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					                                                      MANAGEMENT’S DISCUSSION & ANALYSIS


6   O R C A E X P L O R AT I O N G R O U P I N C .
    2011 Q3 INTERIM REPORT




                                                     Management’s

                           Discussion
                             & Analysis
                             FORWARD LOOKING STATEMENTS
                             THIS MDA OF FINANCIAL CONDITIONS AND RESULTS OF OPERATIONS FOR THE THREE AND NINE MONTHS ENDED 30
                             SEPTEMBER 2011 SHOULD BE READ IN CONJUNCTION WITH THE AUDITED CONSOLIDATED FINANCIAL STATEMENTS
                             AND NOTES THERETO AS AT AND FOR THE YEAR ENDED 31 DECEMBER 2010. THIS MDA IS BASED ON THE INFORMATION
                             AVAILABLE ON 28 NOVEMBER 2011.

                             CERTAIN STATEMENTS IN THIS MD&A INCLUDING (I) STATEMENTS THAT MAY CONTAIN WORDS SUCH AS “ANTICIPATE”,
                             “COULD”, “EXPECT”, “SEEK”, “MAY”, “INTEND”, “WILL”, “BELIEVE”, “SHOULD”, “PROJECT”, “FORECAST”, “PLAN” AND SIMILAR
                             EXPRESSIONS, INCLUDING THE NEGATIVES THEREOF, (II) STATEMENTS THAT ARE BASED ON CURRENT EXPECTATIONS AND
                             ESTIMATES ABOUT THE MARKETS IN WHICH ORCA EXPLORATION OPERATES AND (III) STATEMENTS OF BELIEF, INTENTIONS
                             AND EXPECTATIONS ABOUT DEVELOPMENTS, RESULTS AND EVENTS THAT WILL OR MAY OCCUR IN THE FUTURE,
                             CONSTITUTE “FORWARD-LOOKING STATEMENTS” AND ARE BASED ON CERTAIN ASSUMPTIONS AND ANALYSIS MADE BY
                             ORCA EXPLORATION. FORWARD-LOOKING STATEMENTS IN THIS MD&A INCLUDE, BUT ARE NOT LIMITED TO, STATEMENTS
                             WITH RESPECT TO FUTURE CAPITAL EXPENDITURES, INCLUDING THE AMOUNT, NATURE AND TIMING THEREOF, NATURAL
                             GAS PRICES AND DEMAND.

                             SUCH FORWARD-LOOKING STATEMENTS ARE SUBJECT TO IMPORTANT RISKS AND UNCERTAINTIES, WHICH ARE DIFFICULT
                             TO PREDICT AND THAT MAY AFFECT ORCA EXPLORATION’S OPERATIONS, INCLUDING, BUT NOT LIMITED TO: THE IMPACT OF
                             GENERAL WORLD ECONOMIC CONDITIONS AND SPECIFCALLY IN TANZANIA, ITALY AND CANADA; INDUSTRY CONDITIONS,
                             INCLUDING THE ADOPTION OF NEW ENVIRONMENTAL, SAFETY AND OTHER LAWS AND REGULATIONS AND CHANGES IN
                             HOW THEY ARE INTERPRETED AND ENFORCED; SANCTITY OF CONTRACT; VOLATILITY OF OIL AND NATURAL GAS PRICES;
                             OIL AND NATURAL GAS PRODUCT SUPPLY AND DEMAND, RIG AVAILABILITY; RISKS INHERENT IN ORCA EXPLORATION’S
                             ABILITY TO GENERATE SUFFICIENT CASH FLOW FROM OPERATIONS, THIRD PARTY FINANCE OR ASSETS SALES TO MEET
                             ITS CURRENT AND FUTURE OBLIGATIONS; INCREASED COMPETITION; THE FLUCTUATION IN FOREIGN EXCHANGE OR
                             INTEREST RATES; STOCK MARKET VOLATILITY; COST POOL AUDITS AND OTHER FACTORS, MANY OF WHICH ARE BEYOND
                             THE CONTROL OF ORCA EXPLORATION.

                             ORCA EXPLORATION’S ACTUAL RESULTS, PERFORMANCE OR ACHIEVEMENTS COULD DIFFER MATERIALLY FROM THOSE
                             EXPRESSED IN, OR IMPLIED BY, THESE FORWARD-LOOKING STATEMENTS AND, ACCORDINGLY, NO ASSURANCE CAN BE
                             GIVEN THAT ANY OF THE EVENTS ANTICIPATED BY THE FORWARD-LOOKING STATEMENTS WILL TRANSPIRE OR OCCUR, OR
                             IF ANY OF THEM DO TRANSPIRE OR OCCUR, WHAT BENEFITS ORCA EXPLORATION WILL DERIVE THEREFROM. SUBJECT TO
                             APPLICABLE LAW, ORCA EXPLORATION DISCLAIMS ANY INTENTION OR OBLIGATION TO UPDATE OR REVISE ANY FORWARD-
                             LOOKING STATEMENTS, WHETHER AS A RESULT OF NEW INFORMATION, FUTURE EVENTS OR OTHERWISE. ALL FORWARD-
                             LOOKING STATEMENTS CONTAINED IN THIS DOCUMENT ARE EXPRESSLY QUALIFIED BY THIS CAUTIONARY STATEMENT.

                             NON-GAAP MEASURES
                             THE COMPANY EVALUATES ITS PERFORMANCE BASED ON FUNDS FLOW FROM OPERATING ACTIVITIES AND OPERATING
                             NETBACKS. FUNDS FLOW FROM OPERATING ACTIVITIES IS A NON-GAAP (GENERALLY ACCEPTED ACCOUNTING PRINCIPLES)
                             TERM THAT REPRESENTS CASH FLOW FROM OPERATIONS BEFORE WORKING CAPITAL ADJUSTMENTS. IT IS A KEY MEASURE
                             AS IT DEMONSTRATES THE COMPANY’S ABILITY TO GENERATE CASH NECESSARY TO ACHIEVE GROWTH THROUGH CAPITAL
                             INVESTMENTS. ORCA EXPLORATION ALSO ASSESSES ITS PERFORMANCE UTILIZING OPERATING NETBACKS. OPERATING
                             NETBACKS REPRESENT THE PROFIT MARGIN ASSOCIATED WITH THE PRODUCTION AND SALE OF ADDITIONAL GAS AND
                             IS CALCULATED AS REVENUES LESS PROCESSING AND TRANSPORTATION TARIFFS, GOVERNMENT PARASTATAL’S REVENUE
                             SHARE, OPERATING AND DISTRIBUTION COSTS FOR ONE THOUSAND STANDARD CUBIC FEET OF ADDITIONAL GAS. THIS IS
                             A KEY MEASURE AS IT DEMONSTRATES THE PROFIT GENERATED FROM EACH UNIT OF PRODUCTION, AND IS WIDELY USED
                             BY THE INVESTMENT COMMUNITY. THE OPERATIONS IN ITALY ARE CURRENTLY IN THE EXPLORATION PHASE AND HAVE NO
                             ASSOCIATED OPERATING REVENUE. THESE NON-GAAP MEASURES ARE NOT STANDARDISED AND THEREFORE MAY NOT BE
                             COMPARABLE TO SIMILAR MEASUREMENTS OF OTHER ENTITIES.

                             ADDITIONAL INFORMATION REGARDING ORCA EXPLORATION GROUP INC IS AVAILABLE UNDER THE COMPANY’S PROFILE
                             ON SEDAR AT www.sedar.com.
                                                   MANAGEMENT’S DISCUSSION & ANALYSIS


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                                                                                                                 O R C A E X P L O R AT I O N G R O U P I N C .
                                                                                                                 2011 Q3 INTERIM REPORT




BACKGROUND
Tanzania
Orca Exploration’s principal operating asset is its interest in a Production Sharing Agreement (“PSA”) with the Tanzania
Petroleum Development Corporation (“TPDC”) in Tanzania. This PSA covers the production and marketing of certain
gas from the Songo Songo gas field.
The gas in the Songo Songo field is divided between Protected Gas and Additional Gas. The Protected Gas is owned
by	TPDC	and	is	sold	under	a	20-year	gas	agreement	(until	July	2024)	to	Songas	Limited	(“Songas”).	Songas	is	the	owner	
of the infrastructure that enables the gas to be delivered to Dar es Salaam, namely a gas processing plant on Songo
Songo Island, 232 kilometers of pipeline to Dar es Salaam and a 16 kilometer spur to the Wazo Hill Cement Plant.
Songas utilizes the Protected Gas (maximum 45.1 MMcfd) as feedstock for its gas turbine electricity generators at
Ubungo, for onward sale to the Wazo Hill cement plant and for electrification of some villages along the pipeline
route. Orca Exploration receives no revenue for the Protected Gas delivered to Songas and operates the field and gas
processing plant on a ‘no gain no loss’ basis.
Orca Exploration has the right to produce and market all gas in the Songo Songo field in excess of the Protected Gas
requirements (“Additional Gas”).

Italy
During 2010 Orca Exploration farmed in to an oil appraisal block in the Adriatic Sea in Italy and to a gas exploration
prospect in the Po Valley in north eastern Italy.

PRINCIPAL TERMS OF THE TANZANIAN PSA AND RELATED AGREEMENTS
The	principal	terms	of	the	Songo	Songo	PSA	and	related	agreements	are	as	follows:
Obligations and restrictions
(a) The Company has the right to conduct petroleum operations, market and sell all Additional Gas produced and
    share the net revenue with TPDC for a term of 25 years expiring in October 2026.
(b) The PSA covers the two licenses in which the Songo Songo field is located (“Discovery Blocks”). The Proven
    Section is essentially the area covered by the Songo Songo field within the Discovery Blocks.
     N
(c)	 	 o	sales	of	Additional	Gas	may	be	made	from	the	Discovery	Blocks	if	in	Orca	Exploration’s	reasonable	judgment	
     such	sales	would	jeopardise	the	supply	of	Protected	Gas.	Any	Additional	Gas	contracts	entered	into	are	subject	to	
     interruption. Songas has the right to request that the Company and TPDC obtain security reasonably acceptable
     to Songas prior to making any sales of Additional Gas from the Discovery Block to secure the Company’s and
     TPDC’s obligations in respect of Insufficiency (see (d) below).
	       I
        	n	 June	 2008,	 the	 Company	 initialled	 a	 long	 term	 power	 contract	 (Amended	 and	 Restated	 Gas	 Agreement	
        (“ARGA”) with the electricity utility, Tanzania Electric Supply Company (“TANESCO”), the owner of the Ubungo
        power plant, Songas Limited and the Ministry of Energy and Minerals (“MEM”). This contract covers the supply of
        gas to the sixth turbine at the Ubungo power plant and provides for a maximum of approximately 9 MMcfd until
        July	2024.	The	ARGA	provides	clarification	of	the	Protected	Gas	volumes	and	removes	all	terms	dealing	with	the	
        security of the Protected Gas and the consequences of any insufficiency to a new Insufficiency Agreement (“IA”).
        The IA specifies terms under which Songas may demand cash security in order to keep them whole in the event
        of a Protected Gas insufficiency. Once the IA is signed, it will govern the basis for determining security. Under
        the provisional terms of the IA, when it is calculated that funding is required, the Company shall fund an escrow
        account	at	a	rate	of	US$2/Mmbtu	on	all	industrial	Additional	Gas	sales	out	of	its	and	TPDC’s	share	of	revenue	
        and TANESCO shall contribute the same amount on Additional Gas sales to the power sector. The funds provide
        security for Songas in the event of an insufficiency of Protected Gas. The Company is actively monitoring the
        reservoir and does not anticipate that a liability will occur in this respect.
(d) “Insufficiency” occurs if there is insufficient gas from the Discovery Blocks to supply the Protected Gas require-
    ments or is so expensive to develop that its cost exceeds the market price of alternative fuels at Ubungo.
        Where there have been third party sales of Additional Gas by Orca Exploration and TPDC from the Discovery
        Blocks	prior	to	the	occurrence	of	the	Insufficiency,	Orca	Exploration	and	TPDC	shall	be	jointly	liable	for	the	Insuf-
        ficiency and shall satisfy its related liability by either replacing the Indemnified Volume (as defined in (e) below) at
        the Protected Gas price with natural gas from other sources; or by paying money damages equal to the difference
        between:	(a)	the	market	price	for	a	quantity	of	alternative	fuel	that	is	appropriate	for	the	five	gas	turbine	electricity	
        generators at Ubungo without significant modification together with the costs of any modification; and (b)
        the	sum	of	the	price	for	such	volume	of	Protected	Gas	(at	US$0.55/Mmbtu)	and	the	amount	of	transportation	
        revenues previously credited by Songas to the electricity utility, TANESCO, for the gas volumes.
                                                     MANAGEMENT’S DISCUSSION & ANALYSIS


8   O R C A E X P L O R AT I O N G R O U P I N C .
    2011 Q3 INTERIM REPORT



                             (e) The “Indemnified Volume” means the lesser of the total volume of Additional Gas sales supplied from the
                                 Discovery Blocks prior to an Insufficiency and the Insufficiency Volume. “Insufficiency Volume” means the volume
                                 of natural gas determined by multiplying the average of the annual Protected Gas volumes for the three years
                                 prior to the Insufficiency by 110% and multiplied by the number of remaining years (initial term of 20 years) of
                                 the power purchase agreement entered into between Songas and TANESCO in relation to the five gas turbine
                                 electricity generators at Ubungo from the date of the Insufficiency.
                                    As discussed in (c) above an Insufficiency Agreement has been negotiated with TPDC, Songas and TANESCO that
                                    reduces these potential liabilities. The Insufficiency Agreement is expected to be signed at the same time as the
                                    long term power contracts.
                             Access and development of infrastructure
                             (f) The Company is able to utilise the Songas infrastructure including the gas processing plant and main pipeline to
                                 Dar es Salaam. Access to the pipeline and gas processing plant is open and can be utilised by any third party who
                                 wishes to process or transport gas. Ndovu Resources Limited which has a small gas field on Songo Songo Island
                                 has indicated that it wishes to tie its production into the gas processing plant. This is currently under discussion.
                                    Songas is not required to incur capital costs with respect to additional processing and transportation facilities
                                    unless the construction and operation of the facilities are, in the reasonable opinion of Songas, financially viable.
                                    If Songas is unable to finance such facilities, Songas shall permit the seller of the gas to construct the facilities at its
                                    expense, provided that, the facilities are designed, engineered and constructed in accordance with good pipeline
                                    and oilfield practices.
                             Revenue sharing terms and taxation
                             (g) 75% of the gross revenues less processing and pipeline tariffs and direct sales taxes in any year (“Net Revenues”)
                                 can be used to recover past costs incurred. Costs recovered out of Net Revenues are termed “Cost Gas”.
                                    The Company pays and recovers costs of exploring, developing and operating the Additional Gas with two
                                    exceptions:	 (i)	 TPDC	 may	 recover	 reasonable	 market	 and	 market	 research	 costs	 as	 defined	 under	 the	 PSA	
                                    (US$1.4	million	for	the	nine	months	ended	30	September	2011	for	marketing	costs	that	have	been	incurred	
                                    by TPDC since start up); and (ii) TPDC has the right to elect to participate in the drilling of at least one well for
                                    Additional Gas in the Discovery Blocks for which there is a development program as detailed in the Additional
                                    Gas	plans	as	submitted	to	the	MEM	(“Additional	Gas	Plan”)	subject	to	TPDC	being	able	to	elect	to	participate	
                                    in a development program only once and TPDC having to pay a proportion of the costs of such development
                                    program by committing to pay between 5% and 20% of the total costs (“Specified Proportion”). If TPDC does
                                    not notify the Company within 90 days of notice from the Company that the MEM has approved the Additional
                                    Gas Plan, then TPDC is deemed not to have elected. If TPDC elects to participate, then it will be entitled to a
                                    rateable proportion of the Cost Gas and their profit share percentage increases by the Specified Proportion for
                                    that development program.
                                    TPDC has indicated that they wish to exercise their right to ‘back in’ to the field development by contribut-
                                    ing 20% of the cost of SS-10 and the cost of future new wells in return for a 20% increase in the profit share
                                    percentage for the production emanating from these wells. The implications and workings of the ‘back in’ are
                                    currently being discussed with TPDC and there may be the need for reserve and accounting modifications
                                    once these discussions are concluded. For the purpose of the reserves certification as at 31 December 2010, it
                                    has been assumed that they will ‘back in’ for 20% for all future new wells and other developments and this is
                                    reflected in the Company’s net reserve position.
                             (h) On 27 February 2009, the energy regulator, Energy and Water Utility Regulatory Authority (“EWURA”), issued
                                 an	order	that	saw	the	introduction	of	a	flat	rate	tariff	of	US$0.59/mcf	from	1	January	2010.	The	Company’s	long	
                                 term gas price to the power sector as set out in the initialed ARGA and the Portfolio Gas Sales Agreement is
                                 based on the price of gas at the wellhead. As a consequence, the Company is not impacted by the changes to
                                 the tariff paid to Songas or other operators in respect of sales to the power sector.
                                    During Q2 2011, the Company signed a Re-rating Agreement with TANESCO and Songas to run the gas
                                    processing plant at levels of up to 110 MMcfd (the pipeline and pressure requirements at the Ubungo power
                                    plant restrict the infrastructure capacity to a maximum of 102 MMcfd). Under the terms of the Re-rating
                                    Agreement,	the	Company	effectively	pays	an	additional	tariff	of	US$0.30/mcf	for	sales	between	70	MMcfd	and	
                                    90	MMcfd	and	US$0.40/mcf	for	volumes	above	90	MMcfd	in	addition	to	the	tariff	of	US$0.59/mcf	payable	to	
                                    Songas as set by the energy regulator, EWURA.
                                              MANAGEMENT’S DISCUSSION & ANALYSIS


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                                                                                                        O R C A E X P L O R AT I O N G R O U P I N C .
                                                                                                        2011 Q3 INTERIM REPORT




(i) The cost of maintaining the wells and flowlines is split between the Protected Gas and Additional Gas users in
    proportion to the volume of their respective sales. The cost of operating the gas processing plant and the pipeline
    to Dar es Salaam is covered through the payment of the pipeline tariff.
      P
(j)		 	 rofits	on	sales	from	the	Proven	Section	(“Profit	Gas”)	are	shared	between	TPDC	and	the	Company,	the	proportion	
      of which is dependent on the average daily volumes of Additional Gas sold or cumulative production.
      The Company receives a higher share of the net revenues after cost recovery, the higher the cumulative production
      or the average daily sales, whichever is higher. The Profit Gas share is a minimum of 25% and a maximum of 55%.

           Average daily sales           Cumulative sales               TPDC’s share              Company’s share
            of Additional Gas            of Additional Gas              of Profit Gas               of Profit Gas
                 MMCFD                          BCF                          %                           %
                 0 - 20                      0 – 125                         75                         25
               > 20 <= 30                 > 125 <= 250                       70                         30
               > 30 <= 40                 > 250 <= 375                       65                          35
               > 40 <= 50                 > 375 <= 500                       60                         40
                  > 50                        > 500                          45                          55

      For Additional Gas produced outside of the Proven Section, the Company’s Profit Gas share is 55%.
      Where TPDC elects to participate in a development program, their profit share percentage increases by
      the Specified Proportion (for that development program) with a corresponding decrease in the Company’s
      percentage share of Profit Gas.
      The Company is liable to income tax. Where income tax is payable, there is a corresponding deduction in the
      amount of the Profit Gas payable to TPDC.
(k) Additional Profits Tax is payable where the Company has recovered its costs plus a specified return out of Cost
    Gas	revenues	and	Profit	Gas	revenues.	As	a	result:	(i)	no	Additional	Profits	Tax	is	payable	until	the	Company	
    recovers its costs out of Additional Gas revenues plus an annual return of 25% plus the percentage change
    in the United States Industrial Goods Producer Price Index (“PPI”); and (ii) the maximum Additional Profits Tax
    rate is 55% of the Company’s Profit Gas when costs have been recovered with an annual return of 35% plus PPI
    return. The PSA is, therefore, structured to encourage the Company to develop the market and the gas fields in
    the knowledge that the profit share can increase with larger daily gas sales and that the costs will be recovered
    with a 25% plus PPI annual return before Additional Profits Tax becomes payable. Additional Profits Tax can
    have	a	significant	negative	impact	on	the	project	economics	if	only	limited	capital	expenditure	is	incurred.
Operatorship
(l)   The Company is appointed to develop, produce and process Protected Gas and operate and maintain the
      gas production facilities and processing plant, including the staffing, procurement, capital improvements,
      contract maintenance, maintain books and records, prepare reports, maintain permits, handle waste, liaise
      with the Government of Tanzania (“GoT”) and take all necessary safe, health and environmental precautions all
      in accordance with good oilfield practices. In return, the Company is paid or reimbursed by Songas so that the
      Company neither benefits nor suffers a loss as a result of its performance.
(m) In the event of loss arising from Songas’ failure to perform and the loss is not fully compensated by Songas, Orca
    Exploration, or insurance coverage, then Orca Exploration is liable to a performance and operation guarantee
    of	US$2.5	million	when	(i)	the	loss	is	caused	by	the	gross	negligence	or	wilful	misconduct	of	the	Company,	its	
    subsidiaries	or	employees,	and	(ii)	Songas	has	insufficient	funds	to	cure	the	loss	and	operate	the	project.
                                                      MANAGEMENT’S DISCUSSION & ANALYSIS


10   O R C A E X P L O R AT I O N G R O U P I N C .
     2011 Q3 INTERIM REPORT




                              Results for the quarter ended 30 September 2011
                              OPERATING VOLUMES
                              The additional gas sales volumes for the quarter were 5,161 MMcf or 56.1 MMcfd. This represents an increase of 40%
                              over Q3 2010. The total additional gas sales volumes for the nine months ended 30 September 2011 were 12,158
                              MMcf or 56.1 MMcfd an increase of 24% over 2010.
                              The	Company	sales	volumes	were	split	between	the	industrial	and	power	sectors	as	follows:


                                                                                          Three months ended                 Nine months ended
                                                                                      30-Sep 2011   30-Sep 2010         30-Sep 2011    30-Sep 2010
                              GROSS SALES VOLUME (MMCF):
                              Industrial sector                                               719             770            1,957            1,817
                              Power sector                                                  4,442           2,918           10,201           8,014
                                  Total volumes                                             5,161           3,688           12,158           9,831


                              GROSS DAILY SALES VOLUME (MMCFD):
                              Industrial sector                                                7.8             8.4              7.2             6.7
                              Power sector                                                   48.3            31.7              37.4            29.4
                              Total daily sales volume                                       56.1            40.1              44.6            36.1

                              Industrial sector
                              Industrial sales volumes of 719 MMcf (7.8 MMcfd) were recorded in Q3 2011. This represents a decrease of 7% over
                              the 770 MMcf (8.4 MMcfd) recorded in Q3 2010. The decrease is mainly due to the fall in the level of Additional Gas
                              supplied to Kiln 4 at Tanzania Portland Cement Company’s (“TPCC”) Wazo Hill cement plant compared to Q3 2010.
                              Industrial sales volumes for the nine months ended 30 September 2011 have increased by 8% to 1,957 MMcf from
                              1,817 MMcfd in 2010, with the sales to Wazo Hill cement plant accounting for 30% of the total sales recorded in
                              2011 and 2010.
                              Power sector
                              Power sector sales volumes of 4,442 MMcf (48.3 MMcfd) were recorded in Q3 2011. This represents an increase of
                              52% over the 2,918 MMcf (31.7 MMcfd) recorded in Q3 2010. The volume of gas consumed by the Ubungo power
                              plant has remained at a similar level during both periods. The increase is a consequence of the supply of gas to the
                              Symbion	power	plant	that	was	re-commissioned	in	July	2011	in	response	to	the	Tanzanian	power	crisis.	
                              Power sector sales volumes for the nine months ended 30 September 2011 have increased by 27% to 10,201 MMcf
                              from 8,014 MMcf in 2010. The increase is the result of a decline in the use of hydro-generation due to the low levels
                              of rain fall experienced during 2011 and a general increase in electricity demand.

                              COMMODITY PRICES
                              The	commodity	prices	achieved	in	the	different	sectors	during	the	quarter	are	shown	in	the	table	below:

                                                                                          Three months ended                Nine months ended
                                                                                           30-Sep          30-Sep           30-Sep          30-Sep
                                                                                             2011            2010             2011            2010
                              US$/MCF

                              Average sales price
                              Industrial sector                                            10.47            8.01             10.10            8.80
                              Power sector                                                   2.76           2.63              2.69            2.59
                              Weighted average price                                        3.83            3.75              3.88            3.74

                              Industrial sector
                              The	average	sales	price	achieved	for	Q3	2011	was	US$10.47/mcf	compared	to	US$8.01/mcf	in	Q3	2010.	The	increase	
                              in sales price is a consequence of the fluctuation in the world energy prices. The price of gas for the industrial sector
                              (with the exception of the gas supplied to the Wazo Hill cement plant) continued to be set at a discount to the price
                              of Heavy Fuel Oil (“HFO”) in Dar es Salaam. The supply of gas to Wazo Hill has a fixed pricing structure that was set
                              by reference to their alternative fuel supply which is imported coal.
                                                  MANAGEMENT’S DISCUSSION & ANALYSIS


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                                                                                                                  O R C A E X P L O R AT I O N G R O U P I N C .
                                                                                                                  2011 Q3 INTERIM REPORT




Power sector
The	average	sales	price	to	the	power	sector	was	US$2.76/mcf	for	the	quarter	compared	to	US$2.63/mcf	in	Q3	2010.	
The increase in the sales price over Q3 2010 is primarily due to the annual inflationary increase in respect of the
supply of Additional Gas to the power sector.

OPERATING REVENUE
Under the terms of the PSA with TPDC, Orca Exploration is responsible for invoicing, collecting and allocating the
revenue from Additional Gas sales.
Orca	Exploration	is	able	to	recover	all	costs	incurred	on	the	exploration	development	and	operations	of	the	project	
out of 75% of the Net Revenues (“Cost Gas”). Any costs not recovered in any period are carried forward to be
recovered out of future revenues. In addition the recovery of the cost pool in 2011 has meant that TPDC is now able
to	recover	its	past	marketing	costs	(US$1.4	million	for	the	nine	months	ended	30	September	2011,	of	which	US$0.6	
million was paid during the quarter) in accordance with the terms of the PSA. The TPDC marketing costs are treated
as a reduction to the Company’s Cost Gas entitlement.
The Additional Gas sales volumes were in excess of 50 MMcfd for Q3 2011 and 30 MMcfd for Q3 2010. Consequently,
the revenue less cost recovery share of revenue (“Profit Gas”) was 55% for Q3 2011 and 35% for Q3 2010 in
accordance with the terms of the PSA.
From	 January	 2011,	 a	 significant	 proportion	 of	 the	 gas	 production	 was	 from	 a	 deemed	 TPDC	 backed	 in	 well	
(namely SS10). As a result TPDC’s profit share increased by 20% for the production attributable to the SS-10 well.
The Company is still to resolve the details of the back in with TPDC.
Orca	Exploration	had	partial	cost	recovery	through	the	quarter	and	accordingly	was	allocated	68.3%	(Q3	2010:	85.0%)	
of	the	Net	Revenues	as	follows:

                                                                 Three months ended                    Nine months ended
                                                                  30-Sep        30-Sep                 30-Sep         30-Sep
                                                                    2011          2010                   2011           2010
FIGURES IN US$’000

Gross sales revenue                                               19,754           13,829              47,154            36,722
Gross tariff for processing plant
and pipeline infrastructure                                       (3,717)           (2,199)            (7,845)            (5,824)
Gross revenue after tariff                                        16,037           11,630             39,309             30,898

Analysed as to:
Company Cost Gas                                                   4,844             8,722             17,150            23,173
Company Profit Gas                                                 6,113             1,156              9,801              2,842
Company operating revenue                                         10,957             9,878             26,951            26,015
TPDC share of revenue                                              5,080             1,752             12,358              4,883
                                                                  16,037           11,630             39,309             30,898
The	 Company’s	 revenue	 reported	 for	 the	 quarter	 amounted	 to	 US$10,457,000	 after	 adjusting	 the	 Company’s	
operating	revenue	of	US$10,957,000	by:
•	   U
     	 S$659,000	for	current	income	tax.	The	Company	is	liable	for	income	tax	in	Tanzania,	but	the	income	tax	is	
     recoverable out of TPDC’s share of Profit Gas when the tax is payable. To account for this, revenue is increased
     to reflect the current income tax charge.
•	   U
     	 S$1,159,000	 for	 the	 deferred	 effect	 of	 Additional	 Profits	Tax.	This	 tax	 is	 considered	 a	 royalty	 and	 is	 netted	
     against revenue.
The Company’s cost pool in Tanzania was fully recovered during Q2 2011 as a result of strong sales revenue and
relatively low capital expenditure levels. This has resulted in a reduction in the percentage of net revenue attribut-
able to the Company prior to any significant expenditure on the drilling activities, which is due to commence at
significant levels in Q4 2011. As a result of the recovery of the cost pool during Q2 2011, the cost gas recovery was
limited to 30% of the gross revenue after tariff in Q3 2011 compared to 75% in Q3 2010.
                                                      MANAGEMENT’S DISCUSSION & ANALYSIS


12   O R C A E X P L O R AT I O N G R O U P I N C .
     2011 Q3 INTERIM REPORT



                              Revenue	per	the	income	statement	may	be	reconciled	to	the	operating	revenue	as	follows:

                                                                                              Three months ended                  Nine months ended
                                                                                               30-Sep        30-Sep               30-Sep         30-Sep
                                                                                                 2011          2010                 2011           2010
                              FIGURES IN US$’000
                              Industrial sector                                                7,517            6,165             19,763          15,994
                              Power sector                                                    12,237            7,664             27,391          20,728
                              Gross sales revenue                                             19,754           13,829             47,154          36,722
                              Processing and transportation tariff                             (3,717)          (2,199)           (7,845)          (5,824)
                              TPDC share of revenue                                           (5,080)           (1,752)          (12,358)          (4,883)
                              Company operating revenue                                       10,957            9,878            26,951           26,015
                              Additional Profits Tax                                           (1,159)           (205)            (1,946)            (565)
                              Current	income	tax	adjustment                                      659            1,302              3,388            2,801
                              Revenue                                                         10,457           10,975            28,393           28,251

                              PROCESSING AND TRANSPORTATION TARIFF
                              A	 flat	 rate	 gas	 processing	 and	 transportation	 tariff	 of	 US$0.59/mcf	 was	 introduced	 on	 1	 January	 2010	 that	 will	
                              enable Songas to make a rate of return on their investment as determined by EWURA. This rate should remain
                              constant	 until	 the	 completion	 of	 the	 Songas	 Expansion	 project	 which	 is	 scheduled	 for	 completion	 in	 Q1	 2013.	
                              The	Company	will	pass	on	any	increase	or	decrease	in	the	EWURA	approved	charges	to	TANESCO/Songas	in	respect	
                              of sales to the power sector. This protocol insulates Orca Exploration from any increases in the gas processing and
                              pipeline infrastructure costs.
                              During Q2 2011, the Company signed a Re-rating Agreement with TANESCO and Songas to run the gas processing
                              plant at levels of up to 110 MMcfd (the pipeline and pressure requirements at the Ubungo power plant restrict the
                              infrastructure	capacity	to	a	maximum	of	102	MMcfd).	The	agreement	was	ratified	in	July	2011	and	the	Company	will	
                              effectively	pay	an	additional	tariff	of	US$0.30/mcf	for	sales	between	70	MMcfd	and	90	MMcfd	and	US$0.40/mcf	for	
                              volumes	above	90	MMcfd	in	addition	to	the	tariff	of	US$0.59/mcf	payable	to	Songas	as	set	by	the	energy	regulator,	
                              EWURA.	The	charge	for	the	additional	tariff	was	US$0.7	million	for	the	quarter.	

                              PRODUCTION AND DISTRIBUTION EXPENSES
                              The well maintenance costs are allocated between Protected and Additional Gas based on the proportion of their
                              respective	sales	during	the	quarter.	The	total	costs	for	the	maintenance	for	the	quarter	was	US$690,000	(Q3	2010:	
                              US$229,000)	and	US$401,000	(Q3	2010:	US$104,000)	was	allocated	for	the	Additional	Gas.	The	total	cost	for	well	
                              maintenance	for	the	nine	months	ended	30	September	2011	was	US$612,000	compared	to	US$336,000	for	the	nine	
                              months ended 30 September 2010. The increase in cost during the quarter is the result of an extensive maintenance
                              program.
                              Other field and operating costs include an apportionment of the annual PSA licence costs, regulatory fees and some
                              costs associated with the evaluation of the reserves and the cost of personnel that are not recoverable from Songas.
                              Distribution costs represent the direct cost of maintaining the ring-main distribution pipeline and pressure reduction
                              station (security, insurance and personnel).
                              TPDC and MEM have indicated that they wish Orca to unbundle the downstream distribution business in Tanzania.
                              The methodology for this is still to be discussed in detail with both TPDC and MEM.
                              These	costs	are	summarized	in	the	table	below:

                                                                                              Three months ended                  Nine months ended
                                                                                               30-Sep        30-Sep               30-Sep         30-Sep
                                                                                                 2011          2010                 2011           2010
                              FIGURES IN US$’000
                              Share of well maintenance                                          401              104                612              336
                              Other field and operating costs                                    776              593              1,484            1,447
                                                                                               1,177              697              2,096            1,783
                              Ringmain distribution pipeline                                     623              601              1,913            1,681
                              Production and distribution expenses                             1,800            1,298              4,009           3,464
                                            MANAGEMENT’S DISCUSSION & ANALYSIS


                                                                                                                                                      13
                                                                                                     O R C A E X P L O R AT I O N G R O U P I N C .
                                                                                                     2011 Q3 INTERIM REPORT




OPERATING NETBACKS
The netback per mcf before general and administrative costs, overheads, tax and Additional Profits Tax may be
analysed	as	follows:	

                                                          Three months ended               Nine months ended
                                                           30-Sep        30-Sep            30-Sep         30-Sep
                                                             2011          2010              2011           2010
(AMOUNTS IN US$/MCF)

Gas price – industrial                                     10.47            8.01            10.10               8.80
Gas price – power                                           2.76            2.63             2.69               2.59
Weighted average price for gas                              3.83            3.75             3.88               3.74
Processing and transportation tariff                        (0.72)         (0.60)           (0.65)             (0.59)
TPDC share of revenue                                       (0.98)         (0.48)           (1.02)             (0.50)
Net selling price                                           2.13            2.67             2.21               2.65
Well maintenance and other operating costs                  (0.23)         (0.19)           (0.17)             (0.18)
Ringmain distribution pipeline                              (0.12)         (0.16)           (0.16)             (0.17)
Operating netback                                           1.78            2.32             1.88               2.30
The	operating	netback	for	the	quarter	was	US$1.78/mcf	(Q3	2010:	US$2.32/mcf ).	
The	increase	in	the	net	selling	price	from	US$3.75/mcf	to	US$3.83/mcf	in	Q3	2011	is	a	consequence	of	the	increase	
in the gas price achieved in both the industrial and power markets.
During Q3 2011, TPDC’s share of revenue increased as a result of greater production from a backed in well, SS-10
and the recovery of past marketing costs in accordance with the terms of the PSA. As a result of the recovery of the
cost pool during Q2 2011 and the relatively modest capital expenditure during Q3 2011, the cost recovery during
the quarter was limited to 30% of the Net Revenues. This has been reflected in the overall decline in the operating
net	back	from	US$2.32/mcf	to	US$1.78/mcf.
The increase in well maintenance and other operating costs is a consequence of the additional chemicals used in
the cleaning of the gas processing flow-lines during the quarter.

GENERAL AND ADMINISTRATIVE EXPENSES
The	general	and	administrative	expenses	(“G&A”)	may	be	analysed	as	follows:
                                                          Three months ended               Nine months ended
                                                           30-Sep        30-Sep            30-Sep         30-Sep
                                                             2011          2010              2011           2010
FIGURES IN US$’000

Employee costs                                             1,401            534             3,106             1,550
Consultants                                                  648            638             1,970             1,973
Travel and accommodation                                     276             197             718                606
Communications                                                27              31               80                 74
Office                                                       333            342             1,165               871
Insurance                                                    106              83             378                246
Auditing and taxation                                         45              39             261                 127
Depreciation                                                  95              48             187                 157
Reporting, regulatory and corporate                          345            252              765                480
                                                           3,276           2,164           8,630             6,084
Marketing costs including legal fees                         537            456             1,352             1,323
New ventures                                                  93              77             351                 145
Stock based compensation                                     493              43             403                329
General and administrative expenses                        4,399           2,740          10,736              7,881
The	G&A	includes	the	costs	of	running	the	gas	business	in	Tanzania	the	majority	of	which	is	recoverable	as	Cost	Gas.
G&A	averaged	approximately	US$1.33	million	per	month	for	Q3	2011	compared	to	US$0.90	million	in	Q3	2010.	
G&A	per	mcf	decreased	to	US$0.78/mcf	(Q3	2010:	US$0.74/mcf ).
                                                      MANAGEMENT’S DISCUSSION & ANALYSIS


14   O R C A E X P L O R AT I O N G R O U P I N C .
     2011 Q3 INTERIM REPORT



                              The main variances for both the quarter and the nine months ended 30 September 2011 compared to the same
                              periods	in	2010	are	summarized	below:
                              Employee costs
                              The increase in employment costs is mainly a consequence of fees and bonus payments incurred in relation to
                              senior executive appointments and their respective salaries. During the last six months, there has been a one of
                              step change in the G&A costs as the management has been upgraded in anticipation of the extensive development
                              program in Tanzania.
                              Office costs
                              The level of office costs have increased due to the establishment of a separate serviced office.
                              Reporting, regulatory and corporate finance
                              The increase of costs is a result of the strengthening of the board of directors and the amount of time incurred in
                              relation to the development of the drilling programme in response to the corrosion tubing issue identified in Q4 2010.
                              Stock based compensation
                              A total of 2,807,400 stock options were outstanding at the end of Q3 2011 compared to 2,557,400 at the end of Q3
                              2010. In August 2011, 250,000 stock options were issued to a newly appointed officer. These options have an exercise
                              price	of	Cdn$4.75	a	term	of	five	years	and	fully	vest	on	the	date	of	grant,	a	charge	of	US$0.61million	was	recorded	as	
                              a one off charge in relation to these options. A total of 240,000 options were exercised in Q4 2010. Of the outstanding
                              options, 1,662,400 were issued in 2004 and were fully expensed by the end of 2007. A total of 895,000 were issued
                              during 2007 and were fully expensed by the end of 2010. All the stock options have been valued using the Black-
                              Scholes option pricing model.
                              A	total	of	930,000	stock	appreciation	rights	were	in	issue	at	the	end	of	Q3	2011	and	Q3	2010.	In	June	2010,	225,000	
                              stock	appreciation	rights	were	issued	to	the	new	non	executive	directors	with	an	exercise	price	of	Cdn$4.20	per	share.	
                              These rights have a five year term and vest in five equal instalments, the first fifth vesting on the anniversary of the
                              grant date. As stock appreciation rights are settled in cash they are re-valued at each reporting date using the Black-
                              Scholes option pricing model. As at 30 September 2011 the following assumptions were used; stock volatility 42%
                              to	72%,	a	risk	free	interest	rate	between	1.50%	and	2.50%	and	a	closing	stock	price	of	Cdn$3.80.	A	reduction	to	stock	
                              based	compensation	of	US$0.17	million	was	recorded	in	Q3	2011	compared	to	a	reduction	of	US$0.03	million	in	Q3	
                              2010	in	respect	of	these	stock	appreciation	rights,	resulting	in	a	total	reduction	of	US$0.26	million	being	recorded	for	
                              the	nine	months	ending	30	September	2011,	compared	to	a	total	credit	of	US$0.28	million	in	2010.	
                              The	total	stock	based	compensation	charges	may	be	summarized	as	follows:

                                                                                          Three months ended                Nine months ended
                                                                                           30-Sep        30-Sep             30-Sep         30-Sep
                                                                                             2011          2010               2011           2010
                              FIGURES IN US$’000

                              Stock options                                                  661               73              661             607
                              Stock appreciation rights                                      (168)            (30)            (258)           (278)
                                                                                             493               43              403             329
                                               MANAGEMENT’S DISCUSSION & ANALYSIS


                                                                                                                                                             15
                                                                                                            O R C A E X P L O R AT I O N G R O U P I N C .
                                                                                                            2011 Q3 INTERIM REPORT




NET FINANCE COSTS
The loss on foreign exchange experienced in the quarter is a result of the 9% appreciation of the US Dollars against
the Tanzanian Shilling. Despite the gas sales price being denominated in US Dollars, the invoices are submitted in
Tanzanian Shillings. Therefore, there is an exchange exposure between the time that the invoices are submitted and
the date that the payment is received. The small gain in foreign exchange is a result of the strengthening US Dollar
against the British pound sterling which has resulted in gains following the payment of trade payables.
The	movement	in	net	financing	charge	is	summarized	in	the	table	below:

                                                              Three months ended                 Nine months ended
                                                               30-Sep        30-Sep              30-Sep         30-Sep
                                                                 2011          2010                2011           2010
FIGURES IN US$’000

FINANCE INCOME
Interest income                                                     1              18                  5                 21
Foreign exchange gain                                               –                –               32                  27
                                                                    1              18                 37                 48
FINANCE CHARGES
Overdraft charges                                                   –               (1)                –                 (13)
Foreign exchange loss                                            (323)           (227)            (1,068)             (939)
                                                                 (323)           (228)            (1,068)             (952)
Net finance costs                                                (322)           (210)            (1,031)             (904)

TAXATION
Income Tax
Under the terms of the PSA with TPDC, the Company is liable for income tax in Tanzania at the corporate tax rate of
30%. However, where income tax is payable, this is recovered from TPDC by deducting an amount from TPDC’s profit
share.	This	is	reflected	in	the	accounts	by	adjusting	the	Company’s	revenue	by	the	appropriate	amount.	
As at 30 September 2011, there were temporary differences between the carrying value of the assets and liabilities for
financial reporting purposes and the amounts used for taxation purposes under the Income Tax Act 2004. Applying
the	30%	Tanzanian	tax	rate,	the	Company	has	recognised	a	deferred	tax	liability	of	US$14.2	million	which	includes	an	
additional	deferred	future	income	tax	charge	of	US$0.7	million	for	the	quarter	(Q3	2010:	US$1.1	million),	resulting	in	a	
total	charge	for	the	nine	months	to	30	September	of	US$1.4	million	and	US$2.9	million	for	2011	and	2010	respectively.	
This tax has no impact on cash flow until it becomes a current income tax at which point the tax is paid to the
Commissioner of Taxes and recovered from TPDC’s share of Profit Gas.
Additional Profits Tax
Under the terms of the PSA, in the event that all costs have been recovered with an annual return of 25% plus the
percentage change in the United States Industrial Goods Producer Price Index, an Additional Profits Tax (“APT”) is
payable.
The Company provides for APT by forecasting the total APT payable as a proportion of the forecast Profit Gas over the
term	of	the	PSA	license.	The	effective	APT	rate	has	been	calculated	to	be	20%.	Accordingly,	US$1.2	million	(Q3	2010:	
US$0.2	million)	has	been	netted	off	revenue	for	the	quarter	ended	30	September	2011.	The	total	adjustment	for	the	
nine	months	to	30	September	was	US$2.0	million	and	US$0.6	million	for	2011	and	2010	respectively.
Management does not anticipate that any APT will be payable in 2011, as the forecast revenues will not be sufficient
to cover the un-recovered costs brought forward as inflated by 25% plus the PPI percentage change and the forecast
expenditures for 2011. The actual APT that will be paid is dependent on the achieved value of the Additional Gas sales
and the quantum and timing of the operating costs and capital expenditure program.
The	 APT	 can	 have	 a	 significant	 negative	 impact	 on	 the	 Songo	 Songo	 project	 economics	 as	 measured	 by	 the	 net	
present	value	of	the	cash	flow	streams.	Higher	revenue	in	the	initial	years	leads	to	a	rapid	payback	of	the	project	
costs and consequently accelerates the payment of the APT that can account for up to 55% of the Company’s profit
share. Therefore, the terms of the PSA rewards the Company for incurring capital expenditure in advance of revenue
generation.
                                                        MANAGEMENT’S DISCUSSION & ANALYSIS


16   O R C A E X P L O R AT I O N G R O U P I N C .
     2011 Q3 INTERIM REPORT



                              DEPLETION AND DEPRECIATION
                              The Natural Gas Properties are depleted using the unit of production method based on the production for the
                              period as a percentage of the total future production from the Songo Songo proven reserves. As at 31 December
                              2010 the proven reserves as evaluated by the independent reservoir engineers, McDaniel & Associates Consultants
                              Ltd	were	369.2	Bcf	on	a	life	of	licence	basis.	This	resulted	in	a	depletion	charge	of	US$0.47/mcf	in	Q1,	Q2	and	Q3	
                              2011.	The	depletion	charge	in	2010	for	the	quarter	and	for	the	nine	months	ended	30	September	2010	was	US$0.31/
                              mcf.
                              Non-Natural	Gas	Properties	are	depreciated	as	follows:

                              Leasehold improvements                                                       Over remaining life of the lease
                              Computer equipment                                                           3 years
                              Vehicles                                                                     3 years
                              Fixtures and fittings                                                        3 years

                              CARRYING AMOUNTS OF ASSETS
                              Capitalised costs are periodically assessed to determine whether it is likely that such costs will be recovered in the
                              future. To the extent that these capitalised costs are unlikely to be recovered in the future, they are written off and
                              charged to earnings.

                              EARNINGS PER SHARE
                              The calculation of basic earnings per share is based on the profit after taxation and comprehensive income for the
                              nine	months	ended	30	September	2011	of	US2.7	million	(2010:	US$8.1	million)	and	a	weighted	average	number	of	
                              Class	A	and	Class	B	shares	outstanding	during	the	period	of	34,689,810	(2010:	29,734,123).
                              In	computing	the	diluted	earnings	per	share,	the	dilutive	effect	of	the	stock	options	was	1,168,558	(2010:	1,085,338)	
                              shares. These are added to the weighted average number of common shares outstanding for the year to date
                              resulting in a diluted weighted average number of Class A and Class B shares of 35,858,368 for nine months ended
                              30 September, 2011.
                              The decline in the earnings per share during 2011 is a result of the decrease in net revenue as a consequence of
                              the recovery of the costs pool in Tanzania and an overall rise in the level of general administrative expenditure as
                              personnel were recruited to enhance the management team.

                              FUNDS GENERATED BY OPERATIONS
                              Funds	flow	from	operating	activities	were	US$5.3	million	for	the	quarter	ended	30	September	2011	(Q3	2010:	US$6.3	
                              million)	and	US$13.6	million	for	the	nine	months	ended	30	September	2011	(2010:	US$15.8	million).

                                                                                              Three months ended               Nine months ended
                                                                                               30-Sep        30-Sep            30-Sep         30-Sep
                                                                                                 2011          2010              2011           2010
                              FIGURES IN US$’000

                              (Loss)/profit	after	taxation                                       (54)          3,578            2,719          8,126
                              Adjustments         (1)
                                                                                               5,377           2,710          10,843           7,703
                              Funds from operations
                              before working capital changes                                   5,323           6,288          13,562          15,829
                              Working	capital	adjustments (1)                                 (7,780)         (1,720)         (10,381)         (6,071)
                              Net cash flows (used in)/from operating activities              (2,457)          4,568            3,181          9,758
                              Net cash flows used in investing activities                     (3,772)           (880)          (5,852)        (2,043)
                              Net cash flows from financing activities                             –             234                –            234
                              Effect of change in foreign exchange                              (132)            (62)            (216)           (313)
                              Net (decrease)/increase in cash
                              and cash equivalents                                            (6,361)          3,860           (2,887)         7,636
                              (1)
                                    PLEASE REFER TO CONDENSED CONSOLIDATED INTERIM STATEMENT OF CASH FLOWS FOR BREAKDOWN

                              The	US$6.4	million	decrease	in	cash	and	cash	equivalents	for	the	quarter	is	a	result	of	the	US$5.3	million	of	funds	
                              from	 operations	 before	 working	 capital	 changes	 during	 the	 quarter	 being	 offset	 by	 US$3.9	 million	 of	 capital	
                              expenditure	incurred	together	with	an	overall	net	cash	reduction	of	US$7.8	million	in	working	capital.
                                                 MANAGEMENT’S DISCUSSION & ANALYSIS


                                                                                                                                                                   17
                                                                                                                  O R C A E X P L O R AT I O N G R O U P I N C .
                                                                                                                  2011 Q3 INTERIM REPORT




The	US$2.9	million	decrease	in	cash	and	cash	equivalents	for	the	nine	months	ended	30	September	2011	is	a	result	
of	 the	 US$13.6	 million	 of	 funds	 generated	 from	 operations	 before	 working	 capital	 changes	 during	 the	 period	
being	offset	by	US$6.9	million	of	capital	expenditure,	together	with	an	overall	net	decrease	in	working	capital	of	
US$9.6	million.

CAPITAL EXPENDITURE
Gross	capital	expenditures	amounted	to	US$3.9	million	during	the	quarter	(Q3	2010:	US$1.2	million)	and	US$6.9	
million	for	the	nine	months	ended	30	September	2011	(2010:	US$2.3	million).
The	capital	expenditure	may	be	analysed	as	follows:

                                                                 Three months ended                  Nine months ended
                                                                  30-Sep        30-Sep               30-Sep         30-Sep
                                                                    2011          2010                 2011           2010
FIGURES IN US$’000

Geological and geophysical and well drilling                      3,463              502              5,486                  991
Pipelines and infrastructure                                        421              692               1,147               1,199
Power development                                                     –                 6                 15                     6
Other equipment                                                      41                23               226                  150
                                                                  3,925            1,223              6,874               2,346
Geological and geophysical and well drilling
A	total	of	US$0.3	million	of	expenditure	was	incurred	during	the	quarter	on	geological	and	geophysical	studies	
in	 preparation	 for	 the	 drilling	 of	 Songo	 Songo	 West	 in	 2012.	 The	 balance	 of	 US$2.4	 million	 was	 spent	 on	 the	
preparation for the drilling of the SS-A well.
A	further	US$0.8	million	was	incurred	in	relation	to	contractual	payments	under	the	terms	of	the	farm	in	on	Petro-
celtic’s Central Adriatic B.R268.RG Permit offshore Italy. The exploration well is due to be drilled in Q1 2012.
Pipelines and infrastructure
A	total	of	US$0.4	million	of	expenditure	was	incurred	during	the	quarter	on	the	development	of	the	compressed	
natural	gas	(“CNG”)	distribution	facilities,	the	long	term	expansion	project	and	connection	of	new	customers	to	the	
low pressure distribution network in Dar es Salaam.

WORKING CAPITAL
Working	capital	as	at	30	September	2011	was	US$58.4	million	compared	with	US$52.4	million	as	at	31	December	
2010	and	may	be	analyzed	as	follows:
                                                                                                               As at
                                                                                                      30-Sep              31-Dec
                                                                                                        2011                2010
FIGURES IN US$’000

Cash and cash equivalents                                                                            42,632              45,519
Trade and other receivables                                                                          26,883              13,583
Taxation receivable                                                                                   4,066                4,009
Prepayments                                                                                             511                  409
                                                                                                     74,092              63,520
Trade and other payables                                                                             14,407                9,156
Taxation payable                                                                                      1,316                2,000
Working capital                                                                                      58,369              52,364
The level of working capital has increased by 11% during the nine months ended 30 September 2011.
The	 majority	 of	 the	 Company’s	 cash	 is	 held	 in	 US	 dollars	 in	 Mauritius.	There	 are	 no	 restrictions	 in	Tanzania	 for	
converting Tanzania Shillings into US dollars.
Of	the	total	trade	and	other	receivables	at	30	September	2011,	US$22.4	million	was	represented	by	trade	receivables	
(Q4	2010:	US$11.9	million)	and	US$4.4	million	other	receivables	(Q4	2010:	US$1.7	million).	The	increase	in	other	
receivables is a consequence of the increased amount owed by Songas for the operation of the Songo Songo
gas	processing	plant,	together	with	costs	that	are	due	to	be	repaid	by	Songas	if	the	long	term	expansion	project	
reaches financial close.
                                                      MANAGEMENT’S DISCUSSION & ANALYSIS


18   O R C A E X P L O R AT I O N G R O U P I N C .
     2011 Q3 INTERIM REPORT



                              Under the contract terms with the industrial customers, the Additional Gas payments must be received within 30
                              days	of	the	month	end.	As	at	30	September	2011,	US$6.0	million	(Q4	2010:	US$4.2	million)	of	trade	receivables	was	
                              due from the industrial customers. A significant part of this amount has been subsequently received. The balance
                              of	US$16.4	million	(Q4	2010:	US$7.7	million)	in	trade	receivables	is	made	up	of	amounts	due	from	the	two	power	
                              customers, TANESCO and Songas.
                              The contracts with Songas and the electricity utility, TANESCO, accounted for 62% of the Company’s operating
                              revenue during the quarter. Songas’ financial security is heavily reliant on the payment of capacity and energy
                              charges by TANESCO. Despite having a history of delayed payments, TANESCO has previously settled in full the
                              outstanding balance subsequent to each quarter end. However, there is concern that TANESCO’s financial position
                              may be deteriorating as it funds the emergency oil fired generation at a time of declining receipts for electricity
                              from parastatal bodies.

                              CONTRACTUAL OBLIGATIONS AND COMMITTED CAPITAL INVESTMENT

                              Contractual Obligations
                              Protected Gas
                              Under	the	terms	of	the	original	gas	agreement	for	the	Songo	Songo	project	(“Gas	Agreement”),	in	the	event	that	
                              there	is	a	shortfall/insufficiency	in	Protected	Gas	as	a	consequence	of	the	sale	of	Additional	Gas,	then	the	Company	
                              is	liable	to	pay	the	difference	between	the	price	of	Protected	Gas	(US$0.55/Mmbtu)	and	the	price	of	an	alternative	
                              feedstock multiplied by the volumes of Protected Gas up to a maximum of the volume of Additional Gas sold (59.8
                              Bcf as at 30 September 2011).
                              The Gas Agreement may be amended by an initialled Amended and Restated Gas Agreement (“ARGA”). The ARGA
                              provides clarification of the Protected Gas volumes and removes all terms dealing with the security of the Protected
                              Gas and the consequences of any insufficiency to a new Insufficiency Agreement (“IA”). The IA specifies terms under
                              which Songas may demand cash security in order to keep them whole in the event of a Protected Gas insufficiency.
                              Once the new IA is signed, it will govern the basis for determining security. Under the provisional terms of the IA,
                              when	it	is	calculated	that	funding	is	required,	the	Company	shall	fund	an	escrow	account	at	a	rate	of	US$2/Mmbtu	
                              on all industrial Additional Gas sales out of its and TPDC share of revenue, and TANESCO shall contribute the same
                              amount on Additional Gas sales to the power sector. The funds provide security for Songas in the event of an insuf-
                              ficiency of Protected Gas. The Company is actively monitoring the reservoir and does not anticipate that a liability
                              will occur in this respect.
                              Back in
                              TPDC has indicated that they wish to exercise their right to ‘back in’ to the field development by contributing 20%
                              of the costs of the future new wells including SS-10 in return for a 20% increase in the profit share percentage
                              for the production emanating from these wells. The implications and workings of the ‘back in’ are currently being
                              discussed with TPDC and there may be the need for additional reserve and accounting modifications once these
                              discussions are concluded. For the purpose of the reserves certification, it has been assumed that they will ‘back
                              in’ for 20% for all future new drilling activities and other developments and this is reflected in the Company’s net
                              reserve position.
                              Re-rating Agreement
                              During Q2 2011, the Company signed a Re-rating Agreement with TANESCO and Songas Limited to increase the gas
                              processing capacity to a maximum of 110 MMcfd (the pipeline and pressure requirements at the Ubungo power
                              plant restrict the infrastructure capacity to a maximum of 102 MMcfd). Under the terms of the Re-rating Agreement,
                              the	Company	effectively	pays	an	additional	tariff	of	US$0.30/mcf	for	sales	between	70	MMcfd	and	90	MMcfd	and	
                              US$0.40/mcf	for	volumes	above	90	MMcfd	in	addition	to	the	tariff	of	US$0.59/mcf	payable	to	Songas	as	set	by	the	
                              energy regulator, EWURA.
                              Under the terms of this agreement, the Company agreed to indemnify Songas Limited for damage to its facilities
                              caused	by	the	re-rating,	up	to	a	maximum	of	US$15	million,	but	only	to	the	extent	that	this	was	not	already	covered	
                              by indemnities from TANESCO or Songas’ insurance policies.
                              Portfolio Gas Sales Agreement
                              On	17	June	2011,	a	long	term	(to	June	2023)	Portfolio	Gas	Sales	Agreement	(PGSA)	was	signed	between	Orca	and	
                              TANESCO.	Under	the	PGSA,	Orca	is	obligated,	subject	to	infrastructure	capacity,	to	sell	a	maximum	of	approximately	
                              37 MMcfd for use in any of TANESCO’s current power plants except those operated by Songas at Ubungo. The
                              current	basic	wellhead	gas	price	of	US$	2.02/	Mcf	is	due	to	increase	to	approximately	US$2.70/Mcf	on	1	July	2012.	
                                              MANAGEMENT’S DISCUSSION & ANALYSIS


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                                                                                                        O R C A E X P L O R AT I O N G R O U P I N C .
                                                                                                        2011 Q3 INTERIM REPORT




Operating leases
The Company has two office rental agreements in Dar es Salaam, expiring on 30 November 2012 and 31 October
2013	at	an	annual	rental	of	US$122,000	and	US$110,000	per	annum	respectively.

Capital Commitments
Italy
On 31 May 2010, the Company signed an agreement with Petroceltic International plc (“Petroceltic”) to farm in on
Petroceltic’s Central Adriatic B.R268.RG Permit offshore Italy. The farm-in commits the Company to fund 30% of the
Elsa-2	appraisal	well	up	to	a	maximum	of	US$11.5	million	to	earn	a	15%	working	interest	in	the	permit.	Thereafter,	
the Company will fund all future costs relating to the well and the permit in proportion to its participating interest.
The Company has also agreed to pay Petroceltic fifteen per cent (15%) of the back costs in relation to the well up to
a	maximum	of	US$0.5	million.
Petroceltic were due to spud the Elsa-2 well prior to 31 October 2010, but the Italian government passed a decree,
following the blowout of the Macondo well in the U.S., that prevented the drilling in the Italian seas within 5 nautical
miles of the coastline and within 12 nautical miles around the perimeter of protected Marine Parks. In view of this,
Petroceltic suspended the permit until such time as the Ministry of Environment issues a decree of environmental
compatibility	for	the	drilling	program.	The	project	in	currently	on	hold	and	Orca	is	not	liable	to	any	costs	associated	
with the drilling of Elsa-2 until a rig contract is signed.
In December 2010, the Company announced a farm in to Northern Petroleum (UK) Limited’s Longastrino Block in
the Po Valley Basin. Under the terms of the farm in, Orca will pay 100% of the costs of the La Tosca well up to a cap
of approximately €4.3 million and 70% of the costs thereafter. If the well is tested and completed, Orca will earn an
additional 5% (taking it to 75%) by paying 100% of the testing costs up to €1.3 million and 75% thereafter. The La
Tosca	exploration	well	will	be	drilled	in	Q1	2012	at	an	estimated	cost	to	the	Company	of	US$8	million.	
Songo Songo
In Q4 2010 the Company reduced the deliverability from its Songo Songo wells following receipt of results of a
corrosion logging survey. Orca suspended production from SS-5, reduced flow rates from the other wells and
expedited the tie in of the new onshore well SS10. As of today, the Company can produce approximately 113
MMcfd though this is currently restricted by the infrastructure capacity to a maximum of 102 MMcfd.
The original corrosion model forecast that the offshore well, SS-9 (currently producing in the region of 30 MMcfd),
would have to be taken out of production at the end of Q1 2012. A new corrosion logging was undertaken shortly
after the quarter end to confirm its condition and it is now considered that the well may stay on production until
31	May	2012	subject	to	further	logging	in	March	2012.		The	Company	has	mobilised	a	rig	to	Songo	Songo	Island	
and a new onshore deviated well will be drilled by the time that SS-9 is taken off production. The total cost of the
SS-A	well	is	estimated	at	US$28	million.		The	Company	has	also	committed	to	purchasing	long	lead	items	for	Songo	
Songo	West	exploration	well,	the	SS-10	enhancement	and	one	further	well	at	a	total	cost	of	US$11	million.	
Cost Sharing Agreement
In	 January	 2011,	 the	 Company	 signed	 a	 cost	 sharing	 agreement	 with	 Songas,	 whereby	 the	 Company	 will	 fund	
50%	of	the	costs	of	getting	the	Songas	Expansion	Project	(installation	of	gas	processing	capacity	and	downstream	
compression	to	increase	the	infrastructure	capacity	to	140	MMcfd)	to	financial	close,	up	to	a	maximum	of	US$2.4	
million. In the event that the costs are approved by the regulator, EWURA, the funds will be repaid by Songas at
financial	close.	To	date	the	company	has	funded	US$0.6	million	of	expenditure.	If	the	project	is	not	successful,	the	
costs will be recoverable by the Company under the terms of the PSA as a cost pool expense with TPDC and will be
written off to the income statement.
Funding
There is sufficient funding to complete the 2011 drilling programme, namely the drilling of the new onshore deviated
well, SS-A. The Company’s 2012 work programme in Tanzania, other than the completion of SS-A and the purchase
of long lead items, will be dependent on a resolution of the matters raised by the Parliamentary Committee and
an improvement in TANESCO’s payment performance which has deteriorated in the last few months. If these are
resolved,	the	Company	will	need	to	secure	a	financing	facility	and/or	raise	new	equity	to	complete	the	expansion	
program in Tanzania on a timely basis.
                                                      MANAGEMENT’S DISCUSSION & ANALYSIS


20   O R C A E X P L O R AT I O N G R O U P I N C .
     2011 Q3 INTERIM REPORT



                              CONTINGENCIES
                              Unbundling
                              TPDC and MEM have indicated that they wish Orca to unbundle the downstream distribution business in Tanzania.
                              The methodology for this is still to be discussed in detail with both TPDC and MEM.
                              Access to infrastructure
                              Ndovu Resources Limited, with support from TPDC and the Ministry of Energy, has indicated that they wish to tie
                              into the gas processing plant on Songo Songo Island and sell up to 10 MMcfd from their Kiliwani North field. The
                              Company is currently in discussions with Ndovu to agree appropriate commercial terms.
                              Cost recovery
                              The Company’s cost pool in Tanzania was recovered early in Q2 2011. This resulted in a reduction in the percentage
                              of net revenue attributable to the Company that will continue until there is any significant expenditure on the
                              drilling activities which will commence in Q4 2011. TPDC is still in the process of auditing the historic cost recovery
                              pool	and	is	currently	disputing	US$34	million	of	costs	that	have	been	allocated	to	the	cost	pool	for	the	period	2002	
                              through to 2009. The Company contends that the disputed costs were appropriately incurred on the Songo Songo
                              project	in	accordance	with	the	terms	of	the	PSA.	To	the	extent	that	it	is	not	possible	to	resolve	the	differences	with	
                              TPDC, the Company will utilise the extensive dispute mechanisms outlined in the PSA which includes international
                              arbitration.

                              RELATED PARTY TRANSACTIONS
                              One	of	the	non	executive	Directors	is	a	partner	at	a	law	firm.	During	the	quarter,	the	Company	incurred	US$37,500	
                              (Q3	 2010:	 US$30,000)	 to	 this	 firm	 for	 services	 provided	 on	 legal	 services,	 resulting	 in	 a	 total	 expenditure	 of	
                              US$112,500	for	the	nine	months	ended	30	September	2011	(2010:	US$105,000)	.	The	transactions	with	this	related	
                              party were made at the exchange amount.

                              SHAREHOLDERS’ EQUITY AND OUTSTANDING SHARE DATA
                                                                                                                                           As at
                                                                                                                                  30-Sep           31-Dec
                                                                                                                                    2011             2010
                              NUMBER OF SHARES (‘000)

                              SHARES OUTSTANDING
                              Class A shares                                                                                       1,751            1,751
                              Class B shares                                                                                     32,939            32,939
                                                                                                                                 34,690            34,690
                              CONVERTIBLE SECURITIES
                              Stock options                                                                                       2,807             2,557
                              Diluted Class A and Class B shares                                                                 37,497            37,247


                              WEIGHTED AVERAGE
                              Class A and Class B shares                                                                         34,690            30,795
                              Convertible securities
                              Stock options                                                                                        1,169            1,098
                              Weighted average diluted Class A and Class B shares                                                35,859            31,893


                              Shares outstanding
                              A total of 250,000 Class B stock options were issued in August 2011.
                              No Class B shares were purchased under the normal course issuer bid.
                              As at 28 November 2011, there were a total of 1,751,195 Class A shares and 32,872,315 Class B shares outstanding.
                                                MANAGEMENT’S DISCUSSION & ANALYSIS


                                                                                                                                                      21
                                                                                                     O R C A E X P L O R AT I O N G R O U P I N C .
                                                                                                     2011 Q3 INTERIM REPORT




SUMMARY QUARTERLY RESULTS
The	following	is	a	summary	of	the	results	for	the	Company	for	the	last	eight	quarters:

FIGURES IN US$’000
                                                  2011                             2010                        2009
EXCEPT WHERE OTHERWISE STATED            Q3          Q2        Q1        Q4       Q3        Q2       Q1           Q4
FINANCIAL
Revenue                               10,457      8,296     9,640    10,557   10,975      9,017    8,259        7,837
(Loss)/profit	after	taxation	            (54)      383      2,390     1,885    3,578      2,608    1,940       1,564
Operating netback (US$/MCF)             1.78       1.80      2.16      2.28      2.32      2.37     2.19         2.29
Working capital                      58,369      57,070    55,759    52,364   30,093     24,941   20,891      16,385
Shareholders’ equity                 101,563    100,956   100,573    98,183   77,827     73,942   70,955     68,860
Earnings per share – basic (US$)        0.00       0.01      0.07      0.05      0.12      0.09     0.07         0.06
Earnings per share – diluted (US$)      0.00       0.01      0.07      0.05      0.12      0.08     0.06         0.06

CAPITAL EXPENDITURES
Geological and geophysical
and well drilling                     3,463       1,124      899        607      502       320      169          (890)
Pipeline and infrastructure             421        364       362        383      692       492       15           157
Power development                         –         11         4          –         6        –        –           343
Other equipment                          41         94        91         45       23        77       50             69


OPERATING
Additional Gas sold
– industrial (MMCF)                     719        688       550        687      770       562      485           542
Additional Gas sold
– power (MMCF)                        4,442       2,965     2,794     2,926     2,918     2,440    2,656       2,570
Average price per mcf
– industrial (US$)                     10.47      10.28      9.42      8.67      8.01      9.45     9.32         9.49
Average price per mcf
– power (US$)                           2.76       2.64      2.62      2.63      2.63      2.56     2.56          2.41
                                                  CORPORATE INFORMATION


                                                                                                                                           33
                                                                                          O R C A E X P L O R AT I O N G R O U P I N C .
                                                                                                    3
                                                                                          2011 Q1 INTERIM REPORT

Board of Directors
W. David Lyons                Lord Howard of Lympne          Robert Wigley                 Beer van Straten
Chairman and                  Non-Executive Director         Non-Executive Director        Non-Executive Director
Chief Executive Officer       London                         Waterlooville, Hampshire      Molkerum
Winchester                    United Kingdom                 United Kingdom                Netherlands
United Kingdom

John Patterson                David Ross                     Robin Gaeta
Non-Executive Director        Non-Executive Director         Non-Executive Director
Nanoose Bay                   Calgary                        Wassenaar
Canada                        Canada                         Netherlands




Officers                      Operating Office               Registered Office             Investor Relations
W. David Lyons                Orca Exploration               Orca Exploration              Nigel A. Friend
Chairman and CEO              Group Inc.                     Group Inc.                    Chief Financial Officer
Winchester                    Barclays House, 5th Floor      P.O. Box 3152                 Tel:	+	255	22	2138737	
United Kingdom                Ohio Street, P.O. Box 80139    Road Town                     nfriend@orcaexploration.com
                              Dar es Salaam                  Tortola                       www.orcaexploration.com
Dale Rollins
                              Tanzania                       British Virgin Islands
Chief Operating Officer
                              Tel:	+	255	22	2138737	
London
                              Fax:	+	255	22	2138938
United Kingdom
Nigel A. Friend
Chief Financial Officer
London
United Kingdom



International Subsidiaries
PanAfrican Energy             PAE PanAfrican                 Orca Exploration Group Inc
Tanzania Limited              Energy Corporation             Orca Exploration Italy Inc
Barclays House, 5th Floor     1st Floor                      Orca Exploration Italy Onshore Inc
Ohio Street, P.O. Box 80139   Cnr	St	George/Chazal	Streets   P.O. Box 3152,
Dar es Salaam                 Port Louis                     Road Town
Tanzania                      Mauritius                      Tortola
Tel:	+	255	22	2138737	        Tel:	+	230	207	8888            British Virgin Islands
Fax:	+	255	22	2138938         Fax:	+	230	207	8833




Engineering
Consultants                   Auditors                       Lawyers                       Transfer Agent
McDaniel & Associates         KPMG LLP                       Burnet, Duckworth             CIBC Mellon
Calgary, Canada               Calgary, Canada                & Palmer LLP                  Trust Company
                                                             Calgary, Canada               Toronto & Montreal, Canada

				
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