EXHIBIT 99-3




CHELSEA OIL AND GAS LTD.

MANAGEMENT DISCUSSION AND ANALYSIS

For the years ended December 31, 2013 and 2012



APRIL 30, 2014





<PAGE>

BASIS OF PREPARATION

The following Management's Discussion and Analysis ("MD&A") dated April 30, 2014
is a review of the results of operations and the liquidity and capital resources
of Chelsea Oil and Gas Ltd. ("Chelsea" or the "Company") for the years ended
December 31, 2013 and 2012.

The audited consolidated financial statements of the Company and its
subsidiaries have been prepared in accordance with IFRS as issued by the
International Accounting Standards Board ("IASB"). This is the second reporting
period in which the Company has prepared its financial statements under IFRS and
the comparative information has been restated from US Generally Accepted
Accounting Principles ("USGAAP") to comply with IFRS. In these financial
statements, the term USGAAP refers to United States GAAP before the adoption of
IFRS. Reconciliations to IFRS from the previously published USGAAP financial
statements are shown in note 19 in the Company's financial statements for the
years ended December 31, 2013 and 2012.

The Company's significant accounting policies under IFRS are presented in note 4
in the audited consolidated financial statements. These policies have been
retrospectively and consistently applied except where specific exemptions
permitted an alternative treatment upon transition to IFRS in accordance with
IFRS 1, First-time Adoption of IFRS. The impact of the new standards, including
reconciliations presenting the change from previous USGAAP to IFRS as at January
1, 2012, and as at and for the year ended December 31, 2012, is presented in
note 19 in the Company's audited consolidated financial statements for the years
ended December 31, 2013 and 2012. AS A RESULT, FINANCIAL STATEMENTS PREVIOUSLY
FILED BY THE COMPANY WHEN IT WAS CALLED AUSTRALIAN-CANADIAN OIL ROYALTIES LTD.
("ACOR") COMPILED UNDER USGAAP ARE NOT DIRECTLY COMPARABLE TO THE ACCOMPANYING
AUDITED CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2013
AND 2012.

Certain information contained herein is forward-looking and based upon
assumptions and anticipated results that are subject to risks, uncertainties and
other factors. Should one or more of these uncertainties materialize or should
the underlying assumptions prove incorrect, actual results may vary materially
from those expected. For additional information, refer to Section 13 - Forward
Looking Statements.

ALL DOLLAR AMOUNTS HEREIN ARE US DOLLARS UNLESS OTHERWISE NOTED.


                                       1
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CHAIRMAN'S MESSAGE

I am pleased to provide this first annual report for Chelsea Oil and Gas Ltd. as
successor to Australian Canadian Oil Royalties Ltd.

Under its new management and Board, Chelsea has assembled a portfolio of oil and
gas assets onshore Australia, principally in Queensland. The assets, by design,
cover the oil and gas risk spectrum. We hold high risk, high reward
unconventional prospects in the Georgina Basin through medium risk conventional
light oil prospects in the Western Flank play of the Cooper Basin, and lower
risk development and exploitation of previous discoveries and newly defined
opportunities within the Surat-Bowen Basin, Australia's oldest petroleum
producing basin.

GEORGINA BASIN

Key to managing and controlling our largest asset, on October 1, 2013 was the
completion of our merger of International TME Resources Inc., which consolidated
ownership of the five million acre ATP 582. This permit includes one million
acres of land within the Toko Syncline of the southern Georgina Basin, the area
of the basin thought to be the most prospective for both conventional and
unconventional hydrocarbon accumulations. Further, a large portion of the permit
covers lands considered prospective for unconventional resources in the Triassic
strata of the Simpson Basin sequence.

Current industry activities in the Georgina Basin with potentially dramatic
impact on Chelsea include the recent announcement by Total S.A of the
acceleration of exploration expenditures on its immediately adjacent joint
venture with Central Petroleum Ltd., from $60 million to $95 million in the
first phase of a three phase programme of up to $190 million of expenditures.
Over 1,000 kilometers of new seismic data has recently been acquired and six
wells are expected to be drilled within the next year to core and evaluate the
unconventional potential of the Cambrian Arthur Creek formation in the Toko
Syncline. This drilling programme is slated to begin in May 2014.

Also, immediately adjacent to Chelsea's ATP 582 west boundary, Statoil ASA has
recently drilled and cased the first of up to five test wells to be drilled
under the terms of their re-structured farm-in with Petrofrontier Corp. Testing
and fracture stimulation is to be conducted on several wells to be determined
after completion of the drilling program. This brings Statoil's potential
expenditure to $205 million over three phases.

Statoil ASA had previously announced it would be increasing its expenditures and
concentrating its efforts in the area of the Owen wells. This area of the
Statoil/Petrofrontier permits is the most geologically similar to that of ATP
582 although it does not have the much thicker interval of prospective Cambrian
strata that is present in the Toko Syncline underlying Chelsea's ATP 582. This
brings Statoil's potential expenditure to $205 million over three phases.

                                       2
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COOPER BASIN

In the Cooper Basin "West Flank" light oil play, Chelsea has farmed out its
non-operated approximate 14% working interest in PEL's 112 and 444 for 3D
seismic and one well commitment to each of its two permits. To date, the 3D has
been completed on both permits and one unsuccessful exploratory well drilled on
PEL 112. The second earning well on PEL 444 is committed to be drilled in 2014.

SURAT-BOWEN BASIN

Chelsea's lower risk exploitation and development assets in the Surat-Bowen
Basin will be the focus of our efforts in the near future as we strive to build
cashflow. Our technical team believes that while the Surat-Bowen basins are
considered mature by Australian standards, much potential remains for not only
secondary and enhanced recovery projects as typically applied in North America,
but also for significant low risk exploration and development in areas and
formations previously considered uneconomic. Further, the fiscal regime for oil
and, especially natural gas is very attractive to producers. Unlike North
American where natural gas prices have fluctuated wildly the past decade, in the
continental market, Australia and particularly Queensland has a long term demand
for natural gas to supply its existing and planned LNG exports to Asia. This
Asian demand and the under- performance of the coal seam gas sector has resulted
in current prices of $8-$10 per GJ, projected to increase to $12 to $14 per GJ
over the next three to five years.

As a result of technical work the past year, and the current and projected
attractive product prices, increased portfolio value has been realized in the
form of potentially significant new Probable gas reserves being attributed to
our Louise PL 40 permit in the basin. As our technical evaluation of the basin
expands, additional new similar opportunities are being recognized and
inventoried.

The environment for oil is similarly attractive. The basin generally produces
very high quality oil that is priced according to Tapis, a Malaysian benchmark
crude that trades at a significant premium to both WTI and Brent crude. Further
pricing support comes from the fact that Australia is a significant net importer
of crude oil.

FUNDING AND CAPITALIZATION

While the Company's commitments are modest considering the scope and potential
of its asset base, funding is required to advance the projects. To this end,
Chelsea has initiated a financing process. Response from the investment
community has been very positive with regard to the Company's assets and in
spite of current challenging market conditions for small cap energy ventures, we
have received support from several investment banks and institutions. We are
optimistic that a significant financing can be secured in the near term,
sufficient to meet our work obligations and advance our current Surat-Bowen
projects to cash generating status. Particulars of any deals reached will of
course be promptly press released.

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SUMMARY

Management and the Board believe strongly in the quality and depth of Chelsea's
assets base. The pieces are in place and the catalysts exist to provide a
step-change in shareholder value. The "free exploration" being carried out by
Total S.A and Statoil ASA in the Georgina Basin is the most significant of these
at this time. The acceleration of Total S.A's expenditures of up to $190 million
on one side of Chelsea and up to $205 million by Statoil ASA on the other side
dwarf the modest $11 million work requirement over the next three years on
Chelsea's ATP 582 and attest to the prospectivity of ATP 582. Chelsea could be
considered an option play on the knowledge and expertise of two of the world's
foremost multi-national energy companies.

An additional catalyst is the potential to establish and grow early cash flow
from the Surat-Bowen assets. Current plans call for a capital expenditure of
approximately five million dollars on a 3D seismic survey, initiation of
pressure maintenance/water flood, at least one development oil well and one
recompletion to evaluate the newly defined Probable gas reserves on the Louise
permit.

In the Cooper Basin, a discovery on the farm-out of PEL's 112 and 444, while a
small working interest, would contribute significant cash flow, as typically
these wells produce at high rates. Also within the Cooper Basin, Chelsea holds
numerous legacy overriding royalty interests (ORRI), generally small in size but
covering extensive permit areas. These include a 0.175% ORR on the 2.9 Tcf
Hornet discovery. A $500 million development of this discovery is planned by
Senex, beginning in 2014. This is forecast to generate up to one million dollars
per year to Chelsea under full field development. In total, including offshore
Gippsland Basin, Chelsea holds varying ORRI's in over 12 million acres in
addition to its net approximate 5.2 million acres of high working interest
lands.

In closing, I thank all shareholders for their patience in the re-structuring of
the Company and the consolidation of its asset base. On behalf of the Board of
directors, I look forward to reporting on the exploitation of Chelsea's
impressive asset portfolio.

WILLIAM (BILL) PETRIE SR.

Executive Chairman
Chelsea Oil and Gas Ltd.



April 30, 2014


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1. OVERALL PERFORMANCE

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 International TME
Resources Inc. and was renamed Chelsea Oil and Gas Ltd. ("Chelsea" or the
"Company"). The address of the Company's head office is 3200, 500-4th Ave SW,
Calgary, AB Canada.

This MD&A and accompanying financial statements for the years ended December 31,
2013 and 2012 are the second continuing disclosures for Chelsea as a Canadian
Reporting Issuer. Chelsea previously reported under USGAAP and filed as a US
Reporting Issuer until June 30, 2012, when the Company became a Foreign Private
Issuer under applicable US Securities Laws.

With the completion of the acquisition of International TME Resources Inc.
("ITME") on October 1, 2013, the Company is now a Canadian Reporting Issuer and
will file its continuing disclosure obligations required under MI 51-105 Issuers
Quoted in the U.S. Over-The-Counter Markets.

2013 HIGHLIGHTS

o    Completed acquisition of ITME on October 1, 2013
o    Reconstituted Board and management of Company with seasoned industry
     professionals with considerable international exploration and development
     experience
o    Obtained NI 51-101 reserves and resource reports for the Company's Georgina
     and Surat Basin assets establishing resource potential in the Georgina
     Basin, and near-term cashflow from the existing discoveries in the Surat
     Basin
o    Initiated financing activities to fund the Company's 2014 / 15 capital
     programme

For the year ended December 31, 2013 the Company's main operations were the
closing of the ITME acquisition and establishment of the new Board and executive
management team. The team have been evaluating the Company's existing assets
throughout 2013, and obtained reserve and resource reports over a portion of the
Company's assets establishing resource potential in the Georgina Basin and
near-term cashflow from the existing discoveries in the Surat Basin.


                                       5
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2.       SELECTED FINANCIAL INFORMATION

ANNUAL INFORMATION FOR THE PAST THREE YEARS

------------------------------------ -------------------------------------------
($US)                                                DECEMBER 31
------------------------------------ -------------------------------------------
                                             2013           2012    2011 USGAAP
                                             IFRS           IFRS
------------------------------------ ------------- -------------- --------------
Total assets                           13,845,019     11,073,620      1,227,350
Current liabilities                     4,418,783      3,667,974        343,564
Revenue                                    98,805         79,325         28,551
Net loss for the year                   1,005,632        382,955        262,283
Basic and diluted loss per share           (0.02)         (0.01)         (0.01)
Weighted average shares outstanding    56,027,645     43,670,542     21,096,182
------------------------------------ ------------- -------------- --------------

SUMMARY QUARTERLY INFORMATION FOR THE PRIOR 8 QUARTERS
<TABLE>
<S>                      <C>       <C>         <C>      <C>       <C>        <C>                 <C>

------------------------ ---------------------------------------- ---------------------------------------
($US)                                     2013                                     2013
------------------------ ---------------------------------------- ---------------------------------------
------------------------ --------- --------- ---------- --------- --------- --------- --------- ---------
                         31-Dec    30-Sep    30-Jun     31-Mar    31-Dec    30-Sep    30-Jun    31-Mar
                           IFRS      IFRS     USGAAP     USGAAP     IFRS      IFRS     USGAAP    USGAAP
------------------------ --------- --------- ---------- --------- --------- --------- --------- ---------
Revenues                   60,795    10,798      8,910    18,302    32,148    16,728    21,696    19,781
Administrative expenses   144,687    12,198     13,167    24,023   219,961    33,206    70,273    73,408
Net loss                 (590,885) (199,845)   (29,512) (185,390) (227,187)  (21,582)  (45,438)  (69,878)
Net loss per share          (0.02)    (0.00)     (0.00)    (0.00)    (0.02)    (0.00)    (0.00)    (0.00)
(basic and diluted)
------------------------ --------- --------- ---------- --------- --------- --------- --------- ---------
</TABLE>

The Company's revenues are earned from its overriding royalties ("ORRI") on its
assets both onshore and offshore Australia. Revenues in 2013 are higher than
preceding years as new discoveries in the Cooper Basin were brought into
production in the second half of the year, with the first revenues received in
the fourth quarter.

Administrative costs in the fourth quarter, and for the year ended 2013 were
higher than comparative periods as the Company incurred legal, financial and
reserve auditor costs. Net loss in 2013 is attributable to the deemed value of
the share purchase warrants granted in January 2013 and interest expense on the
Company's shareholder loans. Net loss in prior periods is attributable to
interest on shareholder loans and general and administrative costs.

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3. RESULTS OF OPERATIONS

ROYALTY INCOME

For the year ended December 31, 2013, the Company received $98,805 (2012 -
$79,235) in freehold royalties from its ORRI both onshore and offshore
Australia. The increase over the prior year is royalties received from new
production in the Cooper Basin which were brought into production in the second
half of the year, with the first revenues received in the fourth quarter.

GENERAL AND ADMINISTRATIVE

For the year ended December 31, 2013, the Company incurred $194,075 (2012 -
$396,848) in general and administrative expenses. The decrease over the prior
year is attributable to reduced professional costs in the current year. Refer to
Item 8 for additional disclosures.

SHARE-BASED COMPENSATION

For the year ended December 31, 2013, the Company incurred $152,963 (2012 -
$nil) share-based compensation expense. 2013 share-based compensation is
associated with the 5.0 million warrants issued in January 2013 to management,
directors and consultants of the Company. Refer to Item 12 for additional
disclosures.

DEPLETION

For the year ended December 31, 2013, the Company incurred $28,431 in depletion
expense (2012 - $25,844). The increase in depletion over the prior year is
commensurate with the increased royalty revenue received over the same period.

FINANCE EXPENSE

For the year ended December 31, 2013, the Company incurred $362,199 in finance
expense (2012 - $23,010). The increase over the prior year is attributable to
interest on the shareholder loans associated with the Company's Surat Basin
acquisition in 2012. The $3.0 million loan note did not accrue interest in 2012,
the Company and debt holders amended the terms of the note in 2013 so that it
accrued interest at 8% per annum, compounded quarterly. This note is secured by
the Company's Surat Basin assets.

FOREIGN EXCHANGE LOSS (GAIN)

For the year ended December 31, 2013 the Company experienced a foreign exchange
loss of $344,066 (2012 - gain of $1,244). The loss is attributable to foreign
gain loss experienced on the translation of shareholder loans held by the
Company's wholly-owned subsidiaries.

CURRENT INCOME TAX EXPENSE

For the year ended December 31, 2013, the Company incurred current income tax
expenses of $22,703 (2012 - $17,822). Current income tax expense is derived from
withholding taxes on the Company's overriding and interest revenue received from
Australian sources. The increase over the prior year is commensurate with the
increase in revenue over the same period.


                                       7
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NET LOSS

For the year ended December 31, 2013, the Company incurred a net loss of
$1,005,632 (2012 - $382,955). The higher loss in 2013 is attributable to
share-based compensation, interest expenses and foreign exchange which were not
experienced in the prior year.

FOREIGN CURRENCY TRANSLATION ADJUSTMENT

Certain of the Company's wholly-owned subsidiaries operate exclusively in
Australia, and utilize the Australian dollar as their functional currency.
Assets and liabilities of the Company's Australian operations are translated
into US dollars at period end exchange rates while revenues and expenses are
translated using average rates for the period. Gains and losses from the
translation are deferred and included in accumulated other comprehensive loss on
the consolidated statements of financial position.

For the year ended December 31, 2013, the Company's foreign currency translation
adjustment was a loss of $697,679 (2012 - gain of $18,896). The adjustment in
2013 is attributable to the 12% decline in the Australian dollar compared to the
US dollar over the year. The Australian dollar was materially on par with the US
dollar throughout 2012, with limited translation impact experienced during the
period.

4. LIQUIDITY AND CAPITAL RESOURCES

At December 31, 2013, the Company had $94,998 (2012 - $72,120) in cash held in
the Company's bank accounts. The Company's total accounts receivable as at
December 31, 2013 was $91,301 (2012 - $331,010). The Company's trade accounts
payable and shareholder loans outstanding as at December 31, 2013 was $4.4
million (2012 - $3.7 million). The Company's net working capital deficiency as
at December 31, 2013 was $4.2 million (2012 - $3.2 million). Refer to Item 5 for
additional disclosures.

The Company has several projects in development. These include the exploration
of the Georgina Basin on ATP 582, the exploitation of the Surat-Bowen Basin
oilfields, and the development of the Louise gas field. In aggregate, the
Company's work commitments for these projects is estimated at $19.0 million
Australian dollars.

The Company has financed its operations to date through the issuance of common
shares to founding directors and other shareholders. Refer to 2013 Summary
herein and note 2 of the audited consolidated financial statements for the year
ended December 31, 2013 for additional discussion of the Company's liquidity and
capital resources, and note 18 for a summary of the Company's commitments.

5. TRANSACTIONS WITH RELATED PARTIES

Concurrent with the acquisition of the assets in the Surat Basin in Australia,
on March 1, 2012, the Company agreed to pay certain vendors $3.0 million within
12 months and 8.57 million shares of the Company. The loan was non-interest
bearing and was recorded at net present value of $2,770,084 and is secured by
the Company's Surat Basin assets.

At December 31, 2012 the net present value of the loan was $2,960,396. On March
25, 2013, the Company agreed to amend the terms of the loan so that interest
would accrue at 8% per annum, with interest accruing from September 1, 2012. On
February 28, 2014, the Company and the vendors agreed to extend the loan to
February 28, 2015.

                                       8
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During 2011, the Company borrowed funds from two stockholders to fund the
deposit for one of its exploration concessions in Australia. In the third
quarter of 2012, $109,250 plus accrued interest of $6,958 was repaid. The
remaining balance of $134,250 accrues interest at 12% per annum.

On January 9, 2013, the Company issued 5.0 million warrants to directors,
officers and consultants. These performance warrants have an exercise price of
$0.25 per warrant, but are only exercisable if the share price of the Company
exceeds $1.00 per share for ten consecutive trading days, with a minimum of
100,000 shares traded over the same period.

6. PROPOSED TRANSACTIONS

The Company has no undisclosed proposed transactions at April 30, 2014.

7. OFF-BALANCE SHEET TRANSACTIONS

As at April 30, 2014, the Company does not have any off-balance sheet
arrangements.

8. ADDITIONAL DISCLOSURE FOR COMPANIES WITHOUT SIGNIFICANT REVENUE

The following table sets forth a breakdown of material components of the general
and administration costs of the Company for the year ended December 31, 2013 and
2012:

------------------------ ------------------------- ---------------------------
                          YEAR ENDED DECEMBER 31,                  YEAR ENDED
($US)                                        2013           DECEMBER 31, 2012
------------------------ ------------------------- ---------------------------
Consulting fees                             2,206                      53,168
Professional fees                         168,765                     270,839
Office                                     23,104                      72,841
------------------------ ------------------------- ---------------------------
TOTAL                                     194,075                     396,848
------------------------ ------------------------- ---------------------------

9. RECENT ACCOUNTING PRONOUNCEMENTS

In November 2009, the IASB published IFRS 9 "Financial Instruments", which
covers the classification and measurement of financial assets as part of its
project to replace IAS 39 "Financial Instruments: Recognition and Measurement."
In October 2010, the requirements for classifying and measuring financial
liabilities were added to IFRS 9. Under this guidance, entities have the option
to recognize financial liabilities at fair value through earnings. If this
option is elected, entities would be required to reverse the portion of the fair
value change due to a company's own credit risk out of earnings and recognize
the change in other comprehensive income. The effective date for IFRS 9 has been
deferred to January 1, 2018. Early adoption will still be available and the
standard is required to be applied retrospectively. The Company is currently
evaluating the impact of adopting this new standard.

                                       9
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In December 2011, "Offsetting Financial Assets and Financial Liabilities",
amendments to IAS 32 "Financial Instruments: Presentation" was published by the
IASB. These amendments clarify the requirements for offsetting financial
instruments. The amendments introduce new disclosure requirements for financial
assets and financial liabilities that are offset in the statements of financial
position, or are subject to enforceable master netting arrangements or similar
agreements. The amendments to IAS 32 are applied retrospectively for annual
periods beginning on or after January 1, 2014. The Company is currently
evaluating the impact of adopting this new standard.

10.      FINANCIAL INSTRUMENTS

A financial instrument is any contract that gives rise to a financial asset of
one party and a financial liability or equity instrument of another party. A
financial asset is any asset that is (i) cash; (ii) a contractual right to
receive cash or another financial asset from another party; (iii) a contractual
right to exchange financial instruments with another party under conditions that
are potentially favourable to the entity; or (iv) an equity instrument of
another entity. A financial liability is any liability that is a contractual
obligation to (i) deliver cash or another financial asset to another party; or
(ii) exchange financial instruments with another party under conditions that are
potentially unfavourable to the entity. An equity instrument is any contract
that evidences a residual interest in the assets of an entity after deducting
all of its liabilities.

As at December 31, 2013, the Company's financial instruments are cash, accounts
receivable and accounts payable and accrued liabilities and shareholder loans.
The carrying amounts reflected in the balance sheet are carrying amounts and
approximate their fair values due to the short-term nature and negligible credit
losses.

The Company does not use derivative instruments or hedges to manage risks
because the Company's exposure to credit risk and interest rate risk is
insignificant.

11.      SUBSEQUENT EVENT

No material subsequent events identified from the date of the audited
consolidated financial statements to April 30, 2014.

12. DISCLOSURE OF OUTSTANDING SHARE DATA

AUTHORIZED AND ISSUED SHARE CAPITAL


CLASS              PAR VALUE       AUTHORIZED       ISSUED
------------------ --------------- ---------------- ---------------
Common                  Nil           Unlimited       64,056,876
Preferred               Nil           Unlimited          Nil
------------------ --------------- ---------------- ---------------
                                                     NUMBER OF SHARES
---------------------------------------------------- -----------------
BALANCE AT JANUARY 1, 2012                                 22,705,680
Issued to acquire exploration and evaluation assets        21,780,935
Issued for cash                                             5,473,385
Share issue costs                                                -
---------------------------------------------------- -----------------
BALANCE AT DECEMBER 31, 2012                               49,960,000
Issued to acquire exploration and evaluation assets            69,065
Issued to acquire ITME                                     13,977,811
Issued to former director                                      50,000
---------------------------------------------------- -----------------
BALANCE AT DECEMBER 31, 2013 AND APRIL 30, 2013            64,056,876
---------------------------------------------------- -----------------

                                       10
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STOCK OPTIONS

As at April 30, 2014, the Company has not issued any stock options under its
stock option plan.

WARRANTS

On January 9, 2013, the Company issued 5.0 million warrants to directors,
officers and consultants. These performance warrants have an exercise price of
$0.25 per warrant, but are only exercisable if the share price of the Company
exceeds $1.00 per share for ten consecutive trading days, with a minimum of
100,000 shares traded over the same period.

13.      FORWARD LOOKING STATEMENTS

Certain statements included or incorporated by reference in this MD&A constitute
forward-looking statements or forward-looking information under applicable
securities legislation. Such forward-looking statements or information are for
the purpose of providing information about Management's current expectations and
plans relating to the future. Readers are cautioned that reliance on such
information may not be appropriate for other purposes, such as making investment
decisions. Forward-looking statements or information typically contain
statements with words such as "anticipate", "believe", "expect", "plan",
"intend", "estimate", "propose", "project" or similar words suggesting future
outcomes or statements regarding an outlook. Forward-looking statements or
information in this MD&A include, but are not limited to, statements or
information with respect to: financing activities; business strategy and
objectives; development plans; exploration plans; acquisition and disposition
plans and the timing thereof; reserve quantities and the discounted present
value of future net cash flows from such reserves; future production levels;
capital expenditures; net revenue; operating and other costs; royalty rates and
taxes.

Forward-looking statements or information are based on a number of factors and
assumptions that have been used to develop such statements and information but
may prove to be incorrect. Although the Company believes that the expectations
reflected in such forward-looking statements or information are reasonable,
undue reliance should not be placed on forward-looking statements because the
Company can give no assurance that such expectations will prove to be correct.
In addition to other factors and assumptions that may be identified in this
MD&A, assumptions have been made regarding, among other things: the impact of
increasing competition; the general stability of the economic and political
environment in which the Company operates; the timely receipt of any required
regulatory approvals; the ability of the Company to obtain qualified staff,
equipment and services in a timely and cost-efficient manner; the ability of the
operator of the projects which the Company has an interest in to operate the
field in a safe, efficient and effective manner; the ability of the Company to
obtain financing on acceptable terms; field production rates and decline rates;
the ability to replace and expand oil and natural gas reserves through
acquisition, development or exploration; the timing and costs of pipeline,
storage and facility construction and expansion and the ability of the Company
to secure adequate product transportation; future oil and natural gas prices;
currency, exchange and interest rates; the regulatory framework regarding
royalties, taxes and environmental matters in the countries in which the Company
operates; and the ability of the Company to successfully market its oil and
natural gas products. Readers are cautioned that the foregoing list is not
exhaustive of all factors and assumptions that may have been used.

                                       11
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Forward-looking statements or information are based on current expectations,
estimates and projections that involve a number of risks and uncertainties that
could cause actual results to differ materially from those anticipated by the
Company and described in the forward-looking statements or information. The
risks and uncertainties that may cause actual results to differ materially from
the forward-looking statements or information include, among other things: the
ability of Management to execute its business plan; general economic and
business conditions; the risk of war or instability affecting countries or
states in which the Company operates; the risks of the oil and natural gas
industry, such as operational risks in exploring for, developing and producing
crude oil and natural gas; market demand; the possibility that government
policies or laws may change or governmental approvals may be delayed or
withheld; risks and uncertainties involving geology of oil and natural gas
deposits; the uncertainty of reserves estimates and reserves life; the ability
of the Company to add production and reserves through acquisition, development
and exploration activities; the Company's ability to enter into or renew
production sharing concession; potential delays or changes in plans with respect
to exploration or development projects or capital expenditures; the uncertainty
of estimates and projections relating to production (including decline rates),
costs and expenses; fluctuations in oil and natural gas prices, foreign
currency, exchange, and interest rate risks inherent in the Company's marketing
operations, including credit risk; uncertainty in amounts and timing of oil
revenue payments; health, safety and environmental risks; risks associated with
existing and potential future law suits and regulatory actions against the
Company; uncertainties as to the availability and cost of financing; and
financial risks affecting the value of the Company's investments. Readers are
cautioned that the foregoing list is not exhaustive of all possible risks and
uncertainties.

THE FORWARD-LOOKING STATEMENTS OR INFORMATION CONTAINED IN THIS MANAGEMENT'S
DISCUSSION AND ANALYSIS ARE MADE AS OF APRIL 30, 2014.

14. RISK FACTORS

OVERVIEW

The Company's primary business consists of the exploration and, if successful,
the development of oil and gas properties. There are a number of inherent risks
associated with the exploration, development and production of oil and gas
reserves, many of these risks are beyond the control of the Company.

Success  in  the junior oil and gas sector is measured by a Company's ability to
raise  funds  and  the  ability  to secure properties of merit. Not all of these
factors  are  within management's control. The ability to raise funds is in part
dependent  on  the  state  of the junior resource stock market, which in turn is
dependent  on  the  economic  climate,  oil and gas prices and perceptions as to
which  way the market is headed. The ability to secure properties of merit is in
large part dependent on management's contacts and the vitality of the sector.

                                       12
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FOR A DETAILED DISCUSSION OF THE COMPANY'S RISK FACTORS, REFER TO CHELSEA'S
ANNUAL INFORMATION FORM DATED MARCH 31, 2014 ON SEDAR.

BUSINESS RISKS AND RISK MITIGATION

There are a number of risks facing participants in the Canadian oil and gas
industry. Some of the risks are common to all businesses, while others are
specific to the sector. The most important of these risks are set out below,
together with the strategies Chelsea employs to mitigate and minimize these
risks.

INHERENT INDUSTRY RISKS - RISKS OF FAILING TO DISCOVER ECONOMIC RESERVES
ADDITIONS

The Company's strategies include focusing on oil and gas prone selected areas in
Australia, utilizing a team of highly qualified professionals with expertise and
experience in these areas, expanding operations in core areas, continuously
assessing new exploration opportunities to complement existing activities and
striving for a balance between higher risk exploratory drilling, and lower risk
development drilling.

Beyond exploration risk, there is the potential that the Company's oil and
natural gas reserves may not be economically produced at prevailing prices.
Chelsea minimizes this risk by generating exploration prospects internally,
targeting high quality projects and by attempting to operate the projects and
the infrastructure used to access the sales markets.

FINANCIAL COMMODITY PRICE, CAPITAL EXPENDITURE REQUIREMENTS, LIQUIDITY AND
ENVIRONMENTAL RISKS

Commodity prices are driven by supply, demand and market conditions outside the
Company's influence and control. Chelsea manages this risk by constantly
monitoring the forecasted price given by aggregators, banks, and third party
engineering firms.

Chelsea manages capital expenditures by two separate tracking systems: a
historical accounting system that records the actual costs and a perpetual
forecasting model that is constantly updated based on real-time information.

Chelsea's capital investment process is based on risk analysis to ensure capital
expenditures balance the objectives of immediate cash flow growth in development
activities and future cash flow from the discovery of reserves through
exploration.

It is likely that in the future, Chelsea will be required to raise additional
capital through debt and equity financings in order to fully realize the
Company's strategic goals and business plans. Chelsea's ability to raise
additional capital will depend on a number of factors, such as general economic
and market conditions that are beyond the Company's control. If the Company is
unable to obtain additional financing or to obtain it on favourable terms,
Chelsea may be required to forego attractive business opportunities. However, as
Chelsea strives to be the operator of virtually all of its operations at a high
working interest position, the Company should be able to be flexible in the
timing of operations to ensure a continued strong financial position. The
Company is committed to maintaining a strong balance sheet combined with an
adaptable capital expenditures program that can be adjusted to capitalize on or
reflect acquisition opportunities or a tightening of liquidity sources if
necessary.

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The Company manages operational risks by employing skilled professionals
utilizing leading-edge technology and conducting regular maintenance and
training programs. Chelsea has updated its operational emergency response plan
to address these operational issues. In addition, a comprehensive insurance
program is maintained to mitigate risks and protect against significant losses
where possible. Chelsea operates in accordance with all applicable environmental
legislation and strives to maintain compliance with such regulations.

15.      DEFINITIONS

In this Management's Discussion and Analysis the terms below have the meanings
indicated:

-------------------------------------------- -----------------------------------

           OIL AND NATURAL GAS LIQUIDS                  NATURAL GAS
-------------------------------------------- -----------------------------------

bbl       barrel                             Mcf     thousand cubic feet
--------- ---------------------------------- ------- ---------------------------

bbls      barrels                            Mmcf    million cubic feet
--------- ---------------------------------- ------- ---------------------------

Mbbls     thousand barrels                   Mcf/d   thousand cubic feet per day
--------- ---------------------------------- ------- ---------------------------

bbls/d    barrels per day                    NGLs    natural gas liquids
--------- ---------------------------------- ------- ---------------------------

boed      barrel of oil equivalent per day   Tcf     trillion cubic feet
--------- ---------------------------------- ------- ---------------------------

OTHER

API(degree)  an indication of the specific gravity of crude oil measured on the
             API gravity scale. Liquid petroleum with a specified gravity of
             28(degree) API or higher is generally referred to as light crude
             oil.

Boe          barrel of oil equivalent on the basis of 1 BOE to 6 Mcf of natural
             gas. BOEs may be misleading, particularly if used in isolation.
             A BOE conversion ratio of 1 BOE for 6 Mcf is based on an energy
             equivalency conversion method primarily applicable at the burner
             tip and does not represent a value equivalency at the wellhead.

Proved       means 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

Probable     means 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

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16.      USE OF ESTIMATES

The preparation of the consolidated financial statements in conformity with IFRS
requires management to make estimates and use judgment regarding the reported
amounts of assets and liabilities and disclosures of contingent assets and
liabilities as at the date of the consolidated financial statements and the
reported amounts of revenues, expenses and impairment during the year. By their
nature, estimates are subject to measurement uncertainty and changes in such
estimates in future periods could require a material change in the financial
statements. Accordingly, actual results may differ from the estimated amounts as
future confirming events occur. Significant estimates and judgments made by
management in the preparation of these consolidated financial statements are as
follows:

RECOVERABILITY OF ASSET CARRYING VALUES

The recoverability of development and production asset carrying values are
assessed at a cash generating unit ("CGU") level. Determination of what
constitutes a CGU is subject to management judgments. The asset composition of a
CGU can directly impact the recoverability of the assets included therein.
Judgments are required to assess when impairment indicators exist and impairment
testing is required. The key estimates used in the determination of cash flows
from oil and natural gas reserves include the following:

Reserves - Assumptions that are valid at the time of reserve estimation may
change significantly when new information becomes available. Changes in forward
price estimates, production costs or recovery rates may change the economic
status of reserves and may ultimately result in reserves being restated. The
Company has obtained an independently evaluated reserves report in respect of
certain of its assets which is complaint with the Canadian Securities
Administrators National Instrument 51-101: Standards for Disclosure for Oil and
Gas Activities.

Oil and natural gas prices - Forward price estimates are used in the cash flow
model. Commodity prices can fluctuate for a variety of reasons including supply
and demand fundamentals, inventory levels, exchanges rates, weather, and
economic and geopolitical factors.

Discount rate - The discount rate used to calculate the net present value of
cash flows is based on estimates of an approximate industry peer group weighted
average cost of capital. Changes in the general economic environment could
result in significant changes to this estimate.

DEPLETION AND DEPRECIATION

Amounts recorded for depletion and depreciation and amounts used for impairment
calculations are based on estimates of total proved and probable petroleum and
natural gas reserves and future development capital. By their nature, the
estimates of reserves, including the estimates of future prices, costs and
future cash flows, are subject to measurement uncertainty. Accordingly, the
impact to the consolidated financial statements in future periods could be
material.

Market conditions, discovery and analysis of site conditions and changes in
technology. Other provisions are recognized in the period when it becomes
probable that there will be a future cash outflow.

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SHARE-BASED COMPENSATION

Compensation costs recognized for share based compensation plans are subject to
the estimation of what the ultimate payout will be using pricing models such as
the Black-Scholes model which is based on significant assumptions such as
volatility, dividend yield and expected term. Several compensation plans are
also performance based and are subject to management's judgment as to whether or
not performance criteria will be met.

DEFERRED TAXES

Tax interpretations, regulations and legislation in the various jurisdictions in
which the Company operates are subject to change. As such income taxes are
subject to measurement uncertainty. Deferred income tax assets are assessed by
management at the end of the reporting period to determine the likelihood that
they will be realized from future taxable earnings.

17.      ADDITIONAL INFORMATION

Additional information relating to the Company can be found on SEDAR at
www.sedar.com and on EDGAR at www.sec.gov/edgar.shtml




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