and (iii) if the aggregate adjustment to the Purchase Price determined in accordance with this Agreement for Title Defects and Environmental Defects does exceed three percent (3%) of the Purchase Price prior to any adjustments thereto, then the Purchase Price shall only be adjusted by the amount of such excess.

Section 3.06 Intentionally Omitted.

Section 3.07 Preferential Rights To Purchase. Schedule 3.07 lists all agreements containing a preferential right to purchase (the “Preference Rights”).

Section 3.08 Consents to Assignment. Seller shall use all reasonable efforts to obtain all necessary consents set forth on Schedule 5.11 from Third Parties to assign the Assets prior to the Closing (other than governmental approvals that are customarily obtained after the Closing) and Buyer shall use reasonable efforts to assist Seller with such efforts. If prior to the Closing, Seller fails to obtain a consent to assign that would invalidate the conveyance of the Asset

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affected by the consent to assign to Buyer or materially affect the value or use of the Asset, then Seller shall retain the affected Asset and the Purchase Price shall be reduced by the Allocated Value of the affected Asset. In no event shall Buyer be required by this provision to pay for any such excluded Asset after Closing. For purposes of the foregoing, consent requirements that do not expressly (i) render transfer of the applicable Assets to Buyer void or voidable if such consent is not obtained, (ii) result in lease termination, or (iii) result in liquidated damages or otherwise materially affect the value or the use of the Asset, shall not be objectionable by Buyer and any such Assets shall be conveyed and paid for at Closing without regard to whether or not consents thereto are obtained. Buyer shall reasonably cooperate with Seller in obtaining any required consent including providing assurances of reasonable financial conditions, but Buyer shall not be required to expend funds or make any other type of financial commitments as a condition of obtaining such consent. Notwithstanding anything herein to the contrary, certain leases on Schedule 5.11 are notated as requiring consent prior to Closing or else the Purchase Price shall be reduced, and if any such notated consent is not obtained prior to Closing, then the Purchase Price shall be reduced by the Allocated Value attributable to the applicable lease and such lease shall not ever be assigned to Buyer.

Section 3.09 Remedies for Title Benefits.

(a) If either Party discovers any Title Benefit during the Examination Period affecting the Assets, it shall promptly notify the other Party in writing thereof on or before the expiration of the Examination Period. Subject to Section 3.05, Seller shall be entitled to an upward adjustment to the Purchase Price pursuant to Section 10.02(a)(iv) with respect to all Title Benefits in excess of $50,000 in an amount mutually agreed upon by the Parties; provided, that notwithstanding anything in this Agreement to the contrary (i) if the aggregate adjustment to the Purchase Price for Title Benefits determined in accordance with this Agreement does not exceed three percent (3%) of the Purchase Price prior to any adjustments thereto, then no adjustment of the Purchase Price shall be made therefor and (ii) if the aggregate adjustment to the Purchase Price for Title Benefits determined in accordance with this Agreement does exceed three percent (3%) of the Purchase Price prior to any adjustments thereto, then the Purchase Price shall only be adjusted by the amount of such excess. For purposes of this Agreement, the term “Title Benefit” shall mean Seller’s interest in any Subject Interest that is greater than or in addition to that set forth in Exhibit B (including, without limitation, a Net Revenue Interest that is greater than that set forth in Exhibit B) or Seller’s Working Interest in any Subject Interest that is less than the Working Interest set forth in Exhibit B (without a corresponding decrease in the Net Revenue Interest). Any matters that may otherwise constitute Title Benefits, but of which Buyer has not been specifically notified by Seller in accordance with the foregoing, shall be deemed to have been waived by Seller for all purposes.

(b) If, with respect to a Title Benefit, the Parties are not deemed to have agreed on the amount of the upward Purchase Price Adjustment or have

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not otherwise agreed on such amount prior to the Closing Date, Seller or Buyer shall have the right to elect to have such Purchase Price Adjustment determined by an Independent Expert pursuant to Section 16.03. If the amount of such adjustment is not determined pursuant to this Agreement by the Closing, the undisputed portion of the Purchase Price with respect to the Asset affected by such Title Benefit shall be paid by Buyer at the Closing and, subject to Section 3.05, upon determination of the amount of such adjustment, any unpaid portion thereof shall be paid by Buyer to Seller.

Section 3.10 Intentionally Omitted.

Article IV

Environmental Matters

Section 4.01 Environmental Review.

(a) Buyer shall have the right to conduct or cause a consultant (“Buyer’s Environmental Consultant”) to conduct an environmental review of the Assets and Seller’s records pertaining to the Assets (as set forth in Section 3.01) prior to the expiration of the Examination Period (“Buyer’s Environmental Review”). The cost and expense of Buyer’s Environmental Review, if any, shall be borne solely by Buyer. The scope of work comprising Buyer’s Environmental Review shall not include any intrusive test or procedure without the prior written consent of Seller. Buyer shall (and shall cause Buyer’s Environmental Consultant to): (i) consult with Seller before conducting any work comprising Buyer’s Environmental Review, (ii) perform all such work in a safe and workmanlike manner and so as to not unreasonably interfere with Seller’s operations and (iii) comply with all applicable laws, rules, and regulations. Seller shall use commercially reasonable efforts to obtain any Third Party consents and otherwise cooperate with Buyer in conducting Buyer’s Environmental Review and any activities related thereto. Seller shall have the right to have a representative or representatives accompany Buyer and Buyer’s Environmental Consultant at all times during Buyer’s Environmental Review. With respect to any samples taken in connection with Buyer’s Environmental Review, Buyer shall take split samples, providing one of each such sample, properly labeled and identified, to Seller. The Parties shall execute a “common undertaking” letter regarding the confidentiality for the Environmental Review where appropriate. Buyer hereby agrees to release, defend, indemnify and hold harmless Seller from and against all claims, losses, damages, costs, expenses, causes of action and judgments of any kind or character (INCLUDING THOSE RESULTING FROM SELLER’S SOLE, JOINT, COMPARATIVE OR CONCURRENT NEGLIGENCE OR STRICT LIABILITY) to the extent arising out of Buyer’s Environmental Review. Buyer hereby covenants and agrees that

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it will have at least $2,000,000 of general liability insurance to cover its indemnification hereunder prior to the commencement of the Environmental Review.

(b) Unless otherwise required by applicable law, Buyer shall (and shall cause Buyer’s Environmental Consultant to) treat confidentially any matters revealed by Buyer’s Environmental Review and any reports or data generated from such review (the “Environmental Information”), and Buyer shall not (and shall cause Buyer’s Environmental Consultant to not) disclose any Environmental Information to any Governmental Authority or other Third Party without the prior written consent of Seller unless otherwise required by law. Unless otherwise required by law, prior to the Closing, Buyer may use the Environmental Information only in connection with the transactions contemplated by this Agreement. If Buyer, Buyer’s Environmental Consultant, or any Third Party to whom Buyer has provided any Environmental Information become legally compelled to disclose any of the Environmental Information, Buyer shall, as soon as reasonably practicable, provide Seller with good faith notice prior to any such disclosure so as to allow Seller to attempt to file any protective order, or seek any other remedy, as it deems appropriate under the circumstances. If this Agreement is terminated prior to the Closing, Buyer shall deliver the Environmental Information to Seller, which Environmental Information shall become the sole property of Seller. Buyer shall provide two (2) copies of the Environmental Information to Seller without charge.

(c) Buyer acknowledges that the Assets have been used for exploration, development, and production of oil and gas and that there may be petroleum, produced water, wastes, or other substances or materials located in, on or under or associated with the Assets. Equipment and sites included in the Assets may contain asbestos, hazardous substances, or naturally occurring radioactive material (“NORM”). NORM may affix or attach itself to the inside of wells, materials, and equipment as scale, or in other forms. The wells, materials, and equipment located on the Assets may contain NORM and other wastes or hazardous substances. NORM containing material and/or other wastes or hazardous substances may have come in contact with various environmental media, including without limitation, water, soils or sediment. Special procedures may be required for the assessment, remediation, removal, transportation, or disposal of environmental media, wastes, asbestos, hazardous substances and NORM from the Assets.

Section 4.02 Environmental Definitions.

(a) Environmental Defects. For purposes of this Agreement, the term “Environmental Defect” shall mean, with respect to any given Asset, any

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environmental condition that (i) constitutes, pursuant to Environmental Laws (as hereinafter defined) in effect as of the date of this Agreement in the jurisdiction in which such Asset is located, violation of such Environmental Laws or environmental permits, (ii) would reasonably be expected to constitute a violation of such Environmental Laws or environmental permits if investigated by a Governmental Authority (as hereinafter defined), regardless of whether Seller has been so notified or investigated by a Governmental Authority or (iii) would require remediation under such Environmental Laws (other than any plugging and abandonment and associated surface restoration obligations under any applicable Environmental Laws, except for any of the foregoing covered by clauses (i) or (ii)).

(b) Governmental Authority. For purposes of this Agreement, the term “Governmental Authority” shall mean, as to any given Asset, the United States and the state, county, parish, city and political subdivisions in which such Asset is located and that exercises jurisdiction over such Asset, and any agency, department, board or other instrumentality thereof that exercises jurisdiction over such Asset.

(c) Environmental Laws. For purposes of this Agreement, the term “Environmental Laws” shall mean all laws, statutes, ordinances, court decisions, rules and regulations of any Governmental Authority pertaining to health or the environment as may be interpreted by applicable court decisions or administrative orders, including, without limitation, the Clean Air Act, as amended, the Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), the Federal Water Pollution Control Act, as amended, the Occupational Safety and Health Act, as amended, the Resources Conservation and Recovery Act, as amended, the Safe Drinking Water Act, as amended, the Toxic Substances Control Act, as amended, the Superfund Amendment and Reauthorization Act of 1986, as amended, the Hazardous Materials Transportation Act, as amended, and comparable state and local laws.

(d) Environmental Defect Value. For purposes of this Agreement, the term “Environmental Defect Value” shall mean, with respect to any Environmental Defect, the value, as of the Closing Date, of the estimated costs and expenses to correct such Environmental Defect in the most cost-effective manner reasonably available, consistent with Environmental Laws, taking into account that non-permanent remedies (such as mechanisms to contain or stabilize hazardous materials, including monitoring site conditions, natural attenuation, risk-based corrective action, institutional controls or other appropriate restrictions on the use of property, caps, dikes, encapsulation, leachate collection systems, etc.) may be the most cost-effective manner reasonably available.

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Section 4.03 Notice of Environmental Defects.

(a) If Buyer discovers any Environmental Defect affecting the Assets, Buyer shall notify Seller prior to the expiration of the Examination Period of such alleged Environmental Defect. To be effective, such notice must: (i) be in writing; (ii) be received by Seller prior to the expiration of the Examination Period and (iii) describe the Environmental Defect in reasonable detail, to the extent reasonably known by Buyer (including the estimated value of such Environmental Defect as determined by Buyer).

(b) Except for the matters described in Section 14.01(f) and Section 14.04(a) as it relates solely to Section 5.13, any matters that may otherwise constitute Environmental Defects, but of which Seller has not been notified by Buyer in accordance with the foregoing, together with any environmental matter that does not constitute an Environmental Defect, shall be deemed to have been waived by Buyer for all purposes and constitute an Assumed Obligation (as defined in Section 14.02). Upon the receipt of such effective notice from Buyer, Seller, at Seller’s option, shall (i) cure such Environmental Defect at any time prior to the Closing or (ii) exclude the affected Asset from the sale and reduce the Purchase Price by the Allocated Value of such affected Asset as set forth on Exhibit C, or (iii) may, with Buyer’s agreement, take any remedial action with respect to the alleged Environmental Defect and indemnify Buyer pursuant to Section 14.04 against all costs which Buyer may incur in connection with same.

Section 4.04 Remedies for Environmental Defects.

(a) If any Environmental Defect described in a notice delivered in accordance with Section 4.03 is not cured on or before the Closing, and Seller has not elected to exclude the affected Assets from this sale or Buyer and Seller have not agreed for Seller to indemnify Buyer for the Environmental Defect, then the Purchase Price shall be reduced by the Environmental Defect Value of such Environmental Defect as agreed by the Parties.

(b) If Buyer and Seller have not agreed as to the validity of any asserted Environmental Defect, or if the Parties have not agreed on the Environmental Defect Value therefor, and if Seller shall not have elected to exclude the affected Assets from this sale pursuant to Section 4.03(b)(ii), then either Party shall have the right to elect to have the validity of the asserted Environmental Defect, and/or the Environmental Defect Value for such Environmental Defect, determined by an Independent Expert pursuant to Section 16.03. If the validity of any such asserted Environmental Defect or the amount of any such Environmental Defect Value is not determined by the Closing, the Asset affected by such disputed Environmental Defect shall be excluded from the Closing and the

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Purchase Price paid at the Closing shall be reduced by the Allocated Value of that Asset. Notwithstanding the foregoing, either Buyer or Seller shall have the right to exclude an Asset from the sale if the Environmental Defect Value exceeds the Allocated Value of the Asset(s) affected thereby. In no event shall Buyer be required to purchase any such excluded Asset after Closing.

(c) Notwithstanding anything to the contrary in this Agreement, (i) if the Environmental Defect Value for a given individual Environmental Defect does not exceed $50,000, then no adjustment to the Purchase Price shall be made for such Environmental Defect; (ii) if the aggregate adjustment to the Purchase Price determined in accordance with this Agreement for Title Defects and Environmental Defects does not exceed three percent (3%) of the Purchase Price prior to any adjustments thereto, then no adjustment of the Purchase Price shall be made therefore and (iii) if the aggregate adjustment to the Purchase Price determined in accordance with this Agreement for Title Defects and Environmental Defects does exceed three percent (3%) of the Purchase Price prior to any adjustments thereto, then the Purchase Price shall only be adjusted by the amount of such excess.

Article V

Representations and Warranties of Seller

Seller represents and warrants and covenants to and with Buyer that:

Section 5.01 Seller’s Existence. Seller is a Utah corporation duly organized, in good standing and validly existing under the laws of the State of Utah and is qualified to conduct business in the State of Texas. Seller has full legal power, right and authority to carry on its business as such is now being conducted and as contemplated to be conducted. Seller’s headquarters and principal offices are all located in Vancouver, British Columbia.

Section 5.02 Legal Power. Seller has the legal power and right to enter into and perform this Agreement and the transactions contemplated hereby. The consummation of the transactions contemplated by this Agreement will not violate, nor be in conflict with:

(a) any provision of Seller’s articles of incorporation or other governing documents;

(b) except for any preferential purchase rights and consents to assignment which constitute Permitted Encumbrances, any agreement or instrument to which Seller is a party or by which Seller or the Assets are bound that will materially adversely affect the Assets or the use, operation, or value thereof following the Closing; or

(c) any judgment, order, ruling or decree applicable to Seller as a party in interest or any law, rule or regulation applicable to Seller that will materially adversely affect the Assets or the use, operation, or value thereof following the Closing.

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Section 5.03 Execution. The execution, delivery and performance of this Agreement and the transactions contemplated hereby are duly and validly authorized by all requisite corporate action on the part of Seller. This Agreement constitutes the legal, valid and binding obligation of Seller enforceable in accordance with its terms, except as such enforceability may be limited by the effect of bankruptcy, insolvency, reorganization, moratorium, and similar laws from time to time in effect relating to the rights and remedies of creditors, as well as to general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law).

Section 5.04 Brokers. No broker or finder is entitled to any brokerage or finder’s fee, or to any commission, based in any way on agreements, arrangements or understandings made by or on behalf of Seller or any affiliate of Seller for which Buyer has or will have any liabilities or obligations (contingent or otherwise), and Seller shall indemnify Buyer with respect thereto.

Section 5.05 Bankruptcy. There are no bankruptcy, reorganization or arrangement proceedings pending, being contemplated by or to the knowledge of Seller threatened against Seller or any of its affiliates.

Section 5.06 Suits. Except as shown on Schedule 5.06, there is no suit, action, claim, investigation or inquiry by any person or entity or by any administrative agency or Governmental Authority and no legal, administrative or arbitration proceeding pending or, to Seller’s knowledge, threatened against Seller or any of its affiliates with respect to the Assets or against any of the Assets.

Section 5.07 Royalties. All rentals, royalties and other payments due under the Subject Interests described in Exhibit A have been paid, except those amounts held in suspense by the operator which are listed on Schedule 5.07.

Section 5.08 Taxes.

(a) Each material Tax Return required to be filed by Seller with respect to the Assets has been timely and properly filed under applicable laws and all material Taxes due and owed by Seller relating to the Assets have been timely and properly paid.

(b) Except as set forth on Schedule 5.08(b), none of the Assets are subject to or owned by any tax partnership (other than Seller) requiring a partnership income Tax Return to be filed under Subchapter K of Chapter 1 of Subtitle A of the Internal Revenue Code.

(c) Except as set forth on Schedule 5.08(c), the Assets are not subject to any lien for Taxes, other than for current period Taxes not yet due and payable.

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(d) Neither Seller nor any of its affiliates has received written notice of any pending claim with respect to the Assets from any taxing authority for assessment of Taxes, and there are no ongoing audits, suits, proceedings, assessments, reassessments, deficiency claims or other claims relating to any Taxes with respect to the Assets by any applicable taxing authority.

(e) Neither Seller nor any of its affiliates have waived any statute of limitations in respect of Asset Taxes, nor has Seller or any of its affiliates agreed to any extension of time with respect to any Asset Tax assessment or deficiency.

Section 5.09 Contracts. Schedule 5.09 sets forth a list of all material Contracts that exist as of the date of this Agreement (the “Material Contracts”). As of the Closing Date, except as set forth on Schedule 5.09, Seller and its affiliates are not in material breach of, or material default under, and to the knowledge of Seller, no other Person is in material breach of, or material default under, any Material Contract, and there does not exist under any provision thereof, to the knowledge of Seller, any event that, with the giving of notice or the lapse of time or both, would constitute such a material breach or material default by any Person. For the purposes of this Agreement, “Person” shall mean any individual, firm, corporation, partnership, limited liability company, joint venture, association, trust, unincorporated organization, Governmental Authority or any other entity.

Section 5.10 No Conflict or Violation. Neither the execution and delivery of this Agreement nor the consummation of the transactions and performance of the terms and conditions contemplated hereby by Seller will (i) conflict with or result in any breach of any provision of the partnership agreement or other governing documents of Seller; (ii) be rendered void or ineffective by or under the terms, conditions or provisions of any agreement, instrument or obligation to which Seller is a party or is subject; (iii) result in a default under the terms, conditions or provisions of any Asset (or of any agreement, instrument or obligation relating to or burdening any Asset); or (iv) violate or be rendered void or ineffective under any law, other than, in the case of the matters described in clauses (ii), (iii) and (iv) of this Section 5.10, the matters referenced in Section 5.11 and such conflicts, breaches, violations, defaults or other events as will not have a material adverse effect on the value of the Assets, taken as a whole.

Section 5.11 Consents; Preferential Rights. Except for (i) consents or approvals of, or filings with, any applicable Governmental Authorities in connection with assignments of the Assets which are not customarily obtained prior to the assignment of the Assets, (ii) Preference Rights and (iii) the consents, filings or notices expressly described and set forth on Schedule 5.11, no material consent, approval, authorization or permit of, or filing with or notification to, any Third Party is required for or in connection with the execution and delivery of this Agreement by Seller or for or in connection with the consummation of the transactions and performance of the terms and conditions contemplated hereby by Seller. All agreements containing a Preference Right are set forth in Schedule 3.07.

Section 5.12 Compliance with Laws. Except with respect to (i) matters set forth on Schedule 5.12 and (ii) compliance with laws concerning taxes (as to which certain representations and warranties are made pursuant to Section 5.08), Seller has no knowledge of any material violation by Seller or any of its affiliates of any law applicable to the Assets.

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Section 5.13 Wells. Except as set forth on Schedule 5.13, there is no Well included in the Assets that:

(i) Seller or any of its affiliates is obligated on the date of this Agreement by law or agreement to cause to be immediately plugged and abandoned; and

(ii) to the knowledge of Seller, has been plugged and abandoned other than in compliance in all material respects with law.

Section 5.14 Proposed Operations or Expenditures. Except as set forth on Schedule 5.14, as of the date of this Agreement, there are no outstanding authorities for expenditure or other commitments to conduct any operations or expend any amount of money on or with respect to the Assets which are binding on Seller or any of its affiliates or the Assets and will be binding on Buyer after the Closing and which Seller reasonably anticipates will require the expenditure of money in excess of $100,000.00 per item (net to Seller’s interest). Seller shall be responsible for all costs incurred in connection with the drilling and completion of the wells described in Schedule 5.14.

Section 5.15 Status of Seller. Seller is not an “investment company” or a company “controlled” by an “investment company” within the meaning of the Investment Company Act of 1940, as amended.

Section 5.16 Intentionally Omitted.

Section 5.17 Imbalances. Except as set forth on Schedule 12.01, there are no well or gas imbalances associated with the Assets as of the Effective Time.

Section 5.18 Seller’s Knowledge. For purposes of this Agreement, the term “Seller’s knowledge” or words of similar import shall mean and refer solely to the actual knowledge of the following representatives of Seller without duty of investigation or inquiry on the part of any of them: Colin Watt.

Section 5.19 Affiliate Transactions. Except for the operating agreements described on Schedule 5.09, none of the Material Contracts are between Seller, on the one hand, and any affiliate of Seller, on the other hand, other than any such Material Contracts that will be terminated at or prior to Closing.

Section 5.20 Intentionally Omitted.

Section 5.21 Intentionally Omitted.

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Article VI

Representations and Warranties of Buyer

Buyer represents and warrants and covenants to and with Seller that:

Section 6.01 Buyer’s Existence. Buyer is a limited partnership, duly organized and validly existing and in good standing under the laws of the State of Delaware and is qualified to conduct business in the State of Texas. Buyer has full legal power, right and authority to carry on its business as such is now being conducted and as contemplated to be conducted.

Section 6.02 Legal Power. Buyer has the legal power and right to enter into and perform this Agreement and the transactions contemplated hereby. The consummation of the transactions contemplated by this Agreement will not violate, nor be in conflict with:

(a) any provision of Buyer’s limited partnership agreement or other governing documents;

(b) any material agreement or instrument to which Buyer is a party or by which Buyer is bound; or

(c) any judgment, order, ruling or decree applicable to Buyer as a party in interest or any law, rule or regulation applicable to Buyer.

Section 6.03 Execution. The execution, delivery and performance of this Agreement and the transactions contemplated hereby are duly and validly authorized by all requisite limited liability company action on the part of Buyer. This Agreement constitutes the legal, valid and binding obligation of Buyer enforceable in accordance with its terms, except as such enforceability may be limited by the effect of bankruptcy, insolvency, reorganization, moratorium, and similar laws from time to time in effect relating to the rights and remedies of creditors, as well as to general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law).

Section 6.04 Brokers. No broker or finder is entitled to any brokerage or finder’s fee, or to any commission, based in any way on agreements, arrangements or understandings made by or on behalf of Buyer or any affiliate of Buyer for which Seller has or will have any liabilities or obligations (contingent or otherwise), and Buyer shall indemnify Seller with respect thereto.

Section 6.05 Bankruptcy. There are no bankruptcy, reorganization or arrangement proceedings pending, being contemplated by or to the knowledge of Buyer threatened against Buyer or any affiliate of Buyer.

Section 6.06 Suits. There is no suit, action, claim, investigation or inquiry by any person or entity or by any administrative agency or Governmental Authority and no legal, administrative or arbitration proceeding pending or, to Buyer’s knowledge, threatened against Buyer or any affiliate of Buyer that has materially affected or will materially affect Buyer’s ability to consummate the transactions contemplated herein.

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Section 6.07 Qualifications. Buyer is qualified with all applicable Governmental Authorities to own and operate the Assets and has all necessary bonds to own and operate the Assets.

Section 6.08 Investment. Prior to entering into this Agreement, Buyer has relied solely on this Agreement and was advised by its own legal, tax and other professional counsel concerning this Agreement, the Assets and the value thereof. Buyer is acquiring the Assets for its own account and not for distribution or resale in any manner that would violate any state or federal securities law, rule, regulation or order. Buyer understands and acknowledges that if any of the Assets were held to be securities, they would be restricted securities and could not be transferred without registration under applicable state and federal securities laws or the availability of an exemption from such registration.

Section 6.09 Funds. Buyer will have arranged to have available by the Closing Date sufficient funds to enable Buyer to pay in full the Purchase Price as herein provided and otherwise to perform its obligations under this Agreement.

Article VII

Seller’s Conditions to Close

The obligations of Seller to consummate the transaction provided for herein are subject, at the option of Seller, to the fulfillment on or prior to the Closing Date of each of the following conditions (except those which by their nature are, or will be, satisfied at the Closing):

Section 7.01 Representations. The representations and warranties of Buyer herein contained shall be true and correct in all material respects on the Closing Date as though made on and as of such date.

Section 7.02 Performance. Buyer shall have performed all material obligations, covenants and agreements contained in this Agreement to be performed or complied with by it at or prior to the Closing.

Section 7.03 Pending Matters. No suit, action or other proceeding shall be pending or threatened that seeks to restrain, enjoin or otherwise prohibit the consummation of the transactions contemplated by this Agreement.

Section 7.04 Purchase Price. Buyer shall have delivered to Seller the Purchase Price, as the same may be adjusted hereunder, in accordance with the provisions of Article II.

Section 7.05 Title and Environmental. The aggregate amount to be deducted from the Purchase Price at the Closing as determined by the Parties on account of Title Defects, Environmental Defects and Casualty Losses, and the Allocated Value of the Assets (or portion thereof) to be excluded on account of preferential purchase rights and consents shall not exceed twenty percent (20%) of the Purchase Price.

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Section 7.06 Execution and Delivery of the Closing Documents. Buyer shall have executed, acknowledged and delivered, as appropriate, to Seller all closing documents described in Section 10.05.

Section 7.07 Intentionally Omitted.

Article VIII

Buyer’s Conditions to Close

The obligations of Buyer to consummate the transaction provided for herein are subject, at the option of Buyer, to the fulfillment on or prior to the Closing Date of each of the following conditions (except those which by their nature are, or will be, satisfied at the Closing):

Section 8.01 Representations. The representations and warranties of Seller herein contained shall be true and correct in all material respects on the Closing Date as though made on and as of such date.

Section 8.02 Performance. Seller shall have performed all material obligations, covenants and agreements contained in this Agreement to be performed or complied with by it at or prior to the Closing.

Section 8.03 Pending Matters. No suit, action or other proceeding shall be pending or threatened that seeks to restrain, enjoin, or otherwise prohibit the consummation of the transactions contemplated by this Agreement.

Section 8.04 Execution and Delivery of the Closing Documents. Seller (or its affiliates) shall have executed, acknowledged and delivered, as appropriate, to Buyer all closing documents described in Section 10.04.

Section 8.05 Title and Environmental. The aggregate amount to be deducted from the Purchase Price at the Closing as determined by the Parties on account of Title Defects, Environmental Defects and Casualty Losses, and the Allocated Value of the Assets (or portion thereof) to be excluded on account of preferential purchase rights and consents shall not exceed 20 percent (20%) of the Purchase Price.

Section 8.06 Letter Regarding Financial Statements. Seller shall have delivered to Buyer the letter required by Section 17.16 regarding impracticability of preparation of carved out financial statements.

Section 8.07 Intentionally Omitted.

Section 8.08 Intentionally Omitted.

Section 8.09 Intentionally Omitted.

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Article IX

Tax Matters

Section 9.01 Transfer Taxes. Buyer and Seller expect that this transaction will not be subject to any sales, use, transfer or similar Taxes (“Transfer Taxes”) because the transaction is a transfer of realty and the transfer of tangible personal property, if any, is incidental to the transfer of realty. Accordingly, no Transfer Taxes will be collected at Closing from Buyer in connection with this transaction. Seller and Buyer agree to cooperate with each other in attempting to demonstrate that the requirements for any exemption from such Taxes have been met. To the extent any Transfer Taxes or recording fees are nevertheless incurred by or imposed with respect to the transfer of the Assets to Buyer pursuant to this Agreement, such Transfer Taxes or recording fees shall be solely the responsibility of Buyer. Buyer and Seller shall reasonably cooperate in good faith to minimize, to the extent permissible under applicable law, the amount of any such Transfer Taxes and recording fees. For the avoidance of doubt, Seller shall retain all liability for and shall pay all income Tax, franchise Tax and similar Taxes imposed on any income or gain realized by Seller pursuant to the transactions contemplated in this Agreement.

Section 9.02 Asset Taxes. Seller shall retain responsibility for and bear all Asset Taxes for (A) any period ending prior to the Effective Time and (B) the portion of any Straddle Period that ends immediately prior to the Effective Time. All Asset Taxes with respect to the ownership or operation of the Assets arising on or after the Effective Time shall be allocated to and borne by Buyer. For purposes of allocation between Seller and Buyer of Asset Taxes that are payable with respect to Straddle Periods, the portion of any such Taxes that are attributable to the portion of the Straddle Period that ends immediately prior to the Effective Time shall (i) in the case of Asset Taxes that are based upon or related to income or receipts or imposed on a transactional basis such as severance or production Taxes, be deemed equal to the amount that would be payable if the tax year or period ended immediately prior to the Effective Time; and (ii) in the case of other Asset Taxes, be deemed equal to the product of (1) the amount of such Asset Taxes multiplied by (2) the quotient of the number of days in the portion of such Straddle Period ending on the day immediately prior to the day on which the Effective Time occurs, divided by the total number of days in such Straddle Period. To the extent the actual amount of Asset Taxes is not determinable at Closing or at the time the Final Statement is prepared, as applicable, Buyer and Seller shall utilize the most recent information available in estimating the amount of Asset Taxes for purposes of Sections 10.02(a)(ii), 10.02(b)(iii), and 12.02. If, at the time the actual amount of an Asset Tax is determined, the amount of such Asset Tax paid by Seller, plus, if applicable, the amount of any adjustment to the Purchase Price with respect to such Asset Tax made pursuant to Section 10.02(b)(iii) and Section 12.02 minus, if applicable, the amount of any adjustment to the Purchase Price with respect to such Asset Tax made pursuant to Section 10.02(a)(ii) and Section 12.02 is (x) less than Seller’s share of the actual amount of such Asset Tax determined pursuant to the foregoing provisions of this Section 9.02, then Seller shall promptly pay Buyer an amount equal to such difference or (y) more than Seller’s share of the actual amount of such Asset Tax, determined pursuant to the foregoing provisions of this Section 9.02, then Buyer shall promptly pay Seller an amount equal to such difference.

Section 9.03 Purchase Price Allocation. Seller and Buyer shall cooperate in the preparation of Internal Revenue Service Form 8594 pursuant to Section 1060 of the Internal

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Revenue Code of 1986, as amended and the Treasury Regulations promulgated thereunder, to report the allocation of the Purchase Price, the Assumed Obligations and any other items constituting consideration for applicable income Tax purposes (to the extent known at such time) among the Assets and in a manner that is, to the maximum extent possible, consistent with the allocation set forth in Exhibit C (the “Purchase Price Allocation”). Buyer and Seller agree to amend the Purchase Price Allocation to reflect adjustments to the Purchase Price and to report the transactions contemplated by this Agreement consistently with the Purchase Price Allocation, as adjusted by the Parties, on any Tax Return, and will not assert, and will cause their affiliates not to assert, in connection with any Tax audit or other proceeding with respect to Taxes, any asset values or other items inconsistent with the amounts set forth in the Purchase Price Allocation except with the agreement of the other Parties or as required by applicable law.

Section 9.04 Tax Cooperation. The Parties shall cooperate fully, as and to the extent reasonably requested by the other Party, in connection with the filing of Tax Returns and any audit, litigation, or other proceeding with respect to Taxes relating to the Assets. Such cooperation shall include the retention and (upon another Party’s request) the provision of records and information that are relevant to any such Tax Return or audit, litigation or other proceeding and making employees available on a mutually convenient basis to provide additional information and explanation of any material provided under this Agreement. Seller and the Buyer agree to retain all books and records with respect to tax matters pertinent to the Assets relating to any tax period beginning before the Effective Time until the expiration of the statute of limitations of the respective tax periods and to abide by all record retention agreements entered into with any taxing authority.

Section 9.05 754 Elections. Seller shall, prior to the Closing, (i) cause each Asset that is classified as (or treated as being held by) a partnership (other than Seller) for federal income tax purposes to either (x) have in effect an election under Section 754 of the Internal Revenue Code for any taxable year that includes the Closing Date or (y) obtain all necessary consents therefor; and (ii) provide evidence satisfactory to Buyer thereof.

Section 9.06 Tax Definitions.

(a) “Asset Taxes” means all ad valorem, property, excise, severance, production or similar Taxes (including any interest, fine, penalty or addition to Tax imposed by a taxing authority in connection with such Taxes) based upon operation or ownership of the Assets or the production of Hydrocarbons therefrom but excluding, for the avoidance of doubt, (a) income, capital gains, franchise and similar Taxes and (b) Transfer Taxes.

(b) “Straddle Period” shall mean any tax period beginning before and ending after the Effective Time.

(c) “Tax” or “Taxes” means (i) all taxes, assessments, fees, and other charges of any kind whatsoever imposed by any taxing authority, including any federal, state, local and/or foreign income tax, surtax, remittance tax, presumptive tax, net worth tax, special contribution tax, production tax, value added tax, withholding tax, gross receipts tax, windfall profits tax,

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profits tax, ad valorem tax, personal property tax, real property tax, sales tax, goods and services tax, service tax, transfer tax, use tax, excise tax, premium tax, stamp tax, motor vehicle tax, entertainment tax, insurance tax, capital stock tax, franchise tax, occupation tax, payroll tax, employment tax, unemployment tax, disability tax, alternative or add-on minimum tax and estimated tax, (ii) any interest, fine, penalty or additions to tax imposed by a taxing authority in connection with any item described in clause (i), and (iii) any liability in respect of any item described in clauses (i) or (ii) above, that arises by reason of a contract, assumption, transferee or successor liability, operation of law (including by reason of participation in a consolidated, combined or unitary Tax Return) or otherwise.

(d) “Tax Return” shall mean any report, return, information statement, schedule, attachment, payee statement or other information required to be provided to any taxing authority with respect to Taxes or any amendment thereof, including any return of an affiliated, combined or unitary group, and any and all work papers relating to any Tax Return.

Article X

The Closing

Section 10.01 Time and Place of the Closing. If the conditions referred to in Articles VII and VIII of this Agreement have been satisfied or waived in writing, the transactions contemplated by this Agreement (the “Closing”) shall take place on December 30, 2013 (the “Closing Date”) electronically, or at such other time and place as may be designated in writing by Buyer and Seller.

Section 10.02 Adjustments to Purchase Price at the Closing.

(a) The Purchase Price shall be increased by the following amounts:

(i) The proceeds of production of Hydrocarbons attributable to the Assets before the Effective Time and received by Buyer, plus to the extent proceeds thereof are or will be received by Buyer, an amount equal to the value of all Hydrocarbons attributable to the Assets that, at the Effective Time, are owned by Seller and are in storage above the pipeline connection based upon the price for which such production is sold (net of all royalties to be paid by or on behalf of Buyer with respect thereto);

(ii) Asset Taxes prorated to Buyer pursuant to Section 9.02, but paid by Seller before Closing;

(iii) The amount of all Property Expenses incurred in the ordinary course of business attributable to the Assets from and after the Effective Time and paid or payable by Seller, subject to the terms hereof;

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(iv) all upward Purchase Price adjustments for Title Benefits determined in accordance with Article III; and

(v) any other amount subject to an upward Purchase Price adjustment provided for in this Agreement or agreed upon by Buyer and Seller.

(b) The Purchase Price shall be decreased by the following amounts:

(i) The proceeds of production of Hydrocarbons attributable to the Assets occurring from and after the Effective Time and received by Seller (net of all royalties to be paid by or on behalf of Seller with respect thereto);

(ii) The amount of all Property Expenses incurred in the ordinary course of business attributable to the Assets prior to the Effective Time and paid or payable by Buyer;

(iii) Asset Taxes prorated to Seller pursuant to Section 9.02 that are not paid by Seller prior to Closing (which prorated Asset Taxes so deducted from the Purchase Price shall be the sole obligation of Buyer following Closing);

(iv) the Allocated Value of any Subject Interest excluded from sale due to failure to obtain consent pursuant to Section 3.08;

(v) all downward Purchase Price Adjustments for Title Defects and Environmental Defects determined in accordance with Article III and Article IV; and

(vi) any other amount subject to a downward Purchase Price Adjustment provided for in this Agreement or agreed upon by Buyer and Seller.

(c) For purposes of Sections 10.02(a) and (b), “Property Expenses” shall mean all costs and expenses (other than Taxes) that are incurred in the ordinary course of business in the ownership or operation of the Assets, including, without limitation, all drilling costs, all capital expenditures and all regular overhead charges under applicable Third Party operating agreements.

(d) The adjustments described in Sections 10.02(a) and (b) are hereinafter referred to as the “Purchase Price Adjustments.”

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Section 10.03 Closing Statement. On or before December 23, 2013 at 5:00 p.m. Central Standard Time, Seller shall prepare a statement of the estimated Purchase Price Adjustments taking into account the foregoing principles (the “Statement”). On or before December 27, 2013 at 5:00 p.m. Central Standard Time, Buyer will deliver to Seller a written report containing all changes with the explanation therefor that Buyer proposes to be made to the Statement. Such Statement, as agreed upon by the Parties, will be used to determine the Purchase Price payable by Buyer to Seller at the Closing pursuant to Section 10.05(a); provided that if the Parties do not agree upon a Purchase Price Adjustment set forth in the Statement, then the amount of such Purchase Price Adjustment used to determine the Purchase Price payable by Buyer to Seller at the Closing pursuant to Section 10.05(a) shall be the amount set forth in the draft Statement delivered to Buyer, subject to final adjustment and resolution pursuant to Section 12.02. Prior to or at the Closing, Buyer and Seller will execute and deliver to each other the final Statement as prepared in accordance with the terms hereof.

Section 10.04 Actions of Seller at the Closing.

At the Closing, Seller shall:

(a) execute, acknowledge and deliver to Buyer original copies of the assignment substantially in the form as set forth in Exhibit D of this Agreement (the “Assignment”) in sufficient counterparts for recordation in each of the counties in which the Leases and Wells are located and such other instruments (in form and substance mutually agreed upon by Buyer and Seller) as may be reasonably necessary to convey the Assets to Buyer;

(b) execute, acknowledge and deliver to Buyer letters in lieu of transfer or division orders directing all purchasers of production from the Subject Interests to make payment of proceeds attributable to such production to Buyer from and after the Effective Time as reasonably requested by Buyer prior to the Closing Date;

(c) deliver to Buyer possession of the Assets;

(d) execute and deliver to Buyer a certificate of non-foreign status of Seller meeting the requirements of Treasury Regulation Section 1.1445-2(b)(2);

(e) execute and deliver the Statement;

(f) execute, acknowledge and deliver any other agreements provided for herein or necessary or desirable to effectuate the transactions contemplated hereby;

(g) deliver to Buyer appropriate releases in recordable form of any financing liens upon the Assets, duly executed by the lender(s) of record in form and substance reasonably satisfactory to Buyer; and

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(h) Seller will deliver a letter to Buyer at Closing stating that full carve out audited financial statements are not available and are impracticable for Seller to prepare as noted in Section 17.16(a).

Section 10.05 Actions of Buyer at the Closing.

At the Closing, Buyer shall:

(a) deliver to Seller the Purchase Price (as adjusted pursuant to the provisions hereof) by wire transfer to an account designated in writing by Seller;

(b) execute and deliver the Statement;

(c) take possession of the Assets; and

(d) execute, acknowledge and deliver the Assignment and any other agreements provided for herein or necessary or desirable to effectuate the transactions contemplated hereby.

Article XI

Termination

Section 11.01 Right of Termination. This Agreement may be terminated at any time at or prior to the Closing:

(a) by mutual written consent of the Parties;

(b) by Seller on the Closing Date if the conditions set forth in Article VII have not been satisfied in all material respects by Buyer or waived by Seller in writing by the Closing Date;

(c) by Buyer on the Closing Date if the conditions set forth in Article VIII have not been satisfied in all material respects by Seller or waived by Buyer in writing by the Closing Date;

(d) by either Party, if the Closing shall not have occurred on or before December 30, 2013;

(e) by either Party if any Governmental Authority shall have issued an order, judgment or decree or taken any other action challenging, delaying, restraining, enjoining, prohibiting or invalidating the consummation of any of the transactions contemplated herein;

(f) by either Party if (i) the aggregate amount of the Purchase Price Adjustments agreed upon between the Parties or otherwise finally determined pursuant to this Agreement with respect to all uncured Title Defects (net of the aggregate amount of the Purchase Price Adjustments for all Title Benefits agreed by the Parties) plus (ii) the aggregate amount

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of the Environmental Defect Values agreed upon between the Parties or otherwise finally determined pursuant to this Agreement with respect to all Environmental Defects, exceeds twenty percent (20%) of the Purchase Price;

(g) by Buyer in accordance with Section 13.05(c); or

(h) as otherwise provided herein;

provided, however, that no Party shall have the right to terminate this Agreement pursuant to clause (b), (c), or (d) above if such Party is at such time in material breach of any provision of this Agreement.

Section 11.02 Effect of Termination. In the event that the Closing does not occur as a result of any Party exercising its right to terminate pursuant to Section 11.01 then, except as set forth in Section 11.03, this Agreement (other than the provisions hereof which survive by their terms) shall be null and void and no Party shall have any further rights, liabilities or obligations under this Agreement.

Section 11.03 Termination Remedies.

(a) If all conditions precedent to the obligations of Buyer set forth in Article VII, or of Seller set forth in Article VIII, (such Party that has satisfied its conditions precedent, the “Performing Party”) have been met and the transactions contemplated by this Agreement are not consummated on or before the Closing Date because of the failure of Buyer or Seller to perform any of its material obligations hereunder or the breach of any representation herein by Buyer or Seller (such party that has not satisfied its conditions precedent, the “Breaching Party”) and the Performing Party has performed all of its material obligations hereunder and has not breached any representation herein, then in such event, the Performing Party shall have the option to terminate this Agreement and pursue remedies that might be available to it at law. Additionally, in lieu of terminating this Agreement, the Performing Party shall have the right of specific performance of this Agreement against the Breaching Party.

Section 11.04 Attorneys’ Fees, Etc. If either Party to this Agreement resorts to legal proceedings to enforce this Agreement, the prevailing Party in such proceedings shall be entitled to recover all costs incurred by such Party, including reasonable attorneys’ fees, in addition to any other relief to which such Party may be entitled. Notwithstanding anything to the contrary in this Agreement, in no event shall either Party be entitled to receive any punitive, indirect or consequential damages unless same are a part of a Third Party claim for which a Party is seeking indemnification hereunder, REGARDLESS OF WHETHER CAUSED OR CONTRIBUTED TO BY THE SOLE, JOINT, COMPARATIVE OR CONCURRENT NEGLIGENCE OR STRICT LIABILITY OF THE OTHER PARTY.

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Article XII

Post Closing Obligations

Section 12.01 Gas Imbalances. Buyer and Seller agree that the net gas imbalance attributable to the Assets as of the Effective Time is believed to be that which is set forth on Schedule 12.01 (the “Agreed Imbalance”), notwithstanding that the actual imbalance may be less or greater. Buyer and Seller shall verify the actual net gas imbalance in the post-closing accounting pursuant to Section 12.02 and any imbalance shall be accounted for between the parties at the price of $3.25 per MMBTU but only as to those volumes which exceed or are less than the Agreed Imbalance. Such settlement shall be final and neither party thereafter shall make claim upon the other concerning the gas imbalances of the Assets. BUYER HEREBY ASSUMES ALL RIGHTS AND LIABILITIES RELATING TO GAS IMBALANCES DISCOVERED AFTER THE FINAL STATEMENT INCLUDING ANY REVENUE ADJUSTMENT CAUSED BY SUCH SUBSEQUENTLY DISCOVERED IMBALANCE AND AGREES TO DEFEND AND INDEMNIFY SELLER FROM AND AGAINST ANY CLAIM BY ANYONE ARISING OUT OF SUCH GAS IMBALANCES REGARDLESS OF SELLER’S NEGLIGENCE OR FAULT (INCLUDING STRICT LIABILITY).

Section 12.02 Final Statement.

(a) On or before 180 days after the Closing Date, Seller shall prepare and deliver to Buyer a post-closing statement setting forth a detailed calculation of all post-Closing Purchase Price Adjustments and supporting documentation pursuant to Section 10.02 (the “Final Statement”). The Final Statement shall include any adjustment, estimate or payment which was not finally determined as of the Closing Date and any amount to be accounted for pursuant to Section 12.01. To the extent reasonably required by Seller, Buyer shall assist in the preparation of the Final Statement. Seller shall provide Buyer such data and information as Buyer may reasonably request supporting the amounts reflected on the Final Statement in order to permit Buyer to perform or cause to be performed an audit. The Final Statement shall become final and binding upon the parties on the thirtieth (30th) calendar day following receipt thereof by Buyer (the “Final Settlement Date”) unless Buyer gives written notice of its disagreement (a “Notice of Disagreement”) to Seller prior to such date. Any Notice of Disagreement shall specify in detail the dollar amount, nature and basis of any disagreement so asserted. If a Notice of Disagreement is received by Seller in a timely manner, then the Parties shall resolve the Dispute (as defined in Section 16.01) evidenced by the Notice of Disagreement in accordance with Article XVI.

(b) Within five (5) calendar days after the Final Settlement Date, Seller shall pay to Buyer or Buyer shall pay to Seller in immediately available funds the net amount due upon (i) the undisputed Final Statement or (ii) resolution of any Dispute regarding a Notice of Disagreement, the revised Final Statement reflecting such resolutions, which the Parties shall issue, or cause the Independent Expert or arbitrators to issue, as applicable, following such resolution.

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Section 12.03 Intentionally Omitted.

Section 12.04 Financial Statements. Seller shall, as soon as practicable, but no later than February 21, 2014 at 5:00 p.m. Central Standard Time, provide the Financial Statements to Buyer.

Section 12.05 Further Cooperation. Seller shall make the Records available to be picked up by Buyer at the offices of Seller during normal business hours within five (5) calendar days after the Closing to the extent the Records are in the possession of Seller and are not subject to contractual restrictions on transferability. Seller shall have the right to retain copies of any of the Records pursuant to the rights granted under Section 17.03.

After the Closing Date, each Party, at the request of the other and without additional consideration, shall execute and deliver, or shall cause to be executed and delivered, from time to time such further instruments of conveyance and transfer and shall take such other action as the other Party may reasonably request to convey and deliver the Assets to Buyer and to accomplish the orderly transfer of the Assets to Buyer in the manner contemplated by this Agreement. After the Closing, the Parties will cooperate to have all proceeds received attributable to the Assets be paid to the proper Party hereunder and to have all expenditures to be made with respect to the Assets be made by the proper Party hereunder.

Article XIII

Operation of the Assets

Section 13.01 Operations after Effective Time. Seller agrees, from and after the date hereof until the Closing, except as expressly contemplated by this Agreement, as expressly consented to in writing by Buyer, or in situations wherein emergency action is taken in the face of risk to life, property or the environment, to, or to cause its affiliates to:

(a) maintain the books of account and records relating to the Assets in the usual, regular and ordinary manner, in accordance with the usual accounting practices of each such Person;

(b) not enter into a contract, or materially amend or change the terms of any such contract that would involve individual commitments of more than $100,000 or enter into any other material contract;

(c) not plug or abandon any Well located on the Assets without Buyer’s prior written consent;

(d) not transfer, sell, mortgage, pledge or dispose of any of the Assets other than the sale and/or disposal of Hydrocarbons in the ordinary course of business and, upon advance written notice to Buyer, sales of equipment that is no longer necessary in the operation of the Assets or for which

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comparable replacement equipment has been obtained and installed or create or suffer to exist any lien on the Assets other than a lien that is a Permitted Encumbrance;

(e) preserve in full force and effect and not waive, amend, change, revise or otherwise all oil and gas leases, operating agreements, easements, rights-of-way, permits, licenses and agreements that relate to the Assets;

(f) not grant or create any Preferential Purchase Right or other transfer restriction with respect to the Assets;

(g) not elect to go non-consent with respect to any operation with respect to the Assets;

(h) submit to Buyer for prior written approval, all requests for operating or capital expenditures relating to the Assets that involve individual commitments of more than $100,000;

(i) maintain any bonds, insurance, letters of credit, guarantees or deposits with any Governmental Authorities or any other Third Parties required or necessary for the operation of the Assets;

(j) maintain any consent, license, permit, grant or other authorization from any Governmental Authority required or necessary for the operation of the Assets; and

(k) obtain Buyer’s written approval prior to voting under any operating, joint venture, partnership or similar agreement, which approval shall not be unreasonably withheld or delayed.

Section 13.02 Limitations on the Operational Obligations and Liabilities of Seller.

(a) From and after the date of execution of this Agreement and until the Closing, and subject to the provisions of applicable operating and other agreements, Seller shall carry on its business with respect to the Assets in substantially the same manner as before execution of this Agreement.

(b) Buyer acknowledges that Seller owns undivided interests in some or all of the Assets, and Buyer agrees that the acts or omissions of the other working interest owners shall not constitute a violation of the provisions of this Article XIII, nor shall any action required by a vote of working interest owners constitute such a violation so long as Seller has voted its interests in a manner that complies with the provisions of this Article XIII.

Section 13.03 No Liability of Seller. Notwithstanding anything to the contrary in this Article XIII, Seller shall have no liability to Buyer for, and Buyer hereby agrees to release, defend, indemnify and hold harmless Seller from, the incorrect payment of delay rentals,

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royalties, shut-in royalties or similar payments or for any failure to pay any such payments through mistake or oversight (INCLUDING THOSE RESULTING FROM SELLER’S SOLE, JOINT, COMPARATIVE OR CONCURRENT NEGLIGENCE OR STRICT LIABILITY) provided that such payments relate to production months after the Effective Time. In no event shall Buyer’s remedy for any Seller’s breach of its obligations under this Article XIII exceed the Allocated Value of the Assets affected by such breach.

Section 13.04 Intentionally Omitted.

Section 13.05 Casualty Loss.

(a) Except as provided in this Section 13.05, Buyer shall assume all risk of loss with respect to, and any change in the condition of, the Assets from the date of this Agreement until the Closing, including with respect to the depletion of Hydrocarbons, the watering-out of any Well, the collapse of casing, sand infiltration of Wells, and the depreciation of personal property.

(b) If after the date of this Agreement and prior to the Closing any part of the Assets shall be damaged or destroyed by fire or other casualty or if any part of the Assets shall be taken in condemnation or under the right of eminent domain or if proceedings for such purposes shall be pending or threatened, this Agreement shall remain in full force and effect notwithstanding any such destruction, taking or proceeding, or the threat thereof and the Parties shall proceed with the transactions contemplated by this Agreement notwithstanding such destruction or taking without reduction of the Purchase Price, but subject to Section 13.05(c).

(c) Notwithstanding Section 13.05(a), in the event of any loss described in Section 13.05(b), at the Closing, Buyer shall have the option to: (i) exclude the affected Asset from the sale and reduce the Purchase Price by the Allocated Value of such affected Asset as set forth on Exhibit C or (ii) include the affected Asset in the sale, in which event Seller shall pay to Buyer all sums paid to Seller by Third Parties by reason of the destruction or taking of such Assets (up to the Allocated Value thereof), including any sums paid pursuant to any policy or agreement of insurance or indemnity, and shall assign, transfer and set over unto Buyer all of the rights, title and interest of Seller in and to any claims, causes of action, unpaid proceeds or other payments from Third Parties, including any policy or agreement of insurance or indemnity, arising out of such destruction or taking (up to the Allocated Value thereof). Notwithstanding anything to the contrary in this Section 13.05, other than as provided in any joint operating agreement to which any of the Assets are subject, Seller shall not be obligated to carry or maintain, and shall have no obligation or liability to Buyer for its failure to carry or maintain, any insurance coverage with respect to any of the Assets. Notwithstanding anything to the contrary contained in this Section 13.05, should the uncompensated loss exceed twenty percent (20%) of the Purchase Price, Buyer shall have the option to terminate this Agreement.

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Section 13.06 Operatorship. Seller makes no representation and/or warranty to Buyer as to the transferability or assignability of operatorship of such Wells, but Seller shall and shall cause its affiliates to, cooperate with Buyer and use its commercially reasonable efforts to cause operatorship of the Wells and Leases to be transferred to Buyer. Buyer acknowledges that the rights and obligations associated with such wells are governed by applicable agreements and that operatorship will be determined by the terms of those agreements.

Section 13.07 Records. Seller shall, and shall cause its affiliates to, provide Buyer with all accounting records and information relating to the Assets for the period from the Effective Time to the Closing Date, including all revenue and joint interest billing information and well master information.

Section 13.08 Intentionally Omitted.

Section 13.09 Intentionally Omitted.

Article XIV

Obligations and Indemnification

Section 14.01 Retained Obligations. Provided that the Closing occurs, Seller shall retain (a) all obligations and liabilities of Seller for the payment or improper payment of royalties, rentals and other similar payments under the Leases relating to the Subject Interests to the extent attributable to periods prior to the Effective Time; (b) all obligations of Seller under the Contracts for (i) overhead charges related to periods prior to the Effective Time, (ii) costs and expenses incurred prior to the Effective Time for goods and services provided prior to the Effective Time and (iii) other payment obligations that accrue and become due prior to the Effective Time; (c) all liability of Seller to Third Parties for personal injury or death to the extent occurring prior to the Effective Time as a result of the operation of the Assets; (d)(i) any and all income Taxes, franchise Taxes and similar Taxes imposed by any applicable law on Seller or any of its affiliates, or any combined, unitary, or consolidated group of which any of the foregoing is or was a member, (ii) Asset Taxes allocable to Seller pursuant to Section 9.02 taking into account, and without duplication of, such Asset Taxes effectively borne by Seller pursuant to Section 10.02(b)(iii) or Section 12.02, (iii) any Taxes imposed on or with respect to the ownership or operation of the Excluded Assets, and (iv) and any all other Taxes imposed on or with respect to the ownership or operation of the Assets for any tax period (or portion thereof) ending before the Effective Time; (e) all litigation existing as of the Closing Date, to the extent it relates to the period of time prior to the Effective Time; (f) any offsite disposal of hazardous materials by Seller from the Subject Interests to offsite locations occurring prior to the Effective Time; (g) Seller’s employment relationship with its employees and Seller’s employee benefit plans; (h) all liability of Seller under any credit facilities; (i) all liability of Seller under any hedging, swap, put, call, collar, future, derivative or similar arrangement; and (j) the Excluded Assets (collectively, the “Retained Obligations”, and the items specified in (c), (d), (f), (g), (h), (i), (j) and (k) herein, the “Specified Retained Obligations”).

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Section 14.02 Assumed Obligations. Provided that the Closing occurs, subject to Buyer’s indemnification rights under Section 14.04, Buyer hereby assumes all duties, obligations and liabilities of every kind and character of Seller with respect to the Assets or the ownership or operation thereof (other than the Retained Obligations), attributable to periods before and after the Effective Time, including, without limitation, those arising out of (a) the terms of the Easements, Contracts, Leases, Personal Property or Subject Interests comprising part of the Assets, (b) Gas Imbalances, (c) suspense accounts, (d)(i) Asset Taxes allocable to Buyer pursuant to Section 9.02 taking into account, and without duplication of, such Asset Taxes effectively borne by Buyer pursuant to Section 10.02(a)(ii) or Section 12.02 and (ii) the Transfer Taxes, if any, allocable to Buyer pursuant to Section 9.01, (e) the condition (including, without limitation, environmental condition) of the Subject Interests regardless of whether such condition arose before or after the Effective Time, (f) obligations to properly plug and abandon or re-plug or re-abandon or remove wells, flowlines, gathering lines or other facilities, equipment or other personal property or fixtures comprising part of the Assets, (g) obligations to restore the surface of the Subject Interests and obligations to remediate or bring the Subject Interests into compliance with applicable Environmental Laws (including conducting any remediation activities that may be required on or otherwise in connection with activities on the Subject Interests) regardless of whether such obligations or conditions or event giving rise to such obligations arose, occurred or accrued before or after the Effective Time and (h) any other duty, obligation, event, condition or liability assumed by Buyer under the terms of this Agreement (collectively, the “Assumed Obligations”). Buyer’s obligations under this Section 14.02 shall survive the Closing without time limitation.

Section 14.03 Buyer’s Indemnification. Provided that the Closing occurs, except for matters for which Seller has an indemnification obligation hereunder, Buyer shall release, defend, indemnify and hold harmless Seller, its partners, and their respective officers, directors, employees, agents, partners, representatives, members, shareholders, affiliates, subsidiaries, successors and assigns (collectively, the “Seller Indemnitees”) from and against any and all claims, damages, liabilities, losses, causes of action, costs and expenses (including, without limitation, those involving theories of negligence or strict liability and including court costs and attorneys’ fees) (collectively, the “Losses”) to the extent resulting from or arising out of, (a) the Assumed Obligations, (b) any breach by Buyer of any of Buyer’s representations and warranties contained in Article VI or (c) any breach by Buyer of its covenants hereunder, REGARDLESS OF WHETHER CAUSED OR CONTRIBUTED TO BY THE SOLE, JOINT, COMPARATIVE OR CONCURRENT NEGLIGENCE OR STRICT LIABILITY OF ANY OF THE SELLER INDEMNITEES. Buyer’s indemnification obligation under Section 14.03(b) and Section 14.03(c) (other than as applicable to breaches of Buyer under Sections 3.05(b), 3.08, 4.04(b), Article IX, 10.02, 10.03, 10.05(a), Article XII, Article XVII and Article XVI only) shall apply only if Seller has provided Buyer with written notice claiming indemnification under those provisions within twelve (12) months following Closing and (2) shall only apply after a deductible percentage of two percent (2%) of the Purchase Price, and then only to the extent of the excess of the claims above the two percent (2%) deductible of the Purchase Price and (3) shall never exceed a maximum aggregate sum of fifteen percent (15%) of the Purchase Price, inclusive of attorneys’ fees and all other expenses of litigation.

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Section 14.04 Seller’s Indemnification. Provided that the Closing occurs, Seller shall release, defend, indemnify and hold harmless Buyer, its partners, and their respective officers, directors, employees, agents, partners, representatives, members, shareholders, affiliates, subsidiaries, successors and assigns (collectively, the “Buyer Indemnitees”) from and against any and all Losses to the extent resulting from or arising out of (a) the Retained Obligations, (b) any breach by Seller of any of Seller’s representations and warranties contained in Article V or (c) any breach by Seller of its covenants hereunder, REGARDLESS OF WHETHER CAUSED OR CONTRIBUTED TO BY THE SOLE, JOINT, COMPARATIVE OR CONCURRENT NEGLIGENCE OR STRICT LIABILITY OF ANY OF THE BUYER INDEMNITEES. Notwithstanding anything to the contrary contained herein, Seller’s indemnification obligation under Section 14.04(a) (other than with respect to the Specified Retained Obligations), Section 14.04(b) and Section 14.04(c) (other than as applicable to breaches of Seller under Sections3.05(b), 3.08, 4.04(b), Article IX, 10.02, 10.03, 10.05(a), Article XII, Article XVI and Article XVII only) (1) shall only apply if Buyer has provided Seller with written notice claiming indemnification within twelve (12) months of the Closing and (2) shall only apply after a deductible percentage of two percent (2%) of the Purchase Price, and then only to the extent of the excess of the claims above the two percent (2%) deductible of the Purchase Price and (3) shall never exceed a maximum aggregate sum of fifteen percent (15%) of the Purchase Price, inclusive of attorneys’ fees and all other expenses of litigation.

Section 14.05 Notices and Defense of Indemnified Matters. Each Party shall promptly notify the other Party of any matter of which it becomes aware and for which it is entitled to indemnification from the other Party under this Agreement; provided that the delay or failure of any Party to so notify the indemnified Party shall only reduce the indemnified Party’s claim to the extent such claim was prejudiced as a result of such delay or failure. The indemnifying Party shall be obligated to defend, at the indemnifying Party’s sole expense, any litigation or other administrative or adversarial proceeding against the indemnified Party relating to any matter for which the indemnifying Party has agreed to indemnify and hold the indemnified Party harmless under this Agreement; provided that the indemnified Party shall not enter into any settlement without the indemnified Party’s consent, not to be unreasonably withheld or delayed. However, the indemnified Party shall have the right to participate with the indemnifying Party in the defense of any such matter at its own expense.

Section 14.06 Exclusive Remedies. The Parties acknowledge and agree that, following Closing, the remedies set forth in this Article XIV for each Party, as limited above in this Article XIV, shall be the exclusive remedies of such Party for any claimed breaches by the other Party of its representations, warranties, and covenants under this Agreement.

Article XV

Limitations on Representations and Warranties

Section 15.01 Disclaimers of Representations and Warranties. The express representations and warranties of Seller contained in this Agreement are exclusive and are in lieu of all other representations and warranties, express, implied or statutory. EXCEPT FOR THE EXPRESS REPRESENTATIONS OF SELLER IN THIS AGREEMENT AND THE ASSIGNMENT (INCLUDING SECTION 2.01 THEREOF), BUYER ACKNOWLEDGES

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THAT SELLER HAS NOT MADE, AND SELLER HEREBY EXPRESSLY DISCLAIMS AND NEGATES, AND BUYER HEREBY EXPRESSLY WAIVES, ANY REPRESENTATION OR WARRANTY, EXPRESS, IMPLIED, AT COMMON LAW, BY STATUTE OR OTHERWISE RELATING TO (A) PRODUCTION RATES, RECOMPLETION OPPORTUNITIES, DECLINE RATES, GAS BALANCING INFORMATION OR THE QUALITY, QUANTITY OR VOLUME OF THE RESERVES OF HYDROCARBONS, IF ANY, ATTRIBUTABLE TO THE ASSETS, (B) THE ACCURACY, COMPLETENESS OR MATERIALITY OF ANY INFORMATION, DATA OR OTHER MATERIALS (WRITTEN OR ORAL) NOW, HERETOFORE OR HEREAFTER FURNISHED TO BUYER BY OR ON BEHALF OF SELLER AND (C) THE ENVIRONMENTAL CONDITION OF THE ASSETS. EXCEPT FOR THE EXPRESS WARRANTIES OF SELLER IN THIS AGREEMENT AND THE ASSIGNMENT, SELLER EXPRESSLY DISCLAIMS AND NEGATES, AND BUYER HEREBY WAIVES, AS TO PERSONAL PROPERTY, EQUIPMENT, INVENTORY, MACHINERY AND FIXTURES CONSTITUTING A PART OF THE ASSETS (I) ANY IMPLIED OR EXPRESS WARRANTY OF MERCHANTABILITY, (II) ANY IMPLIED OR EXPRESS WARRANTY OF FITNESS FOR A PARTICULAR PURPOSE, (III) ANY IMPLIED OR EXPRESS WARRANTY OF CONFORMITY TO MODELS OR SAMPLES OF MATERIALS, (IV) ANY RIGHTS OF PURCHASERS UNDER APPROPRIATE STATUTES TO CLAIM DIMINUTION OF CONSIDERATION OR RETURN OF THE PURCHASE PRICE, (V) ANY IMPLIED OR EXPRESS WARRANTY OF FREEDOM FROM DEFECTS, WHETHER KNOWN OR UNKNOWN, (VI) ANY AND ALL IMPLIED WARRANTIES EXISTING UNDER APPLICABLE LAW AND (VII) ANY IMPLIED OR EXPRESS WARRANTY REGARDING ENVIRONMENTAL LAWS, THE RELEASE OF MATERIALS INTO THE ENVIRONMENT, OR PROTECTION OF THE ENVIRONMENT OR HEALTH, IT BEING THE EXPRESS INTENTION OF BUYER AND SELLER THAT, EXCEPT AS PROVIDED IN THIS AGREEMENT AND THE ASSIGNMENT, THE PERSONAL PROPERTY, EQUIPMENT, INVENTORY, MACHINERY AND FIXTURES INCLUDED IN THE ASSETS SHALL BE CONVEYED TO BUYER, AND BUYER SHALL ACCEPT SAME, AS IS, WHERE IS, WITH ALL FAULTS AND IN THEIR PRESENT CONDITION AND STATE OF REPAIR AND BUYER REPRESENTS TO SELLER THAT BUYER WILL MAKE OR CAUSE TO BE MADE SUCH INSPECTIONS WITH RESPECT TO SUCH PERSONAL PROPERTY, EQUIPMENT, INVENTORY, MACHINERY AND FIXTURES AS BUYER DEEMS APPROPRIATE. SELLER AND BUYER AGREE THAT, TO THE EXTENT REQUIRED BY APPLICABLE LAW TO BE EFFECTIVE, THE DISCLAIMERS OF CERTAIN WARRANTIES CONTAINED IN THIS SECTION ARE “CONSPICUOUS” DISCLAIMERS FOR THE PURPOSES OF ANY APPLICABLE LAW, RULE OR ORDER.

Section 15.02 Independent Investigation. Buyer represents and acknowledges that it is knowledgeable of the oil and gas business and of the usual and customary practices of producers such as Seller and that it has had (or will have prior to the Closing) access to the Assets, the officers and employees of Seller, and the books, records and files of Seller relating to the Assets, and in making the decision to enter into this Agreement and consummate the transactions contemplated hereby, Buyer will rely solely on the basis of its own independent due diligence investigation of the Assets and upon the representations and warranties made in Article V, and not on any other representations or warranties of Seller or any other person or entity.

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Section 15.03 Survival. Except as specifically provided otherwise elsewhere in this Agreement, the representations, warranties and covenants of Buyer and Seller under this Agreement shall survive for a period of twelve (12) months from the Closing. Notwithstanding anything to the contrary herein, (a) Buyer’s obligation to indemnify under Section 14.03(a) shall survive the Closing without time limitation, (b) Seller’s obligation to indemnify under Section 14.04(a) with respect to the Specified Retained Obligations only shall survive the Closing and terminate upon the statute of limitations applicable thereto, (c) the provisions of Article XV, Article XVI and Article XVII shall survive without time limitation, and (d) the other covenants contained herein that by their terms are to be performed after the Closing shall survive the Closing on the terms thereof.

Article XVI

Dispute Resolution

Section 16.01 General. Any and all claims, disputes, controversies or other matters in question arising out of or relating to title issues, environmental issues, or calculation of the Statement or revisions thereto (all of which are referred to herein as “Disputes” which term shall not include any other disputes, claims, controversies or other matters in question arising under this Agreement) shall be resolved in the manner prescribed by this Article XVI.

Section 16.02 Senior Management. If a Dispute occurs that the senior representatives of the Parties responsible for the transaction contemplated by this Agreement have been unable to settle or agree upon within a period of fifteen (15) calendar days after such Dispute arose, Seller shall nominate and commit one of its senior officers, and Buyer shall nominate and commit one of its senior officers, to meet at a mutually agreed time and place not later than thirty (30) calendar days after the Dispute has arisen to attempt to resolve same. If such senior management have been unable to resolve such Dispute within a period of fifteen (15) calendar days after such meeting, or if such meeting has not occurred within forty-five (45) calendar days following such Dispute arising, then either Party shall have the right, by written notice to the other, to resolve the Dispute through the relevant Independent Expert pursuant to Section 16.03.

Section 16.03 Dispute by Independent Expert.

(a) Each Party shall have the right to submit Disputes regarding title issues, environmental issues, or calculation of the Statement, the Final Statement or revisions thereto, to an independent expert appointed in accordance with this Section 16.03 (each, an “Independent Expert”), who shall serve as sole arbitrator. The Independent Expert shall be appointed by mutual agreement of the Parties from among candidates with experience and expertise in the area that is the subject of such Dispute, and failing such agreement, such Independent Expert for such Dispute shall be selected by the Chief Judge of the United States District Court for the Southern District of Texas.

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(b) Disputes to be resolved by an Independent Expert shall be resolved in accordance with mutually agreed procedures and rules and failing such agreement, in accordance with the rules and procedures of the Texas Arbitration Act and the Rules of the American Arbitration Association to the extent such Rules do not conflict with such Texas Arbitration Act or the provisions of this Agreement. The Independent Expert shall be instructed by the Parties to resolve such Dispute as soon as reasonably practicable in light of the circumstances. The decision and award of the Independent Expert shall be binding upon the Parties as an award under the Federal Arbitration Act and final and nonappealable to the maximum extent permitted by law, and judgment thereon may be entered in a court of competent jurisdiction and enforced by any Party as a final judgment of such court.

(c) The charges and expenses of the arbitration (including, without limitation, the Independent Expert) shall be shared equally by Seller and Buyer.

(d) Any arbitration hearing held pursuant to Section 16.03 shall be held in Midland, Texas.

Section 16.04 Limitation on Arbitration. ALL OTHER DISAGREEMENTS, DIFFERENCES, OR DISPUTES ARISING BETWEEN SELLER AND BUYER UNDER THE TERMS OF THIS AGREEMENT (AND NOT COVERED BY SECTION 16.03) SHALL NOT BE SUBJECT TO ARBITRATION AND SHALL BE DETERMINED BY A COURT OF COMPETENT JURISDICTION, UNLESS THE PARTIES OTHERWISE MUTUALLY AGREE.

Article XVII

Miscellaneous

Section 17.01 Names. As soon as reasonably possible after the end of the Term in the Transition Services Agreement, but in no event later than sixty (60) calendar days after the end of the Term in the Transition Services Agreement, Buyer shall remove the names of Seller and its affiliates, and all variations thereof, from all of the Assets and make the requisite filings with, and provide the requisite notices to, the appropriate federal, state or local agencies to place the title or other indicia of ownership, including operation of the Assets, in a name other than the name of Seller or any of its affiliates, or any variations thereof.

Section 17.02 Expenses. Except as otherwise expressly set forth in this Agreement, each Party shall be solely responsible for all expenses, including due diligence expenses, incurred by it in connection with this transaction, and neither Party shall be entitled to any reimbursement for such expenses from the other Party.

Section 17.03 Document Retention. As used in this Section 17.03, the term “Documents” shall mean all files, documents, books, records and other data delivered to Buyer by Seller pursuant to the provisions of this Agreement (other than those that Seller has retained either the original or a copy of), including, but not limited to: financial and tax accounting

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records; land, title and division of interest files; contracts; engineering and well files; and books and records related to the operation of the Assets prior to the Closing Date. Prior to the Closing, Seller or its representatives shall have the right to make and retain copies of the Documents at its or their expense.

Section 17.04 Entire Agreement. This Agreement, the documents to be executed hereunder, and the exhibits attached hereto constitute the entire agreement between the Parties pertaining to the subject matter hereof and supersede all prior agreements, understandings, negotiations and discussions, whether oral or written, of the Parties pertaining to the subject matter hereof. No supplement, amendment, alteration, modification or waiver of this Agreement shall be binding unless executed in writing by the Parties and specifically referencing this Agreement.

Section 17.05 Waiver. No waiver of any of the provisions of this Agreement shall be deemed or shall constitute a waiver of any other provisions hereof (whether or not similar), nor shall such waiver constitute a continuing waiver unless otherwise expressly provided.

Section 17.06 Publicity. Neither Seller nor Buyer will issue any public announcement or press release concerning this transaction without the written consent of the other Party (except as required by law or the applicable rules or regulations of any Governmental Authority or stock exchange, and in such case the Parties shall consult with each other with regard to the wording of the announcement or press release).

Section 17.07 Construction. The captions in this Agreement are for convenience only and shall not be considered a part of or affect the construction or interpretation of any provision of this Agreement. The Parties acknowledge that they have participated jointly in the negotiation and drafting of this Agreement and as such the Parties agree that if an ambiguity or question of intent or interpretation arises hereunder, this Agreement shall not be construed more strictly against one Party than another on the grounds of authorship.

Section 17.08 No Third Party Beneficiaries. Except as provided in Sections 14.03 and 14.04, nothing in this Agreement shall provide any benefit to any Third Party or entitle any Third Party to any claim, cause of action, remedy or right of any kind, it being the intent of the Parties that this Agreement shall otherwise not be construed as a Third Party beneficiary contract.

Section 17.09 Assignment. No Party may assign or delegate any of its rights or duties hereunder without the prior written consent of the other Party, and any such assignment shall be void. Except as otherwise provided herein, this Agreement shall be binding upon and inure to the benefit of the Parties hereto and their respective permitted successors, assigns and legal representatives.

Section 17.10 Governing Law. This Agreement, other documents delivered pursuant hereto and the legal relations between the Parties shall be governed and construed in accordance with the laws of the State of Texas, without giving effect to principles of conflicts of laws that would result in the application of the laws of another jurisdiction.

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Section 17.11 Notices. Any notice, communication, request, instruction or other document required or permitted hereunder shall be given in writing and delivered in person or sent by U.S. Mail postage prepaid, return receipt requested, nationally recognized, receipt overnight courier, email or facsimile to the addresses of Seller and Buyer set forth below. Any such notice shall be effective only upon receipt.

Seller:	Lynden USA Inc. 1055 West Georgia Street, Suite 2480 Vancouver, BC V6E 0B6 Attn: Colin Watt Phone: 604-629-2991 Fax: 604-602-9311
Buyer:	Greg Brown c/o BreitBurn Management Company, LLC 515 S. Flower Street, Ste. 4800 Los Angeles, CA 90071 Fax: (213) 225-5916

Either Party may, by written notice so delivered to the other Party, change its address for notice purposes hereunder.

Section 17.12 Severability. If any term or other provision of this Agreement is invalid, illegal or incapable of being enforced by any rule of law or public policy, all other conditions and provisions of this Agreement shall nevertheless remain in full force and effect and the Parties shall negotiate in good faith to modify this Agreement so as to effect their original intent as closely as possible in an acceptable manner to the end that the transactions contemplated hereby are fulfilled to the extent possible.

Section 17.13 Time of the Essence. Time shall be of the essence with respect to all time periods and notice periods set forth in this Agreement.

Section 17.14 Counterpart Execution. This Agreement may be executed in any number of counterparts, and each counterpart hereof shall be effective as to each party that executes the same whether or not all of such parties execute the same counterpart. If counterparts of this Agreement are executed, the signature pages from various counterparts may be combined into one composite instrument for all purposes. All counterparts together shall constitute only one Agreement, but each counterpart shall be considered an original. Any counterpart submitted or transmitted via facsimile or email shall have the same force and effect as an original manually executed counterpart.

Section 17.15 Jury Trial Waiver. SELLER AND BUYER HEREBY EXPRESSLY AND KNOWINGLY WAIVE ANY AND ALL RIGHTS TO TRIAL BY JURY OF ANY AND

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ALL CLAIMS AND CAUSES OF ACTION ARISING UNDER OR IN CONNECTION WITH THIS AGREEMENT, INCLUDING, WITHOUT LIMITATION, ANY AND ALL CLAIMS AND CAUSES OF ACTION IN ANY WAY BASED UPON OR RELATING TO THE NEGOTIATION, FORMATION, CONSTRUCTION, INTERPRETATION, ENFORCEABILITY, PERFORMANCE, AND/OR BREACH OF THIS AGREEMENT.

Section 17.16 Financial Statements.

(a) Seller acknowledges that full carve out audited financial statements are not available for the subject properties and that full carve out financial statements are impracticable for Seller to prepare. Seller will deliver a letter to Buyer at closing stating that full carve out audited financial statements are not available and are impracticable for Seller to prepare. Seller will prepare statements of revenues and direct operating expenses and supplemental reserve disclosures including proved reserve tables and the standardized measure of discounted cash flows as required by the Securities Exchange Commission (“SEC”) by Buyer pursuant to the Securities Act of 1933, as amended (the “Securities Act”), or the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and that such statements of revenues and direct operating expenses will be audited so that they comply with the requirements of a registration statement under the Securities Act, report or other filing under the Exchange Act and the rules set forth in Regulation S-X. As soon as practicable, but no later than February 21, 2014 at 5:00 p.m. Central Standard Time, Seller will have prepared and will deliver, at Buyer’s expense, audited statements of revenues and direct operating expenses applicable to the Assets for the calendar year 2012, along with unaudited interim quarterly periods for the first three quarters of 2012 and 2013. Seller shall deliver or cause to be delivered, to Seller’s auditor such representation letters, in form and substance customary for representation letters provided to external audit firms by Seller (if the financial statements are subject of an audit or are the subject of a review pursuant to Statements of Accounting Standards 100 (Interim Financial Information)), as may be reasonably requested by Seller’s Auditor, with respect to the statement of revenues and direct operating expenses. Also by February 21, 2014, Seller will have prepared and delivered, at Buyer’s expense, a separate unaudited statement of revenues and direct operating expenses applicable to the Assets for the partial interim quarterly period for the fourth quarter of 2013, (i.e., beginning on October 1, 2013 and ending with the Closing Date of December 30, 2013), and for the fourth quarter of 2012, and any other financial information necessary to comply with the requirements of a registration statement under the Securities Act, report or other filing under the Exchange Act and the rules set forth in Regulation S-X (the “Financial Statements”). In addition, by January 31, 2014, Seller shall provide Buyer with lease operating statements for the fourth quarter of 2013.

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(b) Seller agrees to consent to the inclusion or incorporation by reference of the statements of revenues and direct operating expenses and all supplemental information therein in any registration statement, report, or other document of Buyer to be filed with the SEC upon receipt of written notice from Buyer’s counsel that the statements of revenues and direct operating expenses and all supplemental information therein are required to be included or incorporated by reference to satisfy any rule or regulation of the SEC or to satisfy relevant financial disclosure obligations under the Securities Act or the Exchange Act. Upon request of Buyer, Seller agrees to request the external audit firm that audits the statements of revenues and direct operating expenses (the “Audit Firm”) to consent to the inclusion or incorporation by reference of its audit opinion with respect to the audited statements of revenues and direct operating expenses in any such registration statement, report or other document and provide to the Audit Firm such customary representation letters as may be reasonably requested by the Audit Firm. Seller shall (i) provide Buyer and Buyer’s independent accountants with access to management by Seller to Seller’s independent accountants to the extent applicable to the Assets and (ii) authorize Seller’s Audit Firm to provide such Audit Firm’s consent to the incorporation of the audited statements of revenues and direct operating expenses by reference to satisfy any rule or regulation of the SEC or to satisfy relevant financial disclosure obligations under the Securities Act or the Exchange Act.

THIS SPACE INTENTIONALLY LEFT BLANK/

SIGNATURES ON FOLLOWING PAGE

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IN WITNESS WHEREOF, Seller and Buyer have executed and delivered this Agreement as of the date first set forth above.

SELLER:
Lynden USA Inc.
By:	/s/ Colin Watt
Name:	Colin Watt
Title:	President
BUYER:
BreitBurn Operating L.P.
By:	BreitBurn Operating GP, LLC,
	its general partner
By:	/s/ Halbert S. Washburn
Name:	Halbert S. Washburn
Title:	Chief Executive Officer

Signature Page to

Purchase and Sale Agreement

EX-23.1

Exhibit 23.1

CAWLEY, GILLESPIE & ASSOCIATES, INC.

PETROLEUM CONSULTANTS
13640 BRIARWICK DRIVE, SUITE 100	306 WEST SEVENTH STREET, SUITE 302	1000 LOUISIANA STREET, SUITE 625
AUSTIN, TEXAS 78729-1707	FORT WORTH, TEXAS 76102-4987	HOUSTON, TEXAS 77002-5008
512-249-7000	817-336-2461	713-651-9944
	www.cgaus.com

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the references to our firm in the form and context in which they appear in this Registration Statement on Form 10 of Lynden Energy Corp., including under the heading “Experts.” We hereby further consent to the use in such Registration Statement of information contained in our reports, dated October 22, 2013 and September 22, 2014, relating to the estimates of the oil and gas reserves, future production and income attributable to certain leasehold and royalty interests of Lynden Energy Corp. We hereby further consent to the inclusion of the aforementioned reports as exhibits to such Registration Statement.

CAWLEY, GILLESPIE & ASSOCIATES, INC.

Texas Registered Engineering Firm F-693

Fort Worth, Texas

December 19, 2014

EX-99.1

Exhibit 99.1

CAWLEY, GILLESPIE & ASSOCIATES, INC.

PETROLEUM CONSULTANTS

13640 BRIARWICK DRIVE, SUITE 100	306 WEST SEVENTH STREET, SUITE 302	1000 LOUISIANA STREET, SUITE 625
AUSTIN, TEXAS 78729-1707	FORT WORTH, TEXAS 76102-4987	HOUSTON, TEXAS 77002-5008
512-249-7000	817- 336-2461	713-651-9944
	www.cgaus.com

September 22, 2014

Mr. Colin Watt

President and CEO

Lynden Energy Corp.

888 Dunsmuir Street

Suite 1200

Vancouver, BC V6C 3K4

Re:	Evaluation Summary
	Lynden Energy Corp. Interests
	Proved and Probable Reserves
	Spraberry & Sugg Ranch Fields,
	Various Counties, Texas
	As of June 30, 2014
	Pursuant to the Guidelines of the Securities and Exchange Commission for Reporting Corporate Reserves and Future Net Revenue

Dear Mr. Watt:

As requested, we are submitting our estimates of proved and probable reserves and forecasts of economics attributable to the Lynden Energy Corp. interests located in Spraberry and Sugg Ranch Fields in various counties in Texas. This report, completed September 22, 2014 covers 100% of the proved reserves estimated for Lynden Energy Corp. (“Lynden”). This evaluation utilized an effective date of June 30, 2014, was prepared using constant prices and costs, and conforms to Item 1202(a)(8) of Regulation S-K and other rules of the Securities and Exchange Commission (“SEC”). This report was prepared for the preparation of the Lynden 2014 Form 10 filing.

The reserves and economics for the Total Proved, Proved Developed, Proved Undeveloped and Probable are summarized as follows:

Lynden Energy Corp. Interests

September 22, 2014

Page 2

		Proved				Probable
		Total		Developed		Undeveloped		Undeveloped
Net Reserves
Oil	- Mbbl		3,950.1		2,102.9		1,847.2		210.8
Gas	- MMcf		9,719.1		5,280.4		4,438.8		275.1
NGL	- Mbbl		1,928.1		1,047.4		880.7		54.6
Net Revenue
Oil	- M$		385,725.3		205,349.4		180,375.8		20,588.4
Gas	- M$		39,209.6		21,303.6		17,906.0		1,109.6
NGL	- M$		63,835.5		34,718.0		29,117.5		1,804.3
Severance Taxes	- M$		23,568.5		12,588.8		10,979.6		1,113.3
Ad Valorem Taxes	- M$		12,949.6		6,946.3		6,003.3		620.5
Operating Expenses	- M$		77,509.4		40,868.4		36,641.1		4,670.3
Other Deductions	- M$		19,801.3		11,417.9		8,383.4		1,252.2
Investments	- M$		64,661.3		4,834.2		59,827.2		7,401.3
Net Operating Income (BFIT)	- M$		290,280.1		184,715.5		105,564.6		8,444.7

The Proved Developed reserves are the summation of the PDP and PDNP estimates. The Proved Developed reserves and economics, with a breakout of Proved Developed Producing and Proved Developed Non-Producing, are summarized as follows:

		Proved Developed
		Total		Producing		Non-Producing
Net Reserves
Oil	- Mbbl		2,102.9		1,606.9		496.0
Gas	- MMcf		5,280.4		4,506.8		773.5
NGL	- Mbbl		1,047.4		893.9		153.5
Net Revenue
Oil	- M$		205,349.4		156,914.6		48,434.8
Gas	- M$		21,303.6		18,183.3		3,120.3
NGL	- M$		34,718.0		29,644.0		5,074.1
Severance Taxes	- M$		12,588.8		9,895.5		2,693.4
Ad Valorem Taxes	- M$		6,946.3		5,451.3		1,495.0
Operating Expenses	- M$		40,868.4		39,988.8		879.6
Other Deductions	- M$		11,417.9		8,925.7		2,492.2
Investments	- M$		4,834.2		532.8		4,301.4
Net Operating Income (BFIT)	- M$		184,715.5		139,947.9		44,767.6

Net revenue is prior to deducting state production taxes and Ad Valorem taxes. Future net cash flow is after deducting these taxes, future capital costs, operating expenses and other deductions, but before consideration of federal income taxes.

The oil reserves include oil and condensate. Oil and natural gas liquid (NGL) volumes are expressed in barrels (42 U.S. gallons). Gas volumes are expressed in thousands of standard cubic feet (Mcf) at contract temperature and pressure base.

Lynden Energy Corp. Interests

September 22, 2014

Page 3

Hydrocarbon Pricing

The base oil and gas prices calculated for June 30, 2014 were $100.27/BBL and $4.104/MMBTU, respectively. As specified by the SEC, a company must use a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The base oil price and NGL price is based upon WTI-Cushing oil spot prices during 2013 and 2014 and the base gas price is based upon Henry Hub spot prices during 2013 and 2014.

The base prices were adjusted for oil, NGL and gas differentials, which may include local basis differentials, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. After these adjustments, the net realized prices over the life of the total proved properties were estimated to be $97.650 per barrel of oil, $4.034 per mcf of natural gas and $33.108 per barrel of natural gas liquids. All economic factors were held constant in accordance with SEC guidelines.

Economic Parameters

Ownership was accepted as furnished and has not been independently confirmed. Oil, NGL and gas price differentials, lease operating expenses (LOE), other deductions and investments were calculated and prepared by your office and were reviewed by us for reasonableness. All economic parameters, including expenses and investments, were held constant (not escalated) throughout the life of these properties.

Severance tax rates were applied at normal state percentages of oil and gas revenue. Ad valorem tax rates were forecast as provided by Lynden.

SEC Conformance and Regulations

The reserve classifications and the economic considerations used herein conform to the criteria of the SEC. The reserves and economics are predicated on regulatory agency classifications (as described on pages 2 and 3 of the Appendix), rules, policies, laws, taxes and royalties currently in effect. The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.

This evaluation includes 65 PUD locations based in the Spraberry field in Texas. Each of these drilling locations proposed as part of Lynden’s development plan conforms to the proved undeveloped standards as set forth by the SEC. In our opinion, Lynden has indicated they have intent to complete this development plan within the next five (5) years. Furthermore, Lynden has demonstrated that they have the proper company staffing, financial backing and prior development success to ensure this five (5) year development plan will be fully executed.

Reserve Estimation Methods

Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to offset production, both of which are considered to provide a relatively high degree of accuracy.

Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for Lynden properties. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report. A general discussion of methods customarily employed in the estimation of reserves is described in page 1 of the Appendix.

Lynden Energy Corp. Interests

September 22, 2014

Page 4

General Discussion

The estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. All estimates represent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.

An on-site field inspection of the properties has not been performed nor have the mechanical operation or condition of the wells and their related facilities been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging at abandonment has been included.

Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 50 years. We do not own an interest in the properties or Lynden Energy Corp. and are not employed on a contingent basis. We have used all methods and procedures that we consider necessary under the circumstances to prepare this report. Our work-papers and related data utilized in the preparation of these estimates are available in our office.

Yours very truly,
CAWLEY, GILLESPIE & ASSOCIATES, INC.
TEXAS REGISTERED ENGINEERING FIRM F-693
ROBERT D. RAVNAAS, P.E. PRESIDENT

APPENDIX

Methods Employed in the Estimation of Reserves

The four methods customarily employed in the estimation of reserves are (1) production performance, (2) material balance, (3) volumetric and (4) analogy. Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data available and the characteristics of the reservoirs.

Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the quality, quantity and types of information available on individual properties. Operators are generally required by regulatory authorities to file monthly production reports and may be required to measure and report periodically such data as well pressures, gas-oil ratios, well tests, etc. As a general rule, an operator has complete discretion in obtaining and/or making available geological and engineering data. The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in significant differences in the accuracy and reliability of estimates.

A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows:

Production performance.  This method employs graphical analyses of production data on the premise that all factors which have controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance. The only information required is production history. Capacity production can usually be analyzed from graphs of rates versus time or cumulative production. This procedure is referred to as “decline curve” analysis. Both capacity and restricted production can, in some cases, be analyzed from graphs of producing rate relationships of the various production components. Reserve estimates obtained by this method are generally considered to have a relatively high degree of accuracy with the degree of accuracy increasing as production history accumulates.

Material balance.  This method employs the analysis of the relationship of production and pressure performance on the premise that the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzing changes in pressure with respect to production relationships. This method requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir. The material balance method is applicable to all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids. Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available. Estimates for other reservoir types require extensive data and involve complex calculations most suited to computer models which makes this method generally applicable only to reservoirs where there is economic justification for its use. Reserve estimates obtained by this method are generally considered to have a degree of accuracy that is directly related to the complexity of the reservoir and the quality and quantity of data available.

Volumetric.    This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of hydrocarbons in-place. The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric method is most applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated.

Analogy.    This method which employs experience and judgment to estimate reserves, is based on observations of similar situations and includes consideration of theoretical performance. The analogy method is applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve estimates obtained by this method are generally considered to have a relatively low degree of accuracy.

Much of the information used in the estimation of reserves is itself arrived at by the use of estimates. These estimates are subject to continuing change as additional information becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtained about well and reservoir performance.

Cawley, Gillespie & Associates, Inc. Appendix Page 1

APPENDIX

Reserve Definitions and Classifications

The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves:

“(22)         Proved oil and gas reserves.  Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, 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.

“(i)       The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

“(ii)      In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

“(iii)     Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

“(iv)     Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

“(v)      Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

“(6)           Developed oil and gas reserves.  Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

“(i)       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

“(ii)      Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

“(31)         Undeveloped oil and gas reserves.  Undeveloped oil and gas reserves are reserves of any category 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.

“(i)       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.

“(ii)      Undrilled locations can be classified as having 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.

“(iii)     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, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

Cawley, Gillespie & Associates, Inc. Appendix Page 2

“(18)        Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

“(i)       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. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

“(ii)      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.

“(iii)     Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

“(iv)     See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).

“(17)         Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

“(i)       When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

“(ii)      Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

“(iii)     Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

“(iv)     The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

“(v)      Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

“(vi)     Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.”

Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that “a registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S–K.” This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant is permitted, but not required, to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”

“(26)       Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

“Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).”

Cawley, Gillespie & Associates, Inc. Appendix Page 3

EX-99.2

Exhibit 99.2

CAWLEY, GILLESPIE & ASSOCIATES, INC.

PETROLEUM CONSULTANTS

13640 BRIARWICK DRIVE, SUITE 100	306 WEST SEVENTH STREET, SUITE 302	1000 LOUISIANA STREET, SUITE 625
AUSTIN, TEXAS 78729-1707	FORT WORTH, TEXAS 76102-4987	HOUSTON, TEXAS 77002-5008
512-249-7000	817- 336-2461	713-651-9944
	www.cgaus.com

October 22, 2013

Mr. Colin Watt

President and CEO

Lynden Energy Corp.

888 Dunsmuir Street

Suite 1200

Vancouver, BC V6C 3K4

Re:	Evaluation Summary
	Lynden Energy Corp. Interests
	Proved and Probable Reserves
	Spraberry & Sugg Ranch Fields,
	Various Counties, Texas
	As of June 30, 2013
	Pursuant to the Guidelines of the Securities and Exchange Commission for Reporting Corporate Reserves and Future Net Revenue

Dear Mr. Watt:

As requested, we are submitting our estimates of proved and probable reserves and forecasts of economics attributable to the Lynden Energy Corp. interests located in Spraberry and Sugg Ranch Fields in various counties in Texas. This report, completed October 22, 2013 covers 100% of the proved reserves estimated for Lynden Energy Corp. (“Lynden”). This evaluation utilized an effective date of June 30, 2013, was prepared using constant prices and costs, and conforms to Item 1202(a)(8) of Regulation S-K and other rules of the Securities and Exchange Commission (“SEC”). This report was prepared for the preparation of the Lynden 2013 Form 10 filing.

The reserves and economics for the Total Proved, Proved Developed, Proved Undeveloped and Probable are summarized as follows:

Lynden Energy Corp. Interests

October 22, 2013

Page 2

		Proved				Probable
		Total		Developed		Undeveloped		Undeveloped
Net Reserves
Oil	- Mbbl		3,653.3		1,805.5		1,847.8		121.1
Gas	- MMcf		13,589.3		6,585.1		7,004.3		497.7
NGL	- Mbbl		0.0		0.0		0.0		0.0
Net Revenue
Oil	- M$		310,347.8		153,379.1		156,968.7		10,288.1
Gas	- M$		85,217.5		41,316.8		43,900.6		3,119.2
NGL	- M$		0.0		0.0		0.0		0.0
Severance Taxes	- M$		20,667.3		10,154.2		10,513.1		707.2
Ad Valorem Taxes	- M$		10,442.9		5,140.0		5,302.9		354.0
Operating Expenses	- M$		83,185.0		41,913.0		41,272.0		2,827.1
Other Deductions	- M$		22,926.7		11,369.3		11,557.4		755.5
Investments	- M$		62,447.8		4,861.3		57,586.5		4,020.3
Net Operating Income (BFIT)	- M$		195,895.5		121,258.2		74,637.3		4,743.3

The Proved Developed reserves are the summation of the PDP and PDNP estimates. The Proved Developed reserves and economics, with a breakout of Proved Developed Producing and Proved Developed Non-Producing, are summarized as follows:

		Proved Developed
		Total		Producing		Non-Producing
Net Reserves
Oil	- Mbbl		1,805.5		1,429.7		375.8
Gas	- MMcf		6,585.1		5,659.0		926.0
NGL	- Mbbl		0.0		0.0		0.0
Net Revenue
Oil	- M$		153,379.1		121,452.6		31,926.5
Gas	- M$		41,316.8		35,512.6		5,804.2
NGL	- M$		0.0		0.0		0.0
Severance Taxes	- M$		10,154.2		8,250.3		1,903.9
Ad Valorem Taxes	- M$		5,140.0		4,143.9		996.1
Operating Expenses	- M$		41,913.0		39,224.4		2,688.5
Other Deductions	- M$		11,369.3		9,021.7		2,347.6
Investments	- M$		4,861.3		0.0		4,861.3
Net Operating Income (BFIT)	- M$		121,258.2		96,324.9		24,933.3

Net revenue is prior to deducting state production taxes and Ad Valorem taxes. Future net cash flow is after deducting these taxes, future capital costs, operating expenses and other deductions, but before consideration of federal income taxes.

The oil reserves include oil and condensate. Oil and natural gas liquid (NGL) volumes are expressed in barrels (42 U.S. gallons). Gas volumes are expressed in thousands of standard cubic feet (Mcf) at contract temperature and pressure base.

Lynden Energy Corp. Interests

October 22, 2013

Page 3

Hydrocarbon Pricing

The base oil and gas prices calculated for June 30, 2013 were $91.60/BBL and $3.459/MMBTU, respectively. As specified by the SEC, a company must use a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The base oil price and NGL price is based upon WTI-Cushing oil spot prices during 2012 and 2013 and the base gas price is based upon Henry Hub spot prices during 2012 and 2013.

The base prices were adjusted for oil, NGL and gas differentials, which may include local basis differentials, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. After these adjustments, the net realized prices over the life of the total proved properties were estimated to be $84.951 per barrel of oil and $6.271 per mcf of natural gas. All economic factors were held constant in accordance with SEC guidelines.

Economic Parameters

Ownership was accepted as furnished and has not been independently confirmed. Oil, NGL and gas price differentials, lease operating expenses (LOE), other deductions and investments were calculated and prepared by your office and were reviewed by us for reasonableness. All economic parameters, including expenses and investments, were held constant (not escalated) throughout the life of these properties.

Severance tax rates were applied at normal state percentages of oil and gas revenue. Ad valorem tax rates were forecast as provided by Lynden.

SEC Conformance and Regulations

The reserve classifications and the economic considerations used herein conform to the criteria of the SEC. The reserves and economics are predicated on regulatory agency classifications (as described on pages 2 and 3 of the Appendix), rules, policies, laws, taxes and royalties currently in effect. The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.

This evaluation includes 57 PUD locations based in the Spraberry field in Texas. Each of these drilling locations proposed as part of Lynden’s development plan conforms to the proved undeveloped standards as set forth by the SEC. In our opinion, Lynden has indicated they have intent to complete this development plan within the next five (5) years. Furthermore, Lynden has demonstrated that they have the proper company staffing, financial backing and prior development success to ensure this five (5) year development plan will be fully executed.

Reserve Estimation Methods

Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to offset production, both of which are considered to provide a relatively high degree of accuracy.

Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for Lynden properties. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report. A general discussion of methods customarily employed in the estimation of reserves is described in page 1 of the Appendix.

Lynden Energy Corp. Interests

October 22, 2013

Page 4

General Discussion

The estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. All estimates represent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.

An on-site field inspection of the properties has not been performed nor have the mechanical operation or condition of the wells and their related facilities been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging at abandonment has been included.

Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 50 years. We do not own an interest in the properties or Lynden Energy Corp. and are not employed on a contingent basis. We have used all methods and procedures that we consider necessary under the circumstances to prepare this report. Our work-papers and related data utilized in the preparation of these estimates are available in our office.

Yours very truly,
CAWLEY, GILLESPIE & ASSOCIATES, INC.
TEXAS REGISTERED ENGINEERING FIRM F-693
ROBERT D. RAVNAAS, P.E.
PRESIDENT

APPENDIX

Methods Employed in the Estimation of Reserves

The four methods customarily employed in the estimation of reserves are (1) production performance, (2) material balance, (3) volumetric and (4) analogy. Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data available and the characteristics of the reservoirs.

Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the quality, quantity and types of information available on individual properties. Operators are generally required by regulatory authorities to file monthly production reports and may be required to measure and report periodically such data as well pressures, gas-oil ratios, well tests, etc. As a general rule, an operator has complete discretion in obtaining and/or making available geological and engineering data. The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in significant differences in the accuracy and reliability of estimates.

A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows:

Production performance.  This method employs graphical analyses of production data on the premise that all factors which have controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance. The only information required is production history. Capacity production can usually be analyzed from graphs of rates versus time or cumulative production. This procedure is referred to as “decline curve” analysis. Both capacity and restricted production can, in some cases, be analyzed from graphs of producing rate relationships of the various production components. Reserve estimates obtained by this method are generally considered to have a relatively high degree of accuracy with the degree of accuracy increasing as production history accumulates.

Material balance.  This method employs the analysis of the relationship of production and pressure performance on the premise that the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzing changes in pressure with respect to production relationships. This method requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir. The material balance method is applicable to all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids. Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available. Estimates for other reservoir types require extensive data and involve complex calculations most suited to computer models which makes this method generally applicable only to reservoirs where there is economic justification for its use. Reserve estimates obtained by this method are generally considered to have a degree of accuracy that is directly related to the complexity of the reservoir and the quality and quantity of data available.

Volumetric.    This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of hydrocarbons in-place. The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric method is most applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated.

Analogy.    This method which employs experience and judgment to estimate reserves, is based on observations of similar situations and includes consideration of theoretical performance. The analogy method is applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve estimates obtained by this method are generally considered to have a relatively low degree of accuracy.

Much of the information used in the estimation of reserves is itself arrived at by the use of estimates. These estimates are subject to continuing change as additional information becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtained about well and reservoir performance.

Cawley, Gillespie & Associates, Inc. Appendix Page 1

APPENDIX

Reserve Definitions and Classifications

The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves:

“(22)         Proved oil and gas reserves.  Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, 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.

“(i)      The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

“(ii)      In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

“(iii)      Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

“(iv)      Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

“(v)      Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

“(6)           Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

“(i)       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

“(ii)      Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

“(31)         Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category 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.

“(i)       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.

“(ii)      Undrilled locations can be classified as having 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.

“(iii)     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, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

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“(18)       Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

“(i)       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. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

“(ii)      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.

“(iii)      Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

“(iv)      See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).

“(17)       Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

“(i)       When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

“(ii)       Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

“(iii)      Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

“(iv)      The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

“(v)        Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

“(vi)      Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.”

Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that “a registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S–K.” This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant is permitted, but not required, to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”

“(26)         Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

“Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).”

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