Form 10-12G

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

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):

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; and (v) all dollar amounts refer to United States dollars unless otherwise indicated.

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.

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.

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.

“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.

“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.

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

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

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

“Proved undeveloped reserves” or “PUDs.” 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 are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves will not 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 tests in the area and in the same reservoir.

“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.

“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.

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 of 1933 (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 Securities Exchange Act of 1934 and are required to register with the Securities and Exchange Commission as a domestic registrant.

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, 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.

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:

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.

West Texas has experienced a resurgence in oil-focused exploration and development activity as a result of new completion methods being applied to an unconventional rock package from the Permian Basin, historically one of the most prolific oil basins in North America. The 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 a rapid oil and gas vertical well development program on our Midland Basin acreage, and we now have 97 gross (39.7 net) Wolfberry wells tied-in and producing.

Our independent petroleum engineer, Cawley, Gillespie & Associates, estimates our net Proved plus Probable (P2) reserves attributable to our working interest at June 30, 2014 to be 5.48 million barrels of oil, 13.09 billion cubic feet of gas, and 2.60 million barrels of natural gas liquids. Of this amount, proved reserves were 5.19 million barrels of oil, 12.71 billion cubic feet of gas, and 2.52 million barrels of natural gas liquids. The Net Present Value (10%) of future revenue, before income tax, of the Proved plus Probable reserves as of June 30, 2014 is estimated by Cawley, Gillespie & Associates to be $112.96 million. All of the reserves reported are attributable to vertical wells in the Midland Basin.

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, through a sale, 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 Wolfberry well is currently approximately $2.1 million. Our current plans call for 15 gross (6.26 net) 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 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 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 October 2014. Lynden is funding 24.375% of the cost of the wells on the Wolcott Lease and will have a 20% working interest in the wells. Subject to proposals made by the operator, we currently anticipate three 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.

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.

We currently have one (0.5 net) producing test well on the Mitchell Ranch Project, the Spade 17 #1, where several rounds of completions have been carried out 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, with the first three wells now drilled and the fourth well currently drilling. The wells are 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.

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 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 Parador Basin. The transportation and marketing costs were paid to Abajo at market rates. The majority of the P&NG sales were from the sale of natural gas.

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

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.

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.

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.”

Proved undeveloped reserves. During the year ended June 30, 2014, we converted approximately 1,352 MMBoe of proved undeveloped reserves to proved developed reserves by drilling and completing 24 gross (9.78 net) PUD vertical locations.

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.

The information included in this offering circular about our reserves as of June 30, 2014 and 2013, is based on reports prepared by Cawley, Gillespie and Associates, Inc. (“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 FASB applicable to public reporting companies.

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

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

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.

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.

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. Please see “Item 2. Financial Statements—Year Ended June 30, 2014 (Fiscal 2014) Compared to Year Ended June 30, 2013 (Fiscal 2013)—Results of Operations—P&NG Revenue” for discussion and disclosure related to production, price and cost data.

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.

Leasehold Acreage. The following table sets forth information as of June 30, 2014, relating to our leasehold acreage:

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.

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

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.

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.

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.

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. 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.

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.

The oil and natural gas industry in the United States of America is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also,

numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases 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.

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.

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:

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized

properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, NGLs and natural gas within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but there can be no assurance that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells, or limit the number of locations we can drill.

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.

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.

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.

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.

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.

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.

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.

General. Our operations are subject to stringent and complex federal, state, local and tribal 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:

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 fiscal the 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 it 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 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”) 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 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.

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 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.

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.

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.

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:

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.

If commodity prices decrease, 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.

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:

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

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

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

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

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:

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:

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:

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

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

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.

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 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, 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. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.

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

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

sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be materially and adversely affected.

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

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

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

Our operations are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment, health and safety aspects of our operations, or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations including the acquisition of 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.

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:

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:

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:

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

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

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

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

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

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

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

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

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

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

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 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 all of our officers and most 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:

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.

Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow

used for drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability affecting our ability to finance our operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

The successful acquisition of producing properties requires an assessment of several factors, including:

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

The pre-tax net present value of our estimated reserves is not an accurate estimate of the current fair value of our estimated oil and natural gas reserves.

Pre-tax net present value 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. Pre-tax net present value requires the use of specific pricing as required by the SEC as well as operating and development costs prevailing as of the date of computation. Consequently, it may not reflect the prices ordinarily received or that will be received for oil and natural gas production because of varying market conditions, nor may it reflect the actual costs that will be required to produce or develop the oil and natural gas properties. Accordingly, estimates included herein of future net cash flow may be materially different from the future net cash flows that are ultimately received. Therefore, the pre-tax net present value of our estimated reserves included in this Registration Statement should not be construed as accurate estimates of the current fair value of our proved reserves.

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.

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.

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 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 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 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 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.

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 PCAOB 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.

The selected historical consolidated financial information set forth below as of and for each of the years ended June 30, 2014 and 2013 has been derived from our audited consolidated financial statements. 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.

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.

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 latest information available from the Energy Information Administration of the U.S. Department of Energy, the Spraberry Trend Area ranks 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.

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 “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.

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.

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:

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

Oil and natural gas prices have been subject to significant fluctuations during the past several years. The following table sets forth the average NYMEX oil and natural gas prices for the six months ended June 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:


	Six Months Ended June 30, 2014		Year Ended December 31,
	Six Months Ended June 30, 2014		2013		2012		2011
Average NYMEX prices:
Oil (Bbl)	$	100.84	$	98.05	$	94.15	$	95.11
Natural gas (MMBtu)	$	4.65	$	3.73	$	2.83	$	4.03
High and low NYMEX prices:
Oil (Bbl):
High	$	107.26	$	110.53	$	109.77	$	113.93
Low	$	91.66	$	86.68	$	77.69	$	75.67
Natural gas (MMBtu):
High	$	6.15	$	4.46	$	3.90	$	4.85
Low	$	4.01	$	3.11	$	1.91	$	2.99

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

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

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.

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

The Company reported net income of $13,729,785 (Fiscal 2013 - $13,408,410) and total comprehensive income of $13,377,183 (Fiscal 2013 - $13,536,797) 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 $11,088,651. The Company’s net earnings per common share for Fiscal 2014 was $0.11 (Prior Year - $0.13).

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.

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).

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 as a percentage of total revenues have generally remained relatively consistent, and within an expected range given the Company’s mix of new and older wells.

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. 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 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.

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.

The Company has estimated income tax expense of $10,606,023 (Fiscal 2013 – $4,501,705) 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.

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, the Credit Facility provided a borrowing base of $32 million of which $17.75 million had been drawn. As of the date of this report, $23.3 million has been drawn on the Credit Facility. The Company anticipates continuing to seek upward revisions of the borrowing base.

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 a rapid 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 at June 30, 2014 of approximately $14 million.

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.

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.

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

The table below presents, as of October 22, 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 October 22, 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.

The following table sets forth the names, ages and titles of our directors and executive officers.

Richard Andrews, Chairman of the Board and Director, has served as a member of our 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 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.

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.

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).

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.

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

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:

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.

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 Name 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 their 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.

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.

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.

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.

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.

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.

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 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.

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 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 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.

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.

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

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.

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.

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.

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.

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.

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.

On October 22, 2014, the closing price of our common stock was CDN$0.79 per share. As of October 22, 2014, we had approximately 252 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.

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.

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.

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 the shares of common stock of:

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.

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.

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.

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.

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 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 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.

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:

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.

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

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.

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.

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

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 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.

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.

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.

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 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:

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.

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

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.

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

We have audited the accompanying consolidated financial statements of Lynden Energy Corp. (the “Company”), which comprise the consolidated balance sheets as at June 30, 2014 and June 30, 2013, and the consolidated statements of income and comprehensive income, consolidated statements of changes in shareholders’ equity, and consolidated statements of cash flows for each of the years then ended, and a summary of significant accounting policies and other explanatory information.

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accounting principles generally accepted in the United States, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Our responsibility is to express an opinion on these consolidated 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 comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement. We were not engaged to perform an audit of the Company’s 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 involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Lynden Energy Corp. as at June 30, 2014 and June 30, 2013, and its financial performance and its cash flows for each of the years then ended in accordance with accounting principles generally accepted in the United States.

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.

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.

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.

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

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

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

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.

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.

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

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.

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

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.

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.

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.

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

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

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

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

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

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

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

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

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

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

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.

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.

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

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.

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

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.

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.

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:

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.

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.

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.

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.

Project costs suspended for longer than one year were primarily suspended pending the completion of economic evaluations including, but not limited to, results of additional appraisal drilling, well test analysis, additional geological and geophysical data, facilities and infrastructure development options, development plan approval, and permitting. If additional information becomes available that raises substantial doubt as to the economic or operational viability of any of these projects, the associated costs will be expensed at that time.

The Company 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.

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.

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.

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.

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.

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.

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

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.

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:

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:

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

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.

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.

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:

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:

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.

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.

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.

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

Interest rate risk 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.

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:

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.

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).

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.

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

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:

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:

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%.

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.

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.

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.

Pursuant to the requirements of Section 12 of the Securities Exchange Act of 1934, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized.


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)


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.	25

Item 2.	Financial Information.	46

Item 3.	Properties.	53

Item 4.	Security Ownership of Certain Beneficial Owners and Management.	53

Item 5.	Directors and Executive Officers.	54

Item 6.	Executive Compensation.	56

Item 7.	Certain Relationships and Related Transactions, and Director Independence.	61

Item 8.	Legal Proceedings.	62

Item 9.	Market Price of and Dividends on the Registrant’s Common Equity and Related Stockholder Matters.	62

Item 10.	Recent Sales of Unregistered Securities.	68

Item 11.	Description of Registrant’s Securities to be Registered.	72

Item 12.	Indemnification of Directors and Officers.	75

Item 13.	Financial Statements.	76

Item 14.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.	76

Item 15.	Financial Statements and Exhibits.	76

WHERE YOU CAN FIND MORE INFORMATION		104

EXPERTS		104

SIGNATURES


County	Gross Acres		Net Acres		Lynden Net Interest			Lynden Net Acres
Martin		2,043		1,757		43.75	%		769
		1,127		1,127		20.00	%		225
Midland		640		640		43.75	%		280
Glasscock		5,900		4,480		43.75	%		1,960
Howard		6,388		6,121		40.625	%		2,487
		640		640		25.39	%		162

Total		16,738		14,765					5,883


	30-Sep-13		31-Dec-13		31-Dec-13		31-Mar-14		30-Jun-14		30-Sep-14
			(Breitburn Sale)
Producing Wolfberry well
Gross		76		-12		72		78		91		95
Net		31.68		-4.73		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


	June 30, 2014
	12-Month Unweighted Average Pricing: Oil $100.27, Natural Gas $4.104
	Oil (Mbbl)		Natural Gas (MMcf)		Natural Gas Liquids (Mbbl)		Pre-Tax Present Value Discounted at 10% (M$)
Proved developed producing		2,108.9		5,885.1		1,167.2		67,995
Proved developed non-producing		647.2		1,007.9		200.0		15,354
Proved undeveloped		2,430.8		5,817.1		1,154.2		28,342
Total proved		5,186.9		12,710.10		2,521.4		111,691
Probable		292.5		381.1		75.6		1,271
Total		5,479.4		13,091.2		2,597.0		112,962


	June 30, 2013
	12-Month Unweighted Average Pricing: Oil $91.60, Natural Gas $3.459
	Oil (Mbbl)		Natural Gas (MMcf)		Pre-Tax Present Value Discounted at 10% (M$)
Proved developed producing		1,877.0		7,405.5		49,881.7
Proved developed non-producing		494.2		1,226.6		7,535.2
Proved undeveloped		2,433.1		9,180.1		13,877.2
Total proved		4,804.4		17,812.1		71,294.2
Probable		159.0		654.5		735.0
Total		4,963.4		18,466.6		72,029.2


	Gross Productive Wells						Net Productive Wells
	Oil		Natural Gas		Total		Oil		Natural Gas		Total
Total		91		0		91		37.18		0		37.18


	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


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


	As of June 30,
	2014		2013
Balance Sheet Data:
Cash and cash equivalents	$	13,955,890	$	1,874,400
Property, plant and equipment		91,812,527		73,984,820
Total assets		109,111,434		78,471,594
Shareholders’ equity		72,763,993		46,670,853


Name of Beneficial Owner	Amount and Nature of Beneficial Ownership			Percent of Class
Richard Andrews		8,658,450	⁽¹⁾		6.24	%
Colin Watt		2,917,699	⁽²⁾		2.19	%
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		12,822,249			8.97	%
John Lovoi		26,787,600	⁽⁷⁾		17.06	%


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		69	Chief Financial Officer
Robert Bereskin		72	Director
John McLennan		62	Director
Derek Michaelis		36	Director
Ron Paton		51	Director


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


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		0		0		0	$	252,115	⁽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


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


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


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


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


DATE OF SALE	TYPE OF SECURITY	NUMBER	CONSIDERATION	EXEMPTION FROM REGISTRATION
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

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


	Page

Report of Independent Registered Public Accounting Firm		78

Consolidated Balance Sheets as of June 30, 2014 and June 30, 2013		79

Consolidated Statements of Income and Comprehensive Income for the years ended June 30, 2014 and June 30, 2013		80

Consolidated Statement of Changes in Shareholders’ Equity for the years ended June 30, 2014 and June 30, 2013		81

Consolidated Statements of Cash Flows for the years ended June 30, 2014 and June 30, 2013		82

Notes to the Consolidated Financial Statements		83


	Notes		June 30, 2014			June 30, 2013
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			4,674,210

				32,996,264			4,874,741


Total liabilities				36,347,441			31,800,741

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	)		(21,347,644	)


Total shareholders’ equity				72,763,993			46,670,853


Total liabilities and shareholders’ equity			$	109,111,434		$	78,471,594


Subsequent events		17


	Notes		Year ended June 30, 2014			Year ended June 30, 2013
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	)
Impairments				—			—
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		11,088,651			5,595,986


Net income				13,729,785			13,408,410


Other comprehensive income (loss)
Foreign currency translation adjustment				(352,602	)		128,387


Total comprehensive income for the year			$	13,377,183		$	13,536,797


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			$	0.11		$	0.13
Diluted			$	0.11		$	0.13


	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


	June 30, 2014
	Cost		Accumulated Depletion, Depreciation and Impairment			Net Book Value
Petroleum and natural gas properties
Proved	$	100,407,385	$	(12,781,939	)	$	87,625,446
Suspended exploratory well costs		30,972,613		(26,786,552	)		4,186,061

		131,379,998		(39,568,491	)		91,811,507
Computer equipment		4,820		(3,799	)		1,021

Total property, plant and equipment	$	131,384,818	$	(39,572,290	)	$	91,812,528


	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


	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, 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


	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


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


	June 30, 2014		June 30, 2013
Numerator:
Net earnings	$	14,212,413	$	14,502,691


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	$	0.11	$	0.13


	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	%


	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


	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


	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