Chelsea Oil and Gas Ltd.: Exhibit 99.2 - Filed by newsfilecorp.com

Unless the context otherwise requires, the following terms shall have the respective meanings set out below when used in this Annual Information Form:

“ABCA” means the Business Corporations Act (Alberta), as amended or re-enacted, including the regulations promulgated thereunder;

“AIF” means this Annual Information Form including the appendices hereto;

“AGM” means the Annual General Meeting of the Corporation held on June 2, 2015;

“Arrangement” means the plan of arrangement under the provisions of Section 288 of the BCBA between Chelsea and ITME on the terms and conditions set forth in the Arrangement Agreement;

“Arrangement Agreement” means the arrangement agreement dated May 28, 2013 between ITME and Chelsea in respect of the Arrangement;

“ATP” means Authority to Prospect, an ATP is a concession granted by the State of Queensland, Australia, which entitles its holders to an exclusive right to explore for oil and natural gas in Queensland in the particular area covered by the ATP. Each ATP has an initial term of four years. The area covered by an ATP is reduced by relinquishment of approximately one-fourth of the area at the start of the third year of its effectiveness and an additional one-fourth of the original area at the start of the fourth year of its effectiveness. The area to be relinquished is chosen by the holder of the ATP. An ATP will require some kind of geological and/or geophysical operations, such as new seismic or seismic interpretation, drilling or other operations during the term of the tenure. The amount of work to be performed depends upon the expenditures required for each specific year of the tenure. Holders are only required to expend those amounts as set out in the original concession document. Applications for renewal may be filed at the time of expiration of an ATP;

“ATP 582” means Authority to Prospect number 582, issued pursuant to section 84 of the Petroleum and Gas (Production and Safety) Act 2004;

“BCBCA” means the Business Corporations Act (British Columbia), as amended or re-enacted, including the regulations promulgated thereunder;

“BCSC” has the meaning ascribed under Directors and Officers; Cease Trade Orders in this AIF;

“Best Estimate” means the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50% probability (P50) that the quantities actually recovered will equal or exceed the best estimate;

“Board of Directors” or “Board” means the board of directors of Chelsea Oil, as constituted from time to time, and where the context requires, includes any duly constituted committee thereof;

“Bowen Basin” means a foreland basin in eastern Queensland of Early Permian to Middle Triassic age sediments. It occupies about 160,000km², the southern half of which is covered by the Surat Basin;

“Brokered Private Placement” means the proposed brokered private placement of common shares and convertible common equity led by RiverRock;

“Chapman” means Chapman Petroleum Engineering Ltd., engaged by Chelsea to complete a NI 51-101 reserve report on PL 18, PL 280 and PL 40;

“COGE Handbook” means the Canadian Oil and Gas Evaluation Handbook prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society), as amended from time to time;

“Common Shares” or “Chelsea Common Shares” means the common shares in the capital of the Corporation;

“Cooper Basin” means the sedimentary geological basin of Triassic age covering 130,000 km² in the north east part of South Australia and in the south west part of Queensland;

“Corporation” or “Chelsea” means Chelsea Oil and Gas Ltd., including where the context requires, its predecessors;

“CSG” has the meaning ascribed under Industry Overview; Availability of Services in this AIF;

“DPIIP” means Discovered Petroleum Initially In Place, the quantity of petroleum which is estimated, on a given date, to be contained in known accumulations, plus those quantities already produced therefrom. If the hydrocarbon is oil, it may be referred to as OOIP and if the hydrocarbon is gas, it may be referred to as OGIP;

“Earning Obligations” has the meaning ascribed under General Development of the Business in this AIF;

“Farm-Out” has the meaning ascribed under General Development of the Business in this AIF;

“Farm-Out Interest” has the meaning ascribed under General Development of the Business in this AIF;

“Georgina Basin” means the intracratonic sedimentary basin in central and northern Australia, lying within the Northern Territory and within Queensland and “South Georgina Basin” means the southerly portion of the Georgina Basin;

“Heritage Act” has the meaning ascribed under Industry Overview; Aboriginal Heritage in this AIF;

“High Estimate” means an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10% probability (P10) that the quantities actually recovered will equal or exceed the high estimate;

“FIRB” has the meaning ascribed under Industry Overview; Foreign Acquisitions in Australia in this AIF;

“FIRB approval” has the meaning ascribed under Industry Overview; Acquiring Shares in this AIF;

“Low Estimate” means a conservative estimate of the quantity that it will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90% probability (P90) that the quantities actually recovered will equal or exceed the low estimate;

“MI 51-105” has the meaning ascribed under OTC Reporting Issuer in this AIF;

“Native Title” means agreements signed pursuant to the Native Title Act 1993 which recognizes that the indigenous people of Australia continue to hold rights and interests in relation to certain lands and water;

“NGL” means Natural Gas Liquids, those hydrocarbon components that can be recovered from natural gas as liquids, including but not limited to ethane, propane, butanes, pentanes plus condensate, and small quantities of non-hydrocarbons;

“NI 51-101” means National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities;

“NI 52-110” has the meaning ascribed under Audit Committee in this AIF;

“Non-Brokered Private Placement” means the private placement of 5,473,385 subscription receipts of the Corporation issued at a price of $0.35 per subscription receipt which closed in January, 2012, and which subscription receipts were converted into 5,473,385 Common Shares on February 29, 2012;

“Options” means stock options to purchase Common Shares issued pursuant to the Corporation’s stock option plan;

“Olympia” means Olympia Trust Company, the registrar and transfer agent for the Common Shares;

“ORRI” means Overriding Royalty Interest, an interest assigned out of the lessee’s leasehold or Working Interest. The amounts payable from Overriding Royalty Interests are payments calculated as a percentage of either Gross Production or the gross revenues of the Working Interest (based on the wellhead price) from a concession or lease, usually free and clear of all exploration, drilling and development and production costs, except for any applicable taxes and federal levies. In calculating the wellhead price, pipeline and trucking costs have already been deducted from the refinery price. The overriding royalties discussed herein are generally expressed as a percent of the Gross Production;

“OTCQB” has the meaning ascribed under Market for Securities; Trading Price and Volume in this AIF;

“PEL” means Petroleum Exploration License, an exclusive oil and gas Exploration Permit issued by the South Australian Department of Primary Industries and Resource in the State of South Australia, Australia. The initial term of the tenure is for a five (5) year period;

“PL” means Petroleum Lease, a lease granted by the State of Queensland, Australia under the Petroleum Act and includes any variation, renewal, permit, license or other interest issued in substitution thereof and any other petroleum tenure or rights to explore for or produce Petroleum Substances;

“PRRT” has the meaning ascribed under Industry Overview; Land Tenure and Royalties in this AIF;

“PVIL” has the meaning ascribed under Directors and Officers; Bankruptcies in this AIF;

“RiverRock” means RiverRock Securities Limited, a UK broker and advisor having its principal place of business at 3rd Floor, Grosvenor Gardens, London SW1W 0DH, United Kingdom;

“Simpson Basin” means the intracratonic early to middle Triassic basin occupying 100,000km² of northern South Australia, south east Northern Territory and south west Queensland;

“Surat Basin” means the intracratonic early Jurassic to Cretaceous basin occupying 300,000km² of central southern Queensland and central northern New South Wales;

“Surat-Bowen Basin” means the combination of Permian and Triassic age sediments of the deeper Bowen Basin, overlain by the Jurassic and Cretaceous strata of the Surat Basin. Because intervals of both sequences are prospective and have produced in close or even over-lying proximity, Operators tend to use the two names inter-changeably;

“Section 31 Deed” means the right to negotiate deed of agreement regarding the addition of excluded land into an ATP under Section 31(1)(b) of the Native Title Act 1993 (Cth);

“Terra Nova” means Terra Nova Energy Ltd., operator of PEL 112 and PEL 444;

“Warrant” means one Common Share purchase warrant of the Corporation; and

“Working Interest” means all or a fractional part of the ownership rights granted by a concession or lease. The owner of a Working Interest or a part thereof pays all costs of exploration and is entitled to the Gross Production, less royalties retained by the grantor or lessor, and less Overriding Royalty Interests or other non-operating interests created or assigned from the Working Interest. The owner of a Working Interest may incur operating expenses in excess of income.

Certain other terms used herein but not defined herein are defined in NI 51-101 or in the Glossary of NI 51-101 (contained in Canadian Securities Administrators Staff Notice 51-324 (“CSA Notice 51-324”)) and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101 or in CSA Notice 51-324, as applicable. CSA Notice 51-324 incorporates by reference certain definitions set out in the COGE Handbook.

In this AIF, all dollar amounts are expressed in United States currency, unless otherwise noted.

The term boe may be misleading, particularly if used in isolation. A boe conversion ratio of six Mcf of natural gas per bbl of oil (6 Mcf: 1 bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Additionally, given the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion ratio at 6:1 may be misleading as an indication of value.

The following table sets forth certain standard conversions from Standard Imperial units to the International System of Units (or metric units).

This AIF contains certain forward-looking statements and forward-looking information which are based on the Corporation’s current internal expectations, estimates, projections, assumptions and beliefs, including, among other things, assumptions with respect to production, future capital expenditures and cash flow, based on information available at the time the assumption was made. Readers are cautioned that assumptions used in the preparation of such information may prove to be incorrect. The use of any of the words “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “plan”, “should”, “believe” and similar expressions are intended to identify forward-looking statements and forward- looking information. These statements are not guarantees of future performance and involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements or information. The Corporation believes that the expectations reflected in those forward-looking statements and information are reasonable but no assurance can be given that these expectations, or the assumptions underlying these expectations, will prove to be correct and such forward-looking statements and information included in this AIF should not be unduly relied upon. Such forward-looking statements and information speak only as of the date of this AIF.

In particular, this AIF contains forward-looking statements which include, but are not limited to, statements and information pertaining to the following:

The forward-looking statements contained in this AIF are based on and have been developed with reference to certain factors and assumptions which include, but are not limited to, the following:

The Corporation’s actual results could differ materially from those anticipated in these forward-looking statements and information as a result of both known and unknown risks, including the risk factors set forth under “Risk Factors” in this AIF and those set forth below:

Readers are cautioned that the foregoing lists of factors should not be construed as exhaustive. The forward-looking statements contained in this AIF are expressly qualified by this cautionary statement and by the risk factors described in this AIF under the heading “Risk Factors”. Except as required under applicable securities laws, Chelsea undertakes no obligation to publicly update or revise any forward-looking statements.

The determination of oil and gas resources involves the preparation of estimates that have an inherent degree of associated uncertainty.

The estimation and classification of resources requires the application of professional judgment combined with geological and engineering knowledge to assess whether or not specific resources classification criteria have been satisfied. Knowledge of concepts including uncertainty and risk, probability and statistics, and deterministic and probabilistic estimation methods is required to properly use and apply resource definitions.

Statements relating to “reserves” or “resources” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the resources and reserves described can be profitably produced in the future.

Australian-Canadian Oil Royalties Ltd. was incorporated April 28, 1997 in British Columbia, Canada. On September 27, 2013 Australian-Canadian Oil Royalties Ltd. was continued into the province of Alberta. On October 1, 2013, Australian-Canadian Oil Royalties Ltd. amalgamated with ITME and was renamed “Chelsea Oil and Gas Ltd.”. The address of the Corporation’s head office is 127, 10^th Ave NW, Calgary, Alberta, Canada, T2M 0B4 and its registered office is 4600, 525 – 8^th Avenue S.W., Calgary, Alberta, Canada, T2P 1G1.

The Corporation has three wholly owned subsidiaries: Cooper-Eromanga Oil Inc., Chelsea Oil Australia Pty., and 1629518 Alberta Ltd., which is inactive. In addition, the Corporation holds 20% of Cooper Basin Oil and Gas Inc. which is also inactive.

The following chart presents a summary of Chelsea’s ownership and organizational structure. Each subsidiary companies Country or State of domicile is represented in parentheses, and the ownership of each subsidiary is represented as a percentage.

Chelsea is the parent and holding company for each of its wholly-owned subsidiaries and minority interest in Cooper Basin Oil and Gas Inc. Chelsea also directly holds all of the Corporation’s ORRIs.

Chelsea Oil Australia Pty Ltd. holds the Surat Basin Petroleum Leases: PL 18, PL 40 and PL 280.

Cooper Basin Oil and Gas Inc. has no assets and is not currently active. Chelsea has a 20% minority interest in this company.

Chelsea is engaged in the business of petroleum exploration in Australia, primarily through its Australian subsidiaries, Chelsea Oil Australia Pty Ltd. and Cooper-Eromanga Oil Inc.

On January 13, 2013, the Corporation held its AGM. Shareholders approved the reelection of Mr. Howard Siegel, Mr. William H. Petrie Sr. and Mr. Jesse Meidl to the Board of Directors. Mr. Andre Sakhai was added to the board of directors subsequent to the AGM. Mr. Bernard Lipton and Mr. Jan Soleimani were not re-elected by shareholders of the Corporation.

On May 31, 2013, the Corporation announced the proposed acquisition of ITME and NI 51-101 Resource Report from Ryder Scott, who evaluated a portion of ATP 582 in the South Georgina Basin.

On August 7, 2013, Terra Nova announced the completion of drilling operations at Wolfman-1 in the Cooper Basin. The well was reported as dry, and was drilled at no cost to Chelsea.

On October 1, 2013, Chelsea completed the acquisition of ITME. The acquisition was completed through the Arrangement, whereby Chelsea acquired all of the issued and outstanding common shares of ITME. The Arrangement constituted a “significant acquisition” under Part 8 of National Instrument 51-102- Continuous Disclosure Obligations and Chelsea has filed a business acquisition report on Form 51-102F4 in respect of the Arrangement. In connection with the closing of the Arrangement, the Corporation changed its name to “Chelsea Oil and Gas Ltd.”, moved its corporate and registered head office from Cisco, Texas to Calgary, Alberta, and reconstituted its Board of Directors and executive management team. Toby Pierce, Stewart Gibson and Yves Merer were elected by shareholders to join the Board of Directors of the Corporation, along with Jesse Meidl and William H. Petrie, Sr. Under the terms of the Arrangement, ITME shareholders received 0.5431 of a Common Share in exchange for one ITME common share. Chelsea issued a total of 13,976,542 Common Shares to former ITME shareholders. Upon completion of the transaction, the Corporation received a new OTCQB ticker symbol: COGLF.

On November 29, 2013, the Corporation engaged RiverRock on a commercially reasonable endeavours basis for the purposes of completing a private placement of equity or debt of Chelsea.

On December 2, 2013, Terra Nova announced it had completed the 80 km² Wingman 3D seismic survey in PEL 444 in the Cooper Basin. Having completed the 3D survey and drilling of the Wolfman-1 well, Terra Nova earned a 25.83% Working Interest in both PEL 112 and PEL 444.

On June 16, 2014, the Corporation announced that it had received a two-year extension for ATP 582 from the Queensland government. In addition, the government deferred the mandatory relinquishment requirements while retaining the available extension provisions.

On October 30, 2014, the Corporation announced that it sold its non-operated working interests and associated overriding royalty interests in PEL 112 and 444 in the Cooper Basin, South Australia to an arms length private company for nominal consideration. Following the sale of PEL 112 and PEL 444, all of the Corporation’s working interest properties are located in the state of Queensland.

On June 1, 2015, the Corporation announced that the BCSC granted a full revocation of the cease trade order issued by the BCSC on February 18, 1999 in respect of ITME, a predecessor company to Chelsea.

Throughout 2015 and to the date of this AIF, the Corporation has continued to work with RiverRock to complete the Brokered Private Placement which, which if successful, is expected to enable the Corporation to fund its operations and maintain its debt obligations for 2016 and 2017. There is no certainty that the Brokered Private Placement will be completed.

In tandem, the Corporation has initiated discussions with multiple parties regarding the full or partial sale of some of its assets. The proceeds of any sale would be used by the Corporation to fund its operations and maintain its debt obligations for 2016 and 2017. There is no certainty that any asset sale will be completed.

The Corporation engaged Chapman to prepare a report relating to the Corporation’s reserves in respect of PL 18, 40 and PL 280 as at December 31, 2015. The reserves on the properties described herein are estimates only. Actual reserves on these properties may be greater or less than those estimated.

Set out below is a summary of the light oil, gas and liquids reserves and the net present value of future net revenues of the Corporation as at December 31, 2015, as evaluated by Chapman in its report with a preparation date of March 30, 2016. A summary of the Chapman Reserves Report and accompanying narrative (in Form 51-101F1), as well as the report on the reserves data by Chapman (in Form 51-101F2) and the report of the Corporation’s management on such reserves data (in Form 51-101F3) are included in this Annual Information Form as Appendices B-31, B-2 and B-3. The following is a summary of the Chapman Reserves Report which is qualified in its entirety by the Corporation’s Statement of Reserves Data and Other Oil and Natural Gas Information attached as Appendix B-4 hereto.

OIL AND GAS RESERVES
BASED ON FORECAST PRICES AND COSTS IN AUSTRALIAN DOLLARS^(4)(5)(6)

	Remaining Gas and NGL Reserves
	Company Light Oil		Company Gas		Company NGL		Company Total
	Gross⁽¹⁾	Net⁽¹⁾	Gross⁽¹⁾	Net⁽¹⁾	Gross⁽¹⁾	Net⁽¹⁾	Gross⁽¹⁾	Net⁽¹⁾
	(Mbbl)	(Mbbl)	(MMcf)	(Mmcf)	(mbbl)	(mbbl)	(mbbl)	(mbbl)
Total Proved ⁽²⁾	95	83	-	-	-	-	95	83
Total Probable⁽³⁾	50	44	2,905	2,598	508	444	1,042	912
Total Possible⁽⁴⁾	-	-	14,525	13,001	2,538	2,220	4,959	4,338
Total Proved Plus Probable Plus Possible	145	126	17,430	15,599	3,045	2,664	6,095	5,332

NET PRESENT VALUES OF FUTURE NET REVENUE
BASED ON FORECAST PRICES AND COSTS IN AUSTRALIAN DOLLARS^(4)(5)(6)

	A$ Before Deducting Income Taxes					A$ After Deducting Income Taxes
	Discounted At					Discounted At
	0%	5%	10%	15%	20%	0%	5%	10%	15%	20%
	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
Total Proved ⁽²⁾	4,055	3,138	2,443	1,905	1,482	4,055	3,138	2,443	1,905	1,482
Total Probable⁽³⁾	27,575	23,277	19,854	17,076	14,790	20,737	17,425	14,784	12,638	10,866
Total Possible⁽⁴⁾	130,395	103,245	82,812	67,160	55,043	90,300	70,678	56,019	44,886	36,306
Total Proved Plus Probable Plus Possible	162,025	129,659	105,100	86,164	71,315	115,092	91,240	73,246	59,429	48,650

Chelsea is an Australian focused exploration, development and production company with approximately 5.2 million net Working Interest acres of land onshore Australia. The Corporation has a portfolio of assets, as follows:

The Surat-Bowen Basin is a combination of Permian and Triassic age sediments of the deeper Bowen Basin, overlain by the Jurassic and Cretaceous strata of the Surat Basin. Because intervals of both sequences are prospective and have produced in close or even over-lying proximity, operators tend to use the two names interchangeably.

The Bowen Basin of eastern Queensland is a foreland basin of Early Permian to Middle Triassic age sediments. It occupies about 60,000km², the southern half of which is covered by the Surat Basin. It has a maximum sediment thickness of about 10,000 metres concentrated in two north-trending depocentres, the Taroom Trough to the east and the Denison Trough to the north-west. Deposition in the basin commenced during an Early Permian extensional phase, with fluvial and lacustrine sediments and volcanics being deposited in a series of half-grabens in the east while in the west a thick succession of coals and nonmarine clastics were deposited. Following rifting, there was a thermal subsidence phase extending from the mid Early to Late Permian, during which a basin-wide transgression allowed deposition of deltaic and shallow marine, predominantly clastic sediments as well as extensive coal measures. Foreland loading of the basin spread from east to west during the Late Permian, resulting in accelerated subsidence, which allowed the deposition of a very thick succession of Late Permian marine and fluvial clastics, again with coal and Early to Middle Triassic fluvial and lacustrine clastics. Sedimentation in the basin was terminated by a Middle to Late Triassic contractional event.

Over 100 hydrocarbon accumulations have been discovered in the Bowen Basin, of which about one third are producing fields. Accumulations occur throughout the succession, but the most important reservoirs are in the Early Permian and Middle Triassic. Source rocks have been identified throughout the Permian and in the Middle Triassic and are mostly nonmarine. Proven plays comprise mostly anticlinal closures sometimes enhanced by a stratigraphic component, as well as fault rollovers. Other plays are largely untested. The Bowen Basin also has vast coal resources, with major open cut and underground coal mines in the north of the basin. Large volumes of methane gas are held at shallow depths within Permian coals in the north and have potential for coal seam methane developments.

The Surat Basin is a large, mature, intracratonic, Early Jurassic to Cretaceous basin occupying approximately 300,000km² of central southern Queensland and central northern New South Wales. It has a maximum sediment thickness of 2500 metres and deposition was relatively continuous and widespread. Deposition in the basin commenced with the onset of a period of passive thermal subsidence of much of eastern Australia. During the Early Jurassic, deposition was mostly fluviolacustrine, while by the Middle Jurassic coal swamp environments predominated over much of the basin, except in the north where fluvial sedimentation continued.

Towards the end of the Middle Jurassic, fluvial deposition again predominated and continued until the earliest Cretaceous. A marine transgression followed, depositing paralic and marine sediments and reaching its peak in the Aptian. The subsequent regression caused a fairly abrupt return to fluvial, lacustrine and paludal environments before sedimentation ceased in the Aptian. About 100 hydrocarbon accumulations have been discovered in the Surat Basin, of which about half are producing fields. Most accumulations are reservoired in Early Jurassic sands, with occasional gas occurrences in the Middle and Late Jurassic, but all are sourced from the Permian nonmarine sediments of the underlying Bowen Basin. Proven plays comprise mostly low amplitude anticlinal closures occasionally associated with thrust faulting and drapes over basement highs. Because the basin is largely flat-lying and sedimentation widespread and relatively uniform, other types of traps are unlikely to be important. The upper part of the Surat Basin sequence comprises the Great Artesian Basin of Australia, an enormous fresh water resource.

Chelsea holds a 100% Working Interest in PL 18 and PL 40 as well as a 50% Working Interest in PL 280. The Corporation is in the process of completing the transfer of the EA for PL 280. A portion of proceeds from the sale of PEL 112 and PEL 444 has been held as restricted cash, in the form of a bank guarantee in favour of the Queensland government. Following the posting of the bank guarantee, the Corporation has made application with the Queensland government to complete the transfer of PL 18, PL 40 and PL 280 to Chelsea.

The Corporation’s Surat-Bowen Basin oil assets comprise six existing oil pools with 14 million barrels of light, high quality (51°), high mobility DPIIP, of which, to date, only 6%, or 770,000 barrels has been recovered. As the oil is 51°, it exhibits high mobility. There is no certainty that it will be commercially viable to produce any portion of the resources. To date, exploration has been directed at finding and drilling structural “highs”, usually the first phase of exploration before more subtle stratigraphic prospects are tested. All production has been primary, meaning that no secondary enhancements such as pressure maintenance, water flooding, etc., have been implemented. Oil is produced to single well batteries and trucked about 30 kilometres to Fairymount where it enters the Santos pipeline carrying oil from the Cooper Basin to Brisbane. The last production from the area was from the Yellowbank Creek pool in 2010.

Given the low overall recovery to date (0.770 mmbo or 6% of DPIIP) under primary production methods, there is an opportunity for a relatively low risk redevelopment of the proven productive oil pools. The 9% gross recovery factor assessed by Sproule in the Possible case relating to Chelsea contemplates only infill drilling and projects recovery factors only as achieved to date. NI 51-101 regulations do not provide for allocation of proved reserves via water-flooding without a direct analog in close proximity. There are numerous water-flood projects in Western Canada, including some that recover as high as 40% OOIP; however there are currently no pressure maintenance schemes being implemented in any direct analog in close proximity to Chelsea’s Surat-Bowen Basin assets, and as a result no proved reserves have been allocated. Good reservoir qualities of porosity and permeability, together with the high quality and mobility of the oil suggest that reservoir response should be similar to those observed when similar procedures have been implemented in Western Canada.

On the PL 40 permit, also in the Surat-Bowen Basin, bypassed gas has been identified in three wells on Chelsea’s lands as evaluated by Chapman.

The Georgina Basin is a large (ca. 330,000 km², 5.0mm acres) intracratonic sedimentary basin in central and northern Australia, lying mostly within the Northern Territory and partly within Queensland. It is named after the Georgina River which drains part of the basin. Deposition of locally up to ca. 4 km of marine and non-marine sedimentary rocks took place from the Neoproterozoic to the late Paleozoic (ca. 850-350 Ma). Along with other nearby sedimentary basins of similar age (Amadeus Basin, Officer Basin); the Georgina Basin is believed to have once been part of the hypothetical Centralian Superbasin that was fragmented during episodes of tectonic activity.

More recently, the Georgina Basin has been recognized as having considerable potential for unconventional hydrocarbons within the Arthur Creek Formation of Middle Cambrian age. This has led to all the prospective parts of the basin now being held under exploration permits and a new phase of exploration is under way. The deepest part of the basin, known as the Toko Syncline, lies within Queensland and is considered by many to have the most hydrocarbon potential.

The Simpson Basin extends over 100 000 km² in South Australia, southeast part of Northern Territory, and southwest part of Queensland. Approximately half lies in South Australia. It is a circular, poorly defined depression with one major depo centre, the Poolowanna Trough. The Simpson Basin has a known petroleum system within the Permian and Triassic sequence and recently an operator in the adjacent Northern Territory announced an in-house estimate of 12 to 25 Tcf of prospective unconventional gas resource within its permit. Chelsea does not know if such estimate was prepared by a qualified reserves evaluator or auditor or in accordance with the COGE Handbook. There is no certainty that any portion of the resources will be discovered.

If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. Validation of this resource is likely to increase exploration activity in this area. The basin overlies older Pedirka Basin strata, also considered prospective, and is overlain by the younger Eromanga Basin sediments.

In the Georgina Basin, more specifically the Toko Syncline, three vertical wells have been drilled to basement and one other was abandoned before reaching total depth for mechanical reasons. This well did, however, encounter natural gas which flowed against a full column of drilling fluid at an estimated 200 Mcf per day. This well is important in that it confirms the presence of movable hydrocarbons in the basin. Each of the basement penetrations are on ATP 582 and serve to define the play model and the thermal maturity windows encountered within the Arthur Creek in the wells. These wells are Todd-1 (1991), Netting Fence-1 (1964), Mirrica-1 (1980), and Ethabuka-1 (1974), the well that encountered the gas flow but did not reach what is now the unconventional target. Based on these wells, fairways have been defined within the Toko Syncline as being prospective for oil, gas and liquids, and “dry” natural gas.

All previous seismic and drilling was for conventional structural traps, particularly near the basin-defining Toomba Fault. Approximately 200 kilometres of legacy seismic exists on ATP 582 from 1977 through 1981 vintage. This data is of limited value for any possible defining of hydrocarbon indicators but does serve to define gross structural features.

At the southern portion of ATP 582, thought to contain Simpson Basin strata, management has identified several untested four-way dip closed structures on the basis of similar vintage 2D seismic. No wells have tested this part of ATP 582.

The Corporation has a 100% Working Interest in approximately five million net acres with multi-billion barrel potential. TOTAL and Santos have committed in excess of A$400 million to drill, core and frac up to 8 wells on immediately offsetting lands. Independent geological reports indicate that the Corporation’s acreage is geologically equivalent if not superior to adjoining areas controlled by these super-majors. If the offsetting drilling is successful, the value of Chelsea’s acreage is anticipated to increase exponentially.

The prospective resource in place, if proved to be economically recoverable, would make Chelsea a major stakeholder in one of Australia’s largest gas resources. This resource is projected to be in high demand for Australia’s major LNG plants, which are experiencing short-falls in supply stock. Given the demand from the nearby Asian market, the longer term outlook is for continued strong prices.

Further, Chelsea enjoys a relatively low work commitment to maintain the key acreage position in the Arthur Creek fairway, and benefits from the “free exploration” that is currently being conducted by the above super-majors. A step-change in shareholder value could be achieved with minimal expenditure and dilution.

Chelsea has ORRIs over more than approximately 9.3 million gross acres (60,000 net acres) in the Cooper (Onshore), Gippsland (Offshore) and Victoria (Offshore VIC P54) basins. These interests have generated small amounts of revenue for the Corporation.

License	Basin	Operator	Gross Acres	ORR Interest	Net Royalty Acres
VIC P54	Gippsland	Nexus Energy	155,676	0.05%	78
PEL 111⁽¹⁾	Cooper	Senex Energy	290,101	0.60%	1,741
PEL 115	Cooper	Senex Energy	65,730	0.175%	115
ATP 267	Cooper	Santos	220,800	0.17%	379
ATP 299	Cooper	Santos	441,600	0.06%	254
ATP 560	Cooper	First Source	625,600	0.25%	1,564
Total			1,799,507		4,131

License	Basin	Operator	Gross Acres	ORR Interest	Net Royalty Acres
PEL 88	Cooper	Senex Energy	816,436	0.30%	4,899
PEL 424	Cooper	Senex Energy	1,516,733	0.10%	1,517
ATP 544	Cooper	Australia Pete	901,600	0.81%	7,285
ATP 550	Cooper	Discovery Geo	276,000	0.25%	690
ATP 582	Georgina	Cooper-Eromanga Oil⁽²⁾	5,022,000	0.67%	33,698
ATP 616	Cooper	Sundance Resources	147,200	3.33%	4,907
ATP 636	Cooper	Santos	640,000	0.50%	3,200
Total			9,319,969		56,195

The oil and natural gas industry in Australia is subject to extensive controls and regulations governing its operations (including land tenure, exploration, development and production) imposed by legislation enacted by various levels of government. It is not currently expected that any of these controls or regulations will affect the operations of Chelsea in a manner materially different than they would affect other oil and natural gas companies of a similar size. All current legislation is a matter of public record and Chelsea is unable to predict what additional legislation or amendments may be enacted from time to time. Outlined below are some of the principal aspects of legislation, regulations and agreements governing the oil and natural gas industry in Australia.

The summary below is of a general nature and is not intended to be, nor should it be construed to be, an exhaustive review of the legislation, regulations and agreements governing the oil and natural gas industry in Australia.

In Australia, onshore oil and natural gas exploration and production is regulated by the relevant state or territory in which the exploration or production activities are to take place. The relevant state or territory also regulates oil and natural gas exploration and production in the coastal waters adjacent to that state. Oil and natural gas exploration and production in the offshore area is regulated by the Commonwealth Government of Australia. Broadly, the Australian regime for oil and natural gas exploration and production involves applying for and, if successful in the application, being granted the relevant permit or title under the applicable legislation and payment of royalties to the relevant government for oil and natural gas recovered (in contrast to jurisdictions that regulate oil and natural gas activity by way of contracts between the explorer/producer and the relevant state, such as a production sharing contract). Australia produces and processes significant quantities of both natural gas and crude oil for domestic use and natural gas, which is converted into liquefied natural gas for export to international markets. There are a large number of active oil and natural gas projects in Australia, the most significant of which is the North West Shelf Project, situated in offshore Western Australia, and various operations in the Bass Strait, situated between Tasmania and Victoria. There has recently been considerable investment attention paid to the large coal seam gas resources located in Queensland. The oil and natural gas industry in Australia is mature and is regulated accordingly to known principles and practices.

In Australia, the environmental impact of petroleum exploration and production is regulated at both the federal level and at the state and territory levels.

State and territory legislation not only imposes general duties to prevent or minimize harm to the environment but also imposes specific obligations to obtain authorizations for activities such as the clearance of native vegetation, the taking and use of naturally occurring water and the conduct of activities of potential significance to the environment. Authorizations for such activities must be obtained from the relevant territory or state government departments prior to the commencement of work. Obligations to minimize harm or to rehabilitate harm already caused by an activity can be enforced by way of notices and orders.

Commonwealth legislation has more limited application than state and territory legislation. Commonwealth legislation will only apply where a person proposes to undertake an action that will have or is likely to have a significant impact on a matter of national environmental significance. An action can include, among other things, the clearance or disturbance of native vegetation, the construction of infrastructure or discharge of material into a water body. Matters of national environmental significance include, among other things, wetlands of international importance, listed threatened species and ecological communities and migratory species protected under international agreements.

Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability, and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas, or other pollutants into the air, soil or water may give rise to liabilities to third parties and may require Chelsea to incur costs to remedy any such discharge not covered by Chelsea’s insurance. Although Chelsea will maintain insurance to industry standards once it commences operations, which in part covers liabilities associated with discharges, it is not certain that such insurance will cover all possible environmental events, foreseeable or otherwise, or whether changing regulatory requirements or emerging jurisprudence may render such insurance of little benefit. Further, Chelsea expects incremental future compliance costs in light of increasingly more complex environmental protection requirements, some of which may require the installation of emissions monitoring and measuring devices and verification of emissions data.

Chelsea believes it is in material compliance at this time with environmental legislation in all of the jurisdictions in which it carries on operations. Chelsea is committed to meeting its responsibilities to protect the environment wherever it operates and will take such steps as required to ensure compliance with environmental legislation. No assurance can be given that environmental laws will not result in the curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise adversely affect Chelsea’s financial condition, results of operations or prospectus.

The Australian Federal Government is implementing the Clean Energy Future package, a set of measures aimed at reducing greenhouse gas emissions and increasing the use of renewable energy. The package includes a carbon pricing mechanism, which from July 1, 2012 will impose a price on emissions of greenhouse gases.

The carbon pricing mechanism applies to four of the six greenhouse gases covered by the Kyoto Protocol. Most sectors are included, other than agriculture, which instead is given an incentive to undertake projects to reduce or store emissions. Most sectors are covered by an emissions trading scheme established under the Clean Energy Act 2011, other than transport, where an equivalent carbon price will be applied through reductions to fuel excise and rebate arrangements.

In the first three years, the emissions trading scheme operates as a tax, after which it moves to a conventional cap-and-trade model. Broadly, two activities give rise to liability under the emissions trading scheme. The first is having operational control of a facility (defined as an activity or series of activities forming a single undertaking or enterprise) with annual emissions of at least 25,000 tonnes (measured in CO₂ equivalent). The second is being a supplier of natural gas for use, where the gas is withdrawn from a natural gas pipeline for the purposes of the use. There is also an opt-in mechanism, principally intended for the aviation sector, and some limited flexibility to transfer liability. Unincorporated joint ventures are covered by rules that enable liability to be allocated to the joint venture participants. The scheme includes some flexibility to transfer liability.

In the case of facilities, liability is based on direct emissions from the facility, such as emissions from the combustion of gas or coal. For gas suppliers, liability is based on the potential emissions embedded in the gas they supply. Emissions from large gas consuming facilities such as power stations are captured under the facilities mechanism, rather than through the gas supplier.

For each tonne of emissions, a liable entity must either surrender one eligible emissions unit, or pay the shortfall charge. The charge is set high enough for there to be a strong incentive to buy and surrender units.

The price for carbon units is fixed for the first three years of the scheme, initially at A$23 per unit. During that first phase, carbon units are available in unlimited quantities. From July 1, 2015, the scheme enters the flexible price phase. The scheme's regulator will issue carbon units by auction and the total number of carbon units will be capped at a level to be set by Government. For at least the first three years of the flexible price phase, auctions will be subject to a price ceiling, initially A$20 per unit above international prices. A price floor will also apply, being initially A$15.00 per unit.

The carbon pricing mechanism is linked to Australia's Carbon Farming Initiative ("CFI"); a scheme for land based projects to reduce or store greenhouse gas emissions and earn tradeable credits. Liable entities will be able to use eligible credits from the CFI for up to 5% of liability in the fixed price phase and in unlimited quantities after that.

As to international markets, some classes of international units will also be eligible for surrender, but only in the flexible price phase and, at least initially, only for up to 50% of liability. International units will also be subject to a surrender charge to ensure the effective price is equivalent to the auction floor price.

In Australia, corporate taxpayers are subject to income tax on taxable income at a fixed rate of 30%. Gains arising on sales of capital assets and other specific capital transactions will generally result in capital gains tax at the same rate. Corporate tax losses can generally be carried forward indefinitely to offset future tax liabilities provided certain tests are met (although capital losses can only be offset against capital gains).

Australian tax law provides specific tax concessions for the mining industry, which includes petroleum production. Exploration expenditure is generally deductible in the income year in which it is incurred.

The federal government has also proposed providing a refundable tax offset for exploration costs from July 1, 2011. Environmental protection and site rehabilitation expenditure is also immediately deductible. Certain types of capital expenditures, including the cost of plant and equipment and mining and prospecting rights, can be written off progressively over the useful lives of the applicable assets.

In Australia, the payment of dividends by a wholly-owned subsidiary to its non-resident shareholders may be subject to the deduction of withholding tax at the rate of 15% (where a double taxation agreement applies). However, subject to certain specific exclusions, the repatriation of profits by way of dividends from Chelsea Oil Australia Pty Ltd. to Chelsea will not be subject to the deduction of Australian withholding tax, if and to the extent that those dividends are “franked” by Chelsea Oil Australia Pty Ltd. (a “franked” dividend is effectively a dividend paid from taxed profits). In the event that Chelsea Oil Australia Pty Ltd. distributes “unfranked dividends” (an “unfranked dividend” is effectively a dividend paid from untaxed profits), the unfranked dividends that Chelsea receives will be subject to deduction of Australian withholding tax at the rate of 15%. However, the Australian withholding taxes paid by Chelsea from receiving “unfranked dividends” should result in a foreign tax credit for Chelsea, which is a deduction from Canadian tax otherwise payable by Chelsea. This credit must be calculated on a country-by-country basis and in general terms is limited to the lesser of the income and profits tax paid to the particular foreign country and the Canadian tax otherwise payable for the year on income from sources within that particular country.

Payments of interest and royalties to Chelsea from Chelsea Oil Australia Pty Ltd. will be subject to Australian withholding tax at the rate of 10%.

All dividend, interest and royalty income earned by Chelsea will be subject to the applicable federal and provincial tax laws in Canada.

Australia’s GST, a value-added tax, is imposed at the rate of 10% on the value of domestic supplies of goods or services made or provided by an Australian business. An Australian business that acquires goods or services in carrying on the business will generally be entitled to a credit for any GST included in the cost of the goods or services acquired.

In the course of carrying on its operations, an Australian business may also become liable to various state and territory taxes including payroll tax (levied on salaries of, and other benefits paid to, employees), land tax (levied on land holdings), and stamp duty (levied on certain types of transactions and agreements). The rates of such taxes vary between the states and territories.

Additionally, the government of Australia has implemented a carbon tax regime which may impact the cost of the Corporation’s operations.

To explore for petroleum (oil, coal seam gas, natural gas, etc.) in Queensland, an adult, or a company or registered body under the Corporations Act 2001 (Cwlth), must have been granted an ATP by the Minister for Natural Resources and Mines.

The maximum area that can be published in a call for tenders, for a single ATP, is 100 blocks. Each block is approximately 67 km² or 6,700 hectares or 16,556 acres in area. If and when an ATP is granted to the successful tenderer, it may be for a period of up to a maximum of 12 years. If the period of grant for the ATP is less than 12 years, the holder of the ATP may apply to the Minister to renew the ATP. The renewal period cannot be greater than the period of the initial grant, nor can the ATP continue for longer than 12 years from its initial grant (although, the exception is declared potential commercial areas within ATPs).

Periodic relinquishment requirements must also be made. See sections 42 and 65 of the Petroleum and Gas (Production and Safety) Act 2004. The relinquishment date/s will be notified to the holder at the grant of the ATP. A relinquishment of the area of the ATP is required at least every 4 years during the term of the ATP. Relinquishments are calculated as 8.33% of the area initially granted for the ATP on a yearly basis. Consequently, in most cases, a relinquishment of 33% of the area initially granted for the ATP will be required every 4 years of the term of the ATP. Relinquishments must occur in whole blocks.

If a discovery is made on an ATP, an application can be made for a PL. A PL gives its holder the right to explore for, test for production, and produce petroleum within the area of the PL. The maximum area that may be granted for a PL is 75 sub-blocks. The maximum term that a PL may be granted is 30 years. An application for the Minister to grant a PL must be accompanied by a proposed “initial development plan”.

A proposed “initial development plan” gives detailed information about the nature and extent of activities proposed to be carried out under the PL. Generally, a proposed initial development plan will cover a five year period of activities proposed for the PL.

At the end of the five year period of the initial development plan, or if there is a significant change to an activity provided for under the current development plan, the holder of the PL must lodge a proposed “later development plan”.

The proposed “later development plan” gives detailed information about the nature and extent of activities proposed to be carried out under the PL, and highlights any significant change (and reasons for the change) from activities provided for under the previously approved development plan. Generally a proposed later development plan will cover a five year period.

In 2010, the federal government of Australia announced plans to introduce a “petroleum rent resource tax” (“PRRT”) effective from July 1, 2012 at a rate of 40% on assessable profits made from the exploitation of Australia’s non-renewable resources.

In principle, the PRRT is intended to only be payable on resource extraction activities. Costs of extracting resources and getting them to the taxing point will therefore be deductible for the purposes of the PRRT (although payments of interest or financing costs will not be considered deductible for the purposes of the PRRT). Where losses arise from project costs being greater than project receipts in a given year, the PRRT value of those losses can be carried forward and offset against future profits, or refunded by the government should the project close (e.g. exploration is unsuccessful). Profits made from existing as well as future resources projects will be subject to the PRRT.

The PRRT is expected to operate in parallel with the state and territory royalty regimes by providing a refundable credit to resource entities for state and territory royalties paid to state and territory governments. This is intended to ensure that there is no “double taxation” of profits. Resource entities will continue to be subject to income tax on their exploration and production activities, although PRRT payments will be deductible, and PRRT refunds will be assessable for income tax purposes.

Native title in Australia refers to the various rights the indigenous people of Australia may have in relation to land or waters by virtue of their continuous traditional use of those land or waters since the time of European settlement. The Native Title Act regulates native title in Australia by recognizing that native title may have been extinguished over certain forms of land interests (such as freehold) and setting up a process to deal with land that has not been subject to extinguishment. The act sets out the method by which native title claims may be determined and affording various indigenous groups with procedural rights in respect of land where they hold a registered native title claim. Under the Native Title Act, for any petroleum title to be granted or renewed after December 23, 1996 within an area the subject of a registered native title claim entitles that indigenous group to a “right to negotiate” procedure under the Native Title Act prior to any such grant or renewal. Unless this procedure is complied with, petroleum titles will not be granted over land or waters the subject of the registered native title claim until the “right to negotiate procedure” has been complied with. Once that procedure has been complied with the petroleum title can be granted.

The Native Title Act gives, in many circumstances, a title equivalent to freehold to the native title claimants or holders in respect of certain lands in Queensland and provide for a procedure to follow prior to a grant of a petroleum title in respect of those lands which mirrors in some respects the rights to negotiate under the Native Title Act. In most cases, aboriginal freehold title gives rise to absolute control over the access of non-aboriginals to those lands which are the subject of aboriginal freehold title, as opposed to native title (which commonly gives rise to rights to use land for concurrent purposes such as camping and hunting in areas where there is petroleum exploration and production).

Under the “right to negotiate” procedure, the relevant government must give notice to relevant registered native title claimant and the public before granting or renewing a petroleum tenement. Unless the “expedited procedure” applies to the act in question, the government is also required to give that registered native title claimant the opportunity to make submissions about the proposed grant or renewal. The government, the applicant for the petroleum tenement and the registered native title claimant are then required to negotiate in good faith with a view to reaching an agreement that the proposed act can be done and, if so, on what conditions. The parties have a period of six months in which to negotiate after notice is provided. If an agreement cannot be reached, any party can apply to the Australian National Native Title Tribunal, as the arbitral body, for a determination. The tribunal may determine that the act must not be done, or may be done, or may be done with conditions. See “Risk Factors - Native Title”.

Indigenous land access agreements have been entered into, which agreements are entered into in accordance with the Native Title Act and include indigenous land use agreements which set out procedures for access with respect to petroleum exploration operations, aboriginal heritage protection and production.

As a result of the entering into of the indigenous land access agreements, the “right to negotiate” procedure under the Native Title Act has been completed within respect to ATP 582

The management of Aboriginal heritage within the Northern Territory is governed by the Queensland Aboriginal Cultural Heritage Act 2003 (the “Heritage Act”) and the Aboriginal and Torres Strait Islander Heritage Protection Act 1984 (Cwth) which also applies throughout Australia. The aboriginal heritage legislation protects ethnographic and archaeological (cultural and historic) sites and objects of Aboriginal importance and significance whether they are currently known or not. Under those Acts, any person planning to undertake activities in respect of an area must ensure that they do not damage, disturb or interfere with any Aboriginal sites, objects or remains within that area in carrying out those activities, otherwise that person commits an offence.

However, consent under the Heritage Act may be obtained to undertake certain activities, which would otherwise may constitute an offence. Any proposed work to be carried out, which will disturb aboriginal sites or objects, may be subject to work program conditions which may accompany any such consent. There are detailed procedures set forth in the Indigenous land access agreements that deal with the protocols to assess and manage aboriginal heritage and aboriginal heritage protection issues.

The Aboriginal and Torres Strait Islander Heritage Protection Act 1984 (Cwth) allows the relevant Minister administering the Act to make declarations (including emergency declarations) to preserve land areas and objects of significance to aboriginal people within the Commonwealth of Australia. Declarations may be made when such land areas or objects are under threat of injury or desecration and have the effect of subjecting that land to certain protectionist measures under the Act. In principle, the land that is the subject to Chelsea’s activities might be exposed to such a declaration if its operations constituted a threat to any Aboriginal sites or objects.

In relation to each of Chelsea’s ATPs, PELs and PLs, the aboriginal heritage protocols contained in the applicable indigenous land access agreements have been complied with and numerous heritage surveys have been carried out to determine which areas are to be avoided to protect aboriginal heritage during exploration operations.

The Australian government encourages foreign investment in Australian businesses, provided that the proposed investment is consistent with the national interest. The government has regard to Australian community concern in determining whether a proposal is contrary to the national interest. Consequently, under the Foreign Acquisitions and Takeovers Act 1975 (Cwth) and Foreign Investment Policy, the Australian government can require foreign persons (including corporations) to notify it of proposed acquisitions of shares of a value which exceed prescribed monetary thresholds, acquisitions of certain land or real estate, irrespective of the value and direct investments by foreign governments or their agencies, irrespective of the value of those investments.

The federal Treasurer also has powers with respect to acquisitions in offshore non-Australian entities which hold Australian assets, assets of Australian businesses, and arrangements or understandings in respect to the direction or policy control of Australian organizations or business where the applicable thresholds are met. Where the Treasurer has power, in such circumstances, a foreign investor may voluntarily notify its proposal.

If the federal Treasurer considers that the proposed acquisition would be contrary to the national interest, it has the power to prohibit it. The federal Treasurer is advised by the Foreign Investment Review Board (“FIRB”).

Acquiring shares in a foreign corporation which has an Australian subsidiary (such as Chelsea) may activate the Treasurer’s powers and, in order to avoid an adverse order by the Treasurer, the foreign person may notify of the proposed acquisition and seek a statement of no objections (referred to generally as “FIRB approval”) to that proposal.

As at the date of this AIF, the value of Chelsea and its subsidiaries businesses or total assets do not exceed the monetary thresholds which could trigger the requirement for Australian government approval; and Chelsea’s and its subsidiaries’ interests in land that is not used wholly and exclusively for carrying on a business of primary production do not comprise more than 50% of the total assets of Chelsea and its subsidiaries, which could trigger the requirement for Australian government approval.

If Australian government approval is required for a particular person to acquire shares in Chelsea, the associated risks include: the Australian government orders that the proposed acquisition of shares be prohibited; the Australian government approves the acquisition of shares, but imposes conditions upon that approval which are onerous, prohibitive or uncommercial, having regard to the individual circumstances of the foreign person or corporation; the Australian government extends the time period for it to make its decision on whether or not to approve the acquisition, which may unduly delay the foreign person’s or corporation’s ability to purchase the shares.

Australia is a federation of states each of which has its own constitution, government and laws. The Commonwealth Constitution establishes the Commonwealth of Australia in which specified legislative power are vested in the Commonwealth government.

The Commonwealth constitution lists a range of powers and responsibilities of the federal Parliament. Powers not specified in this section are known as residual powers and remain with the states. This division of powers between the federal and state Parliaments means that the federal Parliament governs (although not always exclusively) international and interstate trade and taxation. Royalties and petroleum exploration are governed at the state level, but issues of native title associated with petroleum exploration are governed federally.

The Commonwealth Parliament of Australia is a bicameral parliament. Government is formed in the lower house, being the “House of Representatives” and has a term of approximately three years. The upper house or “Senate” is comprised of numbers of Senators from each of the States. Failure to control both houses of parliament means that the government of the day may not be able to implement its legislative proposals. The current government is a minority government that requires the support of three independent members of the House of Representatives to maintain the confidence of the House of Representatives.

There is a free market for oil, condensate and liquid petroleum gas in Australia. As a result there are no price controls and export or import approvals are not required. Markets for crude oil and condensate exist in Australia and low-sulphur light crude oil finds a ready domestic and overseas market.

Rights of access to gas transmission and reticulation pipelines have been provided by legislation with arbitration available if negotiations fail with the facility owner. All pipelines in the areas where Chelsea operates are privately owned.

Australia’s coal seam gas (“CSG”) unconventional play, located in the Surat-Bowen Basin less than 40 kilometers from Chelsea’s Surat Basin PL’s is in an active development stage. Australia’s identified CSG reserves have grown substantially in recent years. As at January 2012, GeoScience Australia, a branch of the Australian Federal Government estimated economic demonstrated resources of CSG in Australia were 35,905 PJ (33 Tcf). CSG Reserve life was estimated to be 150 years at current rates of production, however noting that production is projected to substantially increase with the continued development of the CSG industry.

All the major international service companies are involved in supporting the Queensland CSG programs. These companies are able to support complex evaluation and completion programs and have extensive fracture stimulation crews that routinely conduct stimulation programs in the CSG wells.

The Cooper Basin is Australia’s largest, and best serviced conventional onshore basin. In the past two years, companies have started to explore unconventional reservoirs in the Cooper Basin utilizing fracture stimulation programmes similar to those used in North America, and similar to those which Chelsea intends to deploy in the Georgina Basin. The Cooper Basin is approximately 300 kilometers from Chelsea’s ATP 582 and it is anticipated that the continued development of the Cooper Basin will result in drilling and fracture stimulation crews being increasingly available in Central Australia.

Chelsea supplements its management capabilities by contracting local Australian engineers to assist with Chelsea’s drilling program. These local engineers have worked for some of Australia’s largest oil and natural gas companies in similar capacities as they will be utilized by Chelsea. These consultants are able to provide senior management staff with local knowledge, contacts and experience in the Surat and Southern Georgina Basin and similar onshore basins and have extensive knowledge of the local competencies of all the service companies.

Oil and gas exploration is intensely competitive in all phases and involves a high degree of risk. Chelsea competes with numerous other participants in the search for, and the acquisition of, oil and natural gas properties. Chelsea’s competitors include oil and natural gas companies that have substantially greater financial resources, staff and facilities than those of Chelsea. Chelsea is insulated from competition on the lands which it currently holds due to the nature of the proprietary exploration rights granted by the governing bodies under the permits. However, Chelsea may experience competition on surrounding lands if it looks to increase its land position to acquire other prospective leads. Chelsea may also experience competition for lands for which it currently holds rights in the event that, as a condition of the rights, it is required to partially relinquish a certain percent of the lands. In this circumstance, if Chelsea elects to apply for new permits on the relinquished lands, there are no assurances that Chelsea would be successful. Chelsea’s ability to add reserves in the future will depend not only on its ability to explore and develop its present properties, but also on its ability to select and acquire suitable producing properties or prospects for exploratory drilling. Competitive factors in the distribution and marketing of oil and natural gas include price and methods and reliability of delivery. Competition may also be presented by alternate fuel sources. See “Risk Factors – Competition”.

The Corporation’s business is generally cyclical. The exploration and development of oil and natural gas reserves is dependent on access to areas where drilling is to be conducted. Seasonal weather variation, affect access in certain circumstances; however, access to Chelsea’s properties is generally year-round or near year-round.

The health and safety of employees, contractors and the public, as well as the protection of the environment, is of utmost importance to the Corporation. The Corporation endeavours to conduct its operations through the utilization of professionals and experienced qualified contractors and consultants in a manner that will minimize both adverse effects and consequences of emergency situations by:

The Corporation believes that all personnel have a vital role in achieving excellence in environmental, health and safety performance. This is best achieved through careful planning and the support and active participation of everyone involved. Chelsea aligns itself with the best industry practices to ensure positive results.

As of the date hereof, Chelsea has 2 full-time employees, 2 part-time employees and 6 part-time consultants.

The business of Chelsea is subject to risks encountered in the oil and gas industry. The risks and uncertainties below are not the only issues facing Chelsea. Additional risks and uncertainties not presently known to Chelsea or that Chelsea currently considers immaterial may also impair the business and operations of Chelsea and cause the price of the Chelsea Common Shares to decline. If any of the following risks actually occur, Chelsea’s business may be harmed and the financial condition and results of operations may suffer significantly.

Oil and natural gas operations involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome. The long-term commercial success of Chelsea depends on its ability to find, acquire, develop and commercially produce oil and natural gas reserves. The future value of Chelsea is therefore dependent on the success of Chelsea’s activities, which are principally directed toward the exploration, appraisal and development of its properties in Australia. Exploration, appraisal and development of oil and natural gas properties is highly speculative and involves a significant degree of risk. Without the continual addition of new reserves, any existing reserves that Chelsea may discover or acquire at any particular time and the production therefrom will decline over time as such existing reserves are exploited. Any discovery of or future increase in Chelsea’s reserves will depend not only on its ability to explore and develop any properties it may have from time to time, but also on its ability to select and acquire suitable producing properties or prospects. No assurance can be given that Chelsea will be able to continue to locate satisfactory properties for acquisition or participation. Moreover, if such acquisitions or participations are identified, Chelsea may determine that current markets, terms of acquisition and participation or pricing conditions make such acquisitions or participations uneconomical. There is no assurance that commercial quantities of oil and natural gas will be discovered or acquired by Chelsea.

Oil and natural gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, fixing drilling hazards or environmental damage caused by operations could greatly increase the cost of those operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental and other approvals or consents, insufficient storage or transportation capacity or other geological and mechanical conditions. While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees.

Chelsea will have limited financial resources and limited cash flow from operations, and therefore will likely require additional financing in order to carry out its oil and natural gas exploration, acquisition and development activities. There can be no assurance that additional funding will be available, or available under terms favourable to Chelsea. Failure to obtain such financing on a timely basis could cause Chelsea to have limited ability to expend the capital necessary to undertake or complete future drilling programs, forfeit its interest in certain properties, miss certain acquisition opportunities and reduce or terminate its operations. There can be no assurance that debt or equity financing or cash generated by operations will be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable to Chelsea. Moreover, future activities may require Chelsea to alter its capitalization significantly. Financing by issuing additional securities from the Chelsea’s treasury may result in a change of control of Chelsea and dilution to holders of Chelsea Shares.

Chelsea has historically incurred losses from operations. There can be no assurance that Chelsea will achieve profitability in the future. In addition, should Chelsea be unable to continue as a going concern, realization of assets and settlement of liabilities other than in the normal course of business may be at amounts significantly different from those in the financial statements.

Revenues may not occur for some time, if at all. The timing and extent of these is variable and uncertain and accordingly the Corporation is unable to predict when, if at all, profitability will be achieved. An investment in the Common Shares is highly speculative and should only be made by persons who can afford a significant or total loss of their investment.

Chelsea’s future revenue, profitability, growth and the carrying value of its oil and natural gas properties will be substantially dependent on prevailing prices of oil and natural gas. Chelsea’s ability to borrow and to obtain additional capital on attractive terms will also be substantially dependent upon oil and natural gas prices. Prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors beyond the control of Chelsea. These factors include economic conditions in Australia and elsewhere in the world, the actions of the Organization of the Petroleum Exporting Countries (OPEC), governmental regulation, political stability in the Middle East and elsewhere, the foreign supply of oil and natural gas, the price of foreign imports and the availability of alternative fuel sources. Any substantial and extended decline in the price of oil and natural gas could have an adverse effect in the future on Chelsea’s carrying value of its proved reserves, borrowing capacity, revenues, profitability and cash flows from operations, as applicable. There can be no assurance that recent commodity prices will be sustained if and when Chelsea commences production or over the life of the Chelsea’s operations. There is risk that commodity prices may decline in the future, although it is not possible to predict the time or extent of such decline.

Chelsea’s business plan requires significant expenditure, particularly capital expenditure, in its oil and gas exploration phase. Any future profitability from Chelsea’s business will be dependent upon the successful exploration and development of its petroleum properties, and there can be no assurance that Chelsea will achieve profitability in the future. Revenues may not occur for some time, if at all. The timing and extent of these is variable and uncertain and accordingly Chelsea is unable to predict when, if at all, profitability will be achieved.

It may not always be possible for Chelsea to execute its exploration and development strategies in the manner in which Chelsea considers optimal. Chelsea’s exploration and development programs in onshore Australia involve the need to obtain approvals from the relevant authorities, which may require conditions to be satisfied or the exercise of discretion by the relevant authorities. It may not be possible for such conditions to be satisfied.

The proposed management and directors of Chelsea have significant international experience in the oil and gas industry; however, given the fact that Chelsea was incorporated recently, the team has, as a group, limited direct experience operating in onshore Australia, aside from its consultants and advisors.

Acquisitions of oil and natural gas issuers and oil and natural gas assets are typically based on engineering and economic assessments made by independent engineers and Chelsea’s own assessments. These assessments will include a series of assumptions regarding such factors as recoverability and marketability of oil and natural gas, future prices of oil and natural gas and operating costs, future capital expenditures and royalties and other government levies which will be imposed over the producing life of the reserves. Many of these factors are subject to change and are beyond Chelsea’s control. In particular, the prices of, and markets for, oil and natural gas products may change from those anticipated at the time of making such assessment. In addition, all such assessments involve a measure of geologic and engineering uncertainty which could result in lower production and reserves than anticipated. Initial assessments of acquisitions may be based on reports by a firm of independent engineers that are not the same as the firm that Chelsea may use for its year-end reserve evaluations. Because each of these firms may have different evaluation methods and approaches, these initial assessments may differ significantly from the assessments of the firm used by Chelsea. Any such instance may offset the return on and value of the securities of Chelsea.

Oil and natural gas exploration and development activities are dependent on the availability of drilling and related equipment in the particular areas where such activities will be conducted. Demand for such limited equipment or access restrictions may affect the availability of such equipment to Chelsea and may delay exploration and development activities. Recent industry conditions have led to shortages of drilling equipment in certain areas. To the extent that Chelsea is not the operator of its oil and gas properties, Chelsea will be dependent on such operators for the timing of activities related to such properties and will be largely unable to direct or control the activities of the operators.

The inability of Chelsea to generate positive operating cash inflow in the future could have a material adverse impact on Chelsea’s business, financial condition, results of operations and prospects.

Chelsea will manage a variety of projects in the conduct of its business. Project delays may delay expected revenues from operations. Significant project cost over runs could make a project uneconomic. Chelsea’s ability to execute projects and market oil and natural gas depends upon numerous factors beyond Chelsea’s control, including:

Because of these factors, Chelsea could be unable to execute projects on time, on budget or at all.

Chelsea’s ability to market production from any potential oil and natural gas discoveries may depend on its ability to secure transportation. Chelsea may also be affected by deliverability uncertainties related to the proximity of its potential production to pipelines and processing facilities and operational problems affecting such pipelines and facilities.

In addition to the usual delays in payments by purchasers of oil and natural gas to Chelsea or to the operators, and the delays by operators in remitting payment to Chelsea, payments between these parties may be delayed due to restrictions imposed by lenders, accounting delays, delays in the sale or delivery of products, delays in the connection of wells to a gathering system, adjustment for prior periods, or recovery by the operator of expenses incurred in the operation of the properties. Any of these delays could reduce the amount of cash flow available for the business of Chelsea in a given period and expose Chelsea to additional third party credit risks.

From time to time, Chelsea may enter into agreements to receive fixed prices on any future oil and natural gas production to offset the risk of revenue losses if commodity prices decline; however, if commodity prices increase beyond the levels set in such agreements, Chelsea would not benefit from such increases. Similarly, from time to time, Chelsea may enter into agreements to fix the exchange rate of various currencies used in its business in order to offset the risk of revenue or cost related losses in the event of currency fluctuations. There is no certainty that any such currency hedges which may be entered into will benefit Chelsea.

Chelsea’s properties are and will continue to be held in the form of permits, applications, authorities and Working Interests in permits, applications and authorities. If Chelsea or the holder of the permits, applications and authorities fails to meet the specific requirement of the permits, applications or authorities (including any requirements as to their renewal where renewal is available), the permits, applications or authorities may terminate or expire. There can be no assurance that the obligations required to maintain each of the permits, applications and authorities will be met. The termination or expiration of Chelsea’s permits, applications and authorities or the Working Interests relating to the permits, applications and authorities could have a material adverse effect on Chelsea’s business, financial condition, results of operations and prospects.

In the future other companies may operate some of the assets in which Chelsea has an interest. As a result, Chelsea may have limited ability to exercise influence over the operation of such assets or their associated costs, which could have a material adverse effect on Chelsea’s business, financial condition, results of operations and prospects. Therefore, Chelsea’s return on the assets operated by others will depend upon a number of factors that may be outside of Chelsea’s control, including the timing and amount of capital expenditures, the operator’s expertise and financial resources, the approval of other participants, the selection of technology and risk management practices.

The marketability and price of oil and natural gas that may be discovered or acquired by Chelsea will be affected by numerous factors beyond its control. Chelsea’s ability to market oil and natural gas in the future, may depend upon its ability to acquire space on pipelines that deliver natural gas to commercial markets including availability of processing and refining facilities and transportation infrastructure, including access to facilities, pipelines and pipeline capacity and economic tariff rates over which Chelsea may have limited or no control. Chelsea may also be affected by deliverability uncertainties related to the proximity of its reserves to pipelines and processing facilities, and related to operational and maintenance problems with such pipelines and facilities as well as extensive government regulation relating to price, taxes, royalties, land tenure, allowable production, the export of oil and natural gas and many other aspects of the oil and natural gas business. Any delay or failure to acquire access to, or improper operation or maintenance of, such pipelines and facilities could have a material adverse effect on Chelsea’s business, financial condition, results of operations and prospects.

Oil and gas exploration is intensely competitive in all phases and involves a high degree of risk. Chelsea competes with numerous other participants in the search for, and the acquisition of, oil and natural gas properties. Chelsea’s competitors include oil and natural gas companies that have substantially greater financial resources, staff and facilities than those of Chelsea. Currently Chelsea is insulated from competition on the lands which it currently holds due to the nature of the proprietary exploration rights granted by the governing bodies under the various licenses and permits, however Chelsea may face competition on surrounding lands if it seeks to increase its land position to acquire other prospective properties. Chelsea may also face competition from competitors on lands which it currently holds a license or permit for in the event that, as a condition of the license or permit, it is required to partially relinquish certain of the lands. In this circumstance, if Chelsea elects to re-apply for such permits or licenses, there are no assurances that Chelsea will be successful. Chelsea’s ability to add reserves in the future will depend not only on its ability to explore and develop its present properties, but also on its ability to select and acquire suitable producing properties or prospects for exploratory drilling. Competitive factors in the distribution and marketing of oil and natural gas include price and methods and reliability of delivery. Competition may also be presented by alternate fuel sources.

Chelsea’s success will depend in large measure on the performance of its management and other key personnel. The loss of the services of any of such persons could have a material adverse affect on the Chelsea’s business, financial condition, results of operations and prospects. Chelsea does not have key person insurance in effect for management. The contributions of these individuals to the immediate operations of Chelsea are likely to be of central importance. In addition, the competition for qualified personnel in the oil and natural gas industry is intense and there can be no assurance that Chelsea will be able to continue to attract and retain all personnel necessary for the development and operation of its business. Investors must rely upon the ability, expertise, judgment, discretion, integrity and good faith of the management of Chelsea.

The Corporation’s historical resource estimates, available in the Corporation’s disclosure documents filed on SEDAR and on EDGAR, have been classified as undiscovered petroleum initially in place and prospective resources. Any such resource estimates are estimates only. There is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. Readers are cautioned that the volumes presented are estimates only and should not be construed as being exact quantities. Chelsea’s proposed drilling and seismic program must be considered as a high risk exploration play.

There are numerous uncertainties inherent in an estimate of fair market value including many factors beyond the Corporation’s control. The valuations herein represent estimates only. In general, estimates are based upon a number of variable factors and assumptions, such as engineering and geophysical information pertaining to hydrocarbon potential, current material contracts of the Corporation, production history of competitors on similar land positions, access to lands, availability, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies, and future operating costs, all of which may vary from actual results. All such estimates are to some degree speculative, and are only attempts to define the degree of speculation involved.

Chelsea is or may be exposed to third party credit risk through its contractual arrangements with its current or future joint venture partners, marketers of its petroleum and natural gas production and other parties. In the event such entities fail to meet their contractual obligations to Chelsea, such failures could have a material adverse effect on Chelsea’s business, financial condition, results of operations and prospects.

Chelsea may be subject to growth-related risks including capacity constraints and pressure on its internal systems and controls. The ability of Chelsea to manage growth effectively will require it to continue to implement and improve its operational and financial systems and to expand, train and manage its employee base. The inability of Chelsea to deal with this growth could have a material adverse effect on Chelsea’s business, financial condition, results of operations and prospects.

The trading price of securities of oil and natural gas companies is subject to substantial volatility, and such trading prices have been particularly volatile in recent months. This volatility is often based on factors both related and unrelated to the financial performance or prospects of the companies involved. The market price of the Common Shares could be subject to significant fluctuations in response to variations in Chelsea’s operating results, financial condition, liquidity and other internal factors. Factors that could affect the market price of the Common Shares that are unrelated to Chelsea’s performance include domestic and global commodity prices and market perceptions of the attractiveness of particular industries. The price at which the Common Shares will trade cannot be accurately predicted.

Oil and natural gas exploration, development and production operations are subject to all the risks and hazards typically associated with such operations, including hazards such as fire, explosion, blowouts, cratering, sour gas releases and spills, each of which could result in substantial damage to oil and natural gas wells, production facilities, other property and the environment or in personal injury. In accordance with industry practice, Chelsea is not fully insured against all of these risks, nor are all such risks insurable. Prior to drilling, Chelsea will obtain insurance in accordance with industry standards to address certain of these risks. However, such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. In addition, such risks may not be insurable in all circumstances or, in certain circumstances, Chelsea may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons. The payment of any such uninsured liabilities would reduce the funds available to Chelsea. The occurrence of a significant event that Chelsea is not fully insured against, or the insolvency of the insurer of such event, could have a material adverse effect on Chelsea’s business, financial condition, results of operations and prospects.

Chelsea has not paid any dividends on the Common Shares and it is not anticipated that Chelsea will pay any dividends on the Common Shares for the foreseeable future.

The directors or officers of Chelsea may also be directors or officers of other oil and gas companies or otherwise involved in natural resource exploration and development and situations may arise where they are in a conflict of interest with Chelsea. Conflicts of interest, if any, which arise will be subject to and governed by procedures prescribed by the ABCA which require a director or officer of a company who is a party to, or is a director or an officer of, or has some material interest in any person who is a party to, a material contract or proposed material contract with Chelsea to disclose his or her interest and, in the case of directors, to refrain from voting on any matter in respect of such contract unless otherwise permitted under the ABCA.

Title to oil and natural gas interests is often not capable of conclusive determination without incurring substantial expense. Although title reviews will be done according to industry standards prior to the purchase of most oil and natural gas producing properties or the commencement of drilling wells, such reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise to defeat the claim of Chelsea. To the extent title defects do exist, it is possible Chelsea may lose all or a portion of its right, title, estate and interest in and to the properties to which the title relates.

From time to time, Chelsea may enter into transactions to acquire assets or the shares of other corporations. These transactions may be financed partially or wholly with debt, which may increase Chelsea’s debt levels above industry standards. Depending on future exploration and development plans, Chelsea may require additional equity and/or debt financing that may not be available or, if available, may not be available on favourable terms. Neither Chelsea’s articles nor its by-laws limit the amount of indebtedness that Chelsea may incur. The level of Chelsea’s indebtedness from time to time could impair Chelsea’s ability to obtain additional financing in the future on a timely basis to take advantage of business opportunities that may arise. If Chelsea becomes unable to pay its debt service charges or otherwise commits an event of default, such as bankruptcy, lenders may foreclose on or sell Chelsea’s properties.

Many of the operational, capital and other expenses incurred by Chelsea are paid in Australian dollars or US dollars. If Chelsea achieves commercial production, the revenue from its products will likely be denominated in US dollars or Australian dollars. The assets and liabilities of Chelsea are recorded in Canadian dollars. As a result, fluctuations in the Australian dollars or the US dollars against the Canadian dollar could result in unanticipated and material fluctuations in the financial results of Chelsea. Chelsea does not currently use derivative instruments to hedge exposure to foreign exchange risks.

Chelsea may make future acquisitions or enter into financing or other transactions involving the issuance of securities of Chelsea which may be dilutive to existing securityholders.

Oil and natural gas operations (exploration, production, pricing, marketing and transportation) are subject to extensive controls and regulations imposed by various levels of government that may be amended from time to time. Chelsea’s operations require licenses and permits from various governmental authorities. There can be no assurance that Chelsea will be able to obtain all necessary licenses and permits that may be required to carry out exploration and development of its projects.

In Australia, while government policies and regulations in relation to exploration, production and marketing are similar in many respects, they ultimately vary between different states and between different governing bodies. Chelsea’s activities will require compliance with various laws, both state and those of the Commonwealth of Australia, relating to, among other things, the protection of the environment, Aboriginal cultural heritage, native title rights, the protection of workers and the public. Changes in government, government policies and legislation could have a material adverse effect on Chelsea’s business, financial condition, results of operations and prospects.

In particular, in order to pursue its exploration programs in Australia, Chelsea may require approval from government and non-government bodies to facilitate access to any blocks and tenements in which it has an interest. Any tenements residing within reserves, including national parks and conservation reserves, which are subject to state and Commonwealth legislation could be subject to a change in legislation that could have a material adverse effect on Chelsea’s business, financial condition, results of operations and prospects. In addition, any tenements residing in areas which are subject to government policies regarding national defence or of any other particular national interest to Australia may be subject to access requirements that could result in a material adverse effect on Chelsea if they are particularly onerous to Chelsea.

Chelsea’s licenses, permits and authorizations will be subject to applications for renewal in accordance with their terms. Where a licensee has not complied with the conditions to which an exploration permit is subject, or any directions given by the relevant Minister and the Minister is not satisfied that special circumstances exist that justify the granting of the renewal of the permit, the Minister may refuse to grant a renewal of a permit. Where a Minister is satisfied that a commercially exploitable accumulation of petroleum may occur in an exploration permit area, the Minister may require the licensee to apply for a production license or risk losing the exploration permit. A Minister may also refuse to grant a production license, or may grant a production license subject to such conditions as the Minister sees fit but which are unfavourable or particularly onerous to Chelsea. If a permit is not renewed or a production license is not granted or granted subject to unfavourable conditions, Chelsea may suffer significant damage through loss of the opportunity to develop and discover that tenement and this could have an adverse effect on Chelsea’s business plan.

Rights to licenses, permits and authorities held by Chelsea carry with them various obligations in regard to minimum expenditure levels, work commitments and responsibilities in respect of the environment and safety generally. Failure to observe such requirements could prejudice the right to maintain title to a given area.

All phases of the oil and natural gas business present potential environmental risks and hazards and are therefore subject to environmental regulation pursuant to a variety of federal, state and local laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and natural gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and the potential for increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require Chelsea to incur costs to remedy such discharge. Generally, Australian state and territory legislation and associated regulations include provisions for the regulation of activities on petroleum tenement lands. Statutory provisions require petroleum tenement lands to be protected and rehabilitated to ensure that environmental damage is avoidable or minimal where authorized. These provisions may require approvals and consents to be obtained before certain lands may be accessed and explored. In addition, each state and territory government may impose a wide range of obligations on tenement holders to ensure that petroleum operations comply with various environmental standards and requirements.

No assurance can be given that environmental laws will not result in a curtailment of future production (if any) or a material increase in the costs of production, development or exploration activities or otherwise adversely affect the Corporation’s financial condition, results of operations or prospects.

The return on an investment in securities of Chelsea is subject to changes in Canadian and Australian tax laws and government incentive programs and there can be no assurance that such laws or programs will not be changed in a manner that adversely affects Chelsea or the holding and disposing of the securities of Chelsea. Legislation, regulations and policies continue to be introduced by government and government agencies concerning the security of industrial facilities, including oil and natural gas facilities. Chelsea’s operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs Chelsea could incur to comply with any such laws or regulations, but such expenditures could be substantial.

Chelsea, and all of its subsidiaries will file all required income tax returns and believes that it will be in full compliance with the provisions of the Income Tax Act (Canada), United States taxation laws and Australian taxation laws and all other applicable tax legislation. However, such returns are subject to reassessment by applicable taxation authorities. In the event of a successful reassessment of Chelsea, or its subsidiaries, as the case may be, whether by re- characterization of exploration and development expenditures or otherwise, such reassessment may have an impact on current and future taxes payable. In Australia, Chelsea Oil Australia pty will file any annual income tax returns required pursuant to the Australian taxation laws. It will be assessed while in exploration and production phases of its operation. While in exploration it will be assessed as having no or negative income and will be able to retain a credit towards future income in the event that it has an income from production in the future. In other words, losses for the Australian subsidiaries will be able to be set-off against future profits. The Corporation’s subsidiaries will still be required to file annual income tax returns.

Australia is a signatory to the United Nations Framework Convention on Climate Change and has ratified the Kyoto Protocol established thereunder to set legally binding targets to reduce nationwide emissions of carbon dioxide, methane, nitrous oxide and other so called “greenhouse gases”. Subsequently, representatives from approximately 170 countries met in Copenhagen, Denmark to attempt to negotiate a successor to the Kyoto Protocol. The result of such meeting was the Copenhagen Accord, a non-binding political consensus rather than a binding international treaty such as the Kyoto Protocol.

Chelsea’s exploration and production facilities and other operations and activities emit greenhouse gases and Chelsea may therefore be required to comply with various laws under the jurisdiction in which its activities are being carried out. For example, for its Australian activities, it will be required to report its greenhouse gas emissions to the Australian government where those emissions exceed the thresholds prescribed under the

National Greenhouse and Energy Reporting Act 2007 (Cwth). In addition, the Australian Energy Efficiency Opportunities Act 2006 (Cwth) requires persons using more than certain amounts of energy per year to identify and implement opportunities for energy efficiency and to publicly report the results of those measures. Additionally, the Australian government is implementing a national greenhouse emissions cap and an associated national greenhouse emissions trading scheme. Under such a scheme, companies may face potentially significant costs to pay for the greenhouse emissions associated with their operations and activities, as well as face significant increases in energy costs generally. See “Industry Overview”.

The direct or indirect costs of these laws and regulations could have a material adverse effect on Chelsea’s business, financial condition, results of operations and prospects. The future implementation or modification of greenhouse gases regulations, whether to meet the limits required by the Kyoto Protocol, the Copenhagen Accord or as otherwise determined, could have a material impact on the nature of oil and natural gas operations, including those of Chelsea. Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not possible to predict the impact on Chelsea and its operations and financial condition.

The marketability and price of oil and natural gas that may be acquired or discovered by Chelsea is and will continue to be affected by political events throughout the world that cause disruptions in the supply of oil. Conflicts, or conversely peaceful developments, arising in the Middle East, and other areas of the world, have a significant impact on the price of oil and natural gas. Any particular event could result in a material decline in prices and therefore result in a reduction of Chelsea’s net production revenue (if any).

In addition, Chelsea’s properties and facilities could be subject to a terrorist attack. If any of Chelsea’s properties, wells or facilities are the subject of terrorist attack it could have a material adverse effect on Chelsea’s business, financial condition, results of operations and prospects. Chelsea will not have insurance to protect against the risk from terrorism.

The requirement to comply with the procedures provided for under the Native Title Act where native title has not been extinguished is likely to be affected by exploration or production activities have the potential to significantly delay the grant of petroleum tenements in Australian jurisdictions. To the extent such requirements delay or restrict the granting of any petroleum tenements to Chelsea, or petroleum tenements are not granted to Chelsea, it could have a material adverse effect on Chelsea. Indigenous Land Access Agreements with the relevant aboriginal have been entered into and therefore, at present there are no further negotiations currently required under the Native Title Act.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, and technological advances in fuel economy and energy generation devices could reduce the demand for crude oil and other liquid hydrocarbons. The Corporation cannot predict the impact of changing demand for oil and natural gas products, and any major changes may have a material adverse effect on the Corporation’s business, financial condition, results of operations and cash flows and therefore on the dividends declared on the Common Shares.

Numerous statements containing forward-looking information are found in this AIF, documents incorporated by reference herein and other documents forming part of the Corporation’s public disclosure record. Such statements and information are subject to risks and uncertainties and involve certain assumptions, some, but not all, of which are discussed elsewhere in this document. The occurrence or non-occurrence, as the case may be, of any of the events described in such risks could cause actual results to differ materially from those expressed in the forward-looking information.

There are circumstances in which the acquisition of shares by a foreign person or corporation in a foreign corporation which has an Australian subsidiary (such as Chelsea) may activate the Australian Treasurer’s powers and, in order to avoid an adverse order by the Australian Treasurer, require the foreign person or company to provide prior notification of the proposed acquisition and seek a statement of no objections in respect of that proposal. In such case, the associated risks include the Australian Treasurer objecting to the acquisition, the Australian Treasurer imposing conditions on a statement of no objection which are onerous, prohibitive or uncommercial, having regard to the individual circumstances of the foreign person or company and the time period for assessing the acquisition being extended and unduly delaying the foreign person’s or company’s ability to purchase the shares.

The procedures and regulatory powers set forth in applicable laws relating to the protection of Aboriginal cultural heritage in Australia may delay, limit or prevent oil and gas exploration activities in Australia. Such procedures and powers, to the extent they affect Chelsea, could have an adverse effect on Chelsea’s business, financial condition, results of operations and prospects.

Chelsea also faces a number of risk factors that are outside of its control, generally, including, without limitation, terrorist activities, natural disasters, general economic and other conditions.

The Corporation has not paid any dividends on its Common Shares. It is the present intention of the board of directors of the Corporation to retain any earnings to finance the growth and development of the Corporation’s business and therefore the Corporation does not anticipate paying any dividends in the immediate or foreseeable future.

Chelsea is authorized to issue an unlimited number of Common Shares. The holders of Common Shares are entitled to dividends if, as and when declared by the directors, to one vote per share at meetings of the shareholders of Chelsea and, upon liquidation, to receive such assets of Chelsea as are distributable to the holders of the Common Shares.

Chelsea is also authorized to issue an unlimited number of preferred shares without nominal or par value, of which, as at the date hereof, none have been issued. The preferred shares of Chelsea may be issued in one or more series and the directors are authorized to fix the number of shares in each series and to determine the designation, rights, privileges, restrictions and conditions attached to the shares of each series. The preferred shares of Chelsea rank on a parity with the preferred shares of every other series and are entitled to a priority over the Common Shares, and any other class of shares ranking junior to the preferred shares of Chelsea with respect to the payment of dividends and the distribution of assets upon the liquidation of Chelsea.

The principal trading market for the common equity securities of the Corporation is the National Association of Securities Dealers OTC Bulletin Board (the “OTCQB”) quotation system. The symbol is: COGLF. The following are the highs and lows for each month for fiscal year ended December 31, 2015. These quotations reflect inter-dealer prices, without retail mark-up, mark- down or commissions, and may not represent actual transactions.

	Price Range ($)
	High	Low	Trading Volume
2015
January	0.10	0.05	79,255
February	0.10	0.04	202,743
March	0.09	0.04	341,323
April	0.11	0.05	259,993
May	0.10	0.04	321,602
June	0.10	0.04	549,943
July	0.08	0.05	649,634
August	0.10	0.04	426,901
September	0.09	0.04	229,569
October	0.08	0.02	314,357
November	0.05	0.02	191,520
December	0.05	0.01	779,082

The following table sets out the names and municipalities of residence of the directors and executive officers of the Corporation, their present position(s) and offices with the Corporation, their principal occupations during the last five years and their holdings of Common Shares as at the date hereof.

The term of office of the directors expires annually at the time of the Corporation’s annual shareholder meeting or when or until their successor is duly appointed or elected. The term of office of the Corporation’s executive officers expires at the discretion of the Corporation’s directors. As of the date of this AIF, the Corporation’s directors and executive officers, including the directors and officers of the Corporation’s subsidiaries, as a group beneficially own, directly or indirectly, or exercise control or direction over, an aggregate of 14,171,400 of the issued and outstanding Common Shares representing 22.1% of the outstanding Common Shares. Refer to Appendix A – Audit Committee Charter for additional information.

To the knowledge of the Corporation, other than as disclosed below, no director or executive officer is, as of the date of this AIF, or was within 10 years prior to the date of this AIF, a director, chief executive officer or chief financial officer of any company (including the Corporation) that: (i) was subject to a cease trade order, an order similar to a cease trade order or an order that denied the Corporation access to any exemption under securities legislation and which order was in effect for a period of more than 30 consecutive days while he was acting in the capacity as director, chief executive officer or chief financial officer of such company; or (ii) was subject to any of the foregoing orders for a period of more than 30 consecutive days after he ceased to be a director, chief executive officer or chief financial officer of such company and which resulted from an event that occurred while he was acting in such capacity.

William Petrie Sr. and Jesse Meidl were each directors of Birch Lake Energy Inc (“Birch Lake”), which was subject to cease trade orders in the province of Alberta for failure to file financial statements for the financial year ended December 30, 2014 and subsequent periods. The Toronto Stock Exchange (“TSX”) delisted Birch Lake’s common shares for failure to meet the continue disclosure obligations of the TSX on April 5, 2015.

A cease trade order was issued by the BCSC under Section 164 of the Securities Act (British Columbia) against ITME on February 18, 1999 for failure to file certain continuous disclosure documents. Upon completion of the Arrangement, such cease trade order applies in the province of British Columbia to Chelsea. On June 1, 2015, the Corporation announced that the BCSC granted a full revocation of the cease trade order.

To the knowledge of the Corporation, other than as disclosed below, no director, executive officer or shareholder holding a sufficient number of securities to affect materially the control of the Corporation, is, as of the date of this AIF, or was within 10 years prior to the date of this AIF, a director or executive officer of any company that, while such person was acting in that capacity, or within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver-manager or trustee appointed to hold its assets.

To the knowledge of the Corporation, no director or executive officer of the Corporation, or shareholder holding a sufficient number of securities to affect materially the control of the Corporation has, within the 10 years before the date of this AIF, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or become subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of the director, executive officer or Shareholder.

Stewart Gibson resigned from the board of Petro Ventures International Limited (“PVIL”) in March 2013. PVIL is incorporated in Australia and on 13 September 2013, Administrators, Scott Langdon & Cliff Rocke of Korda Mentha, were appointed by the PVIL board.

To the knowledge of the Corporation, no director or executive officer of the Corporation, or shareholder holding a sufficient number of securities to affect materially the control of the Corporation has been subject to any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority, or has been subject to any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision.

To the knowledge of the Corporation, there are no conflicts of interest between the Corporation and its officers, Board of Directors and senior management.

Management of Chelsea is not aware of any existing or contemplated legal proceedings material to Chelsea, to which Chelsea is, or during the financial year ended December 31, 2015 was, a party or of which any of its property is, or during the financing year ended December 31, 2015 was, subject.

Except as set forth below, no director or executive officer of the Corporation or a person or company that beneficially owns, or controls or directs, directly or indirectly, more than ten percent (10%) of any class or series of voting securities of the Corporation, or any associate or affiliate of any such person, has had any material interest, direct or indirect, in any transaction within the three (3) most recently completed financial years or the current financial year that has materially affected or is reasonable expected to materially affect the Corporation.

Each of Jesse Meidl, William H. Petrie, Sr. and William H. Petrie, Jr. were directors, officers and significant shareholders of 1629518 Alberta Ltd., which company was acquired by Chelsea in exchange for the issuance of an aggregate of 13,278,571 Common Shares on February 29, 2012. Concurrently with such acquisition, Chelsea acquired a 100% Working Interest in PL 18 and 40 and a 50% Working Interest in PL 280 and completed the Non-Brokered Private Placement. Each of Messrs. Meidl and Petrie, Sr. were also added to the Board of Directors on such date.

The auditors of Chelsea are KPMG LLP, Chartered Accountants, in Calgary, Alberta.

Computershare Trust Company of Canada, at its office in Calgary, Alberta, is the transfer agent and registrar for the Common Shares.

There are no material contracts entered into by the Corporation or on its behalf in the most recently completed financial year, other than contracts entered into in the ordinary course of business.

The auditors of the Corporation are KPMG LLP, Calgary, Alberta. KPMG LLP has advised the Corporation that they are independent in accordance with the Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta.

Reserve estimates contained in this AIF have been prepared by Sproule and Chapman. As at December 31, 2014, the effective date of those estimates, respectively, and as of the date hereof, the principals, directors, officers and associates of each of Sproule and Chapman, as a group, owned, directly or indirectly, less than one percent of the outstanding Common Shares.

No director, officer or employee of any of the experts referred to herein is or is expected to be elected, appointed or employed as a director, officer or employee of Chelsea or of any associate or affiliate of Chelsea.

Chelsea became an “OTC reporting issuer” on or about October 11, 2013 pursuant to Multilateral Instrument 51-105 Issuers Quoted in the U.S. Over-the-Counter Markets (“MI 51-105”). MI 51-105 provides for certain disclosure obligations that Chelsea must comply with, as well as certain restrictions on resales of securities of Chelsea. Holders of securities of Chelsea are encouraged to review MI 51-105 to understand and comply with the resale restrictions that apply to securities of Chelsea that have been acquired after July 31, 2012. In particular, Chelsea notes the following restriction which applies to all securities that were acquired after July 31, 2012 but prior to October 11, 2013:

Unless permitted under section 11 of Multilateral Instrument 51-105 Issuers Quoted in the U.S. Over-the-Counter Markets, the holder of this security must not trade the security in or from a jurisdiction of Canada unless:

Chelsea specifically notes that the compliance with the resale restrictions imposed by applicable securities laws is the responsibility of each securityholder of Chelsea, securityholders should consult their own legal counsel in their jurisdiction of residence for the full particulars of the resale restrictions applicable to them and no representation of any kind whatsoever is made by Chelsea to any person with respect to the applicable resale restrictions or ability to trade any securities of Chelsea.

The Audit Committee has been structured to comply with the requirements of National Instrument 52- 110 - Audit Committee (“NI 52-110”) as it relates to OTC reporting issuers. The Board has determined that the Audit Committee members have the appropriate level of financial understanding and industry specific knowledge to be able to perform the duties of the position and in particular are financially literate as defined in NI 52-110.

The Audit Committee periodically assesses the adequacy of procedures for the public disclosure of financial information and review, on behalf of the Board, and reports to the Board the results of its review and its recommendations regarding all material matters of a financial reporting and audit nature, including, but not limited to:

The Audit Committee ensures satisfactory procedures for (i) receipt, retention and treatment of complaints received by the Corporation regarding any accounting, internal accounting controls or auditing matters and (ii) the confidential anonymous submission of concerns by employees regarding questionable accounting or auditing matters. The Board is kept informed of the Audit Committee’s activities by a report delivered at each regular meeting of the Board of Directors.

The Audit Committee shall recommend the appointment and terms of engagement of the external auditor annually and reviews and evaluates the external auditor. The external auditor reports directly to the Audit Committee. In addition, the Audit Committee pre-approves non-audit services undertaken by the external auditor and on an annual basis, reviews and discusses with the external auditors all significant relationships such auditors have with the Corporation to determine the auditors’ independence.

The Audit Committee has direct responsibility for overseeing the work of the external auditor engaged for the purpose of preparing or issuing an auditor’s report or performing other audit, review or attest services, including the resolution of disagreements between the external auditor and management.

The Audit Committee meets at least once per financial quarter to fulfill its mandate. A copy of the Audit Committee Charter is attached as Appendix A to this AIF.

The current members of the Audit Committee are Messrs. Pierce (Chairman), Merer and Meidl, all of whom are “financially literate” and each of Messrs. Pierce and Merer are considered to be “independent” under NI 52-110. Mr. Meidl is the Chief Executive Officer of the Corporation and is therefore not considered to be independent.

The following relevant education and experience of the current and proposed members of the Audit Committee have been used in assessing their financial literacy:

Mr. Peirce is current the Chief Executive Officer and Director of Tag Oil Ltd. Mr. Pierce was previously a Director & Senior Analyst with GMP Securities (London, UK) and prior to GMP served as Director of Institutional Research at Tristone Capital (London, U.K.) since 1994. Previous engagements include wellsite geology over a period of five years for numerous companies across the Western Canadian Sedimentary Basin. In addition, he has worked for three years across North and Latin America as a geologist in the mining and exploration industry. Mr. Pierce brings strong geological and financial understanding within resource sectors. Mr. Pierce holds an M.B.A. from the Rotman School of Business and a B.Sc. Geology from the University of Victoria.

A graduate of the School of Geology in Nancy, France, Mr. Merer holds a Masters in Petroleum Economics from the French Institute of Petroleum and began his career in the mining sector before joining Shell in 1979. After twelve years in operations and production roles in the North Sea and Brunei, Mr. Merer moved to London in 1992 and spent four years in a regional business governance role, managing Shell’s interests in French-speaking West Africa. In 1996 he was appointed General Manager of Salym Petroleum Development in Siberia. Mr. Merer then served as Chairman of Shell Syria, based in Damascus, before moving to Beijing for three years as President of Shell China Exploration and Production, in charge of a large portfolio of exploration, development and production assets, both onshore and offshore. In 2006, he moved to Tehran to take on his final role with Shell. As Iran Country Chairman, he was responsible for several joint ventures, large oil and gas projects and a number of important contracts.

Mr. Meidl has over 17 years of experience in the oil and gas sector. He was previously Chief Financial Officer of a private international energy company, headquartered in London, England. Prior thereto, he was an investment banker in the International Oil & Gas group of Thomas Weisel Partners in London (now Stifel Nicolas). Mr. Meidl was previously the Chief Financial Officer for Arsenal Energy Inc., an international exploration company listed on the Toronto Stock Exchange, which held production assets in Canada and the USA and exploration assets in Egypt, Colombia and Uzbekistan. He qualified as a Chartered Accountant with KPMG in Calgary, where he specialized in oil and gas exploration and production and services. He also holds the ICAEW Corporate Finance qualification and a B. Comm. degree from the University of Saskatchewan (Canada).

At no time was a recommendation of the Audit Committee to nominate or compensate an external auditor not adopted by the board of directors.

Any proposed audit and permitted non-audit services (as identified by the Audit Committee at the time the annual audit engagement is approved) to be provided by the external auditor to the Corporation or its subsidiaries must receive prior approval from the Audit Committee. The Corporation has not adopted specific policies and procedures for the engagement of non-audit services. The Audit Committee will review the engagement of non-audit services as may be required.

The Chief Financial Officer shall act as the primary contact to receive and assess any proposed engagements from the external auditor. Following receipt and initial review for eligibility by the primary contact, a proposal would then be forwarded to the Audit Committee for review and confirmation that a proposed engagement is permitted. In the majority of such instances, proposals may be received and considered by the Chair of the Audit Committee (or such other member of the Audit Committee who may be delegated authority to approve audit and permitted non-audit services), for approval of the proposal on behalf of the Audit Committee. The Audit Committee Chair will then inform the Audit Committee of any approvals granted at the next scheduled meeting.

KPMG LLP was appointed as the Corporation’s auditor on March 31, 2014. Prior thereto, KWCO PC in Odessa, Texas in was the auditor of the Corporation from November 26, 2009. The following table provides information about the fees billed to the Corporation for professional services rendered by KPMG LLP and KWCO PC during the three prior fiscal years:

As the Corporation is listed on the OTCQB, it is a “OTC reporting issuer” and may avail itself of exemptions from the requirements of Part 3 Composition of the Audit Committee of NI 52-110, which require the independence of each member of an audit committee.

Additional information regarding the Corporation may be found on SEDAR at www.sedar.com and on EDGAR which can be accessed at www.sec.gov/edgar.shtml.

The Audit Committee (the “Committee”) is a committee of the board of directors (the “Board”) of Chelsea Oil and Gas Ltd. (the “Corporation”) to which the Board has delegated its responsibility for the oversight of the nature and scope of the annual audit, the oversight of management’s reporting on internal accounting standards and practices, the review of financial information, accounting systems and procedures, financial reporting and financial statements and has charged the Committee with the responsibility of recommending, for approval of the Board, the audited financial statements, interim financial statements and other mandatory disclosure releases containing financial information.

All of the members of the Committee must be “financially literate” (as defined in NI 52-110) unless the Board determines that an exemption under NI 52-110 from such requirement in respect of any particular member is available and determines to rely thereon in accordance with the provisions of NI 52-110.

The Committee has authority to communicate directly with the internal auditors (if any) and the external auditors of the Corporation. The Committee will also have the authority to investigate any financial activity of the Corporation. All employees of the Corporation are to cooperate as requested by the Committee.

The Committee may also retain persons having special expertise and/or obtain independent professional advice to assist in filling their responsibilities at such compensation as established by the Committee and at the expense of the Corporation without any further approval of the Board.

APPENDIX B-1
FORM 51-101F1 - STATEMENT OF RESERVES IN DATA AND
OTHER OIL AND NATURAL GAS INFORMATION

Chelsea Oil and Gas Ltd. (the “Corporation”) engaged Chapman Petroleum Engineering Ltd. (“Chapman”) to prepare a report relating to the Corporation’s reserves in respect of PL 18, PL 40 and PL 280 as at December 31, 2015. The reserves on the properties described herein are estimates only. Actual reserves on these properties may be greater or less than those estimated.

Set out below is a summary of the crude oil, natural gas and natural gas liquids reserves and the value of future net revenue of the Corporation as at December 31, 2015 as evaluated by Chapman in its report dated March 18, 2016 (the “Chapman Reserves Report”). The preparation date of the Chapman Reserves Report is March 31, 2015. The pricing used in the forecast price evaluations is set forth in the notes to the tables.

The Chapman Reserves Report was prepared using assumptions and methodology guidelines outlined in the Canadian Oil and Gas Evaluation Handbook and in accordance with National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities (“NI 51-101”).

All evaluations of future revenue are after the deduction of future income tax expenses, unless otherwise noted in the tables, royalties, development costs, production costs and well abandonment costs but before consideration of indirect costs such as administrative, overhead and other miscellaneous expenses. The estimated future net revenue contained in the following tables do not necessarily represent the fair market value of the Corporation’s reserves. There is no assurance that the forecast price and cost assumptions contained in the Sproule Reserves Report will be attained and variances could be material. Other assumptions and qualifications relating to costs and other matters are included in the Chapman Reserves Report. The recovery and reserves estimates on the Corporation’s properties described herein are estimates only. The actual reserves on the Corporation’s properties may be greater or less than those calculated.

LIGHT OIL, NATURAL GAS AND NATURAL GAS LIQUIDS RESERVES
BASED ON FORECAST PRICES AND COSTS IN AUSTRALIAN DOLLARS^(5)(6)(8)

	Remaining Gas and NGL Reserves
	Company Light Oil		Company Gas		Company NGL		Company Total
	Gross⁽¹⁾	Net⁽¹⁾	Gross⁽¹⁾	Net⁽¹⁾	Gross⁽¹⁾	Net⁽¹⁾	Gross⁽¹⁾	Net⁽¹⁾
	(Mbbl)	(Mbbl)	(MMcf)	(Mmcf)	(mbbl)	(mbbl)	(mbbl)	(mbbl)
Total Proved ⁽²⁾	95	83	-	-	-	-	95	83
Total Probable⁽³⁾	50	44	2,905	2,598	508	444	1,042	912
Total Possible⁽⁴⁾	-	-	14,525	13,001	2,538	2,220	4,959	4,338
Total Proved Plus Probable Plus Possible	145	126	17,430	15,599	3,045	2,664	6,095	5,332

	Remaining Gas and NGL Reserves
	Company Light Oil		Company Gas		Company NGL		Company Total
	Gross⁽¹⁾	Net⁽¹⁾	Gross⁽¹⁾	Net⁽¹⁾	Gross⁽¹⁾	Net⁽¹⁾	Gross⁽¹⁾	Net⁽¹⁾
	(Mbbl)	(Mbbl)	(MMcf)	(Mmcf)	(mbbl)	(mbbl)	(mbbl)	(mbbl)
Total Proved ⁽²⁾	95	83	-	-	-	-	95	83
Total Probable⁽³⁾	50	44	2,905	2,598	508	444	1,042	912
Total Possible⁽⁴⁾	-	-	14,525	13,001	2,538	2,220	4,959	4,338
Total Proved Plus Probable Plus Possible	145	126	17,430	15,599	3,045	2,664	6,095	5,332

NET PRESENT VALUES OF FUTURE NET REVENUE
BASED ON FORECAST PRICES AND COSTS IN AUSTRALIAN DOLLARS^(5)(6)(8)

	A$ Before Deducting Income Taxes					A$ After Deducting Income Taxes
	Discounted At					Discounted At
	0%	5%	10%	15%	20%	0%	5%	10%	15%	20%
	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
Total Proved ⁽²⁾	4,055	3,138	2,443	1,905	1,482	4,055	3,138	2,443	1,905	1,482
Total Probable⁽³⁾	27,575	23,277	19,854	17,076	14,790	20,737	17,425	14,784	12,638	10,866
Total Possible⁽⁴⁾	130,395	103,245	82,812	67,160	55,043	90,300	70,678	56,019	44,886	36,306
Total Proved Plus Probable Plus Possible	162,025	129,659	105,100	86,164	71,315	115,092	91,240	73,246	59,429	48,650

	A$ Before Deducting Income Taxes					A$ After Deducting Income Taxes
		Discounted At				Discounted At
	0%	5%	10%	15%	20%	0%	5%	10%	15%	20%
	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
Total Proved ⁽²⁾	4,055	3,138	2,443	1,905	1,482	4,055	3,138	2,443	1,905	1,482
Total Probable⁽³⁾	27,575	23,277	19,854	17,076	14,790	20,737	17,425	14,784	12,638	10,866
Total Possible⁽⁴⁾	130,395	103,245	82,812	67,160	55,043	90,300	70,678	56,019	44,886	36,306
Total Proved Plus Probable Plus Possible	162,025	129,659	105,100	86,164	71,315	115,092	91,240	73,246	59,429	48,650

TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
BASED ON FORECAST PRICES AND COSTS IN AUSTRALIAN DOLLARS^(5)(6)(8)

						Future		Future
						Net		Net
						Revenue		Revenue
				Develop-	Abandon-	Before		After
			Operating	ment	ment	Income	Income	Income
	Revenue	Royalties⁽⁶⁾	Costs	Costs	Costs	Taxes	Taxes	Taxes
	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
Total Proved ⁽²⁾	9,695	1,260	2,478	1,800	102	4,055	-	4,055
Total Proved Plus Probable⁽³⁾	58,616	6,557	9,975	10,119	335	31,630	6,838	24,792
Total Proved Plus Probable Plus Possible	283,402	30,109	43,897	45,848	1,522	162,025	46,933	115,092

FUTURE NET REVENUE BY PRODUCT TYPE
BASED ON FORECAST PRICES AND COSTS
AS AT DECEMBER 31, 2015

OIL AND GAS RESERVES AND NET PRESENT VALUES BY PRODUCT TYPE
BASED ON FORECAST PRICES AND COSTS
AS AT DECEMBER 31, 2015⁽⁵⁾⁽⁸⁾

The pricing assumptions used in the Chapman Reserves Report with respect to net present values of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth below. The forecast price assumptions assume the continuance of current laws and regulations and take into account inflation with respect to future operating and capital costs. There will be adjustments to field prices from the benchmarks below.

Chapman is an independent qualified reserves evaluator appointed pursuant to NI 51-101.

NATURAL GAS & BY-PRODUCTS
HISTORICAL, CONSTANT, CURRENT AND FUTURE PRICES
January 1, 2016

RECONCILIATION OF THE CORPORATION’S GROSS
RESERVES IN CANADA BY PRINCIPAL PRODUCT TYPE
BASED ON FORECAST PRICES AND COSTS IN AUSTRALIAN DOLLARS^(1)(5)(8)(9)

The following table sets forth a reconciliation of the changes in the Company's working interest, before royalties of its reserves as at December 31, 2015 against such reserves as at December 31, 2014 based on the forecast price and cost assumptions set forth in Note 5:

	Light Oil				Natural Gas			Natural Gas Liquids
				Gross
				Proved
				Plus			Gross			Gross
			Gross	Probable			Probable			Probable
	Gross	Gross	Possible	Plus	Gross	Gross	Plus	Gross	Gross	Plus
	Proved	Probable	(Mbbl)	Possible	Probable	Possible	Possible	Probable	Possible	Possible
	(Mbbl) ⁽²⁾	(Mbbl) ⁽³⁾	^(4)(10)	(Mbbl) ⁽¹⁰⁾	(MMcf) ⁽³⁾	(MMcf) ⁽⁴⁾	(MMcf)	(Mboe)⁽³⁾	(Mboe)⁽⁴⁾	(Mboe)

At December 31, 2014	-	145	257	402	2,905	14,525	17,430	508	2,538	3,045
Extensions	-	-	-	-	-	-	-	-	-	-
Improved	-	-	-	-	-	-	-	-	-	-
Recovery
Technical	95	(95)	(257)	(257)	-	-	-	-	-	-
Revisions
Discoveries	-	-	-	-	-	-	-	-	-	-
Acquisitions	-	-	-	-	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-	-	-	-	-
Economic	-	-	-	-	-	-	-	-	-	-
Factors
Production	-	-	-	-	-	-	-	-	-	-
At December 31, 2015	95	50	-	145	2,905	14,525	17,430	508	2,538	3,045

The following table sets forth the volumes of proved undeveloped reserves that were first attributed to the Corporation’s light oil reserves in each of the three most recent financial years and in the aggregate before such time. The Corporation has not been assigned any natural gas or natural gas liquids proven undeveloped reserves over the same period:

The following table sets forth the volumes of probable undeveloped reserves that were first attributed for each of the Corporation’s product types in each of the three most recent financial years and in the aggregate before such time:

The process of evaluating reserves is inherently complex. It requires significant judgments and decisions based on available geological, geophysical, engineering and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change. The reserve estimates contained herein are based on current production forecasts, prices and economic conditions and other factors and assumptions that may affect the reserve estimates and the present worth of future net revenue there from. These factors and assumptions include, among others: (i) historical production in the area compared with production rates from analogous areas; (ii) initial production rates; (iii) production decline rates; (iv) ultimate recovery of reserves; (v) success of future development activities; (vi) marketability of production; (vii) effect of government regulations; and (viii) other government levies imposed over the life of the reserves.

As circumstances change and additional data becomes available, reserve estimates also change. Estimates are reviewed and revised, either upward or downward, as warranted by the new information. Revisions are often required due to changes in well performance, prices, economic conditions and government restrictions. Revisions to reserve estimates can arise from changes in forecasted prices, reservoir performance and geological conditions or production. These revisions can be either positive or negative.

While we do not anticipate any significant economic factors or significant uncertainties will affect any particular component of the reserve data, the reserves can be affected significantly by fluctuations in product pricing, capital expenditures, operating costs, royalty regimes and well performance that are beyond the Corporation’s control.

The following table sets forth the development costs deducted in the estimation of future net revenue attributable to each of the following reserves categories contained in the Chapman Reserves Report:

The Corporation’s primary source of liquidity to fund its estimated future development costs, as outlined in the above table, is derived from the Corporation’s internally-generated cash flow, debt financing when deemed appropriate and new equity issues if made on favourable terms.

The Corporation’s major oil property is PL 18 in the Surat-Bowen basin. The properties held by the Corporation are currently shut-in, but previously produced oil until 2010. Oil will be trucked for processing and sold to a third party marketer. No gas is anticipated to be produced from PL 18. All of the Corporation’s potential oil production is onshore and located in the state of Queensland.

Subject to capital availability, the Corporation intends to complete a 3D seismic survey over PL 18 in 2016, and install water injection facilities to initiate a waterflood over one pool, Yellowbank Creek. Sproule has assigned no reserves to Yellowbank Creek Field. Below is a listing of producing and non-producing wells:

PL 40 contains the Louise gas field. The field has been defined through three penetrations on the Corporation’s lands, additional penetrations both to the north and south of PL 40 and seismic over PL 40. The field is analogous to several nearby gas discoveries, Chelsea intends to evaluate the productivity of the Permian gas reservoir through the recompletion of the Louise-1 well, which previously produced oil from the shallower Triassic Showgrounds Sandstone. Below is a listing of producing and non-producing wells on PL 40:

The following table sets out the Corporation’s undeveloped land position effective December 31, 2015:

Significant Factors or Uncertainties Relevant to Properties with No Attributed Reserves

The largest license in Chelsea’s portfolio is ATP 582. This license is approximately 5.02 million acres in size and provides exposure to two discreet basins: the Georgina Basin and the Simpson Basin (refer to

In 2012, Total entered into the Georgina Basin through a farm-in whereby it would spend up to A$190.0 million by 2016 to earn a 68% Working Interest in an offsetting operators Georgina Basin lands. As well in 2012, Statoil entered into the Georgina Basin through a farm-in whereby it would spend up to A$210.0 million in separate offsetting Georgina Basin lands to earn an 80% Working Interest. The average of the Total and Statoil farm-ins on an Australian dollar per acre basis is A$ 32.78 / acre. After giving effect to the A$ / acre on offsetting lands, this would suggest Chelsea’s Georgina Basin undeveloped acreage could have a value in excess of A$30.0 million.

In 2012, Santos entered into the Simpson Basin through a farm-in with another operator whereby it would spend up to A$150.0 million to earn a 70% Working Interest. The total potential investment on an Australian dollar per acre basis is A$11.28 / acre. Chelsea estimates it has up to 2.0 million acres of Simpson basin sediments. After giving effect to the A$ / acre on offsetting lands, this would suggest Chelsea’s Simpson Basin undeveloped acreage could have a value in excess of A$20.0 million.

Chelsea has a marketing contract with Santos whereby Santos will buy Chelsea’s Surat Basin oil production at a price of Dated Brent + A$2.50 per bbl. Dated Brent is defined as the month average Brent oil price.

Well abandonment cost has been included in the Chapman Report for wells which have reserves assigned. Abandonment costs were provided by the Corporation. The industry’s historical costs are used when available. If representative comparisons are not readily available, an estimate is prepared based on the various regulatory abandonment requirements. In addition to the wells assigned reserves, the Corporation currently has 8.5 net wells for which abandonment and reclamation costs are expected to be incurred.

The total abandonment cost in the Chapman Reserves Report in respect of proved plus probable reserves using forecast prices is $0.4 million (undiscounted) and $0.1 million (discounted at 10%). 100% of such amounts were deducted as abandonment costs in estimating the Corporation’s future net revenue as disclosed above.

Well abandonment costs for all wells with reserves have been included at the property level. Additional abandonment costs associated with non-reserves wells, lease reclamation costs and facility abandonment and reclamation expenses have not been included in this analysis.

In Canada the Corporation was not required to pay any cash income taxes in any jurisdiction for the period ended December 31, 2015. Based on current estimates of the Corporation’s future taxable income and levels of tax deductible expenditures in Australia, management believes that the Corporation will not be required to pay cash income taxes until 2019.

As a Canadian corporation, Chelsea is liable for income taxes under the laws of Canada. Under Canadian law the Company’s Australian-source income is subject to a 25% tax (on Canadian income). Chelsea believes the 30% Australian tax should be a partial credit toward the payment of the 25% Canadian tax under double taxation treaties between the countries.

The Corporation did not incur any material capital expenditures made by the Corporation on its oil and natural gas properties for the year ended December 31, 2015.

The Corporation did not conduct any exploration or development activities during 2015.

The Corporation does not anticipate it will have any production from its oil and natural gas properties during 2016.

The Corporation’s oil and natural gas properties have been shut-in and have not produced since being acquired by Chelsea in 2012.

APPENDIX B-2
FORM 51-101F2 - REPORT ON RESERVES IN DATA
BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR (PL 18 AND 280)

Chapman Petroleum Engineering Ltd.
1122 - 4th Street S.W., Suite 700, Calgary, Alberta T2R 1 Ml • Phone: (403) 266-4141 • Fax: (403) 266-4259 • www.chapeng.ab.cr .

Chelsea Oil Australia Pty. Ltd.
3200 Altius Centre
500 - 4th Avenue SW
Calgary, AB, T2P 2V6

APPENDIX B-3
FORM 51-101F3 - REPORT OF MANAGEMENT AND DIRECTORS ON
RESERVES AND RESOURCES DATA AND OTHER OIL AND GAS INFORMATION

REPORT OF MANAGEMENT AND DIRECTORS ON
RESERVES AND RESOURCES DATA AND OTHER INFORMATION

Management of Chelsea Oil and Gas Ltd. (the “Corporation”) is responsible for the preparation and disclosure of information with respect to the Corporation’s oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data which are estimates of probable reserves and related future net revenue as at December 31, 2015, estimated using forecast prices and costs. In addition, management of the Corporation has included information which are estimates of possible reserves and related future net revenue as at December 31, 2015.

Independent qualified reserves and resources evaluators have evaluated the Corporation’s reserves data with respect to its crude oil and natural gas properties. The report of the independent qualified reserves evaluator is attached as Appendix B-2.

The Reserves Committee of the Board of Directors has reviewed the Corporation’s procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The Board of Directors has, on the recommendation of the Reserves Committee, approved:

Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.

	Page

DEFINITIONS	1

CURRENCY	4

ABBREVIATIONS	4

BARREL OF OIL EQUIVALENCY	4

CONVERSIONS	5

FORWARD LOOKING STATEMENTS	5

NOTE REGARDING RESERVES DATA AND OTHER INFORMATION	7

THE CORPORATION	7

GENERAL DEVELOPMENT OF THE BUSINESS	8

DESCRIPTION OF THE BUSINESS	11

INDUSTRY OVERVIEW	14

RISK FACTORS	21

DIVIDENDS	31

DESCRIPTION OF CAPITAL STRUCTURE	31

MARKET FOR SECURITIES	31

ESCROWED SECURITIES	32

DIRECTORS AND OFFICERS	32

LEGAL PROCEEDINGS AND REGULATORY ACTIONS	34

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	34

AUDITORS, REGISTRAR AND TRANSFER AGENT	34

MATERIAL CONTRACTS	34

INTERESTS OF EXPERTS	34

OTC REPORTING ISSUER	35

AUDIT COMMITTEE	35

ADDITIONAL INFORMATION	37

APPENDIX A – AUDIT COMMITTEE CHARTER

	Crude Oil and Natural Gas Liquids		Natural Gas
bbl	barrel	Mcf	thousand cubic
bbl/d	barrels per day	MMcf	million cubic feet
Mbbl	thousands of barrels	Bcf	billion cubic feet
boe	barrels of oil equivalent of natural gas and crude oil, unless otherwise indicated	Tcf	trillion cubic feet
boepd	barrels of oil equivalent per day	Mcf/d	thousand cubic feet per day
Mboe	thousand boe	MMcf/d	million cubic feet per day
NGL	natural gas liquids	GJ	gigajoule

To Convert From	To	Multiply By
Mcf	cubic metres	28.178
Thousand cubic metres	Mcf	35.494
Bcf	petajoules	1.055
bbl	Cubic metres	0.159
Cubic metres	bbls	6.290
Feet	Metres	0.305
Metres	Feet	3.281
Miles	Kilometres	1.609
Kilometres	Miles	0.621
Acres	Hectares	0.405
Hectares	Acres	2.471

	1.	‘‘Gross Reserves’’ are the Corporation’s Working Interest (operating or non-operating) share before deducting royalties and without including any royalty interests of the Corporation. ‘‘Net Reserves’’ are the Corporation’s Working Interest (operating or non-operating) share after deduction of royalty obligations, plus the Corporation’s royalty interests in reserves.

	2.	’’Proved ’’ reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

	3.	‘‘Probable’’ reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

	4.	‘‘Possible’’ reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable plus possible reserves.

		The pricing assumptions used in the Chapman Reserves Report with respect to net values of future net revenue (forecast) as well as the cost escalation rates used for operating and capital costs are set forth in Appendix B-3 in a table titled ‘‘Natural Gas & By-Products Current and Future Prices Used in Chapman Reserves Report’’. The Natural Gas & By-Products Current and Future Prices rates were developed by Chapman as at December 31, 2014 and reflect the then current year forecast prices and cost escalation rates. Chapman is an independent qualified reserves evaluator appointed pursuant to NI 51-101.

	5.	Values may not add due to rounding.

	6.	Income taxes are Australian income taxes.

	Gross Acres	Avg. ORR Interest	Net Royalty Acres
Producing Overriding Royalty Interests	1,799,507	0.22%	4,131
Non-Producing Overriding Royalty interests	9,319,969	0.60%	56,195
Total Overriding Royalty Interests	11,119,476	0.55%	60,326

•	oil, NGLs and natural gas production levels and their sources of growth;

•	the performance characteristics of the Corporation’s properties and assets;

•	the size of oil, NGL and natural gas resources attributable to the Corporation’s properties;

•	planned development of the Corporation’s future oil and gas properties;

•	capital expenditure programs and other expenditures;

•	commodity prices and interest rates;

•	supply and demand for oil, NGLs and natural gas;

•	expectations regarding the Corporation’s ability to raise capital and to add to resources and reserves through acquisitions, exploration and development;

•	schedules and timing of certain projects and the Corporation’s strategy for growth;

•	the Corporation’s future operating and financial results; and

•	the ability of Chelsea to add resources and reserves at a consistent rate;

•	that commodity prices will not deteriorate significantly;

•	the ability of Chelsea to obtain financing on acceptable terms;

•	the ability of Chelsea to engage drilling and other service contractors and to obtain and transport equipment, services, supplies and personnel in a timely manner and at an acceptable cost to carry out exploration and development activities;

•	the ability of Chelsea to market oil and natural gas successfully;

•	prevailing governmental and other regulatory regimes and tax, environmental and other laws;

•	the timely receipt of regulatory approvals and the terms and conditions of such approvals;

•	the ability of the Corporation to realize drilling success consistent with management’s expectations; and

•	financial information including expected future capital expenditures, debt levels, expenses and cashflows.

•	risks associated with the exploration for and development of oil and natural gas resources and reserves;

•	operational risks and liabilities that are not covered by insurance;

•	volatility in market prices for oil and natural gas;

•	the ability of the Corporation to fund its substantial capital requirements and operations;

•	risks associated with ensuring title to the Corporation’s properties;

•	uncertainties associated with estimating oil and natural gas resources and reserves;

•	incorrect assessments of the value of acquisitions and exploration and development programs and the failure to realize the anticipated benefits of acquisitions;

•	geological, technical, drilling and processing problems;

•	changes in environmental or other legislation applicable to the Corporation’s operations, and the Corporation’s ability to comply with current and future environmental and other laws;

•	the Corporation’s success at acquisition, exploration and development of resources and reserves;

•	the Corporation’s reliance on key operational and management personnel;

•	the ability of the Corporation to obtain and maintain all of its required permits and licenses;

•	competition for, among other things, capital, drilling equipment, acquisitions of resources and reserves, undeveloped lands and skilled personnel;

•	variations in foreign exchange rates and interest rates;

•	fluctuations in national and international financial markets;

•	equipment and technology risks;

•	geo-political risks;

•	changes in general economic, market and business conditions in Canada, the United States, Australia and worldwide; and

•	actions by governmental or regulatory authorities including changes in income tax laws or changes in tax laws and incentive programs and royalties relating to the oil and gas industry.

•	Surat-Bowen Basin: Six existing oil discoveries and one gas pool with independently evaluated reserves.

•	Georgina and Simpson Basins: multi-billion barrel potential in two emerging unconventional resource plays.

•	Overriding Royalty Interests: In addition to its Working Interest lands, the Corporation also holds an ORRI in more than approximately 9.3 million gross acres (60,000 net acres) in both onshore and offshore basins in Australia.

•	complying with government regulations and standards, particularly relating to the environment, health and safety;

•	operations consistent with industry codes, practices and guidelines;

•	ensuring prompt, effective response and repair to emergency situations and environmental incidents;

•	engage contractors who are committed to ensuring compliance with corporate safety and environmental rules and procedures; and

•	communicating openly with members of the public regarding its activities.

•	the effects of inclement weather;

•	the availability of drilling and related equipment;

•	unexpected cost increases;

•	accidental events;

•	currency fluctuations;

•	changes in regulations;

•	the availability and productivity of skilled labour; and

•	the regulation of the oil and natural gas industry by various levels of government and

•	governmental agencies.

Name, Residence and Position	Principal Occupation For The Past Five Years	Director/Officer Since
William H. Petrie Sr.⁽³⁾ Cochrane, Alberta Executive Chairman	Executive Chairman and a Director of Chelsea since March 1, 2012 and Director of Chelsea Oil Australia Pty since November 2011. Chief Executive Officer and Director of Birch Lake Energy Inc. since December 5, 2007.	March 1, 2012 (Director) October 1, 2013 (Executive Chairman)

Jesse D. Meidl⁽¹⁾ Calgary, Alberta Chief Executive Officer	Chief Executive Officer of Chelsea since January 2014, Vice President, Finance and Chief Financial Officer of Caithness Petroleum Limited April 2010. Investment Banker with Westwind Partners and Thomas Weisel Partners International from June 2007.	March 1, 2012 (Director) January 30, 2014 (Chief Executive Officer)

William H. Petrie, Jr. Calgary, Alberta Chief Exploration Officer	Chief Exploration Officer, Former Vice-President Exploration for Windtalker Energy Corp., Former Technical Manager at ENVOI Ltd., UK based firm providing marketing and A&D services.	October 1, 2013

Yves Merer⁽¹⁾⁽²⁾ Dubai, UAE Independent Director	Chief Executive Officer and Director of Caithness Petroleum Limited from August 2011 – December 2013. Prior thereto, consultant from June 2010 – July 2011 in respect of the Middle East and North Africa. Country Chairman of Royal Dutch Shell plc companies in Iran.	October 1, 2013

Stewart Gibson⁽²⁾⁽³⁾ Montrose, Scotland Independent Director	Director and advisor of Sterling Resources Ltd. from May 2010- May 2013. Prior thereto, Managing Director, Chief Operating Officer, President and Chief Executive Officer of Sterling Resources Ltd. from 1999 to May 2010	October 1, 2013

Toby Pierce^(1)(2)(3) Vancouver, BC Independent Director	Chief Executive Officer of Tag Oil Ltd. since June 2015. Chairman and Director of Crest Petroleum Corp. since May 2012. Prior thereto Partner and Senior Oil Equity analyst with GMP Securities LP and Tristone Capital Global Inc. in London, England	October 1, 2013

1.	Member of the Audit Committee.
2.	Member of the Corporate Governance and Compensation Committee.
3.	Member of the Reserves Committee.

	(a)	the security holder trades the security through an investment dealer registered in a jurisdiction of Canada from an account at that dealer in the name of that security holder, and

	(b)	the dealer executes the trade through any of the over-the-counter markets in the United States of America.

		2015		2014		2013
Audit Fees	$	10,000	$	60,000	$	65,000
Audit-Related Fees		-		-		-
Tax Fees	$	7,500		-		-
All Other Fees		-		-		-
Total:	$	17,500	$	60,000	$	65,000

•	oversight of the nature and scope of the annual audit;

•	oversight of management’s reporting on internal accounting standards and practices; and

•	review of financial information, accounting systems and procedures, financial reporting and financial statements.

•	assist directors in meeting their responsibilities (especially for accountability) in respect of the preparation and disclosure of the financial statements of the Corporation and related matters;

•	provide better communication between directors and external auditors;

•	enhance the external auditor’s independence;

•	increase the credibility and objectivity of financial reports; and

•	strengthen the role of the outside directors by facilitating in-depth discussions between directors on the Audit Committee, management and external auditors.

1.	The Committee will be comprised of at least three (3) directors of the Corporation, none of whom are members of management of the Corporation and all of whom are “independent” (as such term is used in National Instrument 52-110 - Audit Committees (“NI 52-110”) unless the Board determines that the exemption contained in NI 52-110 is available and determines to rely thereon.

2.	The Board of Directors may from time to time designate one of the members of the Committee to be the Chairman of the Committee (the “Committee Chairman”).

1.	Oversee the work of the external auditors, including the resolution of any disagreements between management and the external auditors regarding financial reporting.

2.	Satisfy itself on behalf of the Board with respect to Corporation’s internal control systems:

	(a)	identifying, monitoring and mitigating business risks; and

	(b)	ensuring compliance with legal, ethical and regulatory requirements.

	(a)	reviewing changes in accounting principles and policies, or in their application, which may have a material impact on the current or future years’ financial statements;

	(b)	reviewing significant accruals, reserves or other estimates such as the ceiling test calculation;

	(c)	reviewing accounting treatment of unusual or non-recurring transactions; (d)ascertaining compliance with covenants under loan agreements;

	(d)	reviewing disclosure requirements for commitments and contingencies;

	(e)	reviewing adjustments raised by the external auditors, whether or not included in the financial statements;

	(f)	reviewing unresolved differences between management and the external auditors; and

	(g)	obtain explanations of significant variances with comparative reporting periods.

4.	Review the financial statements, prospectuses, MD&A, annual information forms (“AlF”) and all public disclosure containing unaudited financial information (including, without limitation, annual and interim press releases and any other press releases disclosing earnings or financial results) before release and prior to Board approval. The Committee must be satisfied that adequate procedures are in place for the review of the Corporation’s disclosure of all other financial information and will periodically assess the accuracy of those procedures.

5.	With respect to the appointment of external auditors by the Board:

	(a)	recommend to the Board the external auditors to be nominated;

	(b)	recommend to the Board the terms of engagement of the external auditor, including the compensation of the auditors and a confirmation that the external auditors will report directly to the Committee;

	(c)	on an annual basis, review and discuss with the external auditors all significant relationships such auditors have with the Corporation to determine the auditors’ independence;

	(d)	when there is to be a change in auditors, review the issues related to the change and the information to be included in the required notice to securities regulators of such change; and

	(e)	review and pre-approve any non-audit services to be provided to the Corporation or its subsidiaries by the external auditors and consider the impact on the independence of such auditors. The Committee may delegate to one or more independent members the authority to pre-approve non-audit services, provided that the member(s) report to the Committee at the next scheduled meeting such pre-approval and the member(s) comply with such other procedures as may be established by the Committee from time to time.

	(f)	recommend to the Board the external auditors to be nominated;

6.	Review with external auditors (and internal auditor if one is appointed by the Corporation) their assessment of the internal controls of the Corporation, their written reports containing recommendations for improvement, and management’s response and follow-up to any identified weaknesses. The Committee will also review annually with the external auditors their plan for their audit and, upon completion of the audit, their reports upon the financial statements of the Corporation and its subsidiaries.

7.	Review risk management policies and procedures of the Corporation (i.e., hedging, litigation and insurance).

8.	Establish a procedure for:

	(a)	the receipt, retention and treatment of complaints received by the Corporation regarding accounting, internal accounting controls or auditing matters; and

	(b)	the confidential anonymous submission by employees of the Corporation of concerns regarding questionable accounting or auditing matters.

1.	At all meetings of the Committee every question shall be decided by a majority of the votes cast. In case of an equality of votes, the Committee Chairman shall be entitled to a second or casting vote.

2.	The Committee Chairman will preside at all meetings of the Committee, unless the Committee Chairman is not present in which case the members of the Committee that are present will designate from among such members a Committee Chairman for purposes of the meeting.

3.	A quorum for meetings of the Committee will be a majority of its members, and the rules for calling, holding, conducting and adjourning meetings of the Committee will be the same as those governing the Board unless otherwise determined by the Committee or the Board.

4.	Meetings of the Committee should be scheduled to take place at least four times per year.

5.	Minutes of all meetings of the Committee will be taken. The Chief Financial Officer will attend meetings of the Committee, unless otherwise excused from all or part of any such meeting by the Committee Chairman.

6.	The Committee will meet with the external auditor at least once per year (in connection with the preparation of the year-end financial statements) and at such other-times as the external auditor and the Committee consider appropriate.

7.	Agendas, approved by the Committee Chairman, will be circulated to Committee members along with background information on a timely basis prior to the Committee meetings.

8.	The Committee may invite such officers, directors and employees of the Corporation as it sees fit from time, to time to attend at meetings of the Committee and assist in the discussion and consideration of the matters being considered by the Committee.

9.	Minutes of the Committee will be recorded and maintained and circulated to directors who are not members of the Committee or otherwise made available at a subsequent meeting of the Board.

10.	The Committee may retain persons having special expertise and may obtain independent professional advice to assist in fulfilling its responsibilities at the expense of the Corporation.

11.	Any members of the Committee may be removed or replaced at any time by the Board and will cease to be a member of the Committee as soon as such member ceases to be a director. The Board may fill vacancies on the Committee by appointment from among its members. If and whenever a vacancy exists on the Committee, the remaining members may exercise all its powers so long as a quorum remains. Subject to the foregoing, following appointment as a member of the Committee, each member will hold such office until the Committee is reconstituted.

12.	Any issues arising from these meetings that bear on the relationship between the Board and management should be communicated to the Chairman of the Board by the Committee Chairman.

		Future Net Revenue Before Income
		Taxes (Discounted at 10%/Year)
Reserve Category	Product Type	($M)
Total Proved⁽²⁾	Light and Medium Oil (including solution gas and other	2,443
	by-products)
	Heavy Oil (including solution gas and other by-products)	-
	Natural Gas (including by-products but not solution gas)	-

Total Proved Plus	Light and Medium Oil (including solution gas and other	4,853
Probable⁽²⁾⁽³⁾	by-products)
	Heavy Oil (including solution gas and other by-products)	-
	Natural Gas (including by-products but not solution gas)	17,445

Total Proved Plus Probable	Light and Medium Oil (including solution gas and other	4,853
Plus Possible⁽⁴⁾	by-products)
	Heavy Oil (including solution gas and other by-products)	-
	Natural Gas (including by-products but not solution gas)	100,257

	Reserves						Net Present	Unit Values
	Oil		Gas⁽⁹⁾		NGL		Value (BIT)	@ 10%/yr⁽⁹⁾
Product Type by Reserve	Gross	Net	Gross	Net	Gross	Net	10%
Category	MSTB	MSTB	MMscf	MMscf	Mbbl	Mbbl	M$
Light and Medium Oil Proved⁽²⁾
Developed Producing	-	-	-	-	-	-	-	N/A
Developed Non-Producing	-	-	-	-	-	-	-	N/A
Undeveloped	95	83	-	-	-	-	2,443	29.59
Total Proved	95	83	-	-	-	-	2,443	29.59
Probable⁽³⁾	50	44	-	-	-	-	2,410	55.19
Proved Plus Probable	145	126	-	-	-	-	4,853	38.45
Possible⁽⁴⁾	-	-	-	-	-	-	-	N/A
Proved + Probable + Possible	145	126	-	-	-	-	4,853	38.45

Assoc & Non-Assoc Gas Proved⁽²⁾
Developed Producing	-	-	-	-	-	-	-	N/A
Developed Non-Producing	-	-	-	-	-	-	-	N/A
Undeveloped	-	-	-	-	-	-	-	N/A
Total Proved	-	-	-	-	-	-	-	N/A
Probable⁽³⁾	-	-	2,905	2,598	508	454	17,445	6.71
Proved Plus Probable	-	-	2,905	2,598	508	454	17,445	6.71
Possible⁽⁴⁾	-	-	14,525	13,001	2,538	2,271	82,812	6.37
Proved + Probable + Possible	-	-	17,430	15,599	3,045	2,725	100,257	6.43

	Brent Spot (ICE)[1]	Australia [2]
Date	$US/STB	A$/STB

HISTORICAL PRICES
2009	61.74	N/A
2010	79.61	N/A
2011	111.26	N/A
2012	111.63	N/A
2013	108.56	N/A
2014	99.43	N/A
2015	53.32	N/A

CONSTANT PRICES (The average of the first-day-of-the-month price for the preceding 12 months-SEC)
	55.14	73.34
FORECAST PRICES
2016	49.05	65.24
2017	59.95	79.73
2018	70.85	94.23
2019	76.30	101.48
2020	81.75	108.73
2021	85.02	113.08
2022	88.29	117.43
2023	92.65	123.22
2024	94.50	125.69
2025	96.39	128.20
2026	98.32	130.77
2027	100.29	133.38
2028	102.29	136.05
2029	104.34	138.77
2030	106.43	141.55
2031	108.55	144.38

Constant thereafter

Notes:	[1]	The Brent Spot price is estimated based on historic data.

	[2]	The Australian price is estimated based on Brent forecast data converted in A$.

		NGL
	Eastern Australia Gas	Mix [1]
Date	A$/MMBTU	A$/BBL
FORECAST PRICES
2016	8.25	34.77
2017	8.42	35.46
2018	8.58	36.17
2019	8.75	36.89
2020	8.93	37.63
2021	9.11	38.38
2022	9.29	39.15
2023	9.48	39.93
2024	9.67	40.73
2025	9.86	41.55
2026	10.06	42.38
2027	10.26	43.23
2028	10.46	44.09
2029	10.67	44.97
2030	10.89	45.87
2031	11.10	46.79
Constant thereafter

	1.	“Gross Reserves” are the Corporation’s Working Interest (operating or non-operating) share before deducting royalties and without including any royalty interests of the Corporation. “Net Reserves” are the Corporation’s Working Interest (operating or non-operating) share after deduction of royalty obligations, plus the Corporation’s royalty interests in reserves.
	2.	“Proved” reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.
	3.	“Probable” reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.
	4.	“Possible” reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.
	5.	The pricing assumptions used in the Chapman Reserves Report with respect to net values of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth in the preceding table titled “Forecast Oil Prices and Inflation Used in Chapman Reserves Report”. The Forecast Prices, Inflation & Exchange rates were developed by Chapman as at December 31, 2015 and reflect the then current year forecast prices, inflation and exchange rates. Chapman is an independent qualified reserves evaluator appointed pursuant to NI 51-101.
	6.	Reference to M$, $/boe and $/Mcfe are stated in Australian dollars unless otherwise noted.
	7.	Royalties include overriding and Queensland royalties.
	8.	Values may not add due to rounding.
	9.	Unit Values are based on net reserves volumes.
	10.	Chapman did not complete an evaluation of the Corporation’s Possible light oil reserves as at December 31, 2015.

	Light Oil
	Company Net
	(Mbbl)
Aggregate prior to 2013	0⁽¹⁾
December 31, 2013	0⁽¹⁾
December 31, 2014	0⁽¹⁾
December 31, 2015	95⁽²⁾