we are an oil and natural gas company...

TSXV: LVLTSXV: LVL

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2012 :

W W W . L Y N D E N E N E R G Y . C O M

2012 ANNUAL REPORT

2012 ANNUAL REPORT2012 ANNUAL REPORTLYNDEN ENERGY :

FUELING RESULTS: WEST TEXASWEST TEXAS

82514_lynden_AR_Cover_rv1.indd 1 12-12-24 11:16 AM

Mitchell

Sterling

Coke

01 Overview

02 Letter to Shareholders

04 Permian Basin: A West Texas Resurgence

06 Wolfberry Project

10 Mitchell Ranch Project

17 Management Discussion and Analysis

34 Auditors’ Report

36 Consolidated Financial Statements

41 Notes to Consolidated Financial Statements

69 Corporate Information

CONTENTS

Officers and DirectorsOfficers and Directors

Richard Andrews: Richard Andrews: Chairman and DirectorChairman and DirectorColin Watt: Colin Watt: Director, President, CEO and SecretaryDirector, President, CEO and SecretaryRobert Bereskin: Robert Bereskin: DirectorDirectorJohn McLennan: John McLennan: DirectorDirectorRon Paton: Ron Paton: DirectorDirectorLaurie Sadler: Laurie Sadler: CFOCFO

OfficeOffice

Lynden Energy Corp.Lynden Energy Corp.Suite 2480, 1055 West Georgia StreetSuite 2480, 1055 West Georgia StreetVancouver, BC V6E 0B6 (effective February 01, 2013)Vancouver, BC V6E 0B6 (effective February 01, 2013)

Phone: 604-629-2991Phone: 604-629-2991Fax: 604-602-9311Fax: 604-602-9311

E-mail: [email protected]: [email protected]: www.lyndenenergy.comWebsite: www.lyndenenergy.com

Transfer AgentTransfer Agent

Computershare Trust Company of CanadaComputershare Trust Company of Canada510 Burrard Street, 2nd Floor510 Burrard Street, 2nd FloorVancouver, British ColumbiaVancouver, British ColumbiaV6C 3B9V6C 3B9

Trading SymbolTrading Symbol

TSXV: LVLTSXV: LVL

CORPORATE CORPORATE INFORMATIONINFORMATION

This document contains forward-looking statements. The reader is cautioned that assumptions used in the preparation of such statements, although considered accurate at the time of This document contains forward-looking statements. The reader is cautioned that assumptions used in the preparation of such statements, although considered accurate at the time of preparation, may prove incorrect, and the actual results may vary materially from the statements made herein. The Company’s principal activity of oil and natural gas exploration and development preparation, may prove incorrect, and the actual results may vary materially from the statements made herein. The Company’s principal activity of oil and natural gas exploration and development is considered to be inherently risky. Expected timelines relating to oil and gas operations are subject to the customary risks of the oil and gas industry. For a more detailed description of these is considered to be inherently risky. Expected timelines relating to oil and gas operations are subject to the customary risks of the oil and gas industry. For a more detailed description of these risks, and others, see www.lyndenenergy.com/riskfactors.html.risks, and others, see www.lyndenenergy.com/riskfactors.html.

Portions of this document contain information as of December 2012.Portions of this document contain information as of December 2012.

Barrel of oil equivalent (“boe”) amounts have been calculated using a conversion ratio of six thousand cubic feet of natural gas to one barrel of oil (6:1) to express quantities of natural gas and Barrel of oil equivalent (“boe”) amounts have been calculated using a conversion ratio of six thousand cubic feet of natural gas to one barrel of oil (6:1) to express quantities of natural gas and crude oil in a common unit. The term “boe” may be misleading, particularly if used in isolation. The conversion ratio is based on an energy equivalency conversion method primarily applicable crude oil in a common unit. The term “boe” may be misleading, particularly if used in isolation. The conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.at the burner tip and does not represent a value equivalency at the wellhead.MONETARY AMOUNTS IN THIS ANNUAL REPORT ARE IN US DOLLARS UNLESS OTHERWISE NOTED.

PERMIAN BASIN OIL

Wolfberry Project

PERMIAN BASIN OIL

Mitchell Ranch Project

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1

DRIVE : DRIVE :

Capital Structure (as of December 01, 2012)

• Shares Outstanding 109,865,520

• Warrants 27,930,760

• Options 7,752,500

• Fully Diluted 145,548,780

CORPORATE SUMMARY

Lynden energy: Our visiOn cOmbines the pursuit Of gOOd OppOrtunities and Our dedicatiOn tO prOducing meaningfuL vaLue fOr Our sharehOLders.

we are on target for continued growth.

82514_lynden_AR_Front.indd 1 12-12-21 9:44 AM

2 Lynden energy | AnnuAL report 2012 » Let ter to SHAreHoLderS

TO OUR FELLOW SHAREHOLDERS:I am pleased to report to you on our progress during the 12 months ended June 30, 2012 (Fiscal 2012), a period of significant activity and success for our company.

The Company’s performance during 2012 set records on several metrics, including total production, gross revenues and well count.

The cornerstone of our near term growth continues to be our Wolfberry Project where we are undertaking an aggressive development program. However, we expect the Mitchell Ranch Project to have increasing prominence within the company as the development fairways of proven plays continue to expand toward our acreage. Several promising new play concepts that may be applicable to Mitchell Ranch are also being actively tested in proximity to our acreage.

We believe the foundations we have laid over the past several years will lead to significant growth for 2013 and beyond.

Wolfberry ProjectWolfberry Projectfiscal 2012 was a period of considerable growth on our Wolfberry Project. the aggressive Wolfberry drilling program, which continued in 2012, has resulted in dramatic increases in both our well count and our oil and gas production volumes and revenues. We began fiscal 2012 with 12 gross wells, finished with 35, and are projecting substantial growth again in fiscal 2013.

the Wolfberry Project covers in excess of 18,000 gross acres on which a significant inventory of development locations has been established. We continue to see considerable potential to

expand the project by upgrading the reserves through successful development drilling and by continuing to expand our activities into under-tested areas.

the projected pace of drilling on the Wolfberry Project was increased several times during the year as we strove to ‘bring value forward’. We significantly increased the density of drilling in the Wind farms Prospect area in Glasscock county and also began to test and delineate less drilled areas, such as our tubb Prospect Area in Howard county.

We received validation for several years of effort in mid-December 2012, when we entered into a definitive agreement with breitburn energy Partners l.P. of los Angeles, california for the sale of 16 gross (7.0 net) Wolfberry Project wells and underlying leases covering approximately 1,440 gross acres (630 acres net to lynden) for proceeds of $25.0 million. this transaction is expected to close in late December 2012.

Approximately 20% of our production is included in the anticipated sale, however, we continue to believe that we will meet our forecasted December 31, 2012 net production exit rate, after royalties, of 900 – 1,000 boe/day.

We will continue to seek out opportunities to capture value on our more densely drilled and proven acreage in order to build value in our less developed areas where we believe we can achieve the best results for our shareholders.

MitcHell rAncH Project MitcHell rAncH Project While the company did not undertake extensive exploration or development activity on the Mitchell ranch Project during the year, both the leasing and drilling activity by other operators in the eastern

FUELING RESULTS


3Lynden energy | AnnuAL report 2012 » Let ter to SHAreHoLderS

“WE BELIEVE THE FOUNDATIONS WE HAVE LAID “WE BELIEVE THE FOUNDATIONS WE HAVE LAID OVER THE PAST SEVERAL YEARS WILL LEAD TO OVER THE PAST SEVERAL YEARS WILL LEAD TO SIGNIFICANT GROWTH FOR 2013 AND BEYOND.”SIGNIFICANT GROWTH FOR 2013 AND BEYOND.”Colin Watt, President and CEO

Shelf of the Permian basin ensured that the Mitchell ranch Project received considerable attention.

Many of the promising new plays being tested in the Permian basin, such as horizontal well development in each of the Wolfcamp, cline Shale and Mississippian, are being driven by the recognition of the substantial hydrocarbon potential in these horizons, as well as by continual improvements in drilling and well completion practices.

the unique terms of our lease covering the 103,400 acre ranch, 36,000 acres of which has been farmed out for an overriding royalty to a large independent exploration and production company, provides the company with significant leverage to positive development activities by other operators in the region, as well as the flexibility to be patient in anticipation of their results.

We expect several of these operators to report results of their initial testing of these new play concepts in 2013. these results will be incorporated into a more active program of work in 2013 on the 67,400 acres of the ranch held jointly (50% each) with our working interest partner.

finAncinGfinAncinGthe expansion and growth of our company has required considerable new capital. in May 2012 we successfully raised $6.3 million in equity to partially fund the accelerated development of our Wolfberry Project. We believe the predictable nature of an established oil resource play such as the Wolfberry Project is well suited to the conservative use of debt financing in order to enhance shareholder returns. Accordingly, during the year we made active use of our credit facility with texas capital bank of Dallas, texas.

Going forward we anticipate an important strengthening in our financial position with the proceeds from the pending asset sale to breitburn energy, a growing borrowing base under our credit facility, as well as rapidly increasing operating revenues.

SuMMArySuMMAryWe anticipate an exciting year ahead. the Permian basin continues to be a site of major innovation and technological advancement. our projects are well situated to capitalize on these developments.

We believe that we have assembled a unique portfolio of oil and gas assets and our focus is now to realize, for the shareholders, the inherent value of these assets.

i look forward to updating you on our progress throughout the year.

on behalf of the board of Directors, i would like to thank you for the trust and confidence that you have placed in lynden.

colin Watt, President and ceolynDen enerGy corP.December 19, 2012


4

OverviewAlthough its conventional reservoirs are heavily developed, West texas has experienced a

resurgence in oil-focused exploration and development activity as a result of new completion

methods being applied to unconventional rock packages from the Permian basin. the

company’s Wolfberry and Mitchell ranch Projects are well positioned to take advantage of the

continued development and innovation taking place in the Permian basin.

CROWNQUESTcrownQuest operating llc, the operator of both the Wolfberry and Mitchell ranch Projects,

is based in Midland, texas and has extensive knowledge and experience in operating in the

Permian basin. crownQuest has drilled or participated in several hundred new wells where

new completion techniques have been successfully applied in areas adjacent, or in proximity, to our

Wolfberry Project prospect areas. their local knowledge has been essential in identifying new

opportunities that have led to the expansion of the Wolfberry Project and the acquisition of the

Mitchell ranch Project.

LOCATED PRINCIPALLY IN WESTERN LOCATED PRINCIPALLY IN WESTERN TEXAS, THE PERMIAN BASIN IS ONE OF TEXAS, THE PERMIAN BASIN IS ONE OF THE MOST PROLIFIC OIL-PRODUCING THE MOST PROLIFIC OIL-PRODUCING BASINS IN NORTH AMERICA.BASINS IN NORTH AMERICA.


PERMIAN BASIN A TExAS RESURGENCEWest Texas has experienced a resurgence in oil-focused

exploration and development activity as a result of new

completion methods.


Permian Basin

West Texas has experienced a resurgence in oil-focused exploration and development activity as a result of new completion methods being applied to unconventional rock packages from the Permian Basin,historically one of the most proflic oil basins in North America.

Midland, Texas is the primary oil services hub for the Permian Basin.

The Wolfberry Project is located in the Midland Basin.

Midland basin stRatigRaphic section

82514_Lynden_AR12_INSIDE_p6n13_rv1.indd 6 12-12-22 2:33 PM

the largest accumulation of oil and gas reserves in the Permian basin is found in the Spraberry trend, which covers large parts of six counties and has a total area of approximately 2,500 square miles. the Spraberry trend is ranked third in the united States by total proved reserves and seventh in total production. the Wolfcamp, stratigraphically below the Spraberry, is itself a significant producer in the Permian basin. it is equally well-known for its low permeability in most areas in the basin.

the application of new completion methods in and around the Spraberry trend has opened up vast new areas for potential development. our Wolfberry Project is operated by crownQuest operating llc of Midland, texas one of the early adopters and innovators of the completion practices now being used throughout the Midland basin.

the 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 between 7,000 and 11,500 feet, drilling depth. in addition to this main objective, other conventional and unconventional productive zones occur both above and below the Wolfberry assemblage.

our Wolfberry acreage is located in three general prospect areas in the Midland basin where we now have a significant inventory of drill locations.

WOLFBERRY PROJECT

Prospect Name County Gross Acres Net AcresLynden’s Net

InterestLynden Net

Acres

West Martin Martin 4,680 3,985 43.75% 1,743

Midland 920 898 43.75% 393

Glasscock 1,823 1,818 43.75% 795

Martin 1,127 1,127 30.625% 345

Wind farms Glasscock 3,353 2,491 43.75% 1,090

tubb Howard 7,023 6,660 35.5% 2,364

Total 18,931 16,979 6,730


T I M E

2013

1000

100

10

12014 2015 2016 2017 2018 2019 2020 2021 2022 2023

8

Barrels of Oil Natural Gas MCF

Proved 4,986,100 15,856,400

Probable 985,400 3,284,400

Proved plus Probable 5,971,500 19,140,800

0

20

40

60

80

100

120

Mar-

10

Jun-

10

Sep-1

0

Dec-1

0

Mar-

11

Jun-

11

Sep-1

1

Dec-1

1

Mar-

12

Jun-

12

Sep-1

2

Dec-1

2

Mar-

13

Jun-

13

Sep-1

3

Dec-1

3

2010

2011

2012

2013

ACTUAL WELLS PROJECTED WELLS

Wolfberry 175 MbOE type curveApproximately 65% oil and 35% gas

Gas – Dailyoil – Daily

At june 30, 2012 we had interest in 35 gross producing WolfberryProject wells. All of the wells were completed in the ‘typical’Wolfberry formations (Spraberry and Wolfcamp) and many wellswere also completed in the deeper Strawn, Atoka and Mississippianlimetstone and shale formations.

our development work has resulted in the company’s independentpetroleum engineer, cawley, Gillespie & Associates, estimating thecompany’s net Proved plus Probable (P2) reserves attributable tothe company’s working interest at june 30, 2012 to be 5.97 millionbarrels of oil and 19.14 billion cubic feet of gas. of this amount,Proved reserves were 4.99 million barrels of oil and 15.9 billion cubicfeet of gas.

the net Present Value (10%) of future revenue, before incometax, of the Proved plus Probable reserves as of june 30, 2012 isestimated by cawley, Gillespie & Associates to be $85.69 million. All of the reserves reported are attributable to the company’sWolfberry Project.

We see significant potential to expand our Wolfberry Project byupgrading the reserves through successful development drilling andby continuing to expand our activities into under-tested areas.

the company is currently carrying out a rapid oil and gas developmentprogram on its Wolfberry Project. the gross cost of a Wolfberry wellis currently approximately $2.1 million. current plans call for 43 gross(18.14 net) Wolfberry Project wells to spud in fiscal 2013 at an estimatedcost to the company of approximately $44 million. the extensive oiland gas infrastructure in the Midland basin allows for the low cost andtimely tie-in of wells into production.

there is considerable variability in the expected ultimate recoveryfrom well to well, however an average eur per well of 175 Mboe istargeted in several of the Wolfberry Project operating areas.

year over year growth in the number of wells that we haveparticipated in since our involvement in the Wolfberry Project in late2009 has been dramatic.

the company’s well count will decrease by 16 gross (7.0 net) wellsupon the completion of a pending asset sale.


Mar-

10

Jun-

10

Sep-1

0

Dec-1

0

Mar-

11

Jun-

11

Sep-1

1

Dec-1

1

Mar-

12

Jun-

12

Sep-1

2

2012

100

200

300

400

500

600

700

800

900

1000

2011

2010

ACTUAL PrOjeCTed

2011Sep-30

2011dec-31

2012Mar-31

2012jun-30

2012Sep-30

2012dec-31

2013Mar-31

2013jun-30

2013Sep-30

2013dec-31

Producing Wolfberry well

Gross 18 22 31 35 43 56 64 75 85 102

net 7.64 9.39 13.25 14.79 18.2 23.76 27.01 31.69 35.82 42.80

Well spud or drilled awaitingcompletion and/or tie in

Gross 3 4 1 6 6 6 7 9 11 6

net 1.31 1.67 0.31 2.54 2.49 2.46 2.93 3.77 4.43 2.33

production guidanceAfter accounting for lost production from the pending asset sale, we continue to believe that we will meet out forecasted December 31, 2012 net production exit rate, after royalties, of 900 – 1,000 boe/day.

A RAPID OIL AND GAS DEVELOPMENTPROGRAM IS CURRENTLY BEING CARRIEDOUT ON THE WOLFBERRY PROJECT

pending Asset Sale

in mid-December 2012, lynden uSA inc., our wholly owned subsidiary,entered into a definitive agreement with breitburn energy Partners l.P.of los Angeles, california, for the sale of 16 gross (7.0 net) WolfberryProject wells and underlying leases covering approximately 1,440 grossacres (630 acres net to lynden) for proceeds of $25.0 million.

the sale will have an effective date of December 1, 2012, and isexpected to close in 2012.

the company has a 43.75% working interest in the wells to be sold anda right to earn a 43.75% working interest in the portion of the leases notalready held by production. the company’s working interest partner inthe assets has also entered into an agreement to sell its interest. thecompany’s net production, after royalties, from the wells to be sold isapproximately 20% of the company’s production at December 1, 2012.

the sale is in line with the company’s stated objective to sell portions ofits proven acreage in order to manage its working capital position andto redeploy funds to its less developed and unproven acreage, wherethe company believes it can achieve the best returns for shareholders.

Oil (boe/day) Natural gas (boe/day)

HiSTORiCAL bOE/DAY (before Royalties)


Mitchell ranch Project Multi-zone Potential in the Eastern Shelf


Overviewin june 2010 we entered into a Participation Agreement to acquire a 50% interest in a unique

oil and gas lease covering in excess of 100,000 acres in coke, Mitchell, and Sterling counties of

West texas.

All of the acreage is contained within a historical ranch that lies to the immediate west of the

jameson oil field and is approximately 10 miles south-east of the iatan oil field.

the Mitchell ranch 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, we completed, together with our working interest partner, crownrock l.P., a

term assignment with a large, independent exploration and production company (“Seniorco”),

covering approximately 36,000 acres of the 103,400 acre Mitchell ranch Project. the term

assignment acreage is a contiguous block generally located in the southern portion of the ranch.

Pursuant to the 30 month term assignment to Seniorco, which can be extended by 90 day

continuous development, lynden and crownrock retain a 2.5% (as to 1.25% each) overriding

royalty interest on the term assignment acreage.

the term assignment provides for the return to lynden / crownrock, two years after the

expiration of the term of the assignment, of mineral rights above the base of the Strawn

formation. the agreement between the parties also provides for the sharing of certain technical

information on wells drilled by Seniorco, which we believe will greatly assist in the overall

execution of the company’s business strategy on the Mitchell ranch Project.

lynden has a 50% working interest in the 67,400 acres of the Mitchell ranch Project not subject

to the term assignment to Seniorco.


12

Experience: oil on the pits. Drill cuttings and fluids are charted in detail through the drilling process to guide stimulation programs.

Science: extensive technicalwork-ups define unique opportunities in each well.

CURRENT ACTIVITIESin addition to the potential to develop the acreage through the verticaldevelopment of stacked pay, the Mitchell ranch Project hosts severalseparate zones that exhibit potential for horizontal well development.

Several industry operators in the Permian basin have successfullydemonstrated the economics of horizontal development in certainhorizons in the Wolfcamp. other zones are currently being tested,both regionally and in close proximity to the Mitchell ranch Project, forhorizontal development in the cline Shale as well as in the Mississippian.

We are actively monitoring this significant new drilling activity andhave pushed out the timing of our drill testing in order to bestincorporate the results of other operators into the development planon the Mitchell ranch Project.

lynden has a 50% working interest in 67,400 acres

Mitchell

Sterling

Coke

MITCHell RaNCH OPPORTuNITy


13

Permian Basin: MMIITTCCHHEELLL RL RAANNCCH PRH PROOJJEECCTT

MuLTI-zONE POTENTIAL IN THE EAsTERN sHELf

Cline Shale ReSouRCe Play WolfCamP Shale ReSouRCe Play

Development fairways continue to expand Well design and completion recipe unlocked in some areas

82514_Lynden_AR12_INSIDE_p6n13_rv1.indd 13 12-12-22 2:33 PM

14

OUR Objective iS tO Sell pORtiOnS Of OUR pROven acReage in ORdeR tO RedeplOy fUndS tO OUR leSS develOped and UnpROven acReage, wheRe we believe we can achieve the beSt RetURnS fOR OUR ShaRehOldeRS.


82514_lynden_AR_Financials.indd 16 12-12-20 4:07 PM

Lynden energy | AnnuAL report 2012 » MAnAgeMent discussion And AnALysis 17

Description of Business

Lynden Energy Corp. (the “Company”) is a public company continued under the Business Corporations Act (British Columbia). The Company is a reporting issuer in British Columbia, Ontario and Alberta and its shares are listed on the TSX Venture Exchange under the symbol LVL. The Company is in the business of acquiring, exploring and developing petroleum and natural gas (“p&nG”) rights and properties. The Company has various working interests in the Wolfberry Project and Mitchell Ranch Project, located in the Permian Basin in West Texas, USA and in the Paradox Basin Project, located in the State of Utah, USA. There are no other operating segments.

Effective July 1, 2011, the Company prepares its consolidated financial statements in accordance with International Financial Reporting Standards (“IFRS”). The comparative financial information of fiscal 2011 in the management’s discussion and analysis of the results of operations and financial condition (“MD&A”) has also been restated to conform with IFRS. This MD&A should be read in conjunction with Note 19 “Transition to International Financial Reporting Standards” of the Company’s consolidated financial statements for the year ended June 30, 2012.

All figures are expressed in United States dollars unless otherwise stated.

For the purposes of this MD&A, the following terms are defined as follows:

Q1/2012 Three months ended September 30, 2011Q2/2012 Three months ended December 31, 2011Q3/2012 Three months ended March 31, 2012Q4/2012 Three months ended June 30, 2012

Q1/2011 Three months ended September 30, 2010Q2/2011 Three months ended December 31, 2010Q3/2011 Three months ended March 31, 2011Q4/2011 Three months ended June 30, 2011

current Year Year ended June 30, 2012prior Year Year ended June 30, 2011

Additional information about the Company may be found on SEDAR at www.sedar.com. Additional information relating to the Company’s operations and activities can also be found by visiting the Company’s website at www.lyndenenergy.com.

The effective date of this MD&A is October 26, 2012.

forwarD LookinG information

This MD&A contains “forward-looking” information. These statements express a belief, expectation or intention and are generally accompanied by words that convey projected future events or outcomes. The forward-looking statements include statements about the Company’s future operations, well counts, drilling and resource locations, anticipated exploration and production strategies, estimates of oil and natural gas production, reserve volumes and reserve values, projected expenses, revenue, earnings, cash flow, capital expenditures and other costs, capital raising activities, including potential asset divestitures, and hedge transactions. We have based these forward-looking statements on our current expectations and assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments, as well as other factors we believe are appropriate under the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties, including the volatility of oil and natural gas prices, our success in discovering, estimating, and developing oil and natural gas reserves, the availability and terms of capital, credit conditions of global capital markets, changes in economic conditions, regulatory changes (including but not limited to those related to carbon dioxide and greenhouse gas emissions), and other factors, many of which are beyond our control. See Risks and Uncertainties below and www.lyndenenergy.com/riskfactors.html. All of the forward-looking statements made in this MD&A are qualified by these cautionary statements. The actual results or developments anticipated may not be realized or, even if substantially realized, they may not have the expected consequences to or effects on our company or our business or operations. Such statements

MANAgEMENT DISCUSSION AND ANALYSISFor the Year ended June 30, 2012

82514_Lynden_AR12_FINANCIALS_rv1.indd 17 12-12-24 11:13 AM

Lynden energy | AnnuAL report 2012 » MAnAgeMent discussion And AnALysis18

are not guarantees of future performance and actual results or developments may differ materially from those projected in the forward-looking statements.

risks anD uncertainties

The Company’s principal activity of P&Ng exploration and development is considered to be inherently risky. Companies in this industry are subject to many and varied kinds of risks, including but not limited to, environmental, commodity price, political and economic, with some of the most significant risks being:

1. Substantial expenditures are required to explore for P&Ng reserves and there is no assurance that the Company will discover economic reserves;

2. The junior resource market, where the Company raises funds, is extremely volatile and there is no guarantee that the Company will be able to raise funds as it requires them;

3. Future operations will be subject to all of the risks normally incident to the operation and development of P&Ng properties and the drilling of P&Ng wells, which could result in personal injuries, loss of life and damage to property of the Company and others. The marketability and price of P&Ng that may be

acquired or discovered by the Company will be affected by numerous factors beyond the control of the Company. The Company will be subject to market fluctuations in the prices of P&Ng, deliverability uncertainties relating to the proximity of its reserves to pipelines and processing facilities and extensive government regulations. The P&Ng industry is intensely competitive and the Company must compete in all aspects of their operations with a number of other entities that may have greater technical ability and/or financial resources. Title to P&Nginterests is often not capable of conclusive determination, without incurring substantial expense; and

4. The Company is subject to the laws and regulations relating to environmental matters, including provisions relating to reclamation, discharge of hazardous material and other matters. The Company’s exploration and development activities are conducted by partners and/or operators who are in compliance with applicable environmental protection legislation. The Company is not aware of any existing environmental problems related to its properties that may cause material liability to the Company.

For a more detailed description of these risks, and others, see http://www.lyndenenergy.com/riskfactors.html.

prospect name county Gross acres net acres Lynden’s net interest Lynden net acres

West Martin Martin 4,040 3,467 43.75% 1,517

Midland 920 898 43.75% 393

glasscock 1,823 1,818 43.75% 795

Martin 1,127 1,127 30.625% 345

Wind Farms glasscock 3,355 2,419 43.75% 1,058

Tubb Howard 7,148 6,764 35.5% 2,401

total 18,413 16,493 6,509

Boe conversions

Barrel of oil equivalent (“boe”) amounts have been calculated using a conversion ratio of six thousand cubic feet of natural gas to one barrel of oil (6:1) to express quantities of natural gas and crude oil in a common unit. The term “boe” may be misleading, particularly if used in isolation. The conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

p&nG projects

Wolfberry Project, West Texas

The Company is party to a Participation Agreement to acquire interests of up to a 43.75% working interest in P&Ng leases in glasscock, Howard, Martin, Midland and Sterling counties in West Texas, USA. The leases are contained within three prospect areas:



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. The leases are subject to royalties to the mineral rights owners.

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 between 7,000 and 11,500 feet, drilling depth. In addition to this main objective, other conventional and unconventional productive zones occur both above and below the Wolfberry assemblage.

CrownQuest Operating LLC (“CrownQuest”), the operator of the prospects, is based in Midland, Texas and has extensive knowledge and experience in operating in the Permian Basin. The operator has drilled or participated in several hundred new wells in the Permian Basin where new completion techniques have been successfully applied.

The Company’s independent petroleum engineer, Cawley, gillespie & Associates, estimates the Company’s net Proved plus Probable (P2) reserves attributable to the Company’s working interest at June 30, 2012 to be 5.97 million barrels of oil and 19.14 billion cubic feet of gas. Of this amount, Proved reserves were 4.99 million barrels of oil and 15.9 billion cubic feet of gas. The Net Present Value (10%) of future revenue, before income tax, of the Proved plus Probable reserves as of June 30, 2012 is estimated by Cawley, gillespie & Associates to be $85.69 million. All of the reserves reported are attributable to the Company’s Wolfberry Project. A summary of the Cawley, gillespie & Associates report is available at www.sedar.com.

The Company is currently carrying out a rapid oil and gas development program on its Wolfberry Project, where the Company now has 47 gross (19.82 net) wells tied-in and producing. The gross cost of a Wolfberry well is currently approximately $2.1 million. The Company’s current plans call for 46 gross (19.11 net) Wolfberry Project wells to spud in fiscal 2013 at an estimated cost to the Company of approximately $46 million. Pursuant to the terms of the Wolfberry Project Participation Agreement, the Company’s funding amount for the 19.11 net wells is equivalent to 21.84 wells. The following table summarizes recent and anticipated upcoming drilling activity.

actuaL projecteD

2011sep-30

2011Dec-31

2012mar-31

2012jun-30

2012sep-30

2012Dec-31

2013mar-31

2013jun-30

2013sep-30

2013Dec-31

producing wolfberry well

gross 18 22 31 35 43 57 63 74 90 103

Net 7.64 9.39 13.25 14.79 18.2 24.07 26.44 31.04 37.45 42.89

well spud or drilled awaitingcompletion and/or tie in

gross 3 4 1 6 6 5 7 12 6 8

Net 1.31 1.67 0.31 2.54 2.49 2.02 2.93 5.09 2.54 3.20

The Company incurred $26,004,216 of capital expenditures on the project during the Current Year. Of this amount, approximately $860,000 was for land and lease costs; approximately $24,600,000 was for drilling, completion, facilities and tie-in; and approximately $575,000 was for capitalized borrowing costs.



Lower Wolfcamp zone in the historical well was attempted in November 2011, however the well produced back water which matched a zone approximately 3,200 feet above the targeted Lower Wolfcamp zone. Accordingly, the test has been deemed inconclusive due to an undetermined mechanical problem. The Company had anticipated that two new wells would be spud, in the vicinity of the Spade 17 #1, in the summer of 2012 to further test zones of interest near the Spade 17 #1. As a result of significant new drilling activity in the general area around the Mitchell Ranch Project the timing of the new vertical wells has been pushed out in order to best incorporate the results of other operators into the development plan on the Mitchell Ranch Project.

In addition, the Company is actively monitoring the multi-well vertical / horizontal drill program undertaken by SeniorCo on the Mitchell Ranch Project term assignment acreage.

During the Current Year, the Company received $410,208 in P&Ngsales, incurred royalties of $92,298, and incurred production taxes of $14,652. It has been determined that the Mitchell Ranch Project is in the pre-production stage and as such, the net revenues have been credited to capitalized costs.

The Company incurred $286,968 of capital expenditures on the project during the Current Year. The majority of these expenditures were for land acquisition costs and the cost of the re-entry of the historical well.

Paradox Basin Project, Utah

The Paradox Basin project is a natural gas focused project located in the Paradox Basin, Southwest Utah. The project is separated into two contiguous P&Ng prospect area: the Northern Prospect Area and the Southern Prospect Area. The Company has a 55% before payout working interest (41.25% after payout working interest) in an 80% net revenue interest in the Northern Prospect Area. 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 Southern Prospect Area.

The Company 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.

The Company’s interest in the gas gathering system, including approximately 25 miles of pipeline, is held though its 47.99% interest in Abajo gas Transmission Company, LLC (“Abajo”). Through its interest in Abajo, the Company 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.

Mitchell Ranch Project, West Texas

The Company is party to a Participation Agreement with CrownRock LP (“CrownRock”) pertaining to a single P&Ng lease covering approximately 103,400 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 Company’s partner in the Wolfberry and Paradox Basin projects. 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, the Company and CrownRock completed a term assignment with a large, independent exploration and production company (“SeniorCo”), covering approximately 36,000 acres of the 103,400 acre Mitchell Ranch Project, located generally in the southern portion of the ranch. Pursuant to the 30 month term assignment to SeniorCo, which can be extended by 90 day continuous development, the Company and CrownRock retain a 2.5% (as to 1.25% each) overriding royalty interest on the term assignment acreage. The term assignment provides for the return to the Company/CrownRock, two years after the expiration of the term of the assignment, of mineral rights above the base of the Strawn formation. The agreement between the parties also provides for the sharing of certain technical information on wells drilled by SeniorCo, which the Company believes will greatly assist in the overall execution of the Company’s business strategy on the Mitchell Ranch Project.

The Company has a 50% working interest in the 67,400 acres of the Mitchell Ranch Project not subject to the term assignment to SeniorCo.

The Company currently has one (0.5 net) producing well on the 67,400 acres located in the northern portion of the ranch, 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 undertaken in late May 2011, and targeted a Lower Wolfcamp zone between 4,900 and 5,000 feet. On October 13, 2011, the Company reported that in the first 125 days since oil production from this interval began, the well averaged 53 barrels of oil per day. The well has now produced approximately 12,500 barrels of oil from this interval alone. This is the third oil productive interval in this well.

Based on these positive results, a historical well, approximately one mile to the southeast of the Spade 17 #1, was re-entered. Historical logs indicate the presence of a Lower Wolfcamp zone with characteristics similar to those in the Spade 17 #1. A completion of the targeted



During the Current Year, the Company received $197,460 in P&Ng sales, incurred royalties of $33,888, incurred transportation and marketing costs of $28,799, and incurred production taxes of $6,273. 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. It has been determined that the Paradox Basin Project is in the pre-production stage and as such, the net revenues have been credited to capitalized costs.

As a result of the depressed price of natural gas, the Company has not undertaken any material development work on the Paradox Basin Project over the past several years and consequently the Company’s lease holdings continue to expire. The Company expects that substantially all of its lease holdings not held by production will expire in the next three years.

transition to internationaL financiaL reportinG stanDarDs – chanGes in accountinG poLicies

IFRS represents standards and interpretations approved by the International Accounting Standards Board (“IASB”), and are comprised of IFRSs, International Accounting Standards (“IASs”), and interpretations issued by the IFRS Interpretations Committee (“IFRICs”) or the former Standing Interpretations Committee (“SICs”).

At the date of authorization of these financial statements, the IASB and IFRIC has issued the following new and revised Standards and Interpretations which are not yet effective for the relevant reporting periods:

• ifrs 7 (amendment) New disclosure requirements on the effect of offsetting arrangements on an entity’s financial position3

• ifrs 9 New financial instruments standard that replaces IAS 39 for classification and measurement of financial assets and liabilities5

• ifrs 10 New standard to establish principles for the presentation of consolidated financial statements when an entity controls multiple entities3

• ifrs 11 New standard to account for the rights and obligations in accordance with joint agreements3

• ifrs 12 New standard for the disclosure of interests in other entities not within the scope of IFRS 9/IAS 393

• ifrs 13 New standard on the measurement and disclosure of fair value3

• ias 1 (amendment) Presentation of other comprehensive income2

• ias 12 (amendment) Recovery of underlying investment properties measured using a fair value model1

• ias 27 (amendment) New standard issued that supersedes IAS 27 to prescribe the accounting for separate financial statements3

• ias 28 (amendment) New standard issued that supersedes IAS 28 (2003) to prescribe the accounting for investments in associates and joint ventures3

• ias 32 (amendment) Clarifies the application of the requirements of offsetting of financial assets and liabilities4

• ifric 20 Interpretation issued that clarifies when production stripping should lead to the recognition of an asset and how the asset should be measured, both initially and in subsequent periods3

1 Effective for annual periods beginning on or after January 1, 20122 Effective for annual periods beginning on or after July 1, 20123 Effective for annual periods beginning on or after January 1, 20134 Effective for annual periods beginning on or after January 1, 20145 Effective for annual periods beginning on or after January 1, 2015

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



Three months endedJun 30, 2012


Year endedJun 30, 2012

Year endedJun 30, 2011

net revenuesPetroleum revenues $ 3,770,460 $ 1,473,235 $ 12,564,263 $ 3,786,650 Natural gas revenues 648,512 396,518 2,614,566 916,221

4,418,972 1,869,753 15,178,829 4,702,871

Royalties (1,010,920) (423,047) (3,468,298) (1,051,167)Production & operating (677,540) (123,782) (1,821,397) (399,637)

Net back $ 2,730,512 $ 1,322,924 $ 9,889,134 $ 3,252,067

production volumes and pricingtotal volumes

Petroleum production (bbl) 42,317 14,685 137,280 42,147

Natural gas production (mcf) 125,801 42,162 374,377 112,610

Daily production averages (before royalties)

Petroleum (bblpd) 465 161 375 115

Natural gas (mcfpd) 1,382 463 1,023 309

Barrell of oil equivalent (boepd) 695 238 546 167

average prices

Petroleum selling price ($/bbl) $ 89 $ 100 $ 92 $ 90 Natural gas selling price ($/mcf) $ 5.16 $ 9.40 $ 6.98 $ 8.14

The transition to IFRS has not impacted the underlying economics of the Company’s operations or cash flows. However, IFRS has resulted and will result in the following changes in financial reporting processes:

• The Company upgraded its accounting software in fiscal 2011 in order to improve its ability to collect and analyze accounting data;

• The Company will have to gather more timely data on its P&Ng properties in order to look for indicators of impairment at each reporting date; and

• The Company will have to track its E&E and D&P assets at a level no bigger than a cash generating unit in order to properly record movements between the two categories of assets and to record the appropriate amounts of depletion and depreciation for specific assets.

resuLts of operations

The Company reported net earnings of $4,264,192 and total comprehensive income of $4,057,383 for the Current Year compared to a net loss of $859,377 and total comprehensive loss of $641,016 for the Prior Year. Significant components of the Current Year’s net earnings were net revenue of $11,710,531 and depletion and depreciation of $4,749,929.

P&Ng Revenue

The Company reported net P&Ng revenues of $11,710,531 (Prior Year - $3,651,704) for the Current Year, all from its Wolfberry Project wells. In conjunction with the revenues, the Company reported royalties paid of $3,468,298 (Prior Year - $1,051,167) and paid production and operating expenses of $1,821,397 (Prior Year - $399,637) for the Current Year. The Company also incurred $4,749,929 (Prior Year - $1,218,982) of depletion and depreciation for the Current Year.



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

Production volumes have increased steadily in the past four quarters as a result of the pace of drilling and tie-in of new Wolfberry wells (see table in Wolfberry Project section above).

Average selling prices correlate directly to the volatility in the price of oil and natural gas. The Company did not hedge any of its production in the Prior Year or Current year. Accordingly, the Company was impacted by fluctuations in the prices of oil and natural gas. To protect future cash flows for planned capital expenditures, the Company entered into the following commodity contracts subsequent to the Current Year:


Three months endedmar 31, 2012

Three months endedDec 31, 2011

Three months endedsep 30, 2011

net revenuesPetroleum revenues $ 3,770,460 $ 3,571,287 $ 2,742,516 $ 2,480,000 Natural gas revenues 648,512 658,544 650,519 656,991

4,418,972 4,229,831 3,393,035 3,136,991

Royalties (1,010,920) (971,196) (771,803) (714,379)Production & operating (677,540) (508,664) (362,368) (272,825)

Net back $ 2,730,512 $ 2,749,971 $ 2,258,864 $ 2,149,787

production Volumes and pricingtotal volumes

Petroleum production (bbl) 42,317 36,113 30,017 28,833

Natural gas production (mcf) 125,801 94,113 79,989 74,474

Daily production averages (before royalties)

Petroleum (bblpd) 465 397 326 313

Natural gas (mcfpd) 1,382 1,034 869 809

Barrel of oil equivalent (boepd) 695 569 471 448

average prices

Petroleum selling price ($/bbl) $ 89 $ 99 $ 91 $ 86

Natural gas selling price ($/mcf) $ 5.16 $ 7.00 $ 8.13 $ 8.82

percentages of total revenue

Royalties 23% 23% 23% 22%

Production and operating 15% 12% 11% 9%Net back 62% 65% 66% 69%

Time Period Product Type Volume Price Basis

september 2012 to December 2012 Oil Collar 7,500 Bbls/mo $80/Bbl - $104/Bbl NYMEX

January 2013 to august 2013 Oil Collar 5,000 Bbls/mo $80/BBL - $104/BBL NYMEX



The hedge contracts summarized above reflect only a small portion of the Company’s anticipated production and accordingly the Company will continue to be impacted by fluctuations in the prices of oil and natural gas.

The Company anticipates significant increases in daily production volumes as development of the Wolfberry Project continues. The Company is targeting a December 31, 2012 net production exit rate, after royalties, of approximately 900 – 1,000 boe/day.

Production and operating expenses have remained relatively consistent, and within an expected range given the Company’s mix of new and older wells. These expenses are increasing gradually as the Company’s older wells require more maintenance.

general and Administrative

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

general and administrative expenses were $962,244 (Prior Year - $833,244) during Current Year. Some of the differences in expenditures were as follows:

• Administrative fees increased by $40,042 during 2012 over 2011 in conjunction with the Company’s increasing business activities. Administrative fees comprise accounting, secretarial and other administrative services.

• The Company paid directors fees of $48,146 (2011 - $nil) during 2012. The Company started to pay its independent directors fees starting in August 2011. The fees are to compensate the independent directors for the time spent on the Company’s business.

• Office and miscellaneous increased by $9,629 during 2012 over 2011 primarily due to increased printing costs of the Company’s annual report.

• Professional fees include accounting and audit fees and legal fees. Professional fees increased by $29,283 during 2012 over 2011 primarily due to increased legal, audit and tax fees incurred in support of the Company’s expanding business.

• Promotion increased by $12,910 during 2012 over 2011 primarily due to additional work on the Company’s annual report and increased efforts to market the Company.

• Travel decreased by $22,820 during 2012 compared to 2011 primarily due to significant travel costs incurred during Q4/2011 as Management traveled to meet with the operator of the Company’s oil and gas projects and Management travelled throughout North America for investor relations purposes.

Foreign Currency Translation

The foreign exchange gain of $76,576 included in net earnings for 2012 primarily relates to the effect of the strengthening United States dollar on the Company’s liabilities denominated in Canadian dollars.

The foreign currency translation loss of $206,809 included in other comprehensive income for 2012 reflects the strengthening of the United States dollar and relates primarily to translating the Company’s assets denominated in Canadian dollars into the United States dollar. The assets denominated in Canadian dollars relate to Lynden Energy Corp. and Lynden Exploration Ltd., companies whose functional currency is the Canadian dollar.

Share-based Payments

Share-based payments increased by $763,952 during 2012 over 2011. The increase was primarily due to the grant of 2,725,000 share options to directors, officers, employees, and consultants during 2012. The Company uses the Black-Scholes method to determine fair value for all share-based awards. The Company grants share options on a periodic basis in order to provide non-cash compensation to its directors, officers, employees and consultants and to align the interests of the directors, officers, employees and consultants with the interests of shareholders.

Other Items

Finance costs consist of the unwinding of the discount on the decommissioning liabilities.

The Company impaired the Paradox Basin Project to its estimated recoverable amount of $566,700 by estimating the present value of the future net cash flows expected to be derived from the continued use of the asset. Based on oil prices ranging from $80.27 to $91.94; natural gas prices ranging from $2.80 to $4.60; and a discount rate of 18% used in the discounted cash flow model, an impairment of $110,570 was charged to earnings to adjust the carrying value.

The Company reported an impairment of its Mitchell Ranch P&Ng assets during 2011 in the amount of $1,579,595 for a well drilled in 2010 for which future cash flows were anticipated to be $nil.



financiaL conDition, LiQuiDitY anDcapitaL resources

As at June 30, 2012, the Company had a working capital deficit of $12,083,231 compared to a working capital deficit of $1,661,073 as at June 30, 2011.

Major sources of cash during 2012 were 1) $10,349,903 from operating activities; 2) $14,500,000 from the Credit Facility (see below); 3) net proceeds of $6,542,123 from a private placement and the exercise of warrants and share options; and 4) $503,918 of recoveries of exploration and evaluation assets from the Paradox Basin and Mitchell Ranch sales of P&Ng.

The major use of cash during the Current Period was $24,671,755 spent on development and production assets relating to the Wolfberry Project.

On August 31, 2011, the Company reported that the Company’s wholly owned subsidiary, Lynden USA Inc., secured a three year reducing revolving line of credit (the “Credit Facility”) in an amount up to $50 million with Texas Capital Bank of Dallas, Texas. Effective June 30, 2012, the Credit Facility provided a borrowing base of $16.0 million. Subsequent to June 30, 2012, the borrowing base was increased to $26.9 million. As of the date of this MD&A $23.0 million of the borrowing base has been drawn down.

The Credit Facility contains certain mandatory covenants, including minimum current ratio and cash flow requirements, and other standard business operating covenants. Failure to meet these covenants may result in the amounts outstanding under the Credit Facility to become immediately due and payable. The Company has complied with all of these covenants as at and during the year ended June 30, 2012. The Company has pledged its interest in its P&Ng and other assets to Texas Capital Bank as security for liabilities pursuant to the Credit Facility.

The Company is currently carrying out a rapid oil and gas development program on its Wolfberry Project. The gross cost of a Wolfberry well is currently approximately $2.1 million. The Company’s current plans call for 46 gross (19.11 net) Wolfberry Project wells to spud in fiscal 2013 at an estimated cost to the Company of approximately $46 million. The Company anticipates financing the majority of its Wolfberry Project capital expenditures through operating revenues and upward borrowing base revisions on the $50 million reducing revolving line of credit with Texas Capital Bank. In order for the Company to carry out the proposed development program on the Wolfberry Project it is anticipated that the Company will need to raise additional capital through the sale of equity, issuance of debt or the sale of assets.

Income Taxes

The Company reported an income tax recovery of $1,503,678 (2011 - $nil) as the result of recognizing deferred tax assets of $1,593,678 as at June 30, 2012. The Company has started to recognize deferred tax assets during 2012 due to the net earnings in the Company’s US operations reported for 2012 and management’s judgment that it is probable that the Company will report net earnings in future years.

The Company reported an income tax expense of $90,000, included in the amount above, (2011 - $nil) for taxes payable to the state of Texas.

Fourth Quarter Operations

During Q4/2012, the Company incurred net earnings of $1,487,740 compared to a loss of $1,064,870 during Q4/2011. Larger income and expenses incurred and significant discrepancies between Q4/2012 and Q4/2011 are as follows:

• The Company had $2,730,512 (Q4/2011 - $1,322,924) of net P&Ng sales during Q4/2012 from its proven and producing Wolfberry wells. The large increase in sales is due to the successful completion and tie-in of four additional wells in the Current Period.

• The Company incurred $2,135,248 (Q4/2011 - $494,481) of depletion and depreciation during Q4/2012. The large increase is primarily due to higher production rates and an increased carrying cost, which are in turn attributable to the increase in the number of producing wells.

• The Company incurred $321,527 (Q4/2011 - $260,130) of general and administrative expenditures during Q4/2012. The Company has incurred increasing general and administrative costs during fiscal 2012 in order to keep pace with its expanding operations.

• The Company incurred $203,316 (Q4/2011 - $62,994) of non-cash share-based payments expense as a result of the grant and vesting of stock options.

• As discussed above, the Company impaired property, plant and equipment by $110,570 (Q4/2011 - $1,579,595) during Q4/2012.

• As discussed above, the Company recorded a $1,503,678 (Q4/2011 - $nil) income tax recovery during Q4/2012.



Timing of additional capital expenditures on the Mitchell Ranch Project is not presently known, however the Company does not anticipate significant capital expenditures in the next 3 months. There are currently no major capital expenditures planned for the Paradox Basin Project.

While the working capital deficit has significantly increased over the past several quarters, it is the Company’s view that the value of its P&Ng holdings is increasing at a rate significantly greater than the rate of increase of the working capital deficit. It is the Company’s objective to sell portions of its proven acreage in order to manage its working capital position and to redeploy funds to its unproven acreage, where the Company believes it can achieve the best returns for shareholders.

financiaL instruments

As at June 30, 2012, the Company’s financial instruments are cash and cash equivalents, trade and other receivables, the credit facility, and trade and other payables. The amounts reflected in the statement of financial position are carrying amounts and approximate their fair values due to their short-term nature. These financial instruments are classified as follows:

• Cash and cash equivalents – loans and receivables

• Trade and other receivables – loans and receivables

• Credit facility – other financial liabilities

• Trade and other payables – other financial liabilities

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

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

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

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

At June 30, 2012, the Company has no financial instruments measured in the fair value hierarchy.

a) Credit Risk

Credit risk is the risk that one party to a financial instrument will cause a financial loss for the other party by failing to discharge an obligation. The Company’s cash and cash equivalents and trade and other receivables are exposed to credit risk. Management believes the credit risk on cash is low because the counterparties are highly rated financial institutions. The majority of the Company’s trade and other receivables are with customers in the petroleum and natural gas industry and are subject to normal industry credit risks. The Company generally extends unsecured credit to these customers and therefore the collection of trade and other receivables may be affected by changes in economic or other conditions. The Company believes the risk is mitigated by the size and reputation of the companies to which they extend credit. The Company has not experienced any material credit loss in the collection of trade and other receivables to date and therefore has not made any provision for bad debts.



b) Liquidity Risk

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

Advances under the Credit Facility can be in the form of Eurodollar loans, which have a maximum period of 90 days, or in the form of Floating Rate loans, which can remain outstanding to the Credit Facility final maturity date of August 29, 2014. 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 Wolfberry Project 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.

The aging of trade and other receivables are as follows:

June 30, 2012 June 30, 2011 July 1, 2010

trade and other receivables

0 to 60 days $ 1,366,163 $ 929,795 $ 322,325

61 to 120 days 38,465 14,563 32,268

>120 days 44,713 30,150 -

$ 1,449,341 $ 974,508 $ 354,593

total Less than

1 year one to

two years more than two years

Credit facility $ 14,532,753 $ 14,532,753 $ - $ -

Trade and other payables 8,388,644 8,388,644 - -

Income taxes payable 90,000 90,000 - -

$ 23,011,397 $ 23,011,397 $ - $ -

c) Market Risk

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



cashtrade and

otherreceivables

trade andother

payables

net assetsexposure

effect of +/-10% change in

currency

canadian dollar denomination $ 6,594,709 $ 11,888 $ (90,115) $ 6,516,482 $ 651,648

i) Interest Rate Risk

Interest rate risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes in market interest rates. The Company’s cash and credit facility are exposed to interest rate risk as the Company invests cash at floating rates of interest in highly liquid instruments and it borrows funds at floating rates of interest. Fluctuations in interest rates impact interest income and expense. As at June 30, 2012, 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, 2012.

ii) Currency Risk

Currency risk is the risk that fair value or future cash flows of a financial instrument will fluctuate because of changes in foreign exchange rates. Financial instruments that impact the Company’s earnings or loss due to currency fluctuations include Canadian dollar denominatedassets and liabilities. The Company does not use derivative instruments or hedges to manage currency risks. The sensitivity of the Company’searnings 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, 2012, a 10% depreciation or appreciation of the Canadian dollar against the United States dollar would result in an increase or decrease, respectively, in the Company’s earnings or loss by $651,648.

iii) Price Risk

The Company’s P&Ng production is marketed and sold on the spot market to area aggregators based on daily spot prices that are adjusted for product quality and transportation costs. The Company’s cash flow from product sales will therefore be impacted by fluctuations in commodity prices. The Company did not use derivative financial instruments to manage this risk during the year ended June 30, 2012.

off-BaLance sheet arranGements

The Company has not engaged in any off-balance sheet arrangements such as obligations under guarantee contracts, a retained or contingent interest in assets transferred to an unconsolidated entity, any obligation under derivative instruments or any obligation under a material variable interest in an unconsolidated entity that provides financing, liquidity, market risk or credit risk support to the Company or engages in leasing or hedging services with the Company.



For the Years Ended June 30 2012 2011 2010

financial results

P&Ng revenues (net) $ 11,710,531 $ 3,651,704 $ 1,039,599

Earnings (loss) $ 4,264,192 $ (859,377) $ (4,504,327)

Basic and diluted loss per common share $ 0.04 $ (0.01) $ (0.07)

financial position

Working capital (deficit) $ (12,083,231) $ (1,661,073) $ 1,422,984

Total assets $ 54,424,369 $ 24,215,899 $ 37,923,318

Total equity $ 30,576,814 $ 18,592,113 $ 37,133,097

seLecteD annuaL information

The following selected financial data for the years ended June 30, 2012 and 2011 have been prepared in accordance with IFRS and in US dollars. Financial data for the year ended June 30, 2010 is presented in accordance with Canadian gAAP and in Canadian dollars. This selected financial data should be read in conjunction with the Company’s audited consolidated financial statements.

The Company’s P&Ng net revenues have increased steadily over the last three years as more wells were drilled, completed and tied-in. All of these revenues were earned from the Company’s Wolfberry Project wells.

The Company reported earnings for the first time in 2012 as the revenues generated from its Wolfberry Project wells have grown to the point where revenues cover the Company’s expenses. The Company also did not have any significant impairment of property, plant and equipment in 2012.

The most significant components of the loss reported for 2011 were 1) the impairment of $1,579,595 of property, plant, and equipment concerning a well drilled in 2010 on the Mitchell Ranch Project for which future cash flows were anticipated to be $nil; and 2) depletion and depreciation of $1,218,982.

The most significant component of the losses reported for 2010 was the impairment of CDN$3,374,638 of property, plant and equipment to reflect expired Paradox Basin Project leases.

As a result of the transition to IFRS at July 1, 2010, the Company incurred impairments totaling $26,136,815 to its exploration and evaluation assets and its equity investment in Abajo (see note 19 of the consolidated financial statements).

The Company has incurred approximately $960,000, $830,000, and CDN$720,000 in general and administrative expenditures in 2012, 2011 and 2010 respectively.

The Company’s working capital has decreased steadily over the past three fiscal years as the Company has been expending significant capital on its Wolfberry and Mitchell Ranch Projects. During 2012, the Company drew down $14,500,000 on its Credit Facility and has invested these funds into the Wolfberry Project. During 2011 and 2010, capital expenditures outstripped equity financings the Company completed during the same periods.



fiscal 2012 fiscal 2011

2012jun 30

$

2012mar 31

$

2011Dec 31

$

2011sep 30

$

2011jun 30

$

2011mar 31

$

2010Dec 31

$

2010sep 30

$

revenues

P&Ng sales net of royalties 3,408,052 3,258,635 2,621,232 2,422,612 1,446,706 1,149,457 518,797 536,744

expenses

Production & operating 677,540 508,664 362,368 272,825 123,782 105,157 69,027 101,671

Depletion & depreciation 2,135,248 895,754 867,878 851,049 494,481 317,720 223,681 183,100

Share-based payments 203,316 263,970 486,919 419,742 62,994 130,811 158,046 258,144

earnings (loss) 1,487,740 1,357,547 639,271 779,634 (1,064,870) 448,181 (137,548) (105,140)

earnings (loss) per share 0.01 0.01 0.01 0.01 (0.01) - - -

working capital (deficit) (12,083,231) (15,106,536) (11,833,805) (5,599,555) (1,661,073) 5,362,028 6,502,546 (337,194)

2012mar 31

$

2011Dec 11

$

2011sep 30

$

2011jun 30

$

2011mar 31

$

2010Dec 31

$

2010sep 30

$

earnings (loss) as reported 438,690 (815,102) 4,797,693 (1,339,318) (774,076) (1,618,526) (1,446,149)

earnings (loss) restated 1,357,547 639,271 779,634 (1,064,870) 448,181 (137,548) (105,140)

earnings (loss) per share as reported 0.01 (0.01) 0.05 (0.01) (0.01) (0.02) (0.02)

earnings (loss) per share restated 0.01 0.01 0.01 (0.01) - - -

The revenues reported from the March 31/11 quarter onwards have generally increased due to additional Wolfberry wells being drilled and commencing production. The increase in production and operating expenses, and depletion and depreciation expenses, corresponds to the increase in P&Ng sales.

The quarterly earnings (losses) vary considerably mainly due to write-down of P&Ng property interests, P&Ng sales, depletion and depreciation, and granting of share options.

The Company’s working capital deficit has increased significantly over fiscal 2012 as the pace of the Wolfberry Project development has increased. These development expenditures have been financed primarily with debt under the Credit Facility.

The Company has restated the quarterly information above to reflect adjustments to foreign exchange expense during each of the periods. The offsetting entry was to the foreign currency translation reserve, with no impact on the overall equity.

summarY of QuarterLY information

The following table presents selected financial information for each of the most recent eight quarters in accordance with IFRS:



reLateD partY transactions

For year ended June 30, 2012, the Company incurred the following fees and expenses in the normal course of operations with key management and directors and entities related to key management and directors. Expenses have been measured at the exchange amount which is determined on a cost recovery basis.

1 Squall Capital Corp., a private company controlled by Colin Watt.2 Bereskin and Associates, Inc., a private company controlled by Robert Bereskin.3 Western Energy Consultants LLC, a private company controlled by John McLennan.4 Maitland and Company, a law firm with which Ron Paton is associate counsel. 5Share-based payments are the fair value of share options calculated using the Black-Scholes model.

During the year ended June 30, 2012, transportation and marketing costs of $28,799 were paid or accrued to Abajo.

administrativefee

consultingfees

Directors andcommittee

fees

Legalfees

share-basedpayments5

squall capital corp.1 $ 192,803 $ - $ - $ - $ -

richard andrews $ - $ 251,639 $ - $ - $ 549,196

Bereskin and associates, inc.2 $ - $ 19,052 $ 26,074 $ - $ -

western energy consultants LLc3 $ - $ - $ 22,074 $ - $ -

maitland and company4 $ - $ - $ - $ 34,675 $ -

colin watt $ - $ - $ - $ - $ 449,703

ron paton $ - $ - $ - $ - $ 106,713

john mcLennan $ - $ - $ - $ - $ 31,549

robert Bereskin $ - $ - $ - $ - $ 26,967

Laurie sadler $ - $ - $ - $ - $ 23,966

$ 192,803 $ 270,691 $ 48,148 $ 34,675 $ 1,188,094



outstanDinG share Data

As at October 26, 2012, the Company had the following securities issued and outstanding:

number exercise price expiry Date

Common shares 109,865,520 n/a n/a

Warrants 14,214,000 $0.70 October 27, 2013

Warrants 5,906,000 $0.70 November 12, 2013

Warrants 295,760 $0.70 November 19, 2013

Warrants 5,082,500 $0.65 May 4, 2015

Warrants 2,432,500 $0.65 May 18, 2015

Stock options 100,000 $0.80 November 8, 2012

Stock options 765,000 $1.40 April 27, 2013

Stock options 200,000 $0.70 July 20, 2013

Stock options 1,010,000 $0.30 October 7, 2014

Stock options 1,500,000 $0.55 March 16, 2015

Stock options 260,000 $0.60 July 20, 2015

Stock options 2,550,000 $0.80 July 21, 2016

Stock options 75,000 $0.80 September 1, 2016

Stock options 1,397,500 $0.50 July 2, 2017

fully Diluted 145,653,780

Directors anD officers

richard andrews Director, Chairman

colin watt Director, President, CEO and Secretary

robert Bereskin Director

ron paton Director

john mcLennan Director

Laurie sadler CFO


Lynden energy | AnnuAL report 2012 » AudItorS’ report34

We have audited the accompanying consolidated financial statements of Lynden Energy Corp., which comprise the consolidated statements of financial position as at June 30, 2012, June 30, 2011 and July 1, 2010, and the consolidated statements of income (loss) and comprehensive income (loss), changes in equity and cash flows for the years ended June 30, 2012 and June 30, 2011, and a summary of significant accounting policies and other explanatory information.

management’s responsibility for the consolidated financial statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards, 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.

auditor’s responsibilityOur responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. 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.

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. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. 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.

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, 2012, June 30, 2011 and July 1, 2010, and its financial performance and its cash flows for the years ended June 30, 2012 and June 30, 2011 in accordance with International Financial Reporting Standards.

INDEPENDENTAUDITORS’ REPORTto the ShareholderS oF lYnden energY Corp.

DeLoitte & touche LLp2800 - 1055 Dunsmuir Street4 Bentall CentreP.O. Box 49279Vancouver BC V7X 1P4Canada

Tel: 604-669-4466Fax: 778-374-0496www.deloitte.ca


Lynden energy | AnnuAL report 2012 » AudItorS’ report 35

emphasis of matter

Without qualifying our opinion, we draw attention to Note 1 in the consolidated financial statements which indicates that the Company has an accumulated deficit of $36.3 million as of June 30, 2012, and a working capital deficiency of $12.1 million for the year ended June 30, 2012. These conditions, along with other matters as set forth in Note 1, indicate the existence of a material uncertainty that may cast significant doubt about the Company’s ability to continue as a going concern.

other matter

Certain information explaining the transition to International Financial Reporting Standards presented in Note 19 to these consolidated financial statements is derived from financial statements for the years ended June 30, 2011 and June 30, 2010 prepared in accordance with previous Canadian generally accepted accounting principles. The consolidated financial statements of Lynden Energy Corp. for the years ended June 30, 2011 and June 30, 2010 prepared in accordance with Canadian generally accepted accounting principles were audited by another auditor who expressed an unmodified opinion on those statements on October 27, 2011.

Chartered AccountantsOctober 26, 2012Vancouver, Canada


Lynden energy | AnnuAL report 2012 » ConSoLIdAted FInAnCIAL StAteMentS36

CONSOLIDATED FINANCIALSTATEMENTSFor the Years ended June 30, 2012 and 2011

assets notes June 30, 2012 June 30, 2011 July 1, 2010

current assets (note 19) (note 19)

Cash and cash equivalents $ 9,478,825 $ 2,600,966 $ 1,633,799

Trade and other receivables 1,449,341 974,508 354,593

Prepaid expenses - 2,074 5,636

total current assets 10,928,166 3,577,548 1,994,028

non-current assets

Exploration and evaluation assets 5 3,734,764 3,724,856 2,693,053

Property, plant and equipment 6 38,167,761 16,913,495 5,167,310

Deferred tax assets 17 1,593,678 - -

total non-current assets 43,496,203 20,638,351 7,860,363

total assets $ 54,424,369 $ 24,215,899 $ 9,854,391

LiaBiLities anD sHareHoLDers' eQuitY

current liabilities

Credit facility 7 $ 14,532,753 $ - $ -

Trade and other payables 8,388,644 5,238,621 657,391

Income taxes payable 17 90,000 - -

total current liabilities 23,011,397 5,238,621 657,391

Decommissioning liabilities 8 836,158 385,165 215,901

total liabilities 23,847,555 5,623,786 873,292

equity

Common shares 9 48,755,838 43,206,385 36,958,102

Share-based payments reserve 9 18,063,623 15,685,758 11,682,011

Foreign currency translation reserve 11,552 218,361 -

Deficit (36,254,199) (40,518,391) (39,659,014)

total equity 30,576,814 18,592,113 8,981,099

total liabilities and equity $ 54,424,369 $ 24,215,899 $ 9,854,391

nature and continuance of operations 1

subsequent events 18

approved by the Directors:

Colin Watt Ron PatonThe accompanying notes are an integral part of these consolidated financial statements.

LYnDen enerGY corp. consolidated statements of financial position(Presented in US $, except where indicated)


Lynden energy | AnnuAL report 2012 » ConSoLIdAted FInAnCIAL StAteMentS 37


notesYear ended

June 30, 2012Year ended

June 30, 2011

(note 19)

reVenue

Petroleum and natural gas $ 15,178,829 $ 4,702,871

Royalties (3,468,298) (1,051,167)

11,710,531 3,651,704

expenses

Production and operating expenses 1,821,397 399,637

Depletion and depreciation 4,749,929 1,218,982

Foreign exchange loss (gain) (76,576) (109,979)

general and administrative 11 962,244 833,244

Share-based payments 10 1,373,947 609,995

8,830,941 2,951,879

operating earnings 2,879,590 699,825

Interest income 13,642 32,103

Finance costs 8 (22,148) (11,710 )

Impairment of exploration and evaluation assets (110,570 ) (1,579,595)

earnings (loss) before income taxes 2,760,514 (859,377)

income tax recovery 17 (1,503,678) -

net earnings (loss) for the year 4,264,192 (859,377)

other comprehensive income (loss)

Foreign currency translation reserve (206,809) 218,361

total comprehensive income (loss) for the year $ 4,057,383 $ (641,016)

weighted average number of common shares outstanding 9

Basic 96,825,621 87,285,138

Diluted 97,229,621 87,285,138

Basic and diluted earnings (loss) per common share $ 0.04 $ (0.01)

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

LYnDen enerGY corp. consolidated statements of income (Loss) and comprehensive income (Loss)(Presented in US $, except where indicated)


Lynden energy | AnnuAL report 2012 » ConSoLIdAted FInAnCIAL StAteMentS38

common sharesshare-based

payments reserve

foreigncurrency

translationreservenumber amount Deficit total

BaLance at JuLY 1, 2010 (note 19) 73,279,094 $ 36,958,102 $ 11,682,011 $ - $ (39,659,014) $ 8,981,099

Common shares issued for cash:

Private placement 20,200,000 6,249,841 3,653,488 - - 9,903,329

Share issue costs on private placement - (356,012) (206,545) - - (562,557)

Exercise of stock options 33,333 17,271 (7,235) - - 10,036

Exercise of warrants 509,000 270,119 (84,865) - - 185,254

Units issued to agent 215,760 67,064 38,908 - - 105,972

Share-based payments - - 609,996 - - 609,996

Foreign currency translation - - - 218,361 - 218,361

Loss for the year - - - - (859,377) (859,377)

BaLance at June 30, 2011 (note 19) 94,237,187 $ 43,206,385 $ 15,685,758 $ 218,361 $ (40,518,391) $ 18,592,113

Common shares issued for cash:

Private placement 15,000,000 5,200,373 1,077,234 - - 6,277,607

Share issue costs on private placement 30,000 (30,728) (6,498) - - (37,226)

Exercise of stock options 33,333 17,667 (7,235) - - 10,432

Exercise of warrants 565,000 362,141 (70,831) - - 291,310

Share-based payments - - 1,385,195 - - 1,385,195

Foreign currency translation - - - (206,809) - (206,809)

Earnings for the year - - - - 4,264,192 4,264,192

BaLance at June 30, 2012 109,865,520 $ 48,755,838 $ 18,063,623 $ 11,552 $ (36,254,199) $ 30,576,814

LYnDen enerGY corp. consolidated statement of changes in equity(Presented in US $, except where indicated)




Lynden energy | AnnuAL report 2012 » ConSoLIdAted FInAnCIAL StAteMentS 39

notesYear ended

june 30, 2012Year ended

june 30, 2011

operatinG activities

Earnings (loss) for the year $ 4,264,192 $ (859,377)

Adjustments for:

Depletion and depreciation 4,749,929 1,218,982

Share-based payments 1,373,947 609,995

Interest income (13,642) (32,103)

Finance costs 22,148 11,710

Impairment of property and equipment 110,570 1,579,595

Income tax recovery (1,503,678) -

Unrealized foreign exchange loss (gain) 164,409 18,173

Changes in non-cash working capital items:

Trade and other receivables (546,993) (538,935)

Prepaid expenses 2,074 3,562

Trade and other payables 1,726,946 (2,983)

cash generated by operating activities 10,349,902 2,008,619

financing activities

Credit facility 14,500,000 -

Common shares issued for cash, net of issue costs of 9 6,542,123 9,642,034

cash generated by financing activities 21,042,123 9,642,034

investing activities

Interest received 13,642 32,103

Acquisition of exploration and evaluation assets - (691,563)

Recoveries of exploration and evaluation assets 503,918 286,512

Purchases of property, plant and equipment (24,671,755) (10,510,727)

cash used in investing activities (24,154,195) (10,883,675)

effect of exchange rate on cash held in foreign currency (359,971) 200,189

change in cash during the year 6,877,859 967,167

cash and cash equivalents, beginning of year 2,600,966 1,633,799

cash and cash equivalents, end of year $ 9,478,825 $ 2,600,966

cash and cash equivalents

Cash 3,579,570 673,190

guaranteed Investment Certificates 5,899,255 1,927,776

$ 9,478,825 $ 2,600,966

LYnDen enerGY corp. consolidated statements of cash flows(Presented in US $, except where indicated)


CONSOLIDATED FINANCIALSTATEMENTSFor the YearS ended June 30, 2012 and 2011


41Lynden energy | AnnuAL report 2012 » notes to consoLidAted FinAnciAL stAteMents

1. nature anD continuance of operations

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 common shares trade on the TSX Venture Exchange (“TSX-V”) under the symbol LVL. The Company operates in one segment, being the acquisition, exploration and development of petroleum and natural gas properties.

The head office and principal address of the Company is Suite 2150 – 885 West georgia Street, Vancouver, BC, V6C 3E1.

The Company is in the process of exploring and developing its petroleum and natural gas interests. The recoverability of the amounts shown for petroleum and natural gas interests and related deferred exploration costs are dependent upon the existence of economically recoverable reserves, the ability of the Company to obtain necessary financing to complete the development of the reserves and upon future profitable production. The measurement of certain assets and liabilities is dependent on future events, therefore the preparation of these condensed consolidated interim financial statements requires the use of estimates, which may vary from actual results. The success of the Company’s exploration and development of its petroleum and natural gas interests is influenced by significant financial risks, legal and political risks, commodity prices, and the ability of the Company to discover economically recoverable reserves and to bring such reserves into future profitable production.

As at June 30, 2012, the Company had an accumulated deficit of $36,254,199 and working capital deficit of $12,083,231. The Company’s ability to continue as a going concern is dependent upon its ability to continue to raise adequate financing and to commence profitable operations in the future. Management believes it will be successful in raising the necessary funding to continue operations in the normal course of operations through the issuance of share capital and debt; however, there is no assurance that these funds will be available on terms acceptable to the Company or at all. These factors

cast substantial doubt on the Company’s ability to continue its current pace of exploration and development expenditures. During the year, the Company secured a three year reducing revolving line of credit in an amount up to US$50 million which provides for a borrowing base of US$16 million (note 7) as at June 30, 2012. These consolidated financial statements do not give effect to any adjustments to the amounts and classifications of assets and liabilities, which might be necessary should the Company be unable to continue its operations as a going concern. Such adjustments could be material. The Company estimates it has sufficient working capital to continue operations for the year ended June 30, 2013.

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.

2. Basis of preparation

a) Statement of compliance

These consolidated financial statements have been prepared in accordance International Financial Reporting Standards (“IFRS”) issued by the International Accounting Standards Board (“IASB”) and the IFRS Interpretations Committee (“IFRIC”) for the year ended June 30, 2012.

These are the Company’s first IFRS consolidated annual financial statements for the year ending June 30, 2012, with a transition date of July 1, 2010. Previously, the Company prepared its consolidated financial statements in accordance with Canadian generally accepted accounting principles (“Canadian gAAP”). The rules of first time adoption are set out in IFRS 1 ‘First–time Adoption of International Financial Reporting Standards’. In preparing the Company’s first IFRS financial statements, these transition rules have been applied to the amounts previously reported under Canadian gAAP. Reconciliations and descriptions of the effect of transition from Canadian gAAP to IFRS are provided in note 18.

NOTES TO CONSOLIDATEDFINANCIAL STATEMENTSJune 30, 2012. preSented in united StateS dollarS, exCept where indiCated)


42 Lynden energy | AnnuAL report 2012 » notes to consoLidAted FinAnciAL stAteMents

b) Basis of presentation

The consolidated financial statements have been prepared on the historical cost basis except for certain financial instruments, which are measured at fair value, as explained in the accounting policies set out in note 3 and 13.

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

c) Approval of the consolidated financial statements

The consolidated financial statements of the Company for the year ended June 30, 2012 were approved and authorized for issue by the Board of Directors on October 26, 2012.

d) Adoption of new and revised standards and interpretations

The IASB issued a number of new and amended IFRS, amendments and related interpretations which are effective for the Company’s financial year beginning on July 1, 2011. For the purpose of preparing and presenting the financial information for the relevant periods, the Company has consistently adopted all these new standards for the relevant reporting periods.

At the date of authorization of these financial statements, the IASB and IFRIC have issued the following new and revised Standards and Interpretations which are not yet effective for the relevant reporting periods:

• ifrs 7 (amendment)New disclosure requirements on the effect of offsetting arrangements on an entity’s financial position3

• ifrs 9New financial instruments standard that replaces IAS 39 for classification and measurement of financial assetsand liabilities5

• ifrs 10New standard to establish principles for the presentation of consolidated financial statements when an entity controls multiple entities3

• ifrs 11New standard to account for the rights and obligations in accordance with joint agreements3

• ifrs 12New standard for the disclosure of interests in other entities not within the scope of IFRS 9/IAS 393

• ifrs 13New standard on the measurement and disclosure of fair value3

• ias 1 (amendment)Presentation of other comprehensive income2

• ias 12 (amendment)Recovery of underlying investment properties measured using a fair value model1

• ias 27 (amendment)New standard issued that supersedes IAS 27 to prescribe the accounting for separate financial statements3

• ias 28 (amendment)New standard issued that supersedes IAS 28 (2003) to prescribe the accounting for investments in associates and joint ventures3

• ias 32 (amendment)Clarifies the application of the requirements of offsetting of financial assets and liabilities4

• ifric 20Interpretation issued that clarifies when production stripping should lead to the recognition of an asset and how the asset should be measured, both initially and in subsequent periods3

1 Effective for annual periods beginning on or after January 1, 2012 2 Effective for annual periods beginning on or after July 1, 2012 3 Effective for annual periods beginning on or after January 1, 2013 4 Effective for annual periods beginning on or after January 1, 2014 5 Effective for annual periods beginning on or after January 1, 2015

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

3. summarY of siGnificant accountinG poLicies

a) Basis of consolidation

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



achieved when the Company has the power to govern the financial and operating policies of an entity so as to obtain benefits from its activities.

The results of subsidiaries acquired or disposed of during the year are included in the consolidated statement of income (loss) and comprehensive income (loss) 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 4).

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

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

b) Cash and cash equivalents

Cash and cash equivalents in the statement of financial position comprise cash at banks and on hand, and short term deposits with an original maturity of three months or less, which are readily convertible into a known amount of cash. The Company had $5,899,255 (2011 - $1,927,776; 2010 - $nil) in cash equivalents at June 30, 2012.

c) Foreign currency translation

The consolidated financial statements are presented in United States dollars. The individual financial statements of each entity are presented 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 (loss) and comprehensive income (loss) in the period they arise.

As of July 1, 2010, the Company has elected to present its consolidated financial statements in the United States dollar. The results of the Company and Lynden Exploration Ltd. are translated to the United States dollar presentation currency as follows: all assets and liabilities are translated at the exchange rate prevailing at the statement of financial position date; equity balances are translated at the rates of exchange at the transaction dates. All items included in the statements of income (loss) and comprehensive income (loss) are translated using the average monthly exchange rates unless there are significant fluctuations in the exchange rate, in which case the rate at the date of transaction is used. All differences arising upon the translation to the presentation currency are recorded in the foreign currency translation reserve.

d) Property, plant and equipment (“PPE”) and exploration and evaluation assets

PPE are stated at cost less accumulated depreciation and any accumulated impairment losses. The cost of an item of PPE consists of the purchase price, any costs directly attributable to bringing the asset to the location and condition necessary for its intended use and an initial estimate of the costs of dismantling and removing the item and restoring the site on which it is located.

Depreciation is provided at rates calculated to write off the cost of PPE, less their estimated residual value, using the straight-line method at the following annual rates:

computer hardware and software 2 – 3 yearsDevelopment and production assets unit-of-production



When significant parts of PPE have different useful lives, they are accounted for and depreciated as separate parts (components). An item of PPE is derecognized upon disposal or when no future economic benefits are expected to arise from the continued use of the asset or disposal. Any gain or loss arising on disposal of the asset, determined as the difference between the net disposal proceeds and the carrying amount of the asset, is recognized in the consolidated statement of income (loss) and comprehensive income (loss). The Company conducts an annual assessment of the residual balances, useful lives and depreciation methods being used for PPE and any changes arising from the assessment are applied by the Company prospectively.

i) pre-exploration expenditures

Pre-exploration expenditures are costs incurred by the Company prior to acquiring a legal right to explore in a specific area. These expenditures do not meet the definition of an asset and therefore are expensed as incurred.

ii) exploration and evaluation expenditures

Exploration and evaluation activity on P&Ng interests involves the search for P&Ng resources, the determination of technical feasibility and the assessment of commercial viability of an identified resource. Exploration and evaluation activity include but are not limited to, exploration license expenditures, leasehold property acquisition costs, evaluation costs, including drilling costs directly attributable to an identifiable well and direct field costs. These costs are accumulated in cost centres by well, field or property and are not subject to depletion until technical feasibility and commercial feasibility has been determined. Exploration and evaluation assets are assessed for impairment when facts and circumstances suggest the carrying amounts of those assets may exceed their recoverable values. For purposes of impairment testing, exploration and evaluation assets are grouped together with developing and producing assets and are tested at an aggregated cash-generating unit (“CgU”) level. The technical feasibility and commercial viability of extracting a P&Ng resource is considered to be determinable when proved and probable reserves are determined to exist. A review of each exploration license or field is carried out, at least annually, to ascertain whether proved and probable reserves have been discovered. Upon determination of

proved and probable reserves, exploration and evaluation assets attributable to those reserves are tested for impairment and reclassified from exploration and evaluation assets to P&Ng properties.

iii) Development and production costs

P&Ng development and production assets are measured at cost less accumulated depletion and any accumulated impairment losses. The cost of development and production assets includes: transfers from exploration and evaluation assets; the cost to tie-in a well; facility costs; the cost of recognizing provisions for future decommissioning liabilities; geological and geophysical costs; and directly attributable overheads. Development and production assets are grouped into CgU’s for impairment testing. A CgU’s recoverable amount is the higher of its fair value less costs to sell and its value in use. Where the carrying amount of a CgU exceeds its recoverable amount, the asset group is considered impaired and is written down to its recoverable amount.

iv) subsequent costs

Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of PPE are recognized as P&Ng properties only when they increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are recognized in profit or loss as incurred. Such capitalized P&Ng properties generally represent costs incurred in developing proved and/or probable reserves and bringing in or enhancing production from such reserves, and are accumulated on a field basis. The carrying amount of any replaced or sold component is derecognized. The costs of the day-to-day servicing of PPE are recognized in profit or loss as incurred.

v) Depletion and depreciation

The net carrying value of development and production assets is depleted using the unit of production method by reference to the ratio of production in the period to the related proven reserves, taking into account the estimated salvage value of the assets at the end of their useful lives. Proven reserves are estimated at least annually by independent qualified reserve evaluators and represent the estimated quantities of crude oil, natural gas, and natural gas liquids which geological, geophysical, and engineering



data demonstrate with a high degree of certainty to be recoverable in future years from known reservoirs using established technology.

e) Share-based payments

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

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

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

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

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

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

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

f) Taxation

Income tax expense represents the sum of tax currently payable and deferred tax.

current income tax

Current income tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from or paid to the taxation authorities. The tax rates and tax laws used to compute the amount are those that are substantively enacted by the date of the statement of financial position.

Deferred income tax

Deferred income taxes are provided using the liability method on temporary differences at the date of the statement of financial position between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes.

Deferred income taxes are recognized for all taxable temporary differences, except:

• Where the deferred income tax arises from the initial recognition of goodwill or of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither the accounting profit nor taxable earnings; and

• In respect of temporary differences associated with investments in subsidiaries, associates and interests in joint ventures, where the timing of the reversal of the temporary differences can be controlled and it is probable that the temporary differences will not reverse in the foreseeable future.

Deferred income tax assets are recognized for all deductible temporary differences, carry forward of unused tax credits and unused tax losses, to the extent that it is probable that taxable profit will be available against which the deductible temporary differences and the carry forward of unused tax credits and unused tax losses can be utilized.

The carrying amount of deferred income tax assets is reviewed at each date of the statement of financial position and reduced to the extent that it is no longer probable that sufficient taxable profit will be available to allow all or part of the deferred income tax asset to be utilized. Unrecognized deferred income tax assets are



reassessed at each date of the statement of financial position and are recognized to the extent that it has become probable that future taxable profit will allow the deferred tax asset to be recovered.

Deferred income tax assets and liabilities are measured at the tax rates that are expected to apply to the year when the asset is realized or the liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted at the date of the statement of financial position.

Deferred income tax relating to items recognized directly in equity is recognized in equity and not in the statement of income (loss) and comprehensive income (loss).

Deferred income tax assets and deferred income tax liabilities are offset if, and only if, a legally enforceable right exists to set off current tax assets against current tax liabilities and the deferred tax assets and liabilities relate to income taxes levied by the same taxation authority on either the same taxable entity or different taxable entities which intend to either settle current tax liabilities and assets on a net basis, or to realize the assets and settle the liabilities simultaneously, in each future period in which significant amounts of deferred tax assets or liabilities are expected to be settled or recovered.

g) Earnings (loss) per share

The basic earnings (loss) per share is computed by dividing the net earnings (loss) by the weighted average number of common shares outstanding during the period. The diluted earnings (loss) per share reflects the potential dilution of common share equivalents, such as outstanding stock options and share purchase warrants, in the weighted average number of common shares outstanding during the year, if dilutive.

h) Financial assets

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

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

Financial assets classified as loans and receivables and held to maturity are measured at amortized cost using the effective interest method less any allowance for impairment. The effective interest method is a method of calculating the amortized cost of a financial asset and of allocating interest income over the relevant

period. The effective interest rate is the rate that exactly discounts estimated future cash receipts (including all fees and points paid or received that form an integral part of the effective interest rate, transaction costs and other premiums or discounts) through the expected life of the financial asset, or, where appropriate, a shorter period.

Financial assets classified as available-for-sale are measured at fair value with unrealized gains and losses recognized in other comprehensive income (loss) 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.

i) Financial liabilities

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

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

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

j) Impairment of financial assets

The Company assesses at each reporting date whether a financial asset is impaired.



assets carried at amortized cost

If there is objective evidence that an impairment loss on assets carried at amortized cost has been incurred, the amount of the loss is measured as the difference between the asset’s carrying amount and the present value of estimated future cash flows discounted at the financial asset’s original effective interest rate. The carrying amount of the asset is then reduced by the amount of the impairment. The amount of the loss is recognized in earnings.

If, in a subsequent period, the amount of the impairment loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognized, the previously recognized impairment loss is reversed to the extent that the carrying value of the asset does not exceed what the amortized cost would have been had the impairment not been recognized. Any subsequent reversal of an impairment loss is recognized in earnings.

In relation to trade receivables, a provision for impairment is made and an impairment loss is recognized in profit and loss when there is objective evidence (such as the probability of insolvency or significant financial difficulties of the debtor) that the Company will not be able to collect all of the amounts due under the original terms of the invoice. The carrying amount of the receivable is reduced through use of an allowance account. Impaired debts are written off against the allowance account when they are assessed as uncollectible.

available for sale

If an available-for-sale asset is impaired, an amount comprising the difference between its cost and its current fair value, less any impairment loss previously recognized in earnings, is transferred from equity to earnings. Reversals in respect of equity instruments classified as available-for-sale are not recognized in earnings.

k) Impairment of non-financial assets

At each date of the statement of financial position, the Company reviews the carrying amounts of its non-financial assets to determine whether there is an indication that those assets have suffered an impairment loss. If any such indication exists, the recoverable amount of the asset is estimated in order to determine the extent of the impairment loss (if any). Where it is not possible to estimate the recoverable amount of an individual asset, the Company estimates the recoverable amount of the cash-generating unit to which the assets belong.

Recoverable amount is the higher of fair value less costs to sell and value in use. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset.

If the recoverable amount of an asset (or cash-generating unit) is estimated to be less than its carrying amount, the carrying amount of the asset (or cash-generating unit) is reduced to its recoverable amount. An impairment loss is recognized immediately in the statement of income (loss) and comprehensive income (loss).

Where an impairment loss subsequently reverses, the carrying amount of the asset (cash-generating unit) is increased to the revised estimate of its recoverable amount, so that the increased carrying amount does not exceed the carrying amount that would have been determined had no impairment loss been recognized for the asset (or cash-generating unit) in prior years. An impairment of goodwill is not subsequently reversed.

l) Provisions and decommissioning liabilities

Provisions are recognized when the Company has a present obligation (legal or constructive) that has arisen as a result of a past event and it is probable that a future outflow of resources will be required to settle the obligation, provided that a reliable estimate can be made of the amount of the obligation.

Provisions are measured at the present value of the expenditures expected to be required to settle the obligation using a pre-tax rate that reflects current market assessments of the time value of money and the risk specific to the obligation. Any increase in a provision due solely to passage of time is recognized as interest expense.

An obligation to incur restoration, rehabilitation and environmental costs arises when environmental disturbance is caused by the exploration, development or ongoing production of a mineral property interest. Such costs arising for the decommissioning of plant and other site preparation work, discounted to their net present value, are provided for and capitalized at the start of each project to the carrying value of the asset, as soon as the obligation to incur such costs arises. Discount rates using a pre-tax rate that reflect the time value of money are used to calculate the net present value. These costs are charged against profit or loss over the economic life of the related asset, through depletion using the unit-of-production method. The related liability is adjusted for each period for the unwinding of the discount rate and for changes to the current market based discount rate,



amount or timing of the underlying cash flows needed to settle the obligation. Costs for restoration of subsequent site damage which is created on an ongoing basis during production are provided for at their net present values and charged against profits as extraction progresses.

m) Related party transactions

Parties are considered to be related if one party has the ability, directly or indirectly, to control the other party or exercise significant influence over the other party in making financial and operating decisions. Parties are also considered to be related if they are subject to common control or common significant influence, related parties may be individuals or corporate entities. A transaction is considered to be a related party transaction when there is a transfer of resources or obligations between related parties. Related party transactions that are in the normal course of business and have commercial substance are measured at the exchange amount.

n) Significant accounting judgments and estimates

The preparation of these consolidated financial statements requires management to make judgments and estimates and form assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and reported amounts of expenses during the reporting period. On an ongoing basis, management evaluates its judgments and estimates in relation to assets, liabilities and expenses. Management uses historical experience and various other factors it believes to be reasonable under the given circumstances as the basis for its judgments and estimates. Actual outcomes may differ from these estimates under different assumptions and conditions.

Critical judgments exercised in applying accounting policies that have the most significant effect on the amounts recognized in the consolidated financial statements are as follows:

i) The determination of functional currency is discussed in note 3(c).

ii) Assets are grouped into CgUs that have been identified as being the smallest identifiable group of assets that generate cash inflows that are independent of cash inflows of other assets or groups of assets. The determination of these CgUs is based on management’s judgment in regards to shared infrastructure, geographical proximity, product type and other relevant factors.

iii) The application of the Company’s accounting policy for exploration and evaluation expenditures requires judgment in determining whether it is likely that future economic benefit exists when activities have not reached a stage where technical feasibility and commercial viability can be reasonably determined and when technical feasibility and commercial viability have been reached.

Assumptions and estimates that have a significant risk of resulting in material adjustments are as follows:

iv) Management considers both external and internal sources of information in assessing whether there are any indications that the Company’s PPE are impaired. External sources of information management considers include changes in the market, economic and legal environment in which the Company operates that are not within its control and affect the recoverable amount of its PPE. Internal sources of information management consider include the manner in which PPE are being used or are expected to be used and indications of economic performance of the assets.

v) Depletion expense is allocated based on assumed asset lives. Should the asset life or depletion rates differ from the initial estimate, an adjustment would be made in the consolidated statements of income.

vi) The Company uses the Black-Scholes Option Pricing Model for valuation of share-based payments. Option pricing models require the input of subjective assumptions including expected price volatility, interest rate and forfeiture rate. Changes in the input assumptions can materially affect the fair value estimate and the Company’s earnings and equity reserves.

vii) The Company has estimated the net present value of future decommissioning costs of its P&Ng wells. This requires the input of subjective assumptions about the amount of the future clean-up costs and the life of the wells. Changes in the input assumptions can materially affect the Company’s financial position and earnings.

viii) The Company is periodically required to estimate the tax basis of assets and liabilities. Where applicable tax laws and regulations are either unclear or subject to varying interpretations, it is possible that changes in these estimates could occur that materially affect the amounts of deferred income tax assets and liabilities recorded in the financial statements. Changes in deferred tax assets and liabilities generally have a direct impact on earnings in the period of changes.



june 30, 2012 june 30, 2011 july 1, 2010

Total assets $ 2,072,321 $ 9,289,802 $ 10,169,589

Total liabilities $ 792,873 $ 764,303 $ 890,342

Revenues $ 102,600 $ 155,752 $ 168,950

Loss $ 7,246,049 $ 753,747 $ 751,393

Each period, the Company evaluates the likelihood of whether some portion or all of each deferred tax asset will not be realized. This evaluation is based on historic and future expected levels of taxable income, the pattern and timing of reversals of taxable temporary timing differences that give rise to deferred tax liabilities, tax planning initiatives, and future tax rates. Levels of future taxable income are affected by, among other things, the market prices for oil and natural gas, development and production and operating costs, and quantities of proven and probable reserves.

o) Borrowing costs

Borrowing costs directly attributable to the acquisition, construction or production of a qualifying asset are capitalized as part of the cost of that asset until the asset is substantially ready for its intended use. Other borrowing costs are expensed in the period incurred.

p) Revenue recognition

Revenue is recognized to the extent that it is probable that the economic benefits will flow to the Company and the revenue can be reliably measured. Revenue is measured at the fair value of the consideration received, excluding discounts, rebates and other sales tax or duty. Interest income is recognized as interest accrues (using the effective interest rate, that is, the rate that exactly discounts estimated future cash receipts through the expected life of the financial instrument to the net carrying amount of the financial asset).

4. investment in associate

In October 2007, the Company participated, along with its Paradox Basin partners, in the formation of a Utah, USA based natural gas transmission company, Abajo gas Transmission Company, LLC (“Abajo”). The Company purchased a 47.99% interest in Abajo through capital contributions totaling $5,135,000. Abajo holds ownership of the gas gathering systems in the Northern and Southern Prospect Areas of the Company’s Paradox Basin Project (note 5). 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, 2012, June 30, 2011 and July 1, 2010 and for the twelve month periods ended June 30, 2012, 2011 and 2010:

As the Company has impaired the investment in Abajo to $nil as at July 1, 2010, the Company’s cumulative share of losses attributable to Abajo from July 1, 2010 to June 30, 2012 that have not been recognized, amounts to $4,293,076 and $3,814,315 for the year ended June 30, 2012 (note 12a).



5. expLoration anD evaLuation assets

paradox Basin mitchell ranch total

as at juLY 1, 2010 $ 501,428 $ 2,191,625 $ 2,693,053

acquisition and expenditures 263,391 2,715,499 2,978,890

petroleum and natural gas sales (355,572) (193,669) (549,241)

royalties 64,204 43,575 107,779

transportation 50,385 - 50,385

production taxes 16,666 6,919 23,585

impairment - (1,579,595) (1,579,595)

as at june 30, 2011 540,502 3,184,354 3,724,856

acquisition and expenditures 265,268 286,968 552,236

petroleum and natural gas sales (197,460) (410,208) (607,668)

royalties 33,888 92,298 126,186

transportation 28,799 - 28,799

production taxes 6,273 14,652 20,925

impairment (110,570) - (110,570)

as at june 30, 2012 $ 566,700 $ 3,168,064 $ 3,734,764

a) Paradox Basin

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

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

During the year ended June 30, 2012, the Company received $128,500 (2011 - $224,317) of net revenue from sales of P&Ng from its Paradox Basin Project. It has been determined that the Paradox Basin Project is still in the exploration and evaluation stage and as such, the net revenues have been credited to capitalized costs.

b) Mitchell Ranch

The Company is party to a Participation Agreement with CrownRock LP (“CrownRock”) pertaining to a 50% working interest in approximately 103,400 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 (“SeniorCo”), covering approximately 36,000 acres of the 103,400 acre Mitchell Ranch Project. Pursuant to the 30 month term assignment to SeniorCo, which can be extended by 90 day continuous development, the Company and CrownRock retain a 2.5% (as to 1.25% each) overriding royalty interest on the term assignment acreage.



computer

Hardware &

software

Development

and production

assets

total

cost

As at July 1, 2010 $ 3,226 $ 5,405,786 $ 5,409,012

Additions 721 12,964,407 12,965,128

Foreign exchange movement 334 - 334

As at June 30, 2011 4,281 18,370,193 18,374,474

Additions - 26,004,216 26,004,216

Foreign exchange movement (225) - (225)

as at June 30, 2012 $ 4,056 $ 44,374,409 $ 44,378,465

accumulated depreciation and depletion

As at July 1, 2010 $ 2,455 $ 239,247 $ 241,702

Depreciation and depletion 1,050 1,217,931 1,218,981

Foreign exchange movement 296 - 296

As at June 30, 2011 3,801 1,457,178 1,460,979

Depreciation and depletion 231 4,749,698 4,749,929

Foreign exchange movement (204) - (204)

as at June 30, 2012 $ 3,828 $ 6,206,876 $ 6,210,704

carrying value

as at JuLY 1, 2010 $ 771 $ 5,166,539 $ 5,167,310

as at June 30, 2011 $ 480 $ 16,913,015 $ 16,913,495

as at June 30, 2012 $ 228 $ 38,167,533 $ 38,167,761

The Company has a 50% working interest in the 67,400 acres of the Mitchell Ranch Project not subject to the term assignment to SeniorCo.

During the year ended June 30, 2012, the Company received $303,258 (2011 - $143,175) of net revenue from sales of P&Ng from its Mitchell Ranch Project. It has been determined that the Mitchell Ranch Project is in the exploration and evaluation stage and as such, the net revenues have been credited to capitalized costs.

6. propertY, pLant anD eQuipment

The Company has capitalized $574,655 (2011 - $nil) of borrowing costs during 2012 to development and production assets. The Company has pledged its interest in its development and production assets to Texas Capital Bank as security for liabilities pursuant to the Credit Facility.



Development and production assets - wolfberry

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.

7. creDit faciLitY

The Company has a reducing revolving line of credit (the “Credit Facility”) in an amount up to $50 million with Texas Capital Bank of Dallas, Texas. As of June 30, 2012, the Credit Facility has a borrowing base of $16 million, of which $14.5 million has been drawn down (note 18). 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 4.5% 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 Company has complied with all of these covenants as at and during the year ended June 30, 2012. The Company has pledged its interest in its P&Ng and other assets to Texas Capital Bank as security for liabilities pursuant to the Credit Facility.

8. DecommissioninG LiaBiLities

The total decommissioning liabilities were estimated by management based on the Company’s net ownership interest in all wells, estimated costs to reclaim and abandon the wells and the estimated timing of the costs to be incurred in future periods. The total undiscounted amount of the estimated cash flows (adjusted for inflation with weighted-average rate of 2%) to settle the decommissioning liabilities is approximately $1,800,000 as at June 30, 2012 (June 30, 2011 - $1,000,000; July 1, 2010 - $370,000). These payments are expected to be made over the next 14 to 35 years. The Company used a weighted-average risk free rate of 2.58% to calculate the present value of the decommissioning liabilities.

as at juLY 1, 2010 $ 215,901

Unwinding of decommissioning liability 11,710

Adjustment to estimates during the year 157,554

as at june 30, 2011 385,165

Unwinding of decommissioning liability 22,148

Expenditures incurred (36,850)

Adjustment to estimates during the year 465,695

as at june 30, 2012 $ 836,158

9. common shares, warrants anD share option reserve

a) Authorized

An unlimited number of common shares without par value.An unlimited number of preference shares without par value.

b) The Company completed the following private placements during the years ended June 30, 2012 and 2011:

i) 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.



ii) In October and November 2010, the Company closed a non-brokered private placement for gross proceeds of CDN$10,100,000. These funds were raised through the issuance of 20,200,000 units at a price of CDN$0.50 per unit. Each unit is comprised of one common share and one common share purchase warrant. The total proceeds were allocated to common shares in the amount of CDN$6,391,762 and to warrants in the amount of CDN$3,708,238 based on their relative fair values on the dates of closing.

The private placement closed in three stages and therefore 14,214,000 warrants expire on October 27, 2013, 5,786,000 warrants expire on November 12, 2013 and 200,000 warrants expire on November 19, 2013. Each share purchase warrant entitles the holder to purchase one additional common share at a price of CDN$0.70 per common share.

The Company incurred total share issue costs on the private placement of CDN$542,687 which were allocated to common shares in the amount of CDN$343,438 and to warrants in the amount of CDN$199,249 based on their relative fair values. Of these costs, CDN$434,807 was incurred in cash and CDN$107,880 was incurred through the issuance of 215,760 units with the same terms as those issued in the private placement.

c) Warrants:

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

Year endedjune 30, 2012

Year endedjune 30, 2011

Weighted average fair value at issue/modification date (CDN$) $0.12 $0.33

Average risk-free interest rate 1.06% 1.67%

Expected life 1.3 years 3 years

Expected volatility 70% 100%

Expected dividend yield 0% 0%

Forfeiture rate 1% 1%

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

The changes in warrants issued during the year ended June 30, 2012 and the year ended June 30, 2011 are as follows:

Year ended june 30, 2012 Year ended june 30, 2011

number ofwarrants

weighted average exercise

price (cDn$)number of

warrants


price (cDn$)

BaLance, BeGinninG of Year 52,660,986 $ 0.87 32,754,226 $ 0.97

Issued 7,515,000 $ 0.65 20,415,760 $ 0.70

Exercised (565,000) $ 0.50 (509,000) $ 0.36

Expired (31,680,226) $ 0.99 - $ -

BaLance, enD of Year 27,930,760 $ 0.69 52,660,986 $ 0.87



For warrants exercised during the years ended June 30, 2012 and 2011, the weighted average share price at the dates of exercise was $0.69 (2011 - $0.87).

Warrants exercisable and outstanding as at June 30, 2012 are as follows:

expiry Dateexercise price

(cDn$)

October 27, 2013 $0.70 14,214,000

November 12, 2013 $0.70 5,906,000

November 19, 2013 $0.70 295,760

May 4, 2015 $0.65 5,082,500

May 18, 2015 $0.65 2,432,500

27,930,760

June 30, 2012 June 30, 2011

Numerator:

Net earnings (loss) $ 4,264,192 $ (859,377)

Denominator:

Weighted average number of common shares (basic) 96,825,621 87,285,138

Dilutive effect of share options 404,000 -

Weighted average number of common shares (diluted) 97,229,621 87,285,138

Diluted earnings (loss) per common share $ 0.04 $ (0.01)

d) Earnings (loss) per share:

Diluted earnings (loss) per share computation

There are 27,930,760 (2011 – 52,660,986) warrants and 7,196,000 (2011 – 6,830,833) stock options that are not dilutive as at June 30, 2012.

10. sHare-BaseD paYments

a) Stock option plan

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



Year endedJune 30, 2012

Year endedJune 30, 2011

Weighted average fair value at grant date (CDN$) $0.57 $0.40

Average risk-free interest rate 2.11% 2.22%

Expected life 5 years 4 years

Expected volatility 98% 102%

Expected dividend yield 0% 0%

Forfeiture rate 1% 1%

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

b) Stock options

The changes in stock options issued during the years ended June, 2012 and 2011 are as follows:

During the year ended June 30, 2012, the Company granted 2,725,000 stock options to officers, employees, directors, and consultants. The Company recognized $1,373,947 for share-based payments.

During the year ended June 30, 2011, the Company granted 460,000 stock options to officers, directors and consultants. The Company recognized $609,995 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:

Year ended June 30, 2012 Year ended June 30, 2011

number ofoptions


price (cDn$)number of

options


price (cDn$)

BaLance, BeGinninG of Year 6,830,833 $ 0.88 7,263,166 $ 0.87

granted 2,725,000 $ 0.80 460,000 $ 0.64

Exercised (33,333) $ 0.30 (33,333) $ 0.30

Expired (1,397,500) $ 1.00 (859,000) $ 0.64

Cancelled (525,000) $ 1.24 - $ -

BaLance, enD of Year 7,600,000 $ 0.81 6,830,833 $ 0.88



options outstanding options exercisable

exercise price (cDn$)number of

options

weightedaverage

remaining life (years)

number ofoptions

weightedaverage

remaining life (years)

$0.30 to $0.60 2,770,000 0.94 2,770,000 0.94

$0.70 to $0.80 2,925,000 1.44 1,175,001 1.44

$1.00 to $1.40 1,905,000 0.11 1,905,000 0.11

BaLance, enD of Year 7,600,000 2.49 5,850,001 2.49

11. GeneraL anD aDministrative expenses

12. reLateD partY transactions

The following is a summary of the related party transactions that occurred during the year ended June 30, 2012 and 2011.

a) The Company incurred the following fees and expenses in the normal course of operations at amounts agreed upon between the parties to key management and directors and to companies owned by key management and directors.

june 30, 2012 june 30, 2011

Administrative fees $ 192,798 $ 152,756

Consulting fees 329,463 312,054

Directors fees 48,146 -

Filing, listing and transfer agent fees 28,721 31,449

Office and miscellaneous 69,501 59,872

Professional fees 148,963 119,680

Promotion 97,285 84,375

Rent 12,852 15,723

Travel 34,515 57,335

$ 962,244 $ 833,244

For stock options exercised during the years ended June 30, 2012 and 2011, the weighted average share price at the dates of exercise was$0.52 (2011 - $0.55).

The following table summarizes information about stock options outstanding and exercisable at June 30, 2012:



June 30, 2012 June 30, 2011

Administrative fees $ 192,803 $ 158,631

Consulting fees 270,691 288,598

Directors fees 48,148 -

Legal fees 34,675 30,475

Transportation and marketing costs with Abajo 28,799 50,385

$ 575,116 $ 528,089

Trade and other payables include $6,782 (June 30, 2011 - $14,359; July 1, 2010 - $17,772) owing to related parties. Amounts due to or from related parties are unsecured, non-interest bearing and are due on demand.

b) Compensation of key management personnel

The remuneration of directors and other members of key management personnel during the years ended June 30, 2012 and 2011 are as follows:

June 30, 2012 June 30, 2011

Short-term employee benefits (i) $ 511,642 $ 447,229

Share-based payments (ii) 1,188,094 528,195

$ 1,699,736 $ 975,424

i) Short-term employee benefits include administrative fees, consulting fees and directors fees disclosed in note 12a.

ii) Share-based payments represent the expense of the fair value of options granted to key management personnel.

Key management personnel were not paid post-employment benefits, termination benefits, or other long-term benefits during the years ended June 30, 2012 and 2011.

13. financiaL instruments

As at June 30, 2012, the Company’s financial instruments are cash and cash equivalents, trade and other receivables, credit facility, and trade and other payables. The amounts reflected in the statement of financial position are carrying amounts and approximate their fair values due to their short-term nature. These financial instruments are classified as follows:

• Cash and cash equivalents – loans and receivables

• Trade and other receivables – loans and receivables

• Credit facility – other financial liabilities

• Trade and other payables – other financial liabilities



b) Liquidity Risk

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

Advances under the Credit Facility can be in the form of Eurodollar loans, which have a maximum period of 90 days, or in the form of Floating Rate loans, which can remain outstanding to the Credit Facility final maturity date of August 29, 2014. 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 Wolfberry Project 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.

June 30, 2012 June 30, 2011 July 1, 2010

Trade and other receivables

0 to 60 days $ 1,366,163 $ 929,795 $ 322,325

61 to 120 days 38,465 14,563 32,268

> 120 days 44,713 30,150 -

$ 1,449,341 $ 974,508 $ 354,593

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

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

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

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

At June 30, 2012, the Company has no financial instruments measured in the fair value hierarchy.

a) Credit risk

Credit risk is the risk that one party to a financial instrument will cause a financial loss for the other party by failing to discharge an obligation. The Company’s cash and cash equivalents and trade and other receivables are exposed to credit risk. Management believes the credit risk on cash is low because the counterparties are highly rated financial institutions. The majority of the Company’s trade and other receivables are with customers in the petroleum and natural gas industry and are subject to normal industry credit risks. The Company generally extends unsecured credit to these customers and therefore the collection of trade and other receivables may be affected by changes in economic or other conditions. The Company believes the risk is mitigated by the size and reputation of the companies to which they extend credit. The Company has not experienced any material credit loss in the collection of trade and other receivables to date and therefore has not made any provision for bad debts.

The aging of trade and other receivables are as follows:



totalLess than

1 year one to

two yearsmore than two years

Credit facility $ 14,532,753 $ 14,532,753 $ - $ -

Trade and other payables 8,388,644 8,388,644 - -

Income taxes payable 90,000 90,000 - -

$ 23,011,397 $ 23,011,397 $ $

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.

cash

trade andother

receivables

trade andother

payablesnet assets

exposure

effect of +/-10% change in

currency

Canadian dollar denomination $ 6,594,709 $ 11,888 $ (90,115) $ 6,516,482 $ 651,648

c) Market Risk

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

i) interest rate risk

Interest rate risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes in market interest rates. The Company’s cash and credit facility are exposed to interest rate risk as the Company invests cash at floating rates of interest in highly liquid instruments and it borrows funds at floating rates of interest. Fluctuations in interest rates impact interest income and expense. As at June 30, 2012, 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, 2012.

ii) currency risk

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

Based on the above net exposures at June 30, 2012, a 10% depreciation or appreciation of the Canadian dollar against the United States dollar would result in an increase or decrease, respectively, in the Company’s earnings or loss by $651,648.

iii) price risk

The Company’s P&Ng production is marketed and sold on the spot market to area aggregators based on daily spot prices that are adjusted for product quality and transportation costs. The Company’s cash flow from product sales will therefore be impacted by fluctuations in commodity prices. The Company did not use derivative financial instruments to manage this risk during the year ended June 30, 2012.



14. capitaL manaGement

The Company includes as capital the Credit Facility, common shares and share-based payments reserve. The Company’s objectives are to safeguardthe Company’s ability to continue as a going concern in order to pursue the development of its P&Ng properties and to maintain a flexible capital structure which optimizes the costs of capital at an acceptable risk.

The Company manages the capital structure and makes adjustments to it in light of changes in economic conditions and the risk characteristics of theunderlying assets, especially in regards to exploration and development results on its P&Ng properties. To maintain or adjust the capital structure, the Company may attempt to issue new shares, issue debt, acquire or dispose of assets or adjust the amount of cash and cash equivalents. As described in note 7, the Company secured a three year reducing revolving line of credit in an amount up to US$50 million with Texas Capital Bank of Dallas, Texas.

In order to maximize ongoing development efforts, the Company does not pay out dividends. The Company’s investment policy is to invest its cash in highly liquid short-term interest-bearing investments, selected with regards to the expected timing of expenditures from continuing operations.

The Company’s Credit Facility includes a covenant requiring the Company to maintain a current ratio of not less than one-to-one. The current ratio, as defined by its creditor, is the ratio of current assets, calculated as current assets plus any undrawn amounts available of the borrowing base on the Credit Facility, to current liabilities, calculated as current liabilities excluding any current portion drawn on the credit facility. The Company wascompliant with this covenant at June 30, 2012.

15. suppLementaL cash fLow information

june 30, 2012 june 30, 2011

Non-cash financing activities:

Fair value of warrants transferred to common shares

on exercise of warrants $ 70,831 $ 84,865

Fair value of options transferred to common shares

on exercise of options $ 7,235 $ 7,235

Cash payments for interest and taxes:

Interest paid $ 300,857 $ -

Taxes paid $ - $ -

16. seGmenteD information

At June 30, 2012 the Company has one reportable operating segment, being the acquisition, exploration and development of petroleum and natural gasproperties. The Company operates in two reportable geographic segments, being Canada and the United States of America.

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

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

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

• for which discrete financial information is available.



17. income taxes

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

canada usaconsolidated

total

revenues

Year ended June 30, 2012 $ - $ 11,710,531 $ 11,710,531

Year ended June 30, 2011 $ - $ 3,651,704 $ 3,651,704

exploration and evaluation assets

As at June 30, 2012 $ - $ 3,734,764 $ 3,734,764

As at June 30, 2011 $ - $ 3,724,856 $ 3,724,856

As at July 1, 2010 $ - $ 2,693,053 $ 2,693,053

property, plant and equipment

As at June 30, 2012 $ 228 $ 38,167,533 $ 38,167,761

As at June 30, 2011 $ 480 $ 16,913,015 $ 16,913,495

As at July 1, 2010 $ 771 $ 5,166,539 $ 5,167,310

june 30, 2012 june 30, 2011

Net earnings (loss) before income taxes $ 2,760,514 $ (859,377)

Combined statutory tax rate 25.75% 27.51%

Income tax expense (recovery) computed at statutory 710,832 (236,415)

Increase (decrease) attributable to:

Changes in unrecognized deferred tax assets (3,003,403) 2,191,560

Non-deductible (taxable) expenditures 350,137 394,899

Effect of different statutory tax rates on earnings in subsidiaries 684,395 (2,107,690)

Equity investment taxable loss pick-up (245,639) (242,354)

Income tax expense (recovery) $ (1,503,678) $ -

Effective tax rate -54.47% 0.00%

Current income tax expense 90,000 -

Deferred income tax recovery (1,593,678) -

Income tax expense (recovery) $ (1,503,678) $ -

The Company’s revenues and capital assets in geographic locations are as follows:



June 30, 2012 June 30, 2011

Exploration and evaluation assets $ 2,722,157 $ 7,923,986

Non-capital loss carry forwards 6,111,405 10,998,090

Unrealized foreign exchange gain - 3,964,111

Share issuance costs 359,577 502,590

Excess tax value of property, plant and equipment over book value 5,840 6,165

$ 9,198,979 $ 23,394,942

The Company has income tax loss carry forwards of approximately $3,782,696 (2011 - $5,557,126) for US tax purposes. These recognized tax losses will expire between 2030 and 2032.

The Company has unrecognized income tax loss carry forwards of approximately $6,111,405 (2011 - $5,440,964) for Canadian tax purposes. These unrecognized tax losses will expire between 2014 and 2032.

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

June 30, 2012 June 30, 2011

Deferred tax assets:

Exploration and evaluation assets $ 1,162,635 $ -

Non-capital losses carry forwards 1,411,047 -

2,573,682 -

Deferred tax liabilities:

Unrealized foreign exchange gain (980,004) -

$ 1,593,678 $ -

Unrecognized deductible temporary differences, unused tax losses and unused tax credits are attributable to the following:



18. suBseQuent events

a) Subsequent to June 30, 2012, the Company granted 1,397,500 stock options with an exercise price of $0.50 expiring in five years;

b) Subsequent to June 30, 2012, 1,140,000 stock options with an exercise price of $1.30 expired unexercised; and

c) Subsequent to June 30, 2012, the borrowing base was increased to $26.9 million from $16 million and the Company has drawn down an additional $8.5 million of the borrowing base, leaving a balance of $3.9 million available to the Company (note 7).

19. transition to internationaL financiaLreportinG stanDarDs

The Company has adopted IFRS on July 1, 2011 with a transition date of July 1, 2010 (the “Transition Date”). Under IFRS 1 ‘First–time Adoption of International Financial Reporting Standards’ (“IFRS 1”), the IFRS are applied retrospectively at the Transition Date with all adjustments to assets and liabilities as stated under Canadian gAAP taken to retained earnings (deficit) unless certain optional exemptions are applied.

IFRS employs a conceptual framework that is similar to Canadian gAAP. However, significant differences exist in certain matters of recognition, measurement and disclosure. While adoption of IFRS has not changed the Company’s actual cash flows, it has resulted in changes to the Company’s reported financial position and results of operations. In order to allow the users of the financial statements to better understand these changes, the Company’s Canadian gAAP statement of loss and total comprehensive loss and statement of financial position for the year ended June 30, 2011 have been reconciled to IFRS, with the resulting differences explained.

The adoption of IFRS does not have a significant impact on the statement of cash flows for the year ended June 30, 2011. Therefore, no reconciliation is presented in these consolidated financial statements.

The Company has prepared reconciliations of equity as at July 1, 2010 and June 30, 2011 and reconciliations of income (loss) and comprehensive income (loss) for the year ended June 30, 2011, using the accounting policies in note 3 and the following IFRS 1 exemptions and IFRS adjustments:

key first-time adoption exemptions applied and comparative period adjustments

IFRS 1 is the standard that governs mandatory exceptions and optional exemptions that an entity may elect for its transition to IFRS in order to assist the entity with the transition process. This standard is only applicable to the opening balance sheet of the entity on the Transition Date. All adjustments made as a result of adoption of IFRS are offset against the Company’s July 1, 2010 deficit.

IFRS 1 requires that the Company’s estimates under IFRS at the Transition Date must be consistent with estimates made for the same date under Canadian gAAP, unless there is objective evidence that those estimates are in error. The Company’s IFRS estimates as of July 1, 2010 are consistent with its Canadian gAAP estimates at the same date.

The Company has elected to apply the following IFRS 1 optional exemptions at the Transition Date and to adjust for the following comparative period differences between Canadian gAAP and IFRS:

a) Business combinations

IFRS 1 indicates that a first-time adopter may elect not to apply IFRS 3 ‘Business Combinations’ (“IFRS 3”) retrospectively to business combinations that occurred before the Transition Date. Under IFRS 3 – “Business Combinations,” the determination of the fair value of share consideration differs from the determination under Canadian accounting standards. Any difference in the fair value calculation would have a resulting impact on the carrying amount of net assets acquired, non-controlling interest and any goodwill. The Company has used this election and has applied IFRS 3 prospectively from the Transition Date. Accordingly, there is no adjustment required to the Transition Date statement of financial position.

b) Consolidated and separate financial statements

In accordance with IFRS 1, if a company elects to apply IFRS 3 retrospectively, IAS 27 ‘Consolidated and Separate Financial Statements’ (“IAS 27”) must also be applied retrospectively. The Company has elected to apply IFRS prospectively and as a result of this election, the Company’s accounting for its non-controlling interests which existed prior to the Transition Date, per the requirement of IAS 27 ‘Consolidated and Separate Financial Statements’, have been applied prospectively from the date of the transition of IFRS per the required exception in IFRS 1.



f) Impairment test

IFRS requires an asset impairment test to be conducted on transition date where a) the deemed cost exemption available to P&Ng assets has been elected (see note e), and b) when indicators of impairment are present. Under previous Canadian gAAP, impairment of long-lived assets is assessed on the basis of an asset’s estimated undiscounted future cash flows at the cost center level compared with the asset’s carrying amount and if impairment is indicated, discounted cash flows are prepared to quantify the amount of impairment. The Company had one cost center for Canadian gAAP purposes.

IFRS requires the impairment test to occur at the asset level or at the cash generating unit (“CgU”) level when long lived assets exist that do not generate largely independent cash inflows. The carrying amount of the asset or CgU is compared to its recoverable amount which is the higher of value in use or fair value less costs to sell.

During the year ended June 30, 2011, the Company reported an impairment of its Mitchell Ranch P&Ng assets during the year ended June 30, 2011 in the amount of $1,579,595 for a specific asset for which future cash flows were anticipated to be $nil.

As a result of this impairment and the deemed cost exemption taken with respect to the Paradox Basin (note e above), the Company reported a change in the timing of impairments between Canadian gAAP and IFRS which resulted in adjustments on transition of $19,659,597 for the year ended June 30, 2011.

Upon transition to IFRS, the Company evaluated its equity investment in associate (Abajo) for impairment. Based on its estimated recoverable amount of $nil, determined by estimating the present value of the future net cash flows expected to be derived from the continued operations of Abajo; estimated production volumes from the Paradox Basin wells; transmission charges ranging from $0.75/mcf to $0.95/mcf of natural gas; and a discount rate of 18% used in the discounted cash flow model, an adjustment of $4,195,179 was recorded to deficit to adjust the carrying value. The Company had previously recognized an impairment of its investment in Abajo under Canadian gAAP of $3,739,404 during the year ended June 30, 2011.

c) Share-based payments

IFRS 1 encourages, but does not require, first-time adopters to apply IFRS 2 ‘Share-based Payments’ (“IFRS 2”) to equity instruments that were granted on or before November 7, 2002, or equity instruments that were granted subsequent to November 7, 2002 and vested before the later of the Transition Date and January 1, 2005. The Company has elected to not apply IFRS 2 to awards that vested prior to the Transition Date.

d) Borrowing costs

IFRS 1 provides the Company with an option to account for borrowing costs under IAS 23 ‘Borrowing Costs’ (“IAS 23”) as of the Transition Date. The Company has elected to apply IAS 23 prospectively from the Transition Date.

e) Property, plant and equipment (“PPE”)

Upon transition to IFRS, the Company reclassified its exploration and evaluation assets of $24,617,561 to its own line item on the statement of financial position, and $5,928,635 at June 30, 2011. After this and additional IFRS adjustments described in this note, property, plant, and equipment, including development and production assets was $5,167,310 as at July 1, 2010 and $16,913,495 as at June 30, 2011.

The Company has the option to elect fair value at the date of transition as the deemed cost for its PPE. The Company has three P&Ng properties, two of which are in the exploration and evaluation phase (Paradox Basin and Mitchell Ranch) and the third (Wolfberry) is in the development and production phase.

The Company has elected to recognize the Paradox Basin exploration and evaluation P&Ng property at its fair value at the date of transition, and for that to be its deemed cost moving forward. Therefore, upon transition to IFRS, the Company impaired the Paradox Basin Project to its estimated recoverable amount of $501,428 by estimating the present value of the future net cash flows expected to be derived from the continued use of the asset. Based on oil prices ranging from $77.13 to $83.37; natural gas prices ranging from $4.84 to $6.09; and a discount rate of 18% used in the discounted cash flow model, an adjustment of $21,941,636 was recorded to deficit to adjust the carrying value. As a result, the value of the exploration and evaluation assets decreased by $21,941,636 at July 1, 2010.



Due to the change in the timing of impairment between Canadian gAAP and IFRS which resulted in an adjustment on transition of $3,739,404 for the year ended June 30, 2011, there was a change in the timing of recognition of share of equity investment loss upon the transition from Canadian gAAP to IFRS which resulted in an adjustment on transition in the amount of $478,761 reflecting the loss from the investment in associate for the year ended June 30, 2011.

g) Decommissioning liabilities

IAS 37 – “Provisions, Contingent Liabilities and Contingent Assets“, will govern how the Company accounts for its decommissioning liabilities (previously referred to as asset retirement obligations under Canadian gAAP). The discount rate used for the decommissioning liability will be a risk free rate as the estimated provision is adjusted to reflect risks specific to the liability. Under previous Canadian gAAP, the Company used a credit-adjusted risk free rate. Therefore, under IFRS, the decommissioning liabilities have increased as a result of the lower discount rates used.

P&Ng assets for which the IFRS 1 deemed cost exemption was elected, IFRS 1 also provides an exemption, that the Company has elected to use, which allows the Company to measure decommissioning liabilities as at the date of transition of July 1, 2010 to IFRS in accordance with IAS 37 and recognize directly in the Company’s deficit any difference between that amount and the carrying amount of those liabilities at the date of transition to IFRS determined under previous Canadian gAAP.

The decommissioning liabilities related to P&Ng assets for which the IFRS 1 exemption was not elected, were revalued under IFRS retrospectively from the initial date of recognition and measurement of those liabilities.

The measurement changes incurred upon transitioning to IFRS resulted in the Company reporting an increase in decommissioning liabilities of $130,443 as at July 1, 2010 and $135,927 as at June 30, 2011.

As a result of lower interest rates used for the discounting and unwinding of decommissioning liabilities, finance costs increased by $2,835 for the year ended June 30, 2011 when compared to finance costs under previous Canadian gAAP.

h) Depletion and depreciation

The transition to IFRS did not result in any changes in depletion methods. The changes in measuring decommissioning liabilities resulted in an additional $87,928 capitalized to development and production assets which in turn increased the depletion charge by $16,503 for the year ended June 30, 2011.

i) Foreign currency translation reserve

On transition to IFRS and as permitted by IAS 21, the Company changed its presentation currency from the Canadian dollar to the United States dollar to better reflect the expansion of its United States operations and to eliminate the duplications of reporting in two currencies. In accordance with IFRS, the comparative statements of income (loss) and comprehensive income (loss) and cash flows for each quarter have been translated into the presentation currency using the average exchange rates prevailing during each period, and all comparative assets and liabilities have been translated using the exchange rates prevailing at the statement of financial position date. Comparative equity transactions have been translated using the rates of exchange in effect as of the dates of the various transactions.

As permitted by IFRS 1 election for foreign currency translation differences, the Company has deemed the foreign currency translation differences to be $nil at the date of transition. The foreign currency translation loss at July 1, 2010 was reclassified to deficit.

j) Presentation

Certain presentation and classification differs under IFRS in comparison with the Company’s previous Canadian gAAP as follows:

• Interest and finance costs – the net finance income or expense is presented separately from operating expenses. These charges also include the unwinding of the discount rate on decommissioning liabilities that were presented as part of depletion, depreciation and accretion under previous Canadian gAAP; and

• general and administration costs – costs on the statement of income (loss) and total comprehensive income (loss) have been classified by function in accordance with IAS 1. These costs have been reclassified to general and administrative expenses from individual presentation by nature under previous Canadian gAAP.



canadianGaap

July 1, 2010cDn$

canadianGaap

July 1, 2010usD$ notes

effect oftransition to

ifrsJuly 1, 2010

usD$


ifrsJuly 1, 2010

usD$

assets

current assets

Cash $ 1,739,343 $ 1,633,799 $ - $ 1,633,799

Trade and other receivables 377,499 354,593 - 354,593

Prepaid expenses 6,000 5,636 - 5,636

total current assets 2,122,842 1,994,028 - 1,994,028

non-current assets

Investment in associate 4,121,267 4,195,179 f (4,195,179) -

Exploration and evaluation assets - - e 24,617,561 2,693,053

e (21,941,636)

g 17,128

Property, plant and equipment 31,679,209 29,720,800 e (24,617,561) 5,167,310

g 70,800

h (6,729)

total non-current assets 35,800,476 33,915,979 (26,055,616) 7,860,363

total assets $ 37,923,318 $ 35,910,007 $ (26,055,616) $ 9,854,391

LiaBiLities anD eQuitY

current liabilities

Trade and other payables $ 699,858 $ 657,391 $ - $ 657,391

non-current liabilities

Decommissioning liabilities 90,363 85,458 g 130,443 215,901

total liabilities 790,221 742,849 130,443 873,292

equity

Common shares 39,981,071 36,958,102 - 36,958,102

Contributed surplus reserve 12,430,538 11,682,011 - 11,682,011

Foreign currency translation reserve - 318,916 i (318,916) -

Deficit (15,278,512) (13,791,871) e,f,g,h,i (25,867,143) (39,659,014)

total equity 37,133,097 35,167,158 (26,186,059) 8,981,099

total liabilities and equity $ 37,923,318 $ 35,910,007 $ (26,055,616) $ 9,854,391

The Canadian gAAP consolidated statement of financial position as at July 1, 2010 has been reconciled to IFRS as follows:



canadianGaap

June 30, 2011cDn$

canadianGaap

June 30, 2011usD$ notes


ifrsJune 30, 2011

usD$

ifrsJune 30, 2011

usD$

assets

current assets

Cash $ 2,508,632 $ 2,600,966 $ - $ 2,600,966

Trade and other receivables 939,913 974,508 - 974,508

Prepaid expenses 2,000 2,074 - 2,074

total current assets 3,450,545 3,577,548 - 3,577,548

non-current assets

Exploration and evaluation assets - - e 5,928,635 3,724,856

f (1,579,575)

e (702,443)

g 78,239

Property, plant and equipment 23,216,643 22,830,059 e (5,928,635) 16,913,495

g 33,674

h (21,603)

total non-current assets 23,216,643 22,830,059 (2,191,708) 20,638,351

total assets $ 26,667,188 $ 26,407,607 $ (2,191,708) $ 24,215,899

LiaBiLities anD eQuitY

current liabilities

Trade and other payables $ 5,052,649 $ 5,238,621 $ - $ 5,238,621

non-current liabilities

Decommissioning liabilities 250,597 249,238 g 135,927 385,165

total liabilities 5,303,246 5,487,859 135,927 5,623,786

equity

Common shares 46,387,457 43,206,385 - 43,206,385

Contributed surplus reserve 16,494,016 15,685,758 - 15,685,758

Foreign currency translation reserve - 537,277 i (318,916) 218,361

Deficit (41,517,531) (38,509,672) e,f,g,h,i (2,008,719) (40,518,391)

total equity 21,363,942 20,919,748 (2,327,635) 18,592,113

total liabilities and equity $ 26,667,188 $ 26,407,607 $ (2,191,708) $ 24,215,899

The Canadian gAAP consolidated statement of financial position as at June 30, 2011 has been reconciled to IFRS as follows:



Year ended June 30, 2011

canadianGaap cDn$

canadianGaap usD$ notes

effect oftransition toifrs usD$ ifrs usD$

revenue

Petroleum and natural gas $ 4,710,396 $ 4,702,871 $ - $ 4,702,871

Royalties (1,052,849) (1,051,167) - (1,051,167)

3,657,547 3,651,704 - 3,651,704

expenses

Production and operating expenses 400,276 399,637 - 399,637

Depletion and depreciation 1,233,467 1,202,479 h 16,503 1,218,982

Administrative fees 153,000 152,756 - 152,756

Consulting fees 312,554 312,054 - 312,054

Filing, listing and transfer agent fees 31,499 31,449 - 31,449

Foreign currency translation (25,009) (109,979) - (109,979)

Office and miscellaneous 59,967 59,872 - 59,872

Professional fees 119,871 119,680 - 119,680

Promotion 84,510 84,375 - 84,375

Rent 15,749 15,723 - 15,723

Stock-based compensation 610,971 609,995 - 609,995

Travel 57,426 57,335 - 57,335

(3,054,281) (2,935,376) (16,503) (2,951,879)

earnings before other items 603,266 716,328 (16,503) 699,825

other items

Interest income 32,154 32,103 - 32,103

Finance costs (9,105) (8,875) g (2,835) (11,710)

Equity loss on investment in associate (479,527) (478,761) f 478,761 -

Impairment of investment in associate (3,664,762) (3,739,404) f 3,739,404 -

Impairment of property, plant & equipment (22,721,045) (21,239,192) f 19,659,597 (1,579,595)

(26,842,285) (25,434,129) 23,874,927 (1,559,202)

net loss for the period (26,239,019) (24,717,801) 23,858,424 (859,377)

other comprehensive income (loss)

Foreign currency translation fluctuations

taken to equity - 218,361 i - 218,361

total comprehensive income (loss) for the period $ (26,239,019) $ (24,499,440) $ 23,858,424 $ (641,016)

Basid and diluted loss per share $ (0.30)weighted average number of common shares $ (0.01)

outstanding - basic and diluted 87,285,138 87,285,138

The Canadian gAAP consolidated statement of loss and comprehensive loss for the year ended June 30, 2011 has been reconciled to IFRS as follows:


Mitchell

Sterling

Coke

01 Overview

02 Letter to Shareholders

04 Permian Basin: A West Texas Resurgence

06 Wolfberry Project

10 Mitchell Ranch Project

17 Management Discussion and Analysis

34 Auditors’ Report

36 Consolidated Financial Statements

41 Notes to Consolidated Financial Statements

69 Corporate Information

CONTENTS

Officers and DirectorsOfficers and Directors

Richard Andrews: Richard Andrews: Chairman and DirectorChairman and DirectorColin Watt: Colin Watt: Director, President, CEO and SecretaryDirector, President, CEO and SecretaryRobert Bereskin: Robert Bereskin: DirectorDirectorJohn McLennan: John McLennan: DirectorDirectorRon Paton: Ron Paton: DirectorDirectorLaurie Sadler: Laurie Sadler: CFOCFO

OfficeOffice

Lynden Energy Corp.Lynden Energy Corp.Suite 2480, 1055 West Georgia StreetSuite 2480, 1055 West Georgia StreetVancouver, BC V6E 0B6 (effective February 01, 2013)Vancouver, BC V6E 0B6 (effective February 01, 2013)

Phone: 604-629-2991Phone: 604-629-2991Fax: 604-602-9311Fax: 604-602-9311

E-mail: [email protected]: [email protected]: www.lyndenenergy.comWebsite: www.lyndenenergy.com

Transfer AgentTransfer Agent

Computershare Trust Company of CanadaComputershare Trust Company of Canada510 Burrard Street, 2nd Floor510 Burrard Street, 2nd FloorVancouver, British ColumbiaVancouver, British ColumbiaV6C 3B9V6C 3B9

Trading SymbolTrading Symbol

TSXV: LVLTSXV: LVL

CORPORATE CORPORATE INFORMATIONINFORMATION

This document contains forward-looking statements. The reader is cautioned that assumptions used in the preparation of such statements, although considered accurate at the time of This document contains forward-looking statements. The reader is cautioned that assumptions used in the preparation of such statements, although considered accurate at the time of preparation, may prove incorrect, and the actual results may vary materially from the statements made herein. The Company’s principal activity of oil and natural gas exploration and development preparation, may prove incorrect, and the actual results may vary materially from the statements made herein. The Company’s principal activity of oil and natural gas exploration and development is considered to be inherently risky. Expected timelines relating to oil and gas operations are subject to the customary risks of the oil and gas industry. For a more detailed description of these is considered to be inherently risky. Expected timelines relating to oil and gas operations are subject to the customary risks of the oil and gas industry. For a more detailed description of these risks, and others, see www.lyndenenergy.com/riskfactors.html.risks, and others, see www.lyndenenergy.com/riskfactors.html.

Portions of this document contain information as of December 2012.Portions of this document contain information as of December 2012.

Barrel of oil equivalent (“boe”) amounts have been calculated using a conversion ratio of six thousand cubic feet of natural gas to one barrel of oil (6:1) to express quantities of natural gas and Barrel of oil equivalent (“boe”) amounts have been calculated using a conversion ratio of six thousand cubic feet of natural gas to one barrel of oil (6:1) to express quantities of natural gas and crude oil in a common unit. The term “boe” may be misleading, particularly if used in isolation. The conversion ratio is based on an energy equivalency conversion method primarily applicable crude oil in a common unit. The term “boe” may be misleading, particularly if used in isolation. The conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.at the burner tip and does not represent a value equivalency at the wellhead.MONETARY AMOUNTS IN THIS ANNUAL REPORT ARE IN US DOLLARS UNLESS OTHERWISE NOTED.

PERMIAN BASIN OIL

Wolfberry Project

PERMIAN BASIN OIL

Mitchell Ranch Project

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2012 :

W W W . L Y N D E N E N E R G Y . C O M

2012 ANNUAL REPORT

2012 ANNUAL REPORT2012 ANNUAL REPORTLYNDEN ENERGY :

FUELING RESULTS: WEST TEXASWEST TEXAS


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