Orchid Island Capital, Inc.

2011 ANNUAL REPORT

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HIGH VALUE 
SUSTAINABLE 
GROWTH

 
 
 
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ORCA EXPLORATION GROUP INC.  

is an international public company engaged in 

hydrocarbon exploration, development and supply  

of gas in Tanzania and oil appraisal  

and gas exploration in Italy.

Orca Exploration trades on the TSXV under  

the trading symbols ORC.B and ORC.A.

FINANCIAL AND OPERATING HIGHLIGHTS . . . . . . 1
CHAIRMAN & CEO’S LETTER TO SHAREHOLDERS . . . . . . . . . . . . 3
OPERATIONS REVIEW . . . . . . 9
MANAGEMENT’S DISCUSSION & ANALYSIS . . . . . . 31
MANAGEMENT’S REPORT TO SHAREHOLDERS . . . . . . 60
AUDITORS’ REPORT . . . . . . 61
CONSOLIDATED FINANCIAL STATEMENTS . . . . . . 62
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS . . . . . 66
CORPORATE INFORMATION . . . . . . 85

mcf Thousands of 
standard  
cubic feet

MMcf Millions of  

standard  
cubic feet

MMcfd Millions of  

Mmbtu Millions of  

standard cubic  
feet per day

1P Proven  
reserves

British  
thermal units

2P Proven and  
probable  
reserves

Bcf Billions of  
standard  
cubic feet

HHV High heat  
value

Tcf Trillions of 

standard  
cubic feet

LHV Low heat  
value

3P (i) Proven, probable 
and possible 
reserves

GIIP Gas initially  
in place

Kwh Kilowatt hour

MW Megawatt

US$ US dollars

Cdn$ Canadian  

dollars

Bar Fifteen pounds  
per square inch

MMbbl Million barrels  
of oil

£ Euro

(i) 3P  Possible reserves are those additional reserves that are less certain to be recovered than probable resources. There is a 10 percent probability that 
the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

 
 
 
 
 
 
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FINANCIAL AND OPERATING HIGHLIGHTS

Year ended/As at 31 December

2011

2010

Change

Financial (US$000 except where otherwise stated)

Revenue

Profit before taxation

Operating netback (US$/mcf)

Cash and cash equivalents

Working capital

Shareholders’ equity

Earnings per share - basic (US$)

Earnings per share - diluted (US$)

Funds flow from operating activities

Funds per share from operating activities - basic (US$)

Funds per share from operating activities - diluted (US$)

Net cash flows from operating activities

Net cash flows per share from operating activities - basic (US$)

Net cash flows per share from operating activities - diluted (US$)

Outstanding Shares (‘000)

Class A shares

Class B shares

Options

Operating

Additional Gas sold (MMcf) - industrial

Additional Gas sold (MMcf) - power

Additional Gas sold (MMcfd) - industrial

Additional Gas sold (MMcfd) - power

Average price per mcf (US$) - industrial

Average price per mcf (US$) - power

Additional Gas Gross Recoverable Reserves to end of licence (Bcf)

Proved

Probable

Proved plus probable

Proved plus probable plus possible

Present Value, discounted at 10% (US$ million)

Proved

Proved plus probable

Proved plus probable plus possible

45,893

15,320

2.05

34,680

56,006

106,659

0.23

0.22

38,808

16,512

2.29

45,519

52,364

98,183

0.33

0.31

22,658

20,836

0.65

0.63

4,577

0.13

0.13

1,751

32,849

3,057

2,742

14,722

7.5

40.3

10.05

2.77 

469

79

548

844

328

351

412

0.68

0.65

15,534

0.50

0.49

1,751

32,939

2,557

2,504

10,940

6.9

30.0

8.76

2.60

369

82

451

822

236

278

395

18%

(7%)

(10%)

(24%)

7%

9%

(30%)

(29%)

9%

(4%)

(3%)

(71%)

(74%)

(74%)

0%

0%

20%

10%

35%

9%

34%

15%

7%

27%

(4%)

22%

3%

39%

26%

4%

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  HIGHLIGHTS

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Increased	 proven	 reserves	 by	 27%	 to	 469	 Bcf	 (2010:	 369	 Bcf)	 and	
proven	and	probable	reserves	by	22%	to	548	Bcf	(2010:	451	Bcf).

Increased	sales	of	Additional	Gas	by	30%	to	17.5	Bcf	or	47.8	MMcfd	
(2010:	13.4	Bcf	or	36.9	MMcfd).	This	resulted	in	operating	revenue	of	
US$46.4 million.

Increased	funds	from	operations	before	working	capital	changes	by	9%	
to	US$22.7	million	(2010:	US$20.8	million)	despite	brought	forward	
costs being fully recovered in the year.

Increased	working	capital	by	7%	to	US$56.0	million	(2010:	US$52.4	
million).

Agreed	with	the	Government	of	Tanzania	to	increase	deliverability	from	
the	Songo	Songo	field	to	200	MMcfd	in	parallel	with	their	investment	in	
gas processing and pipeline infrastructure.

Planned	 the	 drilling	 of	 two	 development	 wells	 in	 Tanzania	 in	 2012	
(SS-11 and SS-12). SS-11 was spud in February 2012 using the Sakson 
rig PR5 and SS-12 may be drilled once this has been completed.

Held	discussions	with	KCA	Deutag	to	utilise	their	Ben	Avon	jack	up	rig	
for the drilling of the 551 Bcf (mean un-risked resource) exploration 
prospect,	 Songo	 Songo	 West,	 in	 Q4	 2012.	 The	 rig	 is	 expected	 to	 be	
mobilised	to	Mozambique	by	another	operator	in	Q3	2012.

Signed	 a	 Re-rating	 Agreement	 with	 Songas	 and	 the	 electricity	 utility,	
TANESCO,	 that	 enabled	 the	 gas	 processing	 capacity	 to	 be	 increased	
from	 90	 MMcfd	 to	 110	 MMcfd.	 As	 a	 consequence,	 the	 overall	
infrastructure	capacity	increased	to	102	MMcfd	(limited	by	the	pipeline	
diameter).

Signed	a	Portfolio	Gas	Sales	Agreement	(PGSA)	with	TANESCO	for	
the	supply	of	a	maximum	of	37	MMcfd	through	to	approximately	2023.	

Since	 June	 2011,	 217	 MWs	 of	 new	 gas	 fired	 generation	 has	 been	
commissioned	 in	 Tanzania.	 There	 is	 now	 406	 MWs	 of	 gas	 fired	
generation that is dependent on the Company’s gas. Sales volumes are 
expected	to	increase	in	2012	subject	to	the	infrastructure	limitations.

Commenced	the	evaluation	of	the	viability	of	selling	liquid	natural	gas	
in	Tanzania.

Continued	to	plan	for	the	drilling	of	the	La	Tosca	well	in	the	Longastrino	
exploration	block	in	the	Po	Valley,	northern	Italy	(operated	by	Northern	
Petroleum Plc). Under the terms of the farm in agreement, Orca will 
earn  between  70%  and  75%  of  the  block  in  return  for  financing  the 
drilling	 and	 the	 testing	 of	 the	 well	 up	 to	 predefined	 caps.	 The	 well	 is	
expected to be spud in Q3 2012. 

 
 
 
 
 
In 2011Orca celebrated an important milestone – the 10th 

anniversary of the Company’s role in bringing the 

Songo	Songo	gas	field	into	production.	Today	Orca	holds	a	unique	position	
in	the	most	prolific	gas	basin	in	East	Africa.	It	is	the	operator	of	Tanzania’s	
first natural gas development and the largest supplier of natural gas helping to 
address	Tanzania’s	urgent	power	needs.	

Together	with	the	Tanzania	Petroleum	Development	Corporation	(TPDC),	
Songas	Limited,	the	Ministry	of	Energy	and	others,	Orca	is	playing	a	signifi-
cant	role	in	developing	and	producing	the	Songo	Songo	reserves.	The	Songo	
Songo	project	is	one	of	the	most	successful	gas-to-energy	projects	in	Africa	
and	Orca	is	proud	to	be	playing	its	part	in	it.	Looking	to	the	immediate	future	
the Company is fully committed to the successful execution of its US$130 
million Songo Songo exploration and development programme. 

To	bring	more	gas	for	power	generation	as	quickly	as	possible,	Orca	is	
working	closely	with	the	Government	of	Tanzania	and	other	stakeholders	to	
increase	Songo	Songo	gas	field	production.	In	November	2011,	Orca	and	the	
Government	of	Tanzania	agreed	an	accelerated	work	programme	to	increase	
production	from	the	Songo	Songo	gas	field	from	100	MMcfd	to	200	MMcfd.	
The	following	month	Orca	took	delivery	of	the	Sakson	PR5	drilling	rig	on	
Songo	Songo	Island.	The	Sakson	rig	is	currently	drilling	the	SS-11	develop-
ment	well	which	was	spud	in	early	February	2012	and,	subject	to	funding,	
may drill a second development well (SS-12) once the first well is completed. 

CHAIRMAN & CEO’S LETTER TO  

  THE SHAREHOLDERS

Orca is working 
closely with the 
Government of 
Tanzania and other 
stakeholders to 
increase Songo 
Songo production.

INCREASED REVENUES

Revenue	grew	by	18%	to	US$45.9	million	in	2011	(2010:	US$38.8	million).	
The	2011	revenue	increase	was	limited	by	the	fact	that	brought	forward	costs	
had	been	fully	recovered	in	the	first	half	of	2011.	This	reduced	the	percentage	
of net revenue allocated between the Government and the Company from 
75% in 2010 to 52% in 2011. Orca’s total cost recovery share will rise in 2012 
as a result of funds invested by Orca in the current drilling programme.

Funds from operations before working capital changes increased by 9% to 
US$22.7 million and the level of working capital grew from US$52.4 million 
to	US$56.0	million.	The	Company	finished	the	year	with	cash	of	US$34.7	
million	and	no	debt.	The	revenue	growth	was	fuelled	by	Additional	Gas	
sales	of	47.8	MMcfd	in	2011	which	were	made	possible	by	an	infrastructure	
system	re-rating.	In	June	2011	infrastructure	capacity	was	increased	from	90	
MMcfd	to	102	MMcfd.	Additional	Gas	sales	are	expected	to	remain	strong	
through	2012.	With	the	introduction	of	the	new	105	MW	Jacobsen	power	
plant	at	Dar	es	Salaam	in	April	2012,	there	is	now	significantly	more	gas	
demand downstream than can be supplied through the existing infrastruc-
ture system. 

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Orca has an 
excellent gas 
reservoir in the 
Songo Songo field 
that continues  
to perform  
above  
expectations.

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CHAIRMAN & CEO’S LETTER TO THE SHAREHOLDERS

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FOCUSED ON  
INCREASING PRODUCTION

Orca’s 2011 operations focus has 
been on maintaining the highest 
level of gas production possible 
within the current infrastructure 
limits.	In	June	2011	those	limits	
were raised following the signing of 
a Re-rating Agreement with Songas 
Limited	and	the	electricity	utility,	
TANESCO.	The	Agreement	enabled	
the Songo Songo gas processing 
capacity to be increased from 90 
MMcfd	to	110	MMcfd.	However	
gas processing and pipeline capacity 
remains	a	restriction.	To	address	this	
need	the	Government	of	Tanzania	
announced in September 2011 that 
it was in the final stages of negotiat-
ing a 20-year term financing arrange-
ment with the Chinese Exim Bank 
for the construction of a new gas 
processing plant on Songo Songo 
Island	and	an	oversized	onshore	
pipeline to accommodate future 
growth	in	gas	production.	This	is	
expected to initially increase the 
Songo Songo infrastructure capacity 
to	200	MMcfd.	Subsequent	incre-
mental investments in gas process-
ing capacity and the construction 
of a new offshore pipeline to Songo 
Songo could increase gas deliverabil-
ity.	The	target	for	project	completion	
is currently the end of 2013.

A GROWING RESERVE BASE

Orca has an excellent gas reservoir in 
the Songo Songo field that continues 
to perform above expectations.  
As	at	31	December	2011,	the	
independent reserve evaluator 
McDaniel	and	Associates	
Consultants	Ltd.	(“McDaniel”)	
assessed that the Additional Gas 
gross proven (1P) and proven 
and probable (2P) Songo Songo 
reserves available to Orca to the 
end of the licence period are 469 
Bcf	(2010:	369	Bcf)	and	548	Bcf	
(2010:	451	Bcf)	respectively.	These	
significant increases were recorded 
despite Additional Gas 
production of 17.5 Bcf 
during the year.

In	2011	the	Company	
re-evaluated the depth 
conversion techniques for 
the entire field and as a 
result the part of the field 
known as Songo Songo 
North (where the first 
well (SS-1) was drilled 
in	1974	by	AGIP)	is	now	
believed to be larger than 
previously thought. SS-1 
penetrated 1,200 metres 
of Neocomian sands and 
tested gas in the upper 
section, but the well was 
plugged and abandoned. 
Management	recognises	
the importance of Songo 
Songo North for future 
reserves growth.

 
 
 
 
 
 
A VIGOROUS EXPLORATION  
AND DEVELOPMENT AGENDA

Development	plans	put	in	place	in	
2011	will	be	a	major	focus	of	the	
Company	in	2012.	The	goal	is	to	
increase deliverability from the main 
field	to	200	MMcfd	in	parallel	with	
the infrastructure expansions being 
planned	in	country.	To	do	this	Orca	
is currently drilling the new SS-11 
well. A second development well, 
SS-12, may be drilled using the  
same rig.

Currently, the Company can produce 
approximately	113	MMcfd	from	
the Songo Songo field though this is 
currently restricted by the capacity 
of the infrastructure to a maximum 
of	102	MMcfd.	However,	SS-9	
(currently producing in the region 
of	30	MMcfd),	will	have	to	be	taken	
out	of	production	at	the	end	of	May	
2012.	The	Company	will	perform	a	
corrosion log and pressure test the 
annulus/casing to assess whether 
SS-9 can continue in production 
after	the	end	of	May	2012.	In	the	
event that SS-9 is taken off produc-
tion there may be a period where 
the Company can only deliver ap-
proximately	80	MMcfd	until	SS-11	is	
connected to the gas processing plant 
later in 2012.

Orca is moving ahead vigorously 
with plans for the drilling of the 
Songo Songo West exploration 
prospect.	The	Company	is	in	discus-
sion	with	KCA	Deutag	to	secure	the	
Ben	Avon	jack-up	rig	to	drill	the	well.	
The	Ben	Avon	rig	is	being	mobilised	
to	Mozambique	in	Q3	2012	for	a	one	
well program and Orca is looking to 
mobilise	the	rig	to	Tanzania	to	drill	
Songo	Songo	West.	The	location	is	
highly	prospective	and	McDaniel	
has evaluated this prospect and 
assessed it to contain un-risked mean 
resources of 551 Bcf with an upside 
case	in	excess	of	1	Tcf.	

The	exploration	and	develop-
ment programme is dependent on 
adequate	funds	being	available.	This	
is discussed below.

SUSTAINED GAS  
MARKET GROWTH

Sales of Additional Gas to the power 
sector increased by 34% during 2011 
to	40.3	MMcfd	(2010:	30.0	
MMcfd),	mainly	as	a	result	of	the	
increase in the capacity of the gas 
infrastructure that enabled latent 
power	demand	to	be	met.	The	total	
gas	fired	generation	in	Tanzania,	
consuming Additional Gas, is 
currently	406	MWs	having	increased	
since	June	2011	with	the	re-commis-
sioning	of	the	Symbion	112	MW	
plant and the recent start up of the 
105	MW	Jacobsen	plant.	 
At maximum capacity the power 
sector	can	utilise	90	MMcfd	of	
Additional Gas.

During	2011	Orca	maintained	
service to existing customers but  
did not expand industrial sales.  
The	priority	was	to	ensure	that	gas	
was available to meet power sector 
needs at a time of crippling electric-
ity	shortages.	This	will	continue	
until the gas infrastructure capacity 
is increased.

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6

CHAIRMAN & CEO’S LETTER TO THE SHAREHOLDERS

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In Italy we are 
moving forward 
with a land-
based exploration 
program in the  
Po Valley region  
of northern Italy.

When new allocations of Addi-
tional Gas can be made available 
for market expansion there is a 
significant untapped market to be 
developed. A number of the existing 
customers wish to establish a reliable 
electricity supply through the de-
velopment of their own small scale 
generation	capacity.	There	are	also	
a number of other industries and 
hotels that are anxious to sign gas 
purchase	contracts.	The	Company	
will be ready to expand the low 
pressure pipeline system and the 
capacity of the compressed natural 
gas (CNG) infrastructure to meet 
this demand when it can deliver 
more	gas	to	Dar	es	Salaam.

In	addition,	Orca	is	assessing	the	
economic and logistical viability of 
using a small scale liquid natural gas 
(LNG)	plant	to	provide	gas	to	the	
mines	around	Lake	Victoria.	These	
are high margin opportunities that 
are particularly attractive.

ITALIAN ONSHORE 
EXPLORATION 

In	Italy	we	are	moving	forward	
with a land-based exploration 
programme.	The	drilling	of	the	La	
Tosca	farm-in	well	is	scheduled	
to spud in Q3 2012. Northern 
Petroleum, as operator, will drill 
the	well	in	the	Longastrino	Block	
in the Po Valley region of northern 
Italy.	Under	the	terms	of	the	farm-in	
agreement, Orca will pay 100% of 
the	costs	of	the	La	Tosca	1	well	up	
to €4.3 million and 70% thereafter 
for the drilling phase, together with 
back-in costs of €0.6 million to earn 
a 70% interest in the block.

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.	There	
are a number of other prospects on 
the	Longastrino	block	that	will	be	
evaluated following the finalisation 
of	the	drilling	of	the	La	Tosca	well.

 
 
 
 
 
 
Offshore	Italy	Orca’s	participation	
in a low risk, high potential appraisal 
well in the Adriatic remains on 
hold.	However,	it	is	assessed	that	
this could be lifted during 2012. 
Orca has a farm-in agreement with 
Petroceltic	International	Plc	to	
participate in the drilling of the well 
once	the	Italian	Ministry	of	Envi-
ronment issues a decree of environ-
mental compatibility for the drilling 
programme.	The	area	has	significant	
oil exploration upside and as part 
of the farm-in Orca would earn the 
right	to	participate	in	11	adjacent	
exploration blocks in the Central 
Adriatic. Orca is not liable for any 
costs associated with the drilling of 
Elsa-2 until a rig contract is signed.

EXPANSION FINANCING

The	pace	and	extent	of	the	
Company’s 2012 work programme 
will be dependent on the availability 
of	sufficient	capital.	The	planned	
2012 programme includes the 
drilling of two development wells 
(SS-11 and SS-12 on Songo Songo 
Island)	and	two	exploration	wells	
(Songo	Songo	West	and	La	Tosca	in	
Italy).	

The	drilling	of	SS-12	is	dependent	
on the immediate receipt of out-
standing overdue payments of 
approximately US$20 million from 
TANESCO,	the	securing	of	a	US$10	
million overdraft facility and satis-
factory	progress	by	the	Tanzanian	
Government on the infrastructure 
expansion. 

The	drilling	of	Songo	Songo	West	
will, in addition, be dependent on 
the completion of a debt facility that 
is	currently	under	discussion.	This	
financing will be dependent on the 
satisfactory outcome of discussions 
with the Government Negotiation 
Team	(‘GNT’)	that	was	set	up	in	
February 2012 to address a number 
of issues raised by the Parliamentary 
Committee	for	Energy	and	Minerals	

Your management 
team is positive 
about Orca’s 
prospects in both 
Tanzania and Italy.

in respect of the Company’s 
Production Sharing Agreement. 
This	includes,	but	is	not	limited	to,	
TPDC	back	in	rights,	profit	sharing	
arrangements, the unbundling of the 
downstream assets, cost recovery 
and Orca’s management of the 
upstream operations. Orca will 
discuss these matters in good faith 
with	the	GNT	which	may	lead	to	
material changes in the economic 
terms	of	the	PSA.	However	the	
Company reserves its rights to 
defend its position should no satis-
factory agreement be reached. 

The	Board	may	decide	to	defer	the	
drilling of SS-12 and/or Songo 
Songo West if there has not been 
satisfactory resolution of any of the 
conditions outlined above. 

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8

CHAIRMAN & CEO’S LETTER TO THE SHAREHOLDERS

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MANAGEMENT CHANGES

Beer van Straten has been named 
Chief Operating Officer replacing 
Dale	Rollins	who	resigned	in	March	
2012.	Mr.	van	Straten	is	responsible	
for the Company’s field operations 
including the large scale develop-
ment	and	exploration	drilling	program	in	Tanzania.	He	is	a	senior	oil	and	gas	
industry executive with over 20 years high level exploration, production and 
commercial	experience	in	the	North	Sea,	Middle	East	and	Africa.	Mr.	van	
Straten	has	been	associated	with	Orca	since	June	2010	when	he	was	elected	
to	Orca’s	Board	of	Directors.	Prior	to	his	work	with	Orca	he	managed	an	
aggressive	five-rig	programme	in	Egypt	that	doubled	Dana	Gas’	reserves	and	
raised production by 50%.

PIVOTAL YEAR

2012	is	a	pivotal	year	for	Orca.	The	Company	is	moving	forward	vigorously	
to	increase	gas	production	from	Songo	Songo	Island	and	is	working	closely	
with	the	Government	of	Tanzania	and	other	Songo	Songo	stakeholders	to	
meet this need. 

Orca has already taken the first steps in the US$130 million expansion 
program	it	announced	last	November.	The	drilling	of	the	first	development	
well	is	nearing	completion	on	Songo	Songo	Island	and	negotiations	are	
proceeding	to	have	a	jack-up	rig	available	for	the	drilling	of	Songo	Songo	
West	later	this	year.	The	drilling	of	Orca’s	farm-in	well	in	Italy	will	begin	in	
Q3 2012. 

The	Company	is	negotiating	with	the	GNT	in	good	faith.	We	are	concerned	
about the allegations that have been made with respect to the sharing 
of Songo Songo revenues and are approaching the review in a spirit of 
transparency and full cooperation.

Orca is proud of the role it is playing 
in	Tanzania	to	develop	the	country’s	
natural gas resources and make them 
available for the power and industrial 
sectors to the ultimate benefit of all 
Tanzanians.	We	are	also	proud	of	
the role the Company is playing in 
creating quality employment and 
giving back to communities through 
corporate educational and health 
initiatives. 

We are working hard to expand 
Orca’s reserve base, increase value 
for all stakeholders and build greater 
sustainable	value.	There	is	significant	
upside potential. With the continued 
support of our loyal shareholders, 
the strength of our Board, the 
experience of our management 
team and the skills of our dedicated 
employees, we look forward to a year 
of growth.

W.	David	Lyons		 
President and CEO

April 25, 2012

 
 
 
 
 
 
OPERATIONS  REPORT

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9

 
 
 
 
 
 
 
 
 
10

A HISTORY OF WORKING TOGETHER

For the past ten years, 
Orca Exploration Group 
has played an important 
role in Tanzania’s shift from 
costly imported fuel oil to 
domestic natural gas.

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Discovered	in	1974	by	AGIP,	
Tanzania’s	Songo	Songo	gas	field	
lease was acquired by an Orca 
predecessor company in 1991.  
Years of financial and operations 
planning followed.  
By 2001 a consortium to build the 
transportation infrastructure had 
been formed and financing secured. 
In	July	2004	the	first	delivery	of	
natural gas flowed from Songo 
Songo	to	Dar	es	Salaam.	

For	Tanzania	the	development	of	
Songo Songo gas has come at a very 
opportune time. Seasonal droughts 
have severely impacted the country’s 
ability to rely on power from hydro. 
At the same time demand for 
electricity has continued to grow 
every year. 

To	meet	this	growing	demand,	
Tanzania	had	originally	introduced	
power generated by imported fuel 
oil in the 1980s. By the early 1990s 
oil prices and price volatility were 
rising. Even new thermal power 
plants	at	Dar	es	Salaam	couldn’t	
close the power gap between 
demand and supply. Power shortages 
were	impacting	both	Tanzania’s	
national power grid and the  
growing industrial base in the  
Dar	es	Salaam	area.	

To	create	a	long	term	sustainable	
solution Orca worked closely with 
the	Government	of	Tanzania,	
Tanzania	Petroleum	Development	
Corporation,	TANESCO,	the	
Songas consortium and the 
World Bank. By the end of 2002 
construction of gas processing 
facilities and a pipeline system was 
underway	on	Songo	Songo	Island.	

While the Songas-owned gas 
processing plant was being 
constructed	on	Songo	Songo	Island,	
Orca made sure the Songo Songo 
gas wells would be production ready 
when the time came. With contracts 

1974

1974
The Songo Songo  
gas field was  
discovered by AGIP.

1997
A five well servicing 
program was 
completed at Songo 
Songo Island.

1999
Government of 
Tanzania approves the 
Songas Project.

2001
Songas Project achieves 
financial closure.

2003
Tanzanian workforce 
hired and trained to 
operate Songo Songo 
gas plant.

 
 
 
 
 
 
to supply gas for power generation 
in place, Orca constructed a low 
pressure pipeline to sell Additional 
Gas	from	Songo	Songo	to	Dar	
es Salaam industrial customers. 
The	first	two	customers	for	the	
Additional	Gas	were	Kioo	Glass	
and	Tanzanian	Breweries	and	they	
were quickly followed early in 2005 
by four more industrial customers. 
Orca was able to sell the gas to 
industrial customers at 20-25% 
less than the price of heavy fuel oil 
providing serious motivation for 
more customers to make the switch 
to	natural	gas.	Today	Orca	serves	38	
industrial customers.

With gas production from the Songo 
Songo	gas	field	flowing	to	Dar	es	
Salaam	a	new	level	of	Tanzanian	
energy self-sufficiency is being 
achieved.	For	the	first	time	Tanzania	
has been able to use its domestic 
hydrocarbon resources to fuel power 
generators at the Ubungo plant. 

By 2006 an additional development 
program was underway to meet 
TANESCO’s	need	for	more	gas	
for power generation. Orca was 
contracted to sell Additional Gas 
to	fuel	144	MWs	of	short	term,	
emergency	power	generation	at	Dar	
es Salaam.

By the 2007 rainy season the 
reservoirs were filled and increased 
hydro power generation was again 
possible for several months. With 
full reservoirs, the pressure for 
rapid expansion of Songo Songo 
was	reduced.	The	Mtera	dam	which	
supplies	water	to	the	80	MW	Mtera	
and	the	204	MW	Kidatu	hydro	
stations rose from a non-operational 
level of 687 meters above sea level 
to its maximum capacity of 698 
meters. As a result, it was anticipated 
that these hydro units would have 
sufficient water to run at high 
utilisation rates during 2007 and 
2008. 

This	provided	an	opportunity	
for Orca to plan a 16-kilometer 
expansion of its 28-kilometer 
distribution system for 2007 at 
an investment by Orca of US$4.5 
million. With the Government 
projecting	power	demand	of	up	to	
68	MMcfd	at	peak	load	Orca’s	ability	
to meet the needs of both the power 
and industrial sectors was assured. 

During	2008	Songo	Songo	
production had reached the 
physical limits of the Songas gas 
processing plant. Production was 
held	to	a	maximum	of	70	MMcfd.	
Committed to find ways to increase 
production to meet the needs of 
the power sector, Orca financed 
studies that demonstrated that the 
existing infrastructure could be 
re-rated	to	90	MMcfd.	Responding	
to these studies, Songas approved 
the installation of two new valves to 
allow the gas plant to be recertified 
to	90	MMcfd.	

2004
Songo Songo  
in operation and  
first shipment of gas  
was received at 
Ubungo.

2005

2006

Orca (EastCoast Energy) 
launches exploration 
program to find  
more gas.

Marine seismic 
program identifies 
Songo Songo West 
drilling prospect.

Drought increases 
demand for gas-fired 
generation at  
Dar es Salaam.

Orca expands 
service to industrial 
customers with  
25 kilometer pipeline.

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12

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In	early	2009,	with	the	new	valves	
installed, Orca received approval to 
operate the gas processing plant at 
the	90	MMcfd	level	increasing	gas	
supply for urgently needed power 
generation. 

At the same time Orca invested 
US$2.5 million to construct CNG 
(Compressed Natural Gas) facilities 
in	Dar	es	Salaam.	The	facilities	
consist	of	a	“mother	station”	and	
three	“daughter”	stations	for	the	
supply of natural gas to industries 
and hotels as well as to be available 
as a fuel for trucks and buses. 

Committed to continue to 
increase Songo Songo reserves and 
availability of natural gas, Orca 
proposed a new long term expansion 
of	Songo	Songo.	The	studies	showed	
that with two new processing trains 
and added pipeline compression 
production could be increased 
to	144	MMcfd.	By	twinning	the	
onshore	pipeline	to	Dar	es	Salaam	
production could be further 
increased	to	over	200	MMcfd.	

Internationally,	the	Songo	Songo	
project	was	being	well	received.	A	
World Bank study reported that 
“the	Songo	Songo	project	(has)	
performed well during it first six 
years	of	operation.	The	project	had	
also	stimulated	gas	markets:	35	local	
industries were connected for gas, 

replacing the use of heavy 
fuel oil and other types of 
petroleum	fuels…	It	has	
been estimated that 1.8 
million and 0.73 million 
tons of CO2 were reduced 
from power generation 
and local industries 
respectively since 2004 
and	up	to	December	
2010.”	

The	Songo	Songo	project	was	
also credited by the World Bank 
with bringing additional social 
benefits	to	Tanzania.	The	World	
Bank	reported	that	“Because	of	the	
relationship between power supply, 
economic development and poverty 
alleviation,	the	project	intended	
to contribute to a 
reduction of poverty 
by unlocking an 
important and 
genuine new source 
for power generation. 
While the power cuts that occurred 
during various generation shortage 
crises had an impact on the 
country’s economic growth, those 
negative impacts would have been 
even	larger	without	the	project’s	
implementation.	It	is	therefore	likely	
that	the	project’s	main	component	
positively contributed to poverty 
alleviation.”	

During	this	entire	period	the	Songo	
Songo gas reservoir continued to 
perform	above	expectations.	To	
ensure future gas supply, Orca 
completed a workover of its SS-9 
well in 2007 and committed to drill 
a new SS-10 well to further increase 
production.	The	timing	of	these	
upgrades by Orca proved to be very 
important. By mid-2011 gas supply 
for power generation 
had become of 
utmost importance to 
Tanzania.	Providing	
more than 70% of fuel 
required for the national grid, Songo 
Songo gas presented an opportunity 
to further increase power generation 
and reduce load shedding. 

An infrastructure expansion is 
expected to proceed in 2012 and 
be completed by the end of 2013. 
Orca is fully committed to be able 
to supply the gas volumes that will 
be	needed	to	fill	the	system.	The	

ADVANCING 
NATURAL GAS 
DEVELOPMENT

2007

Orca drills first new  
Songo Songo well  
in 25 years.

Orca US$4.5million 
expansion programme 
increases natural 
gas service to more 
industries.

2008
Long-term power 
contracts negotiated 
with TANESCO.

2009

Orca constructs 
new pressure 
reduction station to 
serve Wazo Hill.

Orca completes 
construction of  
CNG facilities at  
Dar es Salaam.

 
 
 
 
 
 
Company has signed a Portfolio 
Gas Supply Agreement (PGSA), 
jointly	with	TDPC	to	supply	gas	to	
TANESCO.

At the same time Orca is continuing 
to expand corporate social 
responsibility programmes on 
Songo	Songo	Island.	Focusing	on	
education and health, the programs 
are delivered through Orca’s 
subsidiary PanAfrican Energy 
Tanzania.	PanAfrican	ensures	that	
the Company’s activities meet 
environmental regulations and 
contribute to sustainable outcomes 
for both the Company and the 
Songo	Songo	Island	community.	

PanAfrican is also committed to 
improving the quality of life of 
the island residents. For the past 
several years, PanAfrican has been 
developing and rolling out health 
and education programmes. 

The	Company	has	assisted	in	
upgrading the local elementary 
school facilities and providing much 
needed educational materials and 
equipment. Currently, PanAfrican 
is supporting the kindergarten, 
which is providing early learning 
facilities for children aged between 
3	and	6	years.	In	addition,	students	
are provided with meals and health 
check-ups. 

The	Company	has	also	recruited	
a professional instructor for the 
learning centre, to provide English 
language instruction, computer 
training and entrepreneurship skills 
to young adults on the island.

In	order	to	increase	local	education	
in a sustainable manner, PanAfrican 
is also sponsoring three teachers to 
attend	Teacher	Training	College	in	
Dar	es	Salaam.	To	meet	the	need	for	
increased educational opportunities 
at the high school level, the 

Company is also sponsoring ten 
students from the island to attend 
Secondary	School	in	Dar	es	Salaam.	
PanAfrican staff are actively involved 
– donating personal time to assist 
in the children’s clinic, where they 
provide community training in 
maternal	healthcare,	HIV	awareness,	
nutrition and vaccination.

2010

2011

Orca funds study 
to increase  
Songo Songo 
production to at 
least 140 MMcfd.

Orca increases 
aid to Songo 
Songo schools 
and provides 
scholarships.

Orca announces 
US$130 million 
expansion program 
to increase gas 
production.

Tanzania 
announces plan 
for 532 kilometer 
coastal pipeline.

2012
Orca begins drilling 
new Songo Songo well 
(SS-11) to increase  
gas production.

2012

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14

OPERATIONS REPORT

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35,000

30,000

25,000

20,000

f
c
M
M

15,000

10,000

5,000

0

d
f
c
M
M

105

95

85

75

65

55

45

35

25

Production Volumes

Protected Gas sales

Additional Gas sales

Flare, generator at the processing 
plant and line pack

GAS PRODUCTION
& SALES

2004

2005

2006

2007

2008

2009

2010

2011

During	 2011,	 30.7	 Bcf	 (2010:	 27.9	 Bcf)	 of	 natural	 gas	 was	 produced	 from	
the	Songo	Songo	field	offshore	Tanzania	or	an	average	of	84.1	MMcfd	(2010:	
76.4	 MMcfd).	 This	 brings	 total	 production	 since	 commercial	 operations	
commenced	on	20	July	2004	to	159	Bcf.	The	increase	in	production	during	
the course of the year has mainly been the consequence of increased demand 
from the power sector. 

Average daily production per month

PROTECTED GAS SALES

Under the terms of a Gas Agreement signed in 2001, the Protected Gas from 
Songo	Songo	is	100%	owned	by	the	Tanzanian	Petroleum	Development	Cor-
poration	(“TPDC”)	and	is	sold	to	Songas	under	a	20	year	Gas	Agreement	for:

1.	 The	operation	of	five	turbines	at	the	Ubungo	power	plant;

2.	

	Onward	sale	to	the	Tanzanian	Portland	Cement	Company	(“TPCC”)	
for	the	operation	of	its	cement	kilns;	and

3.	

Village	electrification	(at	a	rate	not	to	exceed	1	MMcfd).	

The	Protected	Gas	was	allocated	as	follows:

2010

2011

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

2011

2010

Protected Gas 
consumed

Utilisation 
rate

Protected Gas  
consumed

Utilisation 
rate

Year ended 31 December

Bcf

MMcfd

%

Bcf

MMcfd

%

Additional Gas Volumes

Protected Gas user
20000
Ubungo power plant
18000
Industrial Sales
Wazo	Hill	cement	plant
16000

Power Sales
Village electrification programme
14000

12000
Total	consumption
10000

8000

6000

4000

2000

0

2004

2005

2006

2007

2008

2009

2010

2011

f
c
M
M

11.4

1.8

–

13.2

31.4

4.9

–

36.3

82%

83%

– 

80%

12.4

1.8

– 

14.2

34.0

4.9

– 

38.9

89%

84%

–

86%

Protected Gas utilisation decreased at the Ubungo power plant to 82% during 
2011	due	to	TANESCO	utilizing	other	new	gas	fired	plants	for	its	electricity	
generation therefore reducing the demand for Protected Gas at the Ubungo 
power plant. 

The	Wazo	Hill	cement	plant	utilization	reduced	to	83%	during	2011(2010:	
84%) as a consequence of the impact of electricity shortages that hindered 
production. 

No gas was consumed during 2011 on the village electrification program.

 
 
 
 
 
 
 
 
 
 
GAS PRODUCTION

The	maximum	gas	required	for	the	Protected	Gas	users	over	the	remaining	12	
years	and	seven	months	of	the	Gas	Agreement	was	207	Bcf	as	at	31	December	
2011. For the purposes of calculating the level of gas available as Addition-
al  Gas,  an  assumption  has  to  be  made  as  to  the  expected  utilisation  of  the 
f
c
M
Protected	Gas	over	the	remaining	term	of	the	Gas	Agreement.	These	assump-
M
tions	are	reviewed	on	an	annual	basis	based	on	historic	and	projected	usage.	

The	Protected	Gas	users	and	their	forecast	maximum	and	most	likely	demand	
are	as	follows:

Production Volumes

Protected Gas sales

Additional Gas sales

Flare, generator at the processing 
plant and line pack

35,000

30,000

25,000

20,000

15,000

10,000

5,000

Theoretical maximum 
maximum 100% load factor

0

2004

Protected Gas Demand

Six gas turbines at the Ubungo power plant

Less	gas	supplied	to	the	sixth	turbine	 
which is Additional Gas

Total Protected Gas at Ubungo

Wazo Hill cement plant

Village electrification programme

Total daily Protected Gas demand

Protected Gas reserves to end of the  
Songas power purchase agreement (Bcf)

The	 forecast	 theoretical	 maximum	 demand	 by	 the	 Protected	 Gas	 users	 is	
estimated	to	be	45.1	MMcfd	based	on	technical	tests	of	the	Ubungo	turbines	
and	the	Wazo	Hill	cement	plant,	though	there	are	variations	during	the	year	
and	over	time	depending	on	ambient	temperature	and	degradation.	The	‘most	
likely’ utilisation, including the village electrification program, is forecast to 
be	83%	over	the	remaining	term	of	the	Gas	Agreement.	This	compares	with	
an	actual	utilisation	rate	of	80%	in	2011.	The	actual	Protected	Gas	utilisa-
tion at the Ubungo power plant primarily depends on the availability of the 
Ubungo power units.

ADDITIONAL GAS SALES

Under  the  terms  of  a  Gas  Agreement  signed  in  2001,  the  gas  from  the 
Songo Songo field in excess of the volume reserved as Protected Gas, is 
available to Orca Exploration to be marketed as Additional Gas. 

f
c
M
M

 MMcfd

47.4

 (9.2)

105

38.2

5.9

 1.0

d
f
c
 45.1
M
M

207

Most likely

2005

2007

2006
MMcfd

2008

2009

2011
2010
2011
MMcfd

39.8

39.0
Average daily production per month
(7.6)

(7.8)

95

85

75

65

55

45

35

25

32.0

4.2

1.0

37.2

171

31.4

4.9

– 

36.3

2010

2011

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Additional Gas Volumes

Industrial Sales

Power Sales

2004

2005

2006

2007

2008

2009

2010

2011

20000

18000

16000

14000

12000

10000

8000

6000

4000

2000

0

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16

OPERATIONS REPORT

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Power Sector

With  the  recent  gas  discoveries  offshore  by  BG  plc  and  Statoil  that  are 
estimated	to	be	in	excess	of	10	Tcf,	the	Government	of	Tanzania	has	been	able	
to plan their future energy requirements around having plentiful indigenous 
gas	capacity.	The	principal	benefactor	of	this	is	the	power	sector.

Sales	to	the	power	sector	averaged	40.3	MMcfd	in	2011	(2010:	30.0	MMcfd).	 
The	increase	is	primarily	the	result	of	the:

•	

•	

Introduction	of	112	MWs	of	new	gas	fired	generation	in	June	2011	to	
coincide	with	the	re-rating	of	the	infrastructure	capacity;	and	

Failure	 of	 the	 hydro	 capacity	 in	 country	 due	 to	 lack	 of	 rains	 in	 the	
catchment areas. 

The	following	lists	the	capacity	of	the	gas	fired	generation	capable	of	consuming	
Additional	Gas	as	at	31	December	2011	together	with	the	expected	growth	in	
generation	by	30	June	2012.	

DEMAND BY THE POWER SECTOR

Status 

Operational 

Operational

Operational

Operational	(gas	&	jet	fuel)

Total as at 31 December 2011

 Power Plant

Ubungo power plant (Unit 6)

TANESCO	at	Ubungo

Tegeta	

Symbion

Commissioned in April 2012

Jacobsen	at	Ubungo

Total potential as at 30 June 2012

Installed 
capacity

MWs

42

102

45

112

301

105

406

 
 
 
 
 
 
Furture contracted power demand

The	supply	of	Additional	Gas	to	the	power	sector	is	currently	governed	by	the	
initialed	 Amended	 and	 Restated	 Gas	 Agreement	 (“ARGA”)	 and	 the	 signed	
Portfolio	Gas	Supply	Agreement	(“PGSA”).

Under the ARGA, 19.5 % of the gas supplied to the six turbines at Ubungo 
is considered to be Additional Gas. Whilst there is no explicit take or pay in 
the  agreement  the  utilisation  at  the  Ubungo  power  plant  is  expected  to  be 
high	given	the	low	cost	of	the	Protected	Gas	(US$0.55/Mmbtu	LHV	escalat-
ing	 with	 US	 CPI)	 that	 makes	 up	 the	 remaining	 80.5%	 of	 the	 supply	 to	 the	
plant.	 The	 maximum	 volume	 of	 Protected	 and	 Additional	 Gas	 delivered	 to	
the	Ubungo	power	plant	is	capped	at	approximately	47.4	MMcfd.	At	an	84%	
utilisation	rate,	it	is	expected	that	7.8	MMcfd	will	be	supplied	to	the	Ubungo	
power plant as Additional Gas until the termination of the agreement on 31 
July	2024.

The	PGSA	covers	the	supply	of	Additional	Gas	to	a	portfolio	of	gas	generation	
facilities	(that	currently	consists	of	the	TANESCO	Ubungo	102	MW,	Tegeta	
45	 MW	 and	 the	 Symbion	 112	 MW	 power	 plants).	 Further	 delivery	 points	
may	be	added	in	the	future	subject	to	the	consent	of	the	Company	and	TPDC,	
and provided that the gas volumes do not exceed the maximum permissible 
under the contract as detailed below.

Under	the	terms	of	the	PGSA	the	maximum	daily	quantity	(“MDQ”)	that	the	
Company	 is	 obligated	 to	 supply	 is	 approximately	 37	 MMcfd.	 Currently	 the	
Company is selling at much higher volumes than this.

Growth in electricity demand and the potential for 
further gas fired generation 

As	at	31	December	2011,	there	was	approximately	1,144	MWs	
of	installed	power	generation	in	Tanzania.	Given	that	the	popu-
lation	of	Tanzania	is	approximately	40	million,	this	represents	a	
very low electricity demand per capita. 

In	the	last	few	years	there	has	been	a	rebalancing	of	power	gen-
eration	mix	in	Tanzania	resulting	in	hydro	generation	account-
ing	for	less	than	50%	of	the	available	generation.	The	only	major	
water	storage	is	at	the	Mtera	reservoir	which	supplies	the	80	MW	
Mtera	 and	 200	 MW	 Kidatu	 hydro	 plants.	 The	
remaining	261	MWs	of	hydro	generation	is	“run	
of	river”	which	is	only	operational	on	average	for	
4-5 months in the year. Accordingly the level of 
the	Mtera	reservoir	is	integral	to	the	generation	
of	280	MWs	of	electricity.	

There	are	still	significant	black	outs	in	Tanzania	as	
a result of insufficient electricity generation and 
issues	with	transmission.	It	is	envisaged	that	once	
the infrastructure constraints are removed, nearly 
all the Songo Songo reserves could be absorbed 
by a growing electricity sector. 

I

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O
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O
R
C
A

E
X
P
L
O
R
A
T

I

O
N

G
R
O
U
P

I

N
C

.

2
0
1
1

A
N
N
U
A
L

R
E
P
O
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T

17

 
 
 
 
 
 
 
 
 
18

OPERATIONS REPORT

T
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R

L
A
U
N
N
A

1
1
0
2

.

C
N

I

P
U
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R
G

N
O

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L
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X
E

A
C
R
O

INDUSTRIAL SALES

Piped natural gas

Sales  to  the  industrial  sector  averaged  approximately  7.5 
MMcfd	 in	 2011	 (2010:	 6.9	 MMcfd).	 There	 is	 currently	
limited opportunity to connect any new material customers 
(due  to  the  demands  of  the  power  sector)  and  therefore 
growth in the short term will primarily be driven by organic 
growth from within the existing customer base. 

There	 remains	 the	 potential	 for	 good	 growth	 from	 indus-
tries	in	the	future.	In	particular	our	industrial	customers	are	
increasingly looking at ways of generating their own power. 

Compressed Natural Gas (CNG) 

The	 Company	 currently	 has	 a	 compressor,	 a	
vehicle dispenser and three daughter stations.

Through	 the	 CNG	 facilities,	 the	 Company	
sold	94	MMcf	in	2011	(2010:	38	MMcf).	

is	 expected	 to	 grow	
The	 CNG	 market	
gradually  primarily  fuelled  by  industries  not 
located  on  the  existing  pipeline  system  and 
large vehicle users (e.g. Pepsi who has a large 
fleet	of	trucks).	It	is	anticipated	that	once	the	
market  is  established  in  the  medium  term, 
the  local  petrol  retailers  will  retail  the  CNG.  
Accordingly  there  will  be  no  need  for  sig-
nificant  capital  after  this  time,  but  the  price 
realised for the CNG will be reduced.

 
 
 
 
 
 
INFRASTRUCTURE

 Since 2004 
the Company has 
constructed over 50 
kilometers of low 
pressure pipeline 
in Dar es Salaam 
connecting 36 
industrial customers. 

The	sales	of	gas	from	the	Songo	Songo	field	is	currently	being	restricted	by	
the capacity of the infrastructure that processes and transports the gas 232 
kilometers	from	the	field	on	Songo	Songo	Island	to	Dar	es	Salaam.	

During	2011,	the	Company	signed	a	Re-rating	Agreement	with	the	owners	
of	 the	 infrastructure,	 Songas	 Limited	 and	 the	 electricity	 utility,	 TANESCO	
to	increase	the	gas	processing	capacity	from	90	MMcfd	to	110	MMcfd.	This	
increased	the	overall	capacity	of	the	system	to	102	MMcfd	with	the	pipeline	
diameter being the bottleneck.

There	are	a	number	of	initiatives	being	evaluated	to	increase	the	capacity:

•	

Songas	 has	 received	 a	 tariff	 methodology	 order	 from	 the	 regulator	
EWURA	in	respect	of	its	expansion	project.	This	project	will	increase	
the	capacity	to	140	MMcfd	by	the	installation	of	two	new	gas	process-
ing	 trains	 within	 their	 existing	 plant	 on	 Songo	 Songo	 Island	 and	 the	
addition of compression on the onshore section of the pipeline.

•	 The	Government	of	Tanzania	is	seeking	finance	from	the	Chinese	Exim	
Bank  to  construct  a  separate  gas  processing  plant  on  Songo  Songo 
Island	 and	 a	 new	 onshore	 pipeline	 that	 will	 run	 parallel	 to	 the	
existing	 line	 from	 Somanga	 Funga	 to	 Dar	 es	 Salaam.	 This	 will	
increase	the	overall	capacity	of	the	system	to	200	MMcfd.	This	
could be increased with the addition of a new offshore pipeline 
and incremental gas processing units.

The	 Government	 of	 Tanzania	 is	 confident	 that	 their	 initiative	 will	
proceed and will be operational by the end of 2013.

The	 Company	 currently	 pays	 a	 flat	 rate	 regulated	 tariff	 of	 US$0.59/
mcf	to	Songas	to	utilize	the	infrastructure	system	plus	(as	an	incentive	
for Songas to re-rate their gas processing capacity) 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.

Low pressure distribution system

The	low	pressure	distribution	system	has	been	designed	so	that	there	
is	 significant	 spare	 capacity	 and	 security	 of	 supply.	 There	 are	 three	
pressure	reduction	stations	(“PRS”)	and	two	separate	connections	to	
the	16”	high	pressure	pipeline.	

Since  2004,  the  Company 
has  constructed  in  excess  of 
50  kilometers  of  low  pressure 
pipeline	in	Dar	es	Salaam	and	
36  industrial  customers  were 
connected  and  consuming 
Additional  Gas  at  the  end  of 
2011. 

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O
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L
O
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A
T

I

O
N

G
R
O
U
P

I

N
C

.

2
0
1
1

A
N
N
U
A
L

R
E
P
O
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T

19

 
 
 
 
 
 
 
 
 
RESERVES

20

OPERATIONS REPORT

T
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A

1
1
0
2

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N

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A
C
R
O

THE  
SONGO SONGO FIELD 

Summary of Orca Exploration’s 
assessment of Gas Initially  
in Place (GIIP)

During	 2011	 Orca	 undertook	 a	 re-
evaluation  of  all  the  subsurface  data 
and,  although  no  new  geological 
or  geophysical  data  was  acquired, 
a  revised  geological  model  was  developed  which  has  significantly 
affected the way management views the Songo Songo North accumu-
lation.	 Management’s	 view	 of	 the	 exploratory	 prospect	 Songo	 Songo	
West	remains	unchanged.	The	reserves	and	resources	are	assessed	for	
the	following	areas:

1.	 The	 Songo	 Songo	 main	 producing	 field	 (“Songo	 Songo	 Field”,	 

“SS	Field”);

2.	 The	northern	section	of	the	field	that	has	gas	reserves	established	
by	the	drilling	of	SS-1,	but	no	current	production	(“Songo	Songo	
North”,	“SS	North”);	and

3.	 The	exploration	prospect	west	of	the	Songo	Songo	Field	(“Songo	

Songo	West”,	“SSW”).

A	summary	of	management	assessment	of	the	Mid	Case	GIIP	for	the	
Songo Songo Field and Songo Songo North discoveries and the forecast 
unrisked resources of Songo Songo West are illustrated below.

Songo Songo Field and Songo Songo North

Management’s	 internal	 evaluation	 of	 the	 Mid	 Case	 GIIP	 for	 the	
combined  Songo  Songo  Field  and  Songo  Songo  North  discovery  is  2,021 
Bcf.	The	GIIP	estimates	are	based	on	the	top	reservoir	depth	structure	maps	
generated as part of the overhaul of the entire geological model. When broken 
down	managements	assesses	that	the	Songo	Songo	Field	GIIP	has	increased	
9%	 to	 1,468	 Bcf	 (2010:1,345	 Bcf).	 However,	 significantly,	 management	
assesses	that	Songo	Songo	North	GIIP	has	increased	144%	to	553	Bcf	(2010:	
226 Bcf).

 
 
 
 
 
 
8°S
8°S

Maurel Prom

BG & Ophir

Funguo PT

Pan Af En

Chewa

Ndovu Res

Pwenza

Ndovu Res

BG & Ophir

Statoil & Exxon

Zafarani

Statoil
& Exxon

10°S
10°S

BG & Ophir
Ndovu Res

Hydro Tanz

Maurel Prom

BG & Ophir

3,000

Jodari

Chaza

2

,

0

1

,

5

0

0

0

0

1
,

0

0

5

0

0

0

2

,

5

0

0

2

,

5

0

0

2

,

0

0

0

Ndovu Res

Windjammer

Anadarko

Lagosta

Tubarao

Barquentine

Camarao

Mamba South

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O
N
S
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E
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O
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T

Collier

Ironclad

Anadarko

ENI

Statoil

Statoil

Petronas

Petronas

40°E
40°E

42°E
42°E

March 2012

 Songo Songo field is 
the first producing gas 
field in East Africa’s most 
intense gas prospecting 
area offshore Tanzania. 
The area has recorded 
numerous recent gas 
discoveries - shown in red.

Management’s	Mid	Case	GIIP	of	2,021	Bcf	for	the	Songo	Songo	
Field	and	Songo	Songo	North	compares	with	the	McDaniel	
end	2011	GIIP	estimates	as	presented	below:	  

12°S

Bcf

 1P

2P

3P

McDaniels	Songo	Songo	Field	GIIP	(Bcf)

 1,342

1,486

The	 McDaniel	 reserves	 evaluation	 are	 summarised	 in	 more	
detail below.

Reservoir management and surveillance

1,562

Gas discovery
Gas pipeline
Water depth (m)

3,000

14°S

0

50

Kilometres

TANZCO21a

Songo  Songo  Field  reservoir  development  and  management  is  evaluated 
through	the	static	geologic	and	dynamic	reservoir	simulation	models.	Total	
cumulative production from the field of 159.3 Bcf to the end of 2011, repre-
sents	7.9%	of	Management’s	Mid	Case	GIIP.	The	entire	current	production	of	
159.3	Bcf	is	from	the	Songo	Songo	Main	area	which	management	believes	has	
a	Mid	Case	GIIP	of	1,468	Bcf,	which	represents	10.8%	of	the	Songo	Songo	
Main	area	GIIP.	At	this	stage	in	field	life,	greater	confidence	continues	to	be	
placed	in	the	volumetric	estimate	of	GIIP	from	the	static	model,	than	from	
dynamic	estimates	of	GIIP	based	on	Material	Balance	calculations.

The	reservoir	simulation	model	is	used	to	monitor	and	continuously	evaluate	
the reserves of the Songo Songo Field and Songo Songo North in order to 
ensure that the Protected Gas deliverability requirements can be met and to 
manage	forecast	Additional	Gas	sales.	The	model	has	been	used	to	predict	well	
performance and identify the investments in wells and field compression that 
will	be	required	to	meet	forecast	gas	demand.	It	is	used	to	assess	the	likely	well	
response	to	uncertainties	such	as	aquifer	size	and	extent	of	reservoir	compart-
mentalisation, if any. 

The	Company	uses	down	hole	pressure	gauges	to	monitor	and	record	bottom	
hole	 pressure.	 The	 recorded	 pressure	 data	 is	 used	 for	 a	 variety	 of	 purposes	
including near well formation parameter assessment, well deliverability and 
estimates	of	field	GIIP.	The	data	is	also	used	to	update	and	history	match	pro-
duction	data	in	the	simulation	model.	The	performance	of	each	individual	well	
is in addition monitored throughout the year through a scheduled program of 
(multi-rate) well tests and build-up pressure tests.

O
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O
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T

I

O
N

G
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O
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P

I

N
C

.

2
0
1
1

A
N
N
U
A
L

R
E
P
O
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21

 
 
 
 
 
 
 
 
 
22

OPERATIONS REPORT

T
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O
P
E
R

L
A
U
N
N
A

1
1
0
2

.

C
N

I

P
U
O
R
G

N
O

I

T
A
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L
P
X
E

A
C
R
O

The	 downhole	 pressure	 data	 is	 showing	 early	 signs	 for	 the	 presence	 of	 an	
aquifer, although this is not yet definitive and as yet no water break through 
has	occurred.	The	Material	Balance	p/Z	analysis	has	been	extended	to	include	
diagnostic	 analysis	 for	 the	 presence	 of	 an	 aquifer	 using	 Cole	 and	 Havlena	
Odeh plots. At this early stage of production the data remain inconclusive for 
the presence of, or strength of an aquifer, it is therefore too early to assess the 
potential	 impact	 on	 reserves,	 if	 any.	 Management	 will	 continue	 to	 evaluate	
this as more pressure data is available, and by monitoring for the first signs of 
potential water production from the wells.

Development of the Songo Songo Field and Songo Songo North

The	Company’s	immediate	objective	is	to	maximise	the	sales	of	gas	from	the	
Songo Songo Field and Songo Songo North, as well as exploring for gas in 
the	Songo	Songo	West	prospect	(see	under	EXPLORATION).	In	reviewing	
the potential of these reservoirs and the gas demand forecasts, it is assessed 
that the Company should develop the field to be able to deliver a maximum 
peak	of	200	MMcfd	(including	Protected	Gas).	To	achieve	this	and	as	detailed	
above,	an	additional	main	field	development	well	(“SS-11”)	is	currently	being	
drilled	from	an	onshore	location	on	Songo	Songo	Island	and	deviated	to	the	
north	west	where	it	will	be	landed	as	a	high	angle	or	horizontal	producer	at	the	
top	of	the	reservoir	interval.	Following	this	a	second	well	(“SS-12”),	similarly	
designed will be drilled from a nearby location in a deviated manner to the 
south-west.	The	wells	will	be	tied	back	to	the	Songo	Songo	gas	processing	fa-
cilities.	In	addition	larger	tubing	will	be	installed	in	the	SS-10	
well to increase deliverability.

The	current	well	stock	will	not	drain	the	Songo	Songo	North	
reservoir.	 The	 reserves	 located	 in	 this	 area	 of	 the	 field	 are	
not  required  in  the  near  term,  and  as  a  result  there  are  no 
immediate	 plans	 to	 drill	 this	 well.	 In	 addition	 to	 the	 above,	
field  compression  will  need  to  be  installed  to  maintain  the 
deliverability	 of	 the	 wells.	 The	 first	 stage	 of	 compression	 is	
expected to be installed with the expanded gas processing fa-
cilities by the end of 2013.

 
 
 
 
 
 
GAS RESERVES 

In	 accordance	 with	 National	 Instrument	
51-101	Standards	of	Disclosure	for	Oil	and	
Gas  Activities,  the  independent  petroleum 
engineers,	 McDaniel	 prepared	 a	 report	
dated  April  2012  that  assessed  the  Orca 
Exploration  natural  gas  reserves  based  on 
information on the Songo Songo Field and 
Songo	Songo	North	as	at	31	December	2011	
(the	“McDaniel	Report”).	A	summary	of	the	
remaining Additional Gas reserves on a life 
of license and life of field basis are presented 
below.	The	1P	and	2P	reserves	are	based	on	
production to the end of the license period 
(October  2026)  while  the  3P  reserves 
assume that the license will be extended to 
the end of the field life.

Dodoma

Mombasa
Mombasa

200

Tanga
Tanga

Afren

Antrim

5

0

0

2

0

0

Dar Es Salaam
Dar Es Salaam
Dar Es Salaam

Dodsal

Petrodel

Petrodel

Shell Int

Shell Int

Shell Int

Shell Int

Petrobras

Ophir

Petrobras

Maurel Prom

Funguo PT

Pan Af En
Songo
Songo
Songo
Songo

Petrobras

Well 2
Chewa-1 Discovery

BG & Ophir

Well 1
Pweza Discovery

Ndovu Res

BG & Ophir

Statoil & Exxon

Statoil
& Exxon

Zafarani

BG & Ophir

BG & Ophir
Ndovu Res

Hydro Tanz

Well 4
Jodari-1 Discovery
3,000
Well 3
Chaza-1 Discovery

,

2

5

2

0

0

0

0

1

5

1

,

,

Mnazi Bay
Mnazi Bay
Maurel Prom

,

5

0

0

0

0

0

0

0

0

2

2

,

,

5

0

0

0

0

0

Windjammer
Lagosta

Ndovu
Res

Barquentine
Camarao
Mamba South

Tubarao

Collier
Collier

Ironclad
Ironclad

3

,

0
0
0

3,000

March 2012

Gas discovery
Gas pipeline
Water depth (m)

0

3,000

100

TANZCO22a

Kilometres

During	 the	 course	 of	 2011	 no	 significant	
geological  or  geophysical  data  has  been 
acquired  on  or  close  to  the  Songo  Songo 
field that might allow a re-assesment of the 
volumetric	 GIIP	 and	 reserves.	 On	 a	 Gross	
Company basis there has been a 27% increase in Songo Songo’s 1P Additional 
Gas reserves to the end of the license period, and a 17% increase on a life of 
field basis, with a total Additional Gas production of 17.5 Bcf during the year. 
There	has	been	a	22%	increase	in	the	2P	Additional	Gas	reserves	on	a	Gross	
Company	life	of	license	basis	from	from	450.8	Bcf	to	548.5	Bcf.	The	increase	
is	 primarily	 due	 to	 an	 improvement	 in	 the	 recovery	 factors.	 This	 has	 been	
possible as there has been an increase in the level of pressure data as a result of 
the high level of production volumes achieved during 2011.

Orca	 management	 estimates	 that	 the	 total	 recoverable	 Mid	 Case	 reserves	
(Protected  Gas  plus  Additional  Gas)  from  the  Songo  Songo  Field  and  the 
Songo	Songo	North	discovery	is	1,079	Bcf	at	31	December	2011.	

The	gross	and	net	Company	Additional	Gas	reserves	to	end	of	license	are	as	
follows:

Songo Songo 

Additional Gas reserves to October 2026 (Bcf) 

Independent	reserves	evaluation

Proved producing

Proved undeveloped

Total	proved	(1P)

Probable

Total	proved	and	probable	(2P)

Possible

Total	proved,	probable	and	possible	(3P)

2011

Gross (1)

316.3

152.8

469.1

79.4

548.5

296.0

844.5

2011

Net (2)

215.4

82.2

297.6

48.9

346.5

192.5

539.0

2010

Gross

289.5

79.7

369.2

81.6

450.8

370.9

821.7

2010

Net

191.2

47.8

239.0

50.1

289.1

234.1

523.2

(1)  Gross equals the gross reserves that are available for the Company after estimating the effect of the TPDC back in (see below).

(2)  Net equals the economic allocation of the Gross reserves to the Company as determined in accordance with the Production Sharing Agreement.

I

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A
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O
N
S
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P
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O
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A

E
X
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A
T

I

O
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G
R
O
U
P

I

N
C

.

2
0
1
1

A
N
N
U
A
L

R
E
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O
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T

23

 
 
 
 
 
 
 
 
 
 
 
 
 
24

OPERATIONS REPORT

T
R
O
P
E
R

L
A
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N
N
A

1
1
0
2

.

C
N

I

P
U
O
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G

N
O

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Songo Songo 

Additional Gas reserves to end of field life (Bcf)

Independent reserves evaluation

Proved producing

Proved undeveloped

Total	proved	(1P)

Probable

Total	proved	and	probable	(2P)

Possible

Total	proved,	probable	and	possible	(3P)

The	gross	and	net	Company	Additional	Gas	reserves	to	end	of	field	life	are	as	
follows:

2011

Gross (1)

539.8

6.5

546.3

127.6

673.9

170.6

844.5

2011

Net (2)

355.0

0.4

355.4

79.2

434.6

104.3

539.0

2010

Gross

478.4

(11.6)

466.8

153.3

620.1

201.6

821.7

2010

Net

315.8

(10.4)

305.4

95.6

401.0

122.2

523.2

(1)  Gross equals the gross reserves that are available for the Company after estimating the effect of the TPDC back in (see below).

(2)  Net equals the economic allocation of the Gross reserves to the Company as determined in accordance with the Production Sharing Agreement.

The	McDaniel	Report	has	assumed	that	TPDC	will	exercise	its	right	to	‘back	
in’ to the field development by contributing 20% of the costs of the future wells, 
including SS-10, and a proportion of the infrastructure and operating costs, 
in return for a 20% increase in the profit share for the production emanating 
from	these	wells.	McDaniel	has	taken	the	view	that	this	‘back	in’	right	should	
be	treated	as	a	TPDC	working	interest	and	therefore	the	Gross	reserves	have	
been	adjusted	for	the	volumes	of	Additional	Gas	that	are	allocated	to	TPDC	
for	their	working	interest	share.	The	implications	and	workings	of	the	‘back	
in’	are	currently	being	discussed	with	TPDC	and	may	lead	to	future	modifica-
tions in the way the Gross Company reserves are calculated.

For	the	purpose	of	calculating	the	Gross	Additional	Gas	reserves,	McDaniel	
has	assumed	in	their	2P	case	that	171	Bcf	(2010:	190	Bcf)	or	an	average	of	
13.4 Bcf per annum will be required to meet the demands of the Protected 
Gas	users	from	1	January	2012	to	31	July	2024.	During	2011,	the	Protected	
Gas users consumed 13.3 Bcf. 

 
 
 
 
 
 
 
 
 
 
The	principal	assumptions	used	by	McDaniel	in	its	evaluation	of	the	Tanzanian	PSA	are	as	follows:

Gross additional gas reserves

Additional Gas 
price 
1P

Gross Additional 
Gas volumes 
1P

Additional Gas  
price 
2P

Gross Additional 
Gas volumes 
2P

Year

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023-2026

Present value of reserves

US$/mcf

4.08

4.44

4.99

5.08

5.18

5.26

5.33 

5.41

5.49

5.64

5.80

6.19

 MMcfd

 54.57

 54.57 

114.26

131.09

131.09

 131.09 

 131.09 

131.09

128.35

99.81

77.69

56.59

US$/mcf

4.06

4.43

5.07

5.15

5.27

5.39

5.51

5.59

5.67

5.76

5.90

6.09

The	 estimated	 value	 of	 the	 Songo	 Songo	 reserves	 on	 a	 life	 of	 license	 basis	
based	on	the	assumptions	on	production	and	pricing	are	as	follows:

Present value of reserves

US$ millions

Proved producing

Proved undeveloped

Total	proved (1P)

Probable

Total	proved	and	probable (2P)

Possible

Total	proved,	probable	and	possible	(3P)

2011

10%

209.3

118.9

328.2

22.8

351.0

60.7

411.6

5%

301.3

139.2

440.5

39.9

480.4

133.8

614.2

15%

152.4

99.2

251.6

13.5

265.1

29.6

294.7

There	has	been	a	26%	increase	on	the	2P	present	value	at	a	10%	discount	basis	
from	 US$277.6	 million	 to	 US$351.0	 million	 on	 a	 life	 of	 licence	 basis.	 The	
increase is primarily due to an increase in recoverable reserves and an accel-
erated production profile as a result of increased investment in field deliver-
ability.	It	should	be	noted	that	McDaniel	has	assumed	in	the	3P	case,	that	the	
Company	receives	an	extension	to	the	PSA.	Hence	for	this	category	only,	the	
reserves are not restricted to the life of the licence.

2010

10%

180.7

55.0

235.7

41.9

277.6

117.0

394.6

5%

267.2

82.7

349.9

71.3

421.2

269.6

690.8

 MMcfd

57.11

57.11

118.12

136.04

136.04

136.04

136.04

136.04

136.04

136.04

115.10

88.79

15%

128.2

36.6

164.8

25.2

190.0

56.3

246.3

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25

 
 
 
 
 
 
 
 
 
26

OPERATIONS REPORT

T
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1
1
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2

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A
C
R
O

 Songo Songo 
West represents 
a major potential 
upside source of 
reserves in the 
Songo Songo area.

Songo Songo 
West

Songo Songo 
North

SS-1
SS-1

Songo Songo 
Main

SS-9
SS-9

SS-10
SS-10

SS-4
SS-4

SS-6
SS-6

SS-5
SS-5

SS-3
SS-3

SS-7
SS-7

PROVEN 
PROVEN 
SECTION
SECTION

5 kms

KN-1
KN-1

SS-8
SS-8

K-1
K-1

EXPLORATION

TANZANIA

Songo Songo West

Orca Exploration has mapped and evaluated the Songo Songo West prospect 
adjacent	to	the	Songo	Songo	Field	and	is	in	the	early	stages	of	planning	to	drill	
and	test	the	prospect	in	2012.	The	prospect	lies	approximately	2.5	kilometers	
west of the main field and the prognosis is that the prospect is very similar in 
terms	of	trap	and	reservoir	presence	to	the	Songo	Songo	Field.	The	seismic	
on Songo Songo West indicates closure on an elongate north-south oriented 
tilted fault block trap at the same reservoir interval as the main field. Songo 
Songo	West	lies	entirely	within	the	Company’s	Discovery	Blocks.

As with the Songo Songo main field, two reservoirs are envisaged to be present 
within	 the	 SSW	 prospect;	 the	 Neocomian	 and	 the	 Cenomanian,	 although	
the  primary  exploration  potential  lies  within  the  Neocomian  interval. 
McDaniel	 conducted	 an	 independent	 assessment	 of	 natural	 gas	 resources	
in  the  Songo  Songo  West  prospect  in  September  2008.  Several  cases  were 
reviewed	to	estimate	the	size	of	the	potential	gas	accumulation.	The	McDan-
iel’s	Neocomian	and	Cenomanian	GIIP	and	resources	are	summarised	in	the	
tables below.

 
 
 
 
 
 
Neocomian and Cenomanian GIIP and resources

Neocomian (Bcf)

Unrisked	OGIP	

Unrisked resources 

Risked mean resources

Cenomanian (Bcf)

Unrisked	OGIP	

Unrisked resources 

Risked mean resources 

Source: McDaniel September 2008

P90

 232 

 170 

 – 

 P90 

 12 

 9 

–

P50

 566 

 418 

 – 

 P50 

 43 

 32 

 –

Mean

 678 

 505 

 264 

 Mean 

 62 

 46 

 16 

P10

 1,381 

 1,028 

 – 

 P10 

 158 

 118 

 – 

Songo	Songo	West	is	interpreted	by	McDaniel	to	be	a	low	risk	prospect	with	
a	52%	chance	of	success	in	the	Neocomian	and	35%	in	the	Cenomanian.	The	
chance of success is measured as the probability that a hydrocarbon accumu-
lation exists that will demonstrate stabilised flow of hydrocarbons if tested. 
McDaniel	 assessed	 the	 P50,	 unrisked	 recoverable	 resources	 in	 the	 Songo	
Songo West prospect at 450 Bcf and the mean, unrisked recoverable resources 
at	 551	 Bcf.	 Management’s	 unrisked	 mean	 GIIP	 for	 the	 Songo	 Songo	 West	
prospect	of	810	Bcf	compares	with	the	McDaniel	combined	Neocomian	and	
Cenomanian	unrisked	mean	GIIP	of	740	Bcf.	

Songo	Songo	West	represents	a	major	potential	source	of	reserves	upside	in	
the  Songo  Songo  area,  which  could  provide  the  resources  to  underwrite  a 
significant	expansion	of	the	gas	infrastructure	and	markets,	both	in	Tanzania	
and beyond. Orca Exploration is planning to drill the initial exploration well 
(“Songo	Songo	West	South”)	closer	to	Songo	Songo	Island	towards	the	south	
of	 the	 Songo	 Songo	 West	 structure.	 If	 it	 is	 successful	 and	 can	 flow	 at	 com-
mercial rates, the well will be suspended at the mudline as a potential future 
producer	while	a	field	development	plan	is	worked	up.	In	the	case	of	develop-
ment	with	high	angle	to	horizontal	wells,	a	3D	seismic	survey	will	be	required.	
The	most	likely	scenario	is	that	the	southern	part	of	the	field	be	developed	first	
from a central hub tied back to the processing plant on the island, and while 
early field performance is monitored plans to drill up the northern sector of 
the field can be prepared.

Songo Songo West is located in water depths of approximately 18 – 35 meters 
and	will	require	a	jack-up	drilling	rig	to	explore	the	prospect.	Rig	availability	
is a key focus in well planning, and Orca Exploration is actively engaged with 
other operators in East Africa who have a re-
quirement	for	a	jack-up	rig	to	drill	in	shallow	
water	 in	 a	 similar	 timeframe.	 The	 intent	 is	
to  encourage  a  rig  share  opportunity  which 
would	reduce	rig	and	support	vessel	mobiliza-
tion	and	demobilization	costs,	as	well	as	asso-
ciated shared service costs.

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27

 
 
 
 
 
 
 
 
 
 
28

OPERATIONS REPORT

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Corte Dei Signori

Longastrino
Longastrino

Agosta

Orca acreage
Gas field
Prospect
Leads

Agosta

La Rotta

Sub Thrust
Sub Thrust

Mantello

Dosso Degli Angeli
Dosso Degli Angeli

Valli Di
Comocchio Lake

Tre Motte

ITALY

During	 November	 2010,	 Orca	 Ex-
ploration  signed  an  agreement  with 
Northern  Petroleum  plc.  to  acquire 
between	70%	and	75%	of	the	Longas-
trino  Block  in  the  Po  Basin  onshore 
Italy.	 This	 acquisition	 was	 Orca’s	
second	entry	into	Italy	during	2010.	
In	May,	Orca	acquired	a	15%	interest	
in  the  Petroceltic  operated  B.R268.
RG  Permit  in  the  offshore  Central 
Adriatic. 

Bando

Alfonsine

San
Potito

Ilaria

Agosta

Alfonsine

Longastrino

Tre Motte

Dosso Degli
Angeli

Alfonsine

Porto
Corsini

Zorabini

Ravenna

Abbadesse

Cotignola

Baldina

0

10km

La Tosca
La Tosca

0

San Marco 2

Under the terms of the farm in with 
Northern  Petroleum,  Orca  will  pay 
100%	of	the	costs	of	the	La	Tosca-1	
well  up  to  €4.3  million  and  70% 
thereafter  for  the  drilling  phase  of 
the	well.	If	the	well	is	tested	and	completed,	
then Orca will earn an additional 5% by paying 100% of the testing costs up to 
€1.3	million	and	75%	thereafter.	The	Company	will	also	pay	back	costs	of	€0.6	
million.

3km

Earlier  in  2010,  Orca  committed  approximately  US$13  million  to  earn  a 
15%	interest	in	the	Petroceltic	operated	Elsa	discovery	block	and	11	adjacent	
licenses.	The	Elsa	field	has	a	large	volume	of	known	oil	in	place.

The	well	cannot	be	drilled	until	the	Italian	Government	reverses	a	law	that	
excluded the drilling within 5 nautical miles of the coastline and 12 nautical 
miles in the region of protected marine parks (enacted following the blow out 
of	the	Macondo	well	in	the	U.S.	Gulf).	Italy	is	trying	to	reduce	its	dependence	
on imported fuels and it is expected to reverse this law during 2012. Orca is 
not liable to any costs associated with the drilling of Elsa-2 until such time as 
a rig contract is signed.

Central Adriatic - B.R268.RG Permit

The	 B.R268.RG	 Permit	 containing	 Elsa	 is	 located	 on	 and	 at	 the	 northern	
margin	 of	 the	 Jurassic-Miocene	 Apulian	 Carbonate	 Platform.	 Several	 com-
mercial	discoveries	of	oil	are	in	close	proximity	including	the	Rospo	Mare	and	
Ombrina	Mare	fields	on	the	platform,	and	the	Miglianico	field	on	the	platform	
margin.	The	Elsa	discovery	is	analogous	to	the	neighbouring	Miglianico	field,	
and numerous additional prospects and leads have been identified both on 
the	platform	and	at	the	platform	margin	in	the	adjacent	acreage.

The	Elsa	field	is	located	off	the	eastern	coast	of	Italy,	approximately	7	kilome-
ters	offshore	in	around	35m	water.	The	field	was	discovered	by	AGIP	in	1992	
with well Elsa-1, which encountered an oil column of approximately 65m in 
the	Lower	Cretaceous	Maiolica	Formation	at	a	depth	of	around	4,500m.	Due	
to casing restrictions, a sub-optimal open hole drill stem test was attempted 
with	both	water	and	oil	zones	exposed	to	the	wellbore.	Oil	samples,	contami-
nated with water, recovered from the test string had a reported oil gravity of 
15°	 API.	 Uncertainty	 remains	 over	 the	 oil	 gravity,	 especially	 in	 light	 of	 yel-
low-gold fluorescence reported while drilling through the reservoir, and close 
proximity	to	the	Ombrina	Mare	and	Miglianico	fields,	which	lie	at	depths	of	

 
 
 
 
 
 
I

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 Top: Elsa Permit Area 
Bottom: Longastrino  
Permit Area 

Adriatic Sea

d505B.R-EL

d507B.R-EL

d493B.R-EL

d492B.R-EL

d494B.R-EL

around	2,900m	and	4,800m	respectively,	but	which	have	API	gravities	of	18°	
and 34° respectively. Both Orca and Petroceltic believe that the Elsa field will 
be	 commercial	 at	 15°	 API	 oil,	 however	 several	
indications  give  rise  to  the  expectation  that  the 
crude	gravity	may	be	higher	than	the	15°	API.

The	 Elsa-2	 appraisal	 well	 has	 the	 primary	
objective	of	confirming	the	commercial	produc-
tion  potential  of  the  reservoir.  Positive  results 
from	 Elsa-2	 will	 be	 followed	 by	 a	 3D	 seismic	
survey over the field.

The	full	field	mid	case	stock	tank	oil	initially	in	
place	(“STOIIP”)	potential	of	Elsa	is	410	MMbbl.	
The	Operator’s	estimates	of	recoverable	reserves	
are	 in	 the	 region	 of	 100	 MMbbl,	 depending	 on	
oil  gravity  and  viscosity.  Production  would  be 
to  a  floating  production  storage  and  offloading 
(“FPSO”)	and	export	via	a	shuttle	tanker.

The	farm	in	agreement	with	Petroceltic	includes	
the ability to earn equity in a number of offshore 
exploration permits, some of which are within the 
area	subject	to	the	currently	imposed	drilling	ban.	
A number of prospects and leads have been identi-
fied within the exploration acreage ranging in age 
from	Jurassic,	Cretaceous	and	Tertiary	and	having	
primarily  oil  and  some  gas  potential.  A  further 
programme  of  seismic  acquisition  is  planned  to 
evaluate more fully the potential of these explora-
tion permits.

Po Basin - Longastrino Permit

d500B.R-EL

d496B.R-EL

BR268.RG

Miglianico

Elsa
West

ElsaElsa

Ombrina
Mare

d495B.R-EL

S. Stefano
Mare

d499B.R-EL

Rospo
Mare

Fiume TresteFiume
Treste

BR268 RG Elsa
Permits within banned areas 
– contesting rejection notices
Re-permitted blocks. Approved
by MSE and await MATTM approval
Awaiting positive VIA decrees 
from MATTM.
Prospect with oil flows
Oil field
Gas field
12nm limit
5nm limit

ITAELSA-08

Tresigallo

Pomposa

Sabbioncello

Vallicella

Vallezzetta

Bottoni

Migliarino

Gallare

Manara

Porto Verrara

Bando

Alfonsine

Ilaria

Longastrino

Tre Motte

Dosso Degli
Angeli

San Potito

Ravenna

Cotignola

Abbadesse 1DIR

The	Longastrino	permit	is	situated	onshore	Italy	
in  the  Northern  Apennine  foredeep,  commonly 
known  as  the  Po  Valley  Basin.  Numerous  gas 
and gas-condensate fields are located close to the 
permit including Ravenna, Alfonsine, San Potito, 
Cotignola,	Dosso	degli	Angeli	and	Baldina.	Recent	discoveries	include	Agosta	
and	Abbadesse.	There	are	a	number	of	proven	clastic	reservoir	horizons	in	the	
Pliocene	and	Upper	Miocene.	Offset	well	data	indicates	that	these	reservoir	
horizons	have	an	average	porosity	of	20-25%	(maximum	34%)	and	perme-
ability	in	the	range	10-400mD.	Intraformational	clays,	shales	and	marls	act	as	
seals, while the clays also have source potential to generate biogenic gas. 

ITALGO-01

The	principal	target	within	the	Longastrino	Permit	is	the	La	Tosca	prospect.	 
A	 well	 defined	 amplitude	 anomaly	 seen	 on	 3D	 seismic	 is	 present	 within	
mapped	 closure.	 The	 prospect	 is	 just	 2	 kilometers	 to	 the	 north-east	 of	 the	
Alfonsine  gas  field  (300  Bcf)  whose  reservoir  is  the  lower  Pliocene  Porto 
Corsini	Formation.	The	Intra	Lower	Pliocene	target	reservoir	is	mapped	as	
a 3-way dip closed structured trapped against a NW-SE trending thrust fault. 
While	the	primary	reservoir	objective	is	prognosed	at	-1,600m	true	vertical	
depth	subsea	(“TVDSS”),	the	La	Tosca	-1	well	will	be	drilled	to	a	prognosed	
total	 depth	 of	 approximately	 -2,500m	 TVDSS	 to	 test	 deeper	 secondary,	
probable	Miocene,	objectives.

0

15km

March 2011

Orca acreage
Gas field
Condensate field
Gas pipeline
5 nautical mile limit

5  n a u t i c al mile limit

Adele

Azzurra

Porto Corsini
Mare Ovest

Porto Corsini

Zorabini

Baldina

Armida

Diana

Porto Garibaldi
Agostino

Porto Corsini
Mare E

0

0

0

5

Antares

5

10

5

15 kms

10 miles

10 nautical miles

The	 La	 Tosca	 prospect	 is	 estimated	
to contain 45 Bcf of gross mean pro-
spective  resource  with  an  upside  of 
85 Bcf of 99.5% methane gas. Work 
to  secure  a  site  from  which  to  drill 
the	La	Tosca-1	well	is	now	completed	
and  the  well  is  expected  to  spud  in 
Q3 2012.

Upon	 success	 at	 La	 Tosca,	 there	
is  plenty  of  follow-up  exploration 
potential, which initially will require 
additional	 3D	 seismic	 coverage	 to	
confirm  the  potential.  Numerous 
leads  have  been  identified  on  older 
2D	seismic	data	that	if	established	on	
a	new	3D	seismic	dataset,	could	lead	
to significant further exploration.

O
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29

 
 
 
 
 
 
 
 
 
30

OPERATIONS REPORT

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full 

take 

Orca Exploration is committed 
to 
responsibility 
for  the  Company’s  actions 
and  to  incorporate  socially 
responsible practices in all its 
operations	and	decision	making.	It	is	Orca’s	intention	to	create	
positive  impacts  and  operate  sustainably  with  respect  to  the 
environment,  employees,  partners,  communities,  suppliers, 
governments and other stakeholders.

CORPORATE 
SOCIAL 
RESPONSIBLITY

Health	 and	 safety	 are	 top	 priorities	 in	 our	 operations.	 We	 also	 attach	 high	
priority to attracting, developing and retaining talented employees wherever 
we  operate.  Orca  supports  transparency  in  all  its  business  and  financial 
practices and promotes high standards of ethical conduct in all its dealings.

Orca also welcomes the opportunity to give back to communities where we 
operate.	On	Songo	Songo	Island	Orca	is	committed	to	improving	the	quality	
of life of island residents. Over the past several years Orca has developed and 
rolled	out	programmes	that	have	improved	the	health	of	Songo	Songo	Islanders	
and  provided  education  for  youth,  equipment  for  teachers  and  scholarships 
that	are	enabling	island	youth	to	complete	high	school	in	Dar	es	Salaam.

Currently  10  pupils  are  benefitting  from  the  Orca  scholarship  programme 
at	a	school	in	Dar	es	Salaam.	These	children	then	support	organized	reading	
groups and other development programmes when they return to Songo Songo 
Island.	It	is	hoped	that	some	of	these	graduates	may	enter	university	and	Orca	

will continue to sponsor them through their degree courses.

Orca provides assistance on an ongoing basis to the community school on 
Songo	Songo	Island.	The	Company	has	assisted	in	upgrading	the	elemen-
tary school facilities and provided educational materials and equipment. 
Currently the Company is supporting a new kindergarten which it built 
during  2011  and  is  providing  early  learning  facilities  for  children  3  to  6 
years	of	age.	The	Company	has	also	recruited	a	professional	instructor	for	
the	 Learning	 Centre	 to	 provide	 English	 language	 instruction,	 computer	
training  and  entrepreneurial  skills  to  young  adults  and  sponsored  three 
teachers	to	attend	Teacher	Training	College	in	Dar	es	Salaam.

This	year	the	company	will	further	extend	the	kinder-
garten  and  provide  a  fully  equipped  and  secure  play-
ground.	 In	 addition	 Orca	 is	 building	 accommodation	
for the school teachers it has trained and this will incor-
porate	a	new	library	and	IT	centre.

Orca’s	Board	of	Directors	regularly	reviews	the	corporate	
social responsibility aims of the Company and how this 
translates onto practical and beneficial practices.

 
 
 
 
 
 
MANAGEMENT’S DISCUSSION & ANALYSIS 

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32

MANAGEMENT’S DISCUSSION & ANALYSIS

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FORWARD LOOKING STATEMENTS

THIS	 MD&A	 OF	 FINANCIAL	 CONDITIONS	 AND	 RESULTS	 OF	 OPERATIONS	 SHOULD	 BE	 READ	 IN	 CON-
JUNCTION	 WITH	 THE	 AUDITED	 CONSOLIDATED	 FINANCIAL	 STATEMENTS	 AND	 NOTES	 THERETO	
FOR	 YEAR	 ENDED	 31	 DECEMBER	 2011.	 THIS	 MD&A	 IS	 BASED	 ON	 THE	 INFORMATION	 AVAILABLE	 ON	 
25	APRIL	2012.	

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)	 STATE-
MENTS	 THAT	 ARE	 BASED	 ON	 CURRENT	 EXPECTATIONS	 AND	 ESTIMATES	 ABOUT	 THE	 MARKETS	 IN	
WHICH	ORCA	EXPLORATION	OPERATES	AND	(III)	STATEMENTS	OF	BELIEF,	INTENTIONS	AND	EXPEC-
TATIONS	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	 AVAIL-
ABILITY;	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	MATE-
RIALLY	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	APPLICA-
BLE	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	 AC-
TIVITIES	 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	 PRO-
DUCTION	 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	MEA-
SUREMENTS	OF	OTHER	ENTITIES.	

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

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 process-
ing	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.

(c)		 No	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).

In	 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.

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34

MANAGEMENT’S DISCUSSION & ANALYSIS

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	(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	
Insufficiency	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 modifi-
cation;	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.	

(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.	It	is	considered	unlikely	that	this	
will occur during 2012.

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	year	ended	31	December	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.	The	implications	
and	workings	of	the	‘back	in’	are	currently	being	discussed	with	the	Government	Negotiation	Team	(“GNT”)	
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	2011,	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	pro-
cessing	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. 

(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.

(j)		 Profits	on	sales	from	the	Proven	Section	(“Profit	Gas”)	are	shared	between	TPDC	and	the	Company,	the	pro-

portion 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  
of Additional Gas

Cumulative sales  
of Additional Gas

TPDC’s share  
of Profit Gas

Company’s share  
of Profit Gas

MMcfd

0 - 20

> 20 <= 30

> 30 <= 40

> 40 <= 50

> 50

Bcf

0 – 125

> 125 <= 250

> 250 <= 375

> 375 <= 500

> 500

%

75

70

65

60

45

%

25

30

35

40

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 percent-
age 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.

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36

MANAGEMENT’S DISCUSSION & ANALYSIS

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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 Gov-
ernment	of	Tanzania	(“GoT”)	and	take	all	necessary	safe,	health	and	environmental	precautions	all	in	accor-
dance	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.

Consolidation

The	companies	that	are	being	consolidated	are:

Company

Orca	Exploration	Group	Inc

Orca	Exploration	Italy	Inc

Orca	Exploration	Italy	Onshore	Inc

PAE PanAfrican Energy Corporation

PanAfrican	Energy	Tanzania	Limited

Incorporated

British	Virgin	Islands

British	Virgin	Islands

British	Virgin	Islands

Mauritius

Jersey

Orca	Exploration	UK	Services	Limited

United	Kingdom

 
 
 
 
 
 
Results for the year ended 31 December 2011

Operating Volumes 

The	sales	volumes	for	the	year	were	17,464	MMcf	or	47.8	MMcfd.	This	represents	an	overall	increase	of	30%	over	the	
previous	year.	The	Company’s	sales	volumes	were	split	between	the	industrial	and	power	sectors	as	follows:

Operating Volumes

Gross sales volume (MMcf):

Industrial	sector

Power sector

 Total volumes

Gross daily sales volume (MMcfd):

Industrial	sector

Power sector

 Total daily sales volume

Industrial sector

2011

2010

2,742

14,722

17,464

7.5

40.3

47.8

2,504

10,940

13,444

6.9

30.0

36.9

Industrial	sales	volume	increased	by	9%	to	2,742	MMcf	from	2,504	MMcf	in	2010.	The	overall	increase	is	predomi-
nately	a	consequence	of	increased	sales	to	Kioo	Glass	as	a	result	of	the	supply	of	Additional	Gas	for	their	own	power	
generation.	 Sales	 of	 Additional	 Gas	 to	 the	 Wazo	 Hill	 cement	 plant	 operated	 by	 the	 Tanzanian	 Portland	 Cement	
Company	(“TPCC”)	remained	consistent	between	the	two	years.	Industrial	sales	for	the	year	averaged	7.5	MMcfd	
(2010:	6.9	MMcfd).	

Power sector

The	power	sector	sales	volumes	increased	by	35%	to	14,722	MMcf	compared	to	10,940	MMcf	in	2010.	The	increase	
is a result of the 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.	In	order	to	meet	the	increased	demand	the	Symbion	power	plant	was	re-
commissioned	in	July	2011.	

Commodity Prices

US$/mcf

Average sales price

Industrial	sector

Power sector

 Weighted average price

Industrial sector

2011

2010

10.05

2.77

3.92

8.76

2.60

3.75

The	average	gas	price	for	the	year	was	US$10.05/mcf	(2010:	US$8.76/mcf).	The	overall	increase	in	price	achieved	
during the year is a consequence of an increase in world oil prices experienced compared to 2010, together with a 
relative	decline	in	the	level	of	Additional	Gas	sales	to	Wazo	Hill.	The	sales	to	the	Wazo	Hill	cement	plant	are	priced	
by reference to imported coal (their alternative fuel supply) declined from 32% of total industrial volumes in 2010 to 
27% in 2011. 

Power sector

The	average	sales	price	to	the	power	sector	was	US$2.77/mcf	for	the	year,	compared	to	US$2.60/mcf	in	2010.	The	
increase in price is a combination of the 2% annual price indexation and the higher prices achieved under the Portfolio 
Gas	 Sales	 Agreement	 (‘PGSA’)	 Under	 the	 terms	 of	 the	 PGSA	 Additional	 Gas	 consumed	 by	 TANESCO	 above	 37	
MMcfd	is	at	a	higher	sales	price.

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38

MANAGEMENT’S DISCUSSION & ANALYSIS

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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. 

Under	 the	 terms	 of	 the	 PSA,	 TPDC	 is	 able	 to	 recover	 reasonably	 incurred	 marketing	 costs.	 During	 2011,	 TPDC	
recovered	US$1.4	million	in	respect	of	such	marketing	costs.	The	Company’s	Costs	Gas	entitlement	averaged	52%	of	
the	Net	Revenues	during	the	year	(2010:	75%).	The	decline	was	due	to	the	recovery	of	the	historical	cost	pool	during	
2011	and	the	payment	of	the	TPDC	marketing	costs.

The	Additional	Gas	sales	volumes	during	the	year	have	increased	from	37.2	MMcfd	in	Q1	2011	to	57.7	MMcfd	in	Q4	
2011.	Consequently,	the	revenue	less	cost	recovery	share	of	revenue	(“Profit	Gas”)	was	35%	in	Q1	2011,	40%	in	Q2	
2011	and	55%	for	both	Q3	and	Q4	2011	before	adjustments	for	the	TPDC	back-in	discussed	below.

In	 2011	 a	 large	 proportion	 of	 the	 gas	 production	 was	 from	 the	 SS-10	 well,	 which	 has	 been	 deemed	 to	 have	 been	
“backed	into”	by	TPDC.	As	a	consequence	TPDC’s	profit	share	increases	by	20%	for	the	production	of	gas	emanating	
from the SS-10 well. 

Orca	Exploration	was	allocated	a	total	of	73.7%	in	2011	(2010:	84%)	of	the	Net	Revenues	as	follows:

Figures in US$’000

Gross sales revenue

Gross tariff for processing plant and pipeline infrastructure

Gross revenue after tariff

Analysed as to:

Company Cost Gas

Company Profit Gas

Company operating revenue 

TPDC	share	of	revenue

2011

68,394

(11,672)

56,722

29,215

12.579

41,794

14,928

56,722

2010

50,348

(7,932)

42,416

31,812

3,853

35,665

6,751

42,416

The	Company’s	total	revenues	for	the	year	amounted	to	US$45,893,000	after	adjusting	the	Company’s	operating	
revenue	of	US$41,794,000	by:
i)	

US$6,626,000	for	income	tax	in	the	current	year.	The	Company	is	liable	for	income	tax	in	Tanzania,	but	the	
income	 tax	 is	 recoverable	 out	 of	 TPDC’s	 Profit	 Gas	 when	 the	 tax	 is	 payable.	 To	 account	 for	 this,	 revenue	 is	
adjusted	to	reflect	the	current	year	income	tax	charge	or	loss.

ii)	 US$2,527,000	for	the	deferred	effect	of	Additional	Profits	Tax.	This	tax	is	considered	a	royalty	and	is	netted	

against revenue.

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

Figures in US$’000

Industrial	sector

Power sector

Gross sales revenue

Processing and transportation tariff

TPDC	share	of	revenue

Company operating revenue

Additional	Profits	Tax

Current	income	tax	adjustment

Revenue

2011

2010

27,562

40,832

68,384

(11,672)

(14,928)

41,794

(2,527)

6,626

45,893

21,933

28,415

50,348

(7,932)

(6,751)

35,665

(800)

3,943

38,808

Processing and Transportation Tariff

The	Company	currently	pays	a	flat	rate	regulated	gas	processing	and	transportation	tariff	of	US$0.59/mcf	to	Songas.	
Under the terms of the gas contracts with the power sector, the Company will pass on any increase or decrease in the 
EWURA	approved	charges.	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).	Under	the	terms	of	this	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	regulated	tariff	of	US$0.59/mcf	payable	to	Songas.	The	charge	for	the	additional	
tariff was US$1.4 million for the year. 

Production and distribution expenses

The	production	and	distribution	expenses	are	summarised	in	the	table	below:

Figures in US$’000

Share of well maintenance 

Other field and operating costs

Distribution	costs

Production and distribution expenses

2011

806

2,829

3,635

2,453

6,088 

2010

775

1,855

2,630

2,249

4,879

The	well	maintenance	costs	are	allocated	between	Protected	and	Additional	Gas	based	on	the	proportion	of	their	re-
spective	sales	during	the	year.	The	total	costs	for	the	maintenance	for	the	year	was	US$1,453,000	(2010:	US$1,235,000)	
of	which	US$806,000	(2010:	US$775,000)	was	allocated	for	the	Additional	Gas.

Other field operating costs include an apportionment of the annual PSA license costs regulatory fees, the annual evalu-
ation	of	reserves	and	the	cost	of	personnel	and	chemicals	that	are	not	recoverable	from	Songas.	The	increase	in	costs	
over 2010 is primarily a consequence of the payment for additional chemicals to deliver higher levels of Additional 
Gas production.

Distribution	costs	represent	the	direct	cost	of	maintaining	the	ring-main	distribution	pipeline	and	pressure	reduction	
station	(security,	insurance	and	personnel).	The	increase	over	2010	is	a	result	of	higher	insurance	premiums.

TPDC	and	MEM	have	indicated	that	they	wish	Orca	to	unbundle	the	downstream	business	in	Tanzania.	The	method-
ology	for	this	is	still	to	be	discussed	in	detail	with	both	TPDC	and	MEM.

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40

MANAGEMENT’S DISCUSSION & ANALYSIS

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Operating netback 

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

Amounts in US$/mcf

Gas price – industrial

Gas price – power

Weighted average price for gas

Tariff

TPDC	share	of	revenue

Net selling price

Well maintenance and other operating costs

Distribution	costs

Operating netback

2011

10.05

2.77

3.92

(0.67)

(0.85)

2.40

(0.21)

(0.14)

2.05

2010

8.76

2.60

3.75

(0.59)

(0.50)

2.66

(0.20)

(0.17)

2.29

The	operating	netback	decreased	by	10%	from	US$2.29/mcf	to	US$2.05/mcf	in	2011.	

The	increase	in	the	weighted	average	sales	price	from	US$3.75/mcf	to	US$3.92/mcf	is	a	consequence	of	the	increase	in	
gas	price	achieved	in	both	the	industrial	and	power	markets.	The	increase	in	the	price	of	power	sales	is	in	line	with	con-
tractual	arrangements.	The	rise	in	industrial	sales	is	a	consequence	of	the	slight	increase	in	global	energy	prices	during	
2011.	As	a	consequence	of	the	power	crisis	in	Tanzania	the	volume	of	power	sales	accounted	for	84%	of	the	total	Addi-
tional Gas volumes in 2011 compared to 81% in 2010.

The	 increase	 in	 the	 tariff	 rate	 from	 US$0.59/mcf	 to	 US$0.67/mcf	 is	 a	 consequence	 of	 the	 signing	 of	 the	 Re-rating	
Agreement	with	TANESCO	and	Songas	as	discussed	above,	with	the	EWURA	regulated	tariff	remaining	at	US$0.59/
mcf for the year. 

The	increase	in	TPDC’s	revenue	from	US$0.50/mcf	to	US$0.85/mcf	is	a	consequence	of	the	recovery	of	the	cost	pool	
during	2011,	TPDC’s	recovery	of	past	marketing	costs	and	the	increased	profit	share	from	the	production	of	the	SS-10	well.	

The	increase	in	the	well	maintenance	and	other	operating	costs	is	a	consequence	of	the	use	of	additional	chemicals	associ-
ated with the higher levels of Additional Gas production during the year. 

General and Administrative Expenses

The	general	and	administrative	expenses	(“G&A”)	may	be	analysed	as	follows:

Figures in US$’000

Employee costs

Consultancy

Travel	&	accommodation

Communications

Office

Insurance

Auditing & taxation

Depreciation

Reporting, regulatory and corporate finance

Marketing	and	legal	costs	

New ventures

Stock based compensation 

General and administrative expenses

2011

4,658

2,380

1,060

118

2,001

541

302

292

1,045

12,397

1,934

258

851

15,440

2010

2,558

2,745

883

113

1,116

323

215

208

637

8,798

1,876

378

664

11,716

 
 
 
 
 
 
The	G&A	includes	the	running	of	the	gas	business	in	Tanzania	the	majority	of	which	is	recoverable	as	Cost	Gas.

G&A	averaged	approximately	US$1.3	million	per	month	in	2011	(2010:	US$1.0	million).	G&A	per	mcf	was	US$0.88/
mcf	(2010:	US$0.87/mcf).	The	main	variances	are	summarised	below:

Employee costs

The	increase	in	employment	costs	is	a	consequence	of	the	hiring	of	additional	staff,	the	upgrading	of	management	in	
anticipation	of	the	extensive	development	program	in	Tanzania,	together	with	additional	fees	and	bonus	payments	
incurred in relation to new senior executive appointments. 

Office costs

The	level	of	office	costs	have	increased	due	to	the	establishment	of	a	separate	serviced	office	and	the	increase	in	space	
required	for	the	expansion	of	the	Tanzanian	operation.

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 

The	breakdown	of	the	costs	incurred	in	relation	to	stock	based	compensation	is	detailed	in	the	table	below:

Figures in US$’000

Stock options

Stock appreciation rights

2011

1,171

(320)

851

2010

607

57

664

A total of 3,057,400 stock options were issued and outstanding at the end of 2011 compared to 2,557,400 at the end 
of 2010. A total of 500,000 stock options were issued during 2011 with exercise prices ranging from Cdn$3.60 to 
Cdn$4.75, a five year term and immediate vesting at the date of grant. A total one off charge of US$1.2 million was 
recorded in relation to these options. 

A	total	of	930,000	stock	appreciation	rights	were	outstanding	at	the	end	of	2011.	In	June	2010,	225,000	stock	apprecia-
tion	rights	were	issued	to	the	new	non-executive	directors	with	an	exercise	price	of	Cdn$4.20.	The	rights	have	a	term	of	
five years 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	 31	 December	 2011,	 the	 following	 assumptions	 were	 used;	 stock	 volatility	 between	 42%	 and	
75%, a risk free interest rate of 1.50% to 2.50% and a closing stock price of Cdn$2.90. A total credit of US$0.3 million 
was	recorded	in	the	year	as	a	consequence	of:	a	fall	in	the	volatility	of	the	stock	price;	a	shorter	contractual	life	of	the	
majority	of	the	rights	to	less	than	six	months;	together	with	a	decline	in	the	closing	stock	price.	

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42

MANAGEMENT’S DISCUSSION & ANALYSIS

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Net Finance Costs

The	loss	on	foreign	exchange	experienced	in	the	year	is	a	result	of	the	strengthening	US	Dollar	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	rate	exposure	between	the	time	the	invoices	are	submitted	and	the	date	the	payment	is	
received. 

Figures in US$’000

Finance income

Interest	income

Foreign exchange gain

Finance costs

Overdraft charges

Other finance costs

Foreign exchange loss

Net finance costs

Taxation

Income Tax

2011

2010

5

80

85

–

(100)

(938)

(1,038)

(953)

40

–

40

(12)

–

(890)

(902)

(862)

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	31	December	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$15.2	million	which	represents	an	
additional	deferred	future	income	tax	charge	of	US$2.4	million	for	the	year.	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 percent-
age	change	in	the	United	States	Industrial	Goods	Producer	Price	Index,	an	Additional	Profits	Tax	(“APT”)	is	payable.	

The	Company	provides	for	Deferred	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	of	20%	is	then	applied	to	profit	gas	of	US$12.6	million	in	2011	
(2010:	US$3.9	million),	accordingly,	US$2.5	million	(2010:	US$0.8	million)	has	been	netted	off	revenue	for	the	year	
ended	31	December	2011

Management	does	not	anticipate	that	any	APT	will	be	payable	in	2012,	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	expen-
ditures	for	2012.	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	con-
sequently	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 reward the Company for taking higher risks by incurring capital expenditure in advance of revenue 
generation.

 
 
 
 
 
 
 
 
 
 
Depletion and Depreciation Expense

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	2011,	the	proven	
reserves	as	evaluated	by	the	independent	reservoir	engineers	McDaniel	&	Associates	Consultants	Ltd	(“McDaniel”)	
were	469.1	Bcf	after	TPDC	‘back	in’	on	a	life	of	license	basis.	This	leads	to	an	average	depletion	charge	of	US$0.47/
mcf	for	the	year	(2010:	US$0.36/mcf).

Non-Natural	Gas	Properties	are	depreciated	as	follows:

Leasehold	improvements

Computer equipment

Vehicles

Fixtures and fittings

Over remaining life of the lease

3 years

3 years

3 years

Carrying Value 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. 

Funds Generated by Operations

Funds	from	operations	before	working	capital	changes	were	US$22.7	million	for	the	year	ended	31	December	2011	
(2010:	US$20.8	million).	

Figures in US$’000

Profit after taxation

Adjustments	(i)

Funds flow from operating activities 

Working	capital	adjustments	(i)

Net cash flows from operating activities

Net cash flows used in investing activities

Net cash flows from/(used in) financing activities

Increase	in	cash	and	cash	equivalents

Effect of change in foreign exchange

Net (decrease)/increase in cash and cash equivalents
(i)  See consolidated statements of cash flows

2011

7,986

14,672

22,658

(18,101)

4,577

(14,584)

(681)

(10,688)

(151)

(10,839)

2010

10,011

10,825

20,836

(5,302)

15,534

(2,923)

18,705

31,616

(340)

30,976

The	overall	increase	in	sales	volumes	achieved	during	2011	has	not	been	reflected	in	the	funds	flow	from	operation	due	
to	the	recovery	in	the	Tanzanian	cost	pool,	the	increase	in	G&A	and	the	marginal	increase	in	the	costs	of	production	
associated with the record production levels.

The	net	cash	flow	from	operations	has	decreased	due	to	the	increase	in	the	level	of	trade	debtors	following	the	dete-
rioration	in	the	level	of	payments	received	from	TANESCO.	The	increase	in	capital	expenditure	during	the	year	is	a	
consequence of the commencement of the 2011/12 drilling programme.

As  a  consequence  of  the  factors  described  above  the  net  cash  has  decreased  by  US10.8  million  during  the  year.  
The	increase	in	cash	during	2010	was	primarily	a	consequence	of	the	increased	funding	from	the	successful	completion	
of the rights issue in October 2010 (net funding after costs of US$18.5 million). 

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44

MANAGEMENT’S DISCUSSION & ANALYSIS

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Capital Expenditures

Capital	expenditures	amounted	to	US$18.1	million	during	the	year	(2010:	US$3.4	million).	The	capital	expenditures	
may	be	analysed	as	follows:

Figures in US$’000

Geological and geophysical and well drilling

Pipelines and infrastructure

Power development

Other equipment

2011

16,475

1,158

37

465

18,135

2010

1,598

1,582

6

195

3,381

Geological and geophysical and well drilling – US$16.5 million

The	SS-10	development	well	tie-in	to	the	gas	processing	infrastructure	was	completed	in	the	first	quarter	of	the	year	
at a cost of US$0.5 million. A total of US$12.0 million was incurred on the SS-11 development well, including the 
ordering	of	long	lead	items	for	both	the	drilling	of	the	well	and	flow-lines.	The	drilling	of	the	SS-11	development	well	
commenced	in	February	2012	and	is	scheduled	to	be	complete	by	mid	May.	A	total	of	US$1.1	million	was	incurred	on	
the ordering of long lead items for the Songo Songo West exploration well which is currently scheduled to be spud in 
Q4	2012.	The	balance	of	the	expenditure	in	Tanzania	was	spent	on	studies	in	relation	to	the	connection	of	the	develop-
ment wells to the infrastructure, well enhancement and the work-over programme, with a view to enabling the Songo 
Songo	field	to	be	able	to	produce	in	excess	of	200	MMcfd	by	the	end	of	2012	(subject	to	infrastructure	availability).

A total of US$0.9 million was incurred in relation to the payment of past costs incurred by Northern Petroleum on its 
Longastrino	block	in	the	Po	Valley	in	northern	Italy.	The	exploration	well	is	due	to	be	spud	in	July	2012.

Pipelines and infrastructure – US$1.2 million

A total of US$0.7 million was incurred during the year on new customer connections together with a further US$0.2 
million	on	enhancing	the	metering	capabilities	for	both	the	power	and	industrial	sectors.	The	installation	of	the	meters	
has lead to a more efficient invoicing system and has enabled an accurate measure of usage by customers to be obtained 
on a daily basis.

An additional US$0.3 million was incurred during the year on the continued expansion of compressed natural gas 
(“CNG”)	facilities,	with	the	installation	of	a	daughter	station	at	Mikocheni.

Working Capital

Working	capital	as	at	31	December	2011	was	US$56.0	million	(31	December	2010:	US$52.4	million)	and	may	be	
analysed	as	follows:

Figures in US$’000

Cash and cash equivalents

Trade	and	other	receivables

Taxation	receivable

Prepayments

Trade	and	other	payables

Taxation	payable

Working capital

2011

34,680

40,348

5,880

302

81,210

22,801

2,403

2010

45,519

13,583

4,009

409

63,520

9,156

2,000

56,006

52,364

The	increase	in	working	capital	by	US$3.6	million	during	2011	is	a	consequence	of	the	US$22.7	million	of	funds	flow	
for the year being used to fund the US18.1 million capital programme. 

 
 
 
 
 
 
 
 
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The	majority	of	the	cash	is	held	in	US	and	Cdn	Dollars	in	Mauritius,	and	in	Tanzanian	Shillings	in	Tanzanian	bank	
accounts	and	there	are	no	restrictions	to	access	any	of	these	funds.	There	are	no	restrictions	in	Tanzania	for	converting	
Tanzania	Shillings	into	US	Dollars.	Any	surplus	cash	is	held	in	a	fixed	rate	interest	earning	deposit	account.	

Trade	and	other	receivables	at	31	December	2011	represent	US$35.7	million	of	trade	receivables	(2010:	US$11.9	
million),	US$4.7	million	of	other	receivables	(2010:	US$1.7	million)	and	taxation	US$6.5	million	(2010:	US$4.0	
million).	The	increase	in	other	receivables	is	in	relation	to	the	increase	in	funds	receivable	from	Songas	for	the	opera-
torship	of	the	gas	processing	plant	and	associated	projects.	The	increase	in	taxation	is	a	consequence	of	the	level	of	
current	taxation	paid	in	the	year,	whereby	any	tax	payable	is	recoverable	form	TPDC	in	accordance	with	the	produc-
tion sharing agreement.

Under the contract terms with the industrial customers, the Additional Gas payments must be received within 30 
days	of	the	month	end.	As	at	31	December	2011,	US$7.8	million	(2010:	US$4.2	million)	was	due	from	industrial	
customers,	the	majority	of	which	has	subsequently	been	received.	The	balance	of	US$28.0	million	(2010:	US$7.7	
million)	is	made	up	of	amounts	due	from	the	two	power	customers,	TANESCO	and	Songas.

As	at	31	December	2011,	the	Company	has	US$22.8	million	of	financial	liabilities	with	regards	to	trade	and	other	
payables of which US$17.1 million is due within one to three months, US$4.9 million is due within three to six months, 
and	US$0.8	million	is	due	within	six	to	twelve	months.	The	Company	has	a	current	taxation	liability	of	US$2.4	million	
payable within three months.

The	Company	sells	50%	of	its	operating	revenue	(2011	-	US$45.9	million)	to	TANESCO.		Songas’	financial	security	
is	heavily	reliant	on	the	payment	of	capacity	and	energy	charges	by	TANESCO.	TANESCO	is	dependent	on	the	Gov-
ernment	of	Tanzania	for	some	of	its	funding.	Despite	having	a	history	of	delayed	payments,	TANESCO	has	previously	
settled	in	full	the	outstanding	balance	subsequent	to	each	quarter	end.	As	at	31	December,	2011,	TANESCO	owes	the	
Company US$24.2 million of which $11.1 million was collected subsequent to year end. As of the date of this report, 
the	Company	has	not	received	payments	from	TANESCO	with	respect	to	any	2012	production	and	at	the	date	of	this	
report	is	owed	US$22.9	million.	There	is	a	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.	The	Company	
has	been	assured	by	the	Ministry	of	Energy	that	TANESCO	will	pay	the	outstanding	invoices	as	soon	as	TANESCO	
has	signed	a	new	financing	facility,	and	that	this	process	is	nearing	completion.	In	the	event	that	Company	does	not	
collect	from	TANESCO	the	outstanding	receivables	at	year	end	and	TANESCO	continues	to	be	unable	to	pay	the	
Company for subsequent 2012 gas deliveries, the Company may need additional funding for its ongoing operations 
and	to	continue	its	committed	exploration	and	development	program	in	2012.	There	are	no	guarantees	that	such	ad-
ditional funding will be available when needed, or will be available on suitable terms.

Outstanding Share Capital

There	were	34.5	million	shares	outstanding	as	at	31	December	2011	which	may	be	analysed	as	follows:

Number of shares (‘000)

Shares outstanding

Class A shares

Class B shares

Convertible securities

Options

Fully diluted Class A and Class B shares

Weighted average

Class A and Class B shares

Convertible securities

Options

Weighted average diluted Class A and Class B shares

2011

2010

1,751

32,747

34,498

3,057

37,555

1,751

32,939

34,690

2,557 

37,247

34,656

30,795 

1,176

35,832

1,098

31,893

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46

MANAGEMENT’S DISCUSSION & ANALYSIS

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The	movement	in	Class	B	shares	during	the	year	is	analysed	in	the	table	below:

Number of shares (‘000)

As at 1 January

Shares issued

Stock options exercised

Normal course issuer bid

As at 31 December

2011

32,939

–

–

(192)

32,747

2010

 27,743

4,956

240

–

32,939 

As at 25 April 2012, there were a total of 32,742,515 Class B shares and 1,751,195 Class A shares outstanding.

Stock Based Compensation

The	 stock	 option	 plan	 provides	 for	 the	 granting	 of	 stock	 options	 to	 directors,	 officers,	 employees	 and	 consultants.	
The	exercise	price	of	each	stock	option	is	determined	as	the	closing	market	price	of	the	common	shares	on	the	day	
prior to the day of grant. Each stock option granted permits the holder to purchase one common share at the stated 
exercise	price.	The	Company	records	a	charge	to	the	profit	and	loss	account	using	the	Black-Scholes	fair	valuation	
option	pricing	model.	The	valuation	is	dependent	on	a	number	of	estimates,	including	the	risk	free	interest	rate,	the	
level	of	stock	volatility,	together	with	an	estimate	of	the	level	of	forfeiture.	The	level	of	stock	volatility	is	calculated	with	
reference to the historic closing share price at the date of issue.

Number of options (‘000)

As	at	1	January	2011

Granted

Exercised

As at 31 December 2011

Options

2,557

500

–

3,057

There	were	500,000	new	stock	options	issued	during	the	year	with	a	weighted	average	exercise	price	of	Cnd$4.18.	The	
new stock options vest on the date of issue and have a term of five years. A total charge of US$1.2 million has been 
recognised for the year in relation to the new stock options. 

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 (65.1 Bcf as at 31 
December	2011).	

The	Gas	Agreement	may	be	superseded	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.

 
 
 
 
 
 
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	 approxi-
mately	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.	

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	com-
patibility	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.	It	is	currently	anticipated	that	the	Elsa-2	well	will	be	drilled	in	2013.	

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	ap-
proximately	€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	explora-
tion	well	is	expected	to	be	drilled	in	July	2012	at	an	estimated	cost	to	the	Company	of	US$8	million.	

There	are	no	further	capital	commitments	in	Italy.

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MANAGEMENT’S DISCUSSION & ANALYSIS

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Songo Songo deliverability

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.	In	October	a	new	corrosion	logging	programme	was	
undertaken	to	confirm	its	condition	and	it	is	now	considered	that	the	well	may	stay	on	production	until	31	May	2012.	
The	Company	will	perform	a	corrosion	log	and	pressure	test	the	annulus/casing	to	assess	whether	SS-9	can	continue	on	
production	after	the	end	of	May	2012.

The	Company	is	currently	drilling	a	new	onshore	deviated	well	(SS-11)	which	is	expected	to	be	connected	to	the	gas	
processing	plant	by	the	end	of	July	2012.	In	the	event	that	SS-9	is	taken	off	production	there	may	be	a	period	where	the	
Company	can	only	deliver	approximately	80	MMcfd	until	SS-11	is	connected	to	the	gas	processing	plant.

Songo Songo commitments

The	total	cost	of	the	SS-11	well	including	its	connection	to	the	gas	processing	plant	is	estimated	at	US$33	million	and	
US$12	million	was	incurred	on	this	prior	to	31	December	2011.	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 in 2012 
of US$18 million. 

Additional	capital	expenditure	in	Tanzania	is	dependent	on	the	payments	from	TANESCO	being	brought	up	to	date	
and	the	satisfactory	conclusion	of	the	GNT,	satisfactory	progress	on	infrstructure	expansion	and	the	subsequent	raising	
of	finance.	The	capital	expenditure	is	required	to	enable	the	Songo	Songo	field	to	be	able	to	produce	200	MMcfd	in	line	
with the anticipated infrastructure expansion. 

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

The	pace	and	extent	of	the	Company’s	2012	work	programme	will	be	dependent	on	the	availability	of	sufficient	capital.	
The	 planned	 2012	 programme	 includes	 the	 drilling	 of	 two	 development	 wells	 (SS-11	 and	 SS-12	 on	 Songo	 Songo	
Island)	and	two	exploration	wells	(Songo	Songo	West	and	La	Tosca	in	Italy).	

The	drilling	of	SS-12	is	dependent	on	the	immediate	receipt	of	outstanding	overdue	payments	of	approximately	US$20	
million	from	TANESCO,	the	securing	of	a	US$10	million	overdraft	facility	and	satisfactory	progress	by	the	Tanzanian	
Government on the infrastructure expansion. 

In	addition,	the	drilling	of	Songo	Songo	West	will	require	the	Company	to	secure	a	debt	facility,	though	this	is	likely	to	
be	dependent	on	the	satisfactory	outcome	of	discussions	with	the	Government	Negotiation	Team	as	detailed	below.

Contingencies

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.	It	is	
considered unlikely that this will occur during 2012. 

 
 
 
 
 
 
Government Negotiation Team

In	February	2012,	the	Government	announced	that	it	was	setting	up	a	Government	Negotiation	Team	(‘GNT’)	to	
discuss	a	number	of	issues	in	relation	to	the	Company’s	Production	Sharing	Agreement	(‘PSA’)	with	the	Tanzania	
Petroleum	Development	Corporation	that	was	signed	in	October	2001.	

The	scope	of	the	GNT	is	to	discuss	a	number	of	points	that	were	raised	by	the	Parliamentary	Committee	for	Energy	
and	Minerals	into	the	workings	of	the	PSA.	This	includes,	but	is	not	limited	to,	TPDC	back	in	rights,	profit	sharing	
arrangements, the divestment of the downstream assets, cost recovery and Orca’s management of the upstream opera-
tions.	Orca	will	discuss	these	matters	in	good	faith	with	the	GNT,	but	reserves	its	rights	to	defend	its	position	should	
no satisfactory agreement be reached.

Back in

TPDC	has	indicated	that	they	wish	to	exercise	their	right	to	‘back	in’	to	the	field	development.	The	implications	and	
workings	of	the	‘back	in’	will	be	discussed	with	GNT	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. 

Unbundling

TPDC	and	Ministry	of	Energy	and	Mines	(“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	the	GNT.

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.	The	level	of	cost	gas	will	increase	during	2012	as	a	result	of	significant	expen-
diture	on	the	drilling	activities.	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	satisfactorily	resolve	the	differences	with	the	GNT,	the	
Company will utilise the extensive dispute mechanisms outlined in the PSA which includes international arbitration. 

Off-Balance Sheet Transactions

As	at	31	December	2011,	the	Company	had	no	off-balance	sheet	arrangements.

Related Party Transactions

One	of	the	non	executive	Directors	is	a	partner	at	a	law	firm.	During	the	year,	the	Company	incurred	US$154,000	to	
this	firm	for	services	provided.	The	transactions	with	this	related	party	was	made	at	the	exchange	amount.

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50

MANAGEMENT’S DISCUSSION & ANALYSIS

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SUMMARY QUARTERLY RESULTS

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

2011

2010

Q4

Q3

Q2

Q1

Q4

Q3

Q2

Q1

(Figures in US$’000  
except where otherwise stated)

Financial

Revenue 

17,500

10,457

8,296

Profit/(loss) after taxation 

Operating netback (US$/mcf)

5,267

2.41 

(54)

1.78

383

1.80

9,640

2,390

2.16

10,557

10,975

1,885

2.28

3,579

2.32

9,017

2,608

2.37

8,259

1,940

2.19

Working capital

56,006

58,369

57,070

55,759

52,364

30,093

24,941

20,891

Shareholders’ equity

106,659

101,563

100,956

100,573

98,183

77,827

73,942

70,955

Profit/(loss) per share  
– basic (US$)

Profit/(loss) per share  
– diluted (US$)

Capital expenditures

Geological and geophysical  
and well drilling

Pipeline and infrastructure

Power development

Other equipment

Operating

Additional Gas sold – 
industrial (MMcf)

Additional Gas sold  
– power (MMcf)

Average price per mcf  
– industrial (US$)

Average price per mcf  
– power (US$)

0.15 

0.00

0.01

0.07

0.05

0.12

0.09

0.07

0.15 

0.00

0.01

0.07

0.05

0.12

0.08

0.06

10,989

3,463

11 

22 

239 

421

–

41

1,124

364

11

94

899

362

4

91

607

383

–

45

502

692

6

23

320

492

–

77

169

15

–

50

786

719

688

550

687

770

562

485

4 521

4,442

2,965

2,794

2,926

2,918

2,440

2,656

9.94 

10.47

10.28

9.42

8.67

8.01

9.45

9.32

2.97 

2.76

2.64

2.62

2.63

2.63

2.56

2.56

The	principal	developments	in	Q4	2011	were	as	follows:

•		

Achieved	a	quarterly	sales	volume	of	5,307	MMcf	or	57.6	MMcfd	which	represents	the	best	quarter	since	sales	
began in 2004. Sales revenue amounted to US$17.5 million. 

•	 The	Company	took	delivery	of	the	Sakson	PR5	drilling	rig	at	Songo	Songo	Island.	The	rig	commenced	drilling	
the	SS-11	(previously	SS-A)	in	February	2012.	The	SS-11	well	is	the	first	well	in	an	extensive	drilling	and	devel-
opment	programme	in	Tanzania.

•	 The	Company	continued	to	source	a	rig	for	the	highly	prospective	Songo	Songo	West	exploration	well.

•	

•	

On	7	October	2011	the	Company	activated	a	Normal	Course	Issuer	Bid	and	received	the	TSX	Venture	Exchange	
approval to purchase upto 1,701,345 Class B shares during the period 10 October 2011 to 9 October 2012. As 
at	the	31st	December	2011	a	total	of	192,000	Class	B	shares	had	been	re-purchased	

On	18	November	2011,	the	Tanzanian	Parliament	received	a	report	from	a	special	Parliamentary	Committee	
that	accused	Orca’s	subsidiary	PanAfrican	Energy	Limited	(“PanAfrican”)	of	certain	irregularities	and	recom-
mended	that	PanAfrican	be	removed	from	the	Songo	Songo	Production	Sharing	Agreement	(“PSA”).	The	Gov-
ernment	has	set	up	a	Government	Negotiation	Team	to	address	the	Parliamentary	Committee	concerns.	It	is	
assessed	that	this	is	the	right	forum	to	address	and	resolve	the	outstanding	issues.	However	Orca	reserves	its	
right to defend its position should no satisfactory agreement be reached. 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Variance analysis between quarters

Revenue

The	 Company	 commenced	 the	 sale	 of	 Additional	 Gas	 to	 industrial	 customers	 in	 September	 2004.	 Since	 then,	 the	
volumes	of	Additional	Gas	sold	to	the	industrial	sector	have	increased	from	an	average	of	1.2	MMcfd	in	Q4	2004	to	
8.5	MMcfd	in	Q4	2011	(Q4	2010:	7.5	MMcfd).	Industrial	sales	have	traditionally	peaked	in	the	third	quarter	of	each	
year	as	textile	customers	take	advantage	of	low	cotton	prices	during	the	harvest	season.	However	the	Q4	2011	sales	
were	greater	than	the	7.8	MMcfd	recorded	in	Q3	2011	as	a	result	of	industrial	customers	using	gas	for	their	own	power	
generation.	The	average	sales	in	Q3	2010	were	8.4	MMcfd.	The	higher	volume	recorded	in	2011	is	primarily	due	to	
the	sale	of	Additional	Gas	to	Kioo	Glass	for	power	generation,	with	the	sales	to	Wazo	Hill	cement	plant	falling	to	1.8	
MMcfd	in	Q4	2011	compared	to	2.9	MMcfd	in	Q4	2010.	The	average	sales	price	achieved	in	Q4	was	US$9.94/mcf	
compared to US$8.67/mcf in Q4 2010. 

The	sale	of	Additional	Gas	to	the	power	sector	commenced	in	Q3	2005	and	this	contributed	towards	a	significant	step	
increase	in	revenue	from	that	quarter.	In	Q4	2011,	sales	averaged	49.1	MMcfd	compared	to	31.8	MMcfd	in	Q4	2010.	
This	represents	the	highest	daily	rate	recorded.	The	increase	is	a	consequence	of	increased	generation	and	infrastruc-
ture	capacity.	The	average	price	for	power	sales	in	Q4	2011	was	US$2.97/mcf	compared	to	US$2.63/mcf	in	Q4	2010.	
The	price	of	gas	to	the	power	sector	is	set	by	reference	to	the	initialed	Amended	and	Restated	Gas	Agreement	and	the	
Portfolio Gas Sales Agreement. 

Profit before tax

A profit before taxation of US$8.7 million was recorded in Q4 2011 compared to a profit of US$3.6 million in Q4 
2010.	The	increase	is	attributable	to	the	increase	in	Additional	Gas	sales.

Working capital

The	increase	in	working	capital	by	US$1.6	million	during	2011	is	primarily	due	to	higher	level	of	power	sales	achieved	
during 2011. 

SELECTED FINANCIAL INFORMATION

Selected annual financial information derived from the audited consolidated financial statements for the years ended 
31	December	2009,	2010	and	2011	is	set	out	below:

Figures in US$’000 except per share amount

Revenue

Funds flow from operating activities

Profit after taxation

Total	assets

Profit	per	share:

Basic 

Diluted	

2011

45,893

22,658

7,986

151,844

0.23

0.22

2010

38,808

20,836

10,011

124,408

0.33

0.31

2009

25,317

12,332

3,324

86,277

0.11

0.11

Revenue	increased	by	18%	to	US$45.9	million	in	2011	from	US$38.8	million	in	2010.	The	sales	volumes	were	30%	
higher	in	2011	than	2010,	with	the	weighted	average	price	increasing	from	US$3.75/mcf	to	US$3.92/mcf.	In	2011,	
current	taxation	of	US$5.1	million	was	payable	(2010:	US$	2.7	million)	which	in	accordance	with	the	terms	of	the	
PSA	 is	 recoverable	 from	 TPDC.	 Consequently	 revenue	 in	 2011	 has	 been	 uplifted	 by	 the	 gross	 amount	 of	 US$7.3	
million	(2010:	US$3.4	million).	

The	 level	 of	 industrial	 volumes	 increased	 by,	 10%	 to	 2,742	 MMcf	 in	 2011	 from	 2,504	 MMcf	 in	 2010,	 mainly	 as	 a	
consequence	of	the	increase	in	sales	to	Kioo	Limited.	The	level	of	power	volumes	increased	by	35%	to	14,722	MMcf	
(2010:10,940	MMcf).	The	increase	in	power	sales	is	attributable	to	increased	generation	and	infrastructure	capacity.

Revenue	increased	by	53%	to	US$38.8	million	in	2010	from	US$25.3	million	in	2009.	The	increase	was	a	result	of	
an	increase	in	production	volumes	of	22%	together	with	a	4%	increase	in	the	weighted	average	realized	price	from	
US$3.60/mcf in 2009 to US$3.74/mcf in 2010.

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52

MANAGEMENT’S DISCUSSION & ANALYSIS

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Funds from operations before working capital changes increased by 8% from US$20.8 million in 2010 to US$22.7 
million in 2011 as a consequence of increased sales revenue, the impact of which has been reduced by an increase in 
the	level	of	administrative	expenses.	The	funds	from	operation	grew	from	US$12.3	million	in	2009	to	US$20.8	million	
in 2010 mainly as a result of an increased level of sales.

During	2011,	the	Company’s	assets	increased	by	22%	to	US$151.8	million	(2010:	increased	44%	to	US$124.4	million).	
The	Company’s	assets	are	made	up	as	follows:

Figures in US$’000

Current assets

Cash and cash equivalents

Trade	and	other	receivables

Taxation	receivable

Prepayments

Fixed assets

Exploration and evaluation assets

Plant, property and other equipment

Total assets

2011

2010

2009

34,680

40,348

5,880

302

81,210

2,921

67,713

70,634

151,844

45,519

13,583

4,009

409

63,520

942

59,946

60,888

124,408

14,543

8,002

714

465

23,724

760

61,793

62,553

86,277

The	 decrease	 in	 cash	 and	 cash	 equivalents	 in	 2011	 is	 mainly	 the	 consequence	 of	 the	 commencement	 of	 a	 drilling	
programme	to	increase	production	to	200	MMcfd.	The	increase	recorded	in	2010	was	a	consequence	of	the	rights	issue	
and the increase in the level of operating revenue. 

The	increase	in	trade	and	other	receivables	is	primarily	a	consequence	of	the	increase	in	the	level	of	receivables	from	
the	electricity	producers,	TANESCO	and	Songas	Limited,	from	US$7.7	million	to	US$27.9	million.	

Total	capital	expenditure	of	US$18.2	million	was	incurred	in	2011	against	US$3.4	million	in	2010.	The	expenditure	
in 2010 was mainly incurred on the evaluation of the Songo Songo West prospect and the connection of the SS-10 
well	to	the	gas	processing	infrastructure.	The	capital	expenditure	in	2009	was	on	the	development	of	the	CNG	market	
and its associated facilities, continued geological studies of the existing gas reservoir, increasing the overall processing 
capacity	of	the	existing	Songas	facilities	and	connecting	the	Tegeta	45	MW	power	generation	station.	

BUSINESS RISKS

Operating Hazards and Uninsured Risks

The	business	of	Orca	Exploration	is	subject	to	all	of	the	operating	risks	normally	associated	with	the	exploration	for,	
and	the	production,	storage,	transportation	and	marketing	of	oil	and	gas.	These	risks	include	blowouts,	explosions,	fire,	
gaseous leaks, downhole design and integrity, migration of harmful substances and oil spills, any of which could cause 
personal	injury,	result	in	damage	to,	or	destruction	of,	oil	and	gas	wells	or	formations	or	production	facilities	and	other	
property,	equipment	and	the	environment,	as	well	as	interrupt	operations.	In	addition,	all	of	Orca	Exploration’s	opera-
tions	will	be	subject	to	the	risks	normally	incident	to	drilling	of	natural	gas	wells	and	the	operation	and	development	of	
gas properties, including encountering unexpected formations or pressures, premature declines of reservoirs, blowouts, 
equipment and tubing failures and other accidents, sour gas releases, uncontrollable flows of oil, natural gas or well 
fluids,	adverse	weather	conditions,	pollution	and	other	environmental	risks.	Drilling	conducted	by	Orca	Exploration	
overseas will involve increased drilling risks of high pressures and mechanical difficulties, including stuck pipe, collapsed 
casing	and	separated	cable.	The	impact	that	any	of	these	risks	may	have	upon	Orca	Exploration	is	increased	due	to	the	
fact that Orca Exploration currently only has one producing property. Orca Exploration will maintain insurance against 
some,	but	not	all,	potential	risks;	however,	there	can	be	no	assurance	that	such	insurance	will	be	adequate	to	cover	any	
losses	or	exposure	for	liability.	The	occurrence	of	a	significant	unfavourable	event	not	fully	covered	by	insurance	could	
have a material adverse effect on Orca Exploration’s financial condition, results of operations and cash flows. Further-
more, Orca Exploration cannot predict whether insurance will continue to be available at a reasonable cost or at all.

 
 
 
 
 
 
Foreign Operations

Orca	Exploration’s	operations	and	related	assets	are	located	in	Italy	and	Tanzania	which	may	be	considered	to	be	politi-
cally	and/or	economically	unstable.	Exploration	or	development	activities	in	Tanzania	and	Italy	may	require	protracted	
negotiations	with	host	governments,	national	oil	companies	and	third	parties	and	are	frequently	subject	to	economic	
and	political	considerations,	such	as,	the	risks	of	war,	actions	by	terrorist	or	insurgent	groups,	expropriation,	nationaliza-
tion, renegotiation or nullification of existing contracts and production sharing agreements, taxation policies, foreign 
exchange restrictions, changing political conditions, international monetary fluctuations, currency controls and foreign 
governmental regulations that favour or require the awarding of drilling contracts to local contractors or require foreign 
contractors	to	employ	citizens	of,	or	purchase	supplies	from,	a	particular	jurisdiction.	In	addition,	if	a	dispute	arises	with	
foreign	operations,	Orca	Exploration	may	be	subject	to	the	exclusive	jurisdiction	of	foreign	courts.

In	Tanzania	the,	the	state	retains	ownership	of	the	minerals	and	consequently	retains	control	of,	the	exploration	and	pro-
duction of hydrocarbon reserves. Accordingly, these operations may be materially affected by host governments through 
royalty payments, export taxes and regulations, surcharges, value added taxes, production bonuses and other charges.

Orca’s	development	properties	and	its	current	proved	natural	gas	reserves	located	offshore	on	the	Songo	Songo	Island	
in	Tanzania,	will	be	subject	to	regulation	and	control	by	the	government	of	Tanzania	and	certain	of	its	national	and	
parastatal	organizations	including	the	energy	regulator,	EWURA.	Orca	Exploration	and	its	predecessors	have	operated	
in	Tanzania	for	a	number	of	years.	A	Government	Negotiation	Team	(‘GNT’)	was	set	up	in	February	2012	to	address	
a	number	of	issues	raised	by	the	Parliamentary	Committee	for	Energy	and	Minerals	in	respect	of	the	Company’s	Pro-
duction	Sharing	Agreement	(“PSA”).	This	includes,	but	is	not	limited	to,	TPDC	back	in	rights,	profit	sharing	arrange-
ments, the divestment of the downstream assets, cost recovery and Orca’s management of the upstream operations. 
Orca	will	discuss	these	matters	in	good	faith	with	the	GNT	and	will	look	to	reach	a	satisfactory	agreement	that	may	lead	
to	a	change	in	the	economic	terms	of	the	PSA.	However,	the	Company	reserves	its	rights	to	defend	its	position	should	
no	satisfactory	agreement	be	reached.	However,	there	can	be	no	assurance	that	present	or	future	administrations	or	
governmental	regulations	in	Tanzania	will	not	materially	adversely	affect	the	operations	or	future	cash	flows	of	Orca	
Exploration. 

Additional Financing

Depending	 on	 future	 exploration,	 development,	 and	 marketing	 plans,	 Orca	 Exploration	 may	 require	 additional	
financing.	The	ability	of	Orca	Exploration	to	arrange	such	financing	in	the	future	will	depend	in	part	upon	the	prevail-
ing capital market conditions, the business performance of Orca Exploration and the satisfactory conclusion to the 
discussions	with	the	GNT.	There	can	be	no	assurance	that	Orca	Exploration	will	be	successful	in	its	efforts	to	arrange	
additional	financing	on	terms	satisfactory	to	Orca	Exploration.	If	additional	financing	is	raised	by	the	issuance	of	shares	
from treasury of Orca Exploration, control of Orca Exploration may change and shareholders may suffer additional 
dilution.

Industry Conditions

The	oil	and	gas	industry	is	intensely	competitive	and	Orca	Exploration	competes	with	other	companies	which	possess	
greater	technical	and	financial	resources.	Many	of	these	competitors	not	only	explore	for	and	produce	oil	and	natural	
gas, but also carry on refining operations and market petroleum, natural gas products and other products on an interna-
tional	basis.	Oil	and	gas	production	operations	are	also	subject	to	all	the	risks	typically	associated	with	such	operations,	
including premature decline of reservoirs and invasion of water into producing formations. Currently, Orca Explora-
tion	operates	the	Songo	Songo	natural	gas	property	and	has	interests	in	two	permits	in	Italy.	There	is	a	risk	that	in	the	
future	either	the	operatorship	could	change	and	the	property	operated	by	third	parties	or	operations	may	be	subject	
to control by national oil companies, Songas, or parastatal organisations and, as a result, Orca Exploration may have 
limited control over the nature and timing of exploration and development of such properties or the manner in which 
operations are conducted on such properties.

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54

MANAGEMENT’S DISCUSSION & ANALYSIS

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The	marketability	and	price	of	natural	gas	which	may	be	acquired,	discovered	or	marketed	by	Orca	Exploration	will	
be	affected	by	numerous	factors	beyond	its	control.	There	is	currently	no	developed	natural	gas	market	in	Tanzania	
and no infrastructure with which to serve potential new markets beyond that being constructed by Orca Exploration 
and	Songas.	The	ability	of	Orca	Exploration	to	market	any	natural	gas	from	current	or	future	reserves	in	Tanzania	may	
depend	upon	its	ability	to	develop	natural	gas	markets	in	Tanzania	and	the	surrounding	region,	obtain	access	to	the	
necessary infrastructure to deliver sales gas volumes, including acquiring capacity on pipelines which deliver natural 
gas	to	commercial	markets.	Orca	Exploration	is	also	subject	to	market	fluctuations	in	the	prices	of	oil	and	natural	gas,	
uncertainties related to the delivery and proximity of its reserves to pipelines and processing facilities and extensive 
government regulation relating to prices, taxes, royalties, land tenure, allowable production, the export of oil and gas 
and	many	other	aspects	of	the	oil	and	gas	business.	Orca	Exploration	is	also	subject	to	a	variety	of	waste	disposal,	
pollution control and similar environmental laws.

The	oil	and	natural	gas	industry	is	subject	to	varying	environmental	regulations	in	each	of	the	jurisdictions	in	which	
Orca Exploration may operate. Environmental regulations place restrictions and prohibitions on emissions of various 
substances produced concurrently and oil and natural gas and can impact on the selection of drilling sites and facility 
locations, potentially resulting in increased capital expenditures. 

Additional Gas

Orca	Exploration	has	the	right,	under	the	terms	of	the	PSA,	to	market	volumes	of	Additional	Gas	subject	to	satisfying	
the requirements to deliver Protected Gas to Songas.

There	is	a	risk	that	Songas	could	interfere	in	Orca	Exploration’s	ability	to	produce,	transport	and	sell	volumes	of	Ad-
ditional	Gas	if	Orca	Exploration’s	obligations	to	Songas	under	the	Gas	Agreement	are	not	met.	In	particular,	Songas	has	
the right to request reasonable security on all Additional Gas sales. 

Replacement of Reserves

Orca Exploration’s natural gas reserves and production and, therefore, its cash flows and earnings are highly dependent 
upon  Orca  Exploration  developing  and  increasing  its  current  reserve  base  and  discovering  or  acquiring  additional 
reserves. Without the addition of reserves through exploration, acquisition or development activities, Orca Explora-
tion’s	reserves	and	production	will	decline	over	time	as	reserves	are	depleted.	To	the	extent	that	cash	flow	from	opera-
tions is insufficient and external sources of capital become limited or unavailable, Orca Exploration’s ability to make 
the	necessary	capital	investments	to	maintain	and	expand	its	oil	and	natural	gas	reserves	will	be	impaired.	There	can	be	
no assurance that Orca Exploration will be able to find and develop or acquire additional reserves to replace produc-
tion at commercially feasible costs.

Asset Concentration

Orca Exploration’s natural gas reserves are currently limited to one producing property, the Songo Songo field, and the 
production	potential	from	this	field	is	limited	to	five	wells.	There	has	been	limited	production	from	the	six	wells	in	the	
Songo	Songo	field	to	date.	There	is	no	assurance	that	Orca	Exploration	will	have	sufficient	deliverability	through	the	
existing wells to provide additional natural gas sales volumes, and that there may be significant capital expenditures 
associated	with	any	remedial	work,	workovers,	or	new	drilling	required	to	achieve	deliverability.	In	addition,	any	dif-
ficulties relating to the operation or performance of the field would have a material adverse effect on Orca Exploration. 
The	Italian	licences	in	which	Orca	has	an	interest	are	currently	in	the	exploration	phase	of	their	cycle	and	it	may	be	
several years before Orca is able to obtain a revenue stream from these assets.

 
 
 
 
 
 
Environmental and Other Regulations

Extensive	national,	state,	and	local	environmental	laws	and	regulations	in	foreign	jurisdictions	will	affect	nearly	all	of	
Orca	Exploration’s	operations.	These	laws	and	regulations	set	various	standards	regulating	certain	aspects	of	health	
and environmental quality, provide for penalties and other liabilities for the violation of such standards and establish 
in certain circumstances obligations to remediate current and former facilities and locations where operations are or 
were	conducted.	In	addition,	special	provisions	may	be	appropriate	or	required	in	environmentally	sensitive	areas	of	
operation.	There	can	be	no	assurance	that	Orca	Exploration	will	not	incur	substantial	financial	obligations	in	connec-
tion with environmental compliance. Significant liability could be imposed on Orca Exploration for damages, cleanup 
costs or penalties in the event of certain discharges into the environment, environmental damage caused by previous 
owners of property purchased by Orca Exploration or non-compliance with environmental laws or regulations. Such 
liability	could	have	a	material	adverse	effect	on	Orca	Exploration.	Moreover,	Orca	Exploration	cannot	predict	what	en-
vironmental legislation or regulations will be enacted in the future or how existing or future laws or regulations will be 
administered or enforced. Compliance with more stringent laws or regulations, or more vigorous enforcement policies 
of any regulatory authority, could in the future require material expenditures by Orca Exploration for the installation 
and operation of systems and equipment for remedial measures, any or all of which may have a material adverse effect 
on Orca Exploration. As party to various licenses, Orca Exploration has an obligation to restore producing fields to a 
condition acceptable to the authorities at the end of their commercial lives.

While management believes that Orca Exploration is currently in compliance with environmental laws and regulations 
applicable	to	Orca	Exploration’s	operations	in	Tanzania	and	Italy,	no	assurances	can	be	given	that	Orca	Exploration	
will be able to continue to comply with such environmental laws and regulations without incurring substantial costs.

Orca	Exploration’s	petroleum	and	natural	gas	operations	are	subject	to	extensive	governmental	legislation	and	regula-
tion and increased public awareness concerning environmental protection.

No	provision	has	been	recognised	for	future	decommissioning	costs	in	Tanzania	which	are	anticipated	to	be	minimal	
as it is forecast that there will still be commercial gas reserves once Orca Exploration relinquishes the license in 2026. 
Orca Exploration expects that the cost of complying with environmental legislation and regulations will increase in 
the future. Compliance with existing environmental legislation and regulations has not had a material effect on capital 
expenditures, earnings or competitive position of Orca Exploration to date. Although management believes that Orca 
Exploration’s operations and facilities are in material compliance with such laws and regulations, future changes in 
these laws, regulations or interpretations thereof or the nature of its operations may require the Company to make 
significant additional capital expenditures to ensure compliance in the future.

Volatility of Oil and Gas Prices and Markets

Orca Exploration’s financial condition, operating results and future growth will be dependent on the prevailing prices for 
its	natural	gas	production.	Historically,	the	markets	for	oil	and	natural	gas	have	been	volatile	and	such	markets	are	likely	to	
continue	to	be	volatile	in	the	future.	Prices	for	oil	and	natural	gas	are	subject	to	large	fluctuations	in	response	to	relatively	
minor changes to the demand for oil and natural gas, whether the result of uncertainty or a variety of additional factors 
beyond the control of Orca Exploration. Any substantial decline in the prices of oil and natural gas could have a material 
adverse effect on Orca Exploration and the level of its natural gas reserves. Additionally, the economics of producing from 
some wells may change as a result of lower prices, which could result in a suspension of production by Orca Exploration.

No assurance can be given that oil and natural gas prices will be sustained at levels which will enable Orca Exploration to 
operate profitably. From time to time Orca Exploration may avail itself of forward sales or other forms of hedging activi-
ties	with	a	view	to	mitigating	its	exposure	to	the	risk	of	price	volatility.	The	terms	of	the	industrial	gas	supply	contracts	
were	extended	in	2008	for	a	period	of	five	years.	These	contracts	contain	pricing	caps	and	floors	that	limit	the	industrial	
downside	price	to	US$7.38/mcf.	The	Company	also	entered	into	fixed	price	contracts	with	TANESCO	and	Songas	for	
the	supply	of	Additional	Gas	to	the	power	sector.	The	steps	taken	by	the	Company	in	2008	were	very	important	steps	in	
mitigating the exposure to price volatility.

The	Songo	Songo	field	was	the	first	gas	field	to	be	developed	in	East	Africa	and	was	followed	by	a	commercial	gas	discovery	
in	the	south	of	Tanzania	at	Mnazi	Bay.	The	Company	is	the	only	supplier	of	gas	into	the	main	demand	centre	of	Dar	es	
Salaam and has therefore been able to negotiate industrial gas sales contracts with gas prices that are at a discount to the 
lowest	cost	alternative	fuels	in	Dar	es	Salaam,	namely	HFO	and	coal.

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56

MANAGEMENT’S DISCUSSION & ANALYSIS

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There	has	an	increase	in	exploration	activity	in	Tanzania	that	could,	if	successful,	lead	to	increased	competition	for	gas	
markets and lower gas prices in the future.

In	addition,	various	factors,	including	the	availability	and	capacity	of	oil	and	gas	gathering	systems	and	pipelines,	the	effect	
of foreign regulation of production and transportation, general economic conditions, changes in supply due to drilling 
by other producers and changes in demand may adversely affect Orca Exploration’s ability to market its gas production. 

Uncertainties in Estimating Reserves and Future Net Cash Flows

There	are	numerous	uncertainties	inherent	in	estimating	quantities	of	proved	and	probable	reserves	and	cash	flows	to	
be	derived	therefrom,	including	many	factors	beyond	the	control	of	Orca	Exploration.	The	reserve	and	cash	flow	infor-
mation	contained	herein	represents	estimates	only.	The	reserves	and	estimated	future	net	cash	flow	from	Orca	Explo-
ration’s	properties	have	been	independently	evaluated	by	McDaniel	&	Associates	Consultants	Ltd.	These	evaluations	
include a number of assumptions relating to factors such as initial production rates, production decline rates, ultimate 
recovery of reserves, timing and amount of capital expenditures, marketability of production, crude oil price differen-
tials to benchmarks, future prices of oil and natural gas, operating costs, transportation costs, cost recovery provisions 
and	royalties,	TPDC	“back-in”	methodology	and	other	government	levies	that	may	be	imposed	over	the	producing	
life	of	the	reserves.	These	assumptions	were	based	on	price	forecasts	in	use	at	the	date	of	the	relevant	evaluations	were	
prepared	and	many	of	these	assumptions	are	subject	to	change	and	are	beyond	the	control	of	Orca	Exploration.	Actual	
production and cash flows derived therefrom will vary from these evaluations, and such variations could be material.

Title to Properties

Although  title  reviews  have  been  done  and  will  continue  to  be  done  according  to  industry  standards  prior  to  the 
purchase of most oil and natural gas producing properties or the commencement of drilling wells, such reviews do not 
guarantee or certify that an unforeseen defect in the chain of title will not arise to defeat the claim of Orca Exploration 
which could result in a reduction of the revenue received by Orca Exploration.

Acquisition Risks

Orca Exploration intends to acquire natural gas infrastructure and possibly additional oil and gas properties. Although 
Orca Exploration performs a review of the acquired properties that it believes is consistent with industry practices, such 
reviews	are	inherently	incomplete.	It	generally	is	not	feasible	to	review	in	depth	every	individual	property	involved	in	
each acquisition. Ordinarily, Orca Exploration will focus its due diligence efforts on the higher valued properties and will 
sample	the	remainder.	However,	even	an	in	depth	review	of	all	properties	and	records	may	not	necessarily	reveal	existing	
or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their de-
ficiencies	and	capabilities.	Inspections	may	not	be	performed	on	every	well,	and	structural	or	environmental	problems,	
such as ground water contamination, are not necessarily observable even when an inspection is undertaken. Orca Explo-
ration may be required to assume pre-closing liabilities, including environmental liabilities, and may acquire interests in 
properties	on	an	“as	is”	basis.	There	can	be	no	assurance	that	Orca	Exploration’s	acquisitions	will	be	successful.

Reliance on Key Personnel

Orca	Exploration	is	highly	dependent	upon	its	executive	officers	and	key	personnel.	The	unexpected	loss	of	the	services	
of any of these individuals could have a detrimental effect on Orca Exploration. Orca Exploration does not maintain key 
life insurance on any of its employees or officers.

Controlling Shareholder 

W	David	Lyons,	the	Company’s	Chairman,	and	Chief	Executive	Officer	is	the	beneficial	controlling	shareholder	of	
Orca Exploration and holds approximately 99.5% of the outstanding Class A shares and approximately 16.6% of the 
Class	B	shares.	Consequently,	Mr.	Lyons	is	the	beneficial	holder	of	approximately	20.0%	of	the	equity	(22.0%	fully	
diluted) and controls 59.5% of the total votes of Orca Exploration.

 
 
 
 
 
 
CRITICAL ACCOUNTING ESTIMATES  

In	applying	the	Company’s	accounting	policies,	which	are	described	in	note	1,	management	makes	estimates	and	as-
sumptions	concerning	the	future.	The	resulting	accounting	estimates	will,	by	definition,	vary	to	the	actual	results.	The	
estimates	and	assumptions	that	have	a	significant	risk	of	causing	a	material	adjustment	to	the	carrying	amounts	of	assets	
and	liabilities	within	the	next	financial	year	are	discussed	below:

i) 

Reserves

There	are	numerous	uncertainties	inherent	in	estimating	quantities	of	proved	and	probable	reserves	and	cash	
flows	to	be	derived	therefrom,	including	many	factors	beyond	the	control	of	Orca	Exploration.	The	reserve	and	
cash	flow	information	contained	herein	represents	estimates	only.	The	reserves	and	estimated	future	net	cash	flow	
from	Orca	Exploration’s	properties	have	been	independently	evaluated	by	McDaniel	&	Associates	Consultants	
Ltd.	 These	 evaluations	 include	 a	 number	 of	 assumptions	 relating	 to	 factors	 such	 as	 initial	 production	 rates,	
production  decline  rates,  ultimate  recovery  of  reserves,  timing  and  amount  of  capital  expenditures,  market-
ability of production, crude oil price differentials to benchmarks, future prices of oil and natural gas, operating 
costs,	 transportation	 costs,	 cost	 recovery	 provisions	 and	 royalties,	 TPDC	 “back-in”	 methodology	 and	 other	
government	levies	that	may	be	imposed	over	the	producing	life	of	the	reserves.	These	assumptions	were	based	
on price forecasts in use at the date of the relevant evaluations were prepared and many of these assumptions are 
subject	to	change	and	are	beyond	the	control	of	Orca	Exploration.	

Reserves are integral to the amount of depletion charged to the profit or loss.

ii)  Exploration and evaluation assets

Under  the  Company’s  accounting  policy  expenditures  incurred  on  the  exploration  for,  and  evaluation  of, 
reserves	are	capitalized	as	intangible	assets.	These	intangibles	assets	are	then	assessed	for	impairment	when	cir-
cumstances suggest that the carrying amount may exceed its recoverable value. Such circumstances include but 
are	not	limited	to:	

•	

•	

•	

•	

•	

•	

the	period	for	which	the	Company	has	the	right	to	explore	in	the	specific	area	has	expired	during	the	
period,	or	will	expire	in	the	near	future,	and	is	not	expected	to	be	renewed;

no	further	expenditure	on	exploration	and	evaluation	is	budgeted	or	planned;

no	reserves	have	been	encountered;	

the	evaluation	of	seismic	data	indicates	that	the	reserves	are	unlikely	to	be	of	a	commercial	quantity;	

the	quantity	of	mineral	reserves	are	deemed	not	to	be	of	commercially	viable	quantities	and	the	entity	has	
decided	to	discontinue	further	activities;	and

sufficient	data	exists	to	indicate	that,	although	a	development	in	the	specific	area	is	likely	to	proceed,	the	
carrying amount of the exploration and evaluation asset is unlikely to be recovered in full from successful 
development or by sale.

The	assessment	for	impairment	involves	estimates	as	to	(i)	the	likely	future	commerciality	of	the	asset	and	when	
such commerciality should be determined, (ii) future revenues and costs associated with the asset, and (iii) the 
discount rate to be applied to such revenues and costs for the purpose of deriving a recoverable value.

Exploration and evaluation assets are assessed for impairment if (i) sufficient data exists to determine technical 
feasibility  and  commercial  viability,  or  (ii)  facts  and  circumstances  suggest  that  the  carrying  amount  exceeds 
the recoverable amount. For purposes of impairment testing, exploration and evaluation assets are grouped by 
concession.

The	technical	feasibility	and	commercial	viability	of	extracting	a	resource	is	considered	to	be	determinable	based	
on several factors including the assignment of proven reserves. A review of each exploration license or field is 
carried	out,	at	least	annually,	to	ascertain	whether	the	project	is	technically	feasible	and	commercially	viable.	
Upon  determination  of  technical  feasibility  and  commercial  viability,  intangible  exploration  and  evaluation 
assets attributable to those reserves are first tested for impairment and then reclassified from exploration and 
evaluation assets to a separate category within property and equipment referred to as oil and natural gas interests.

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MANAGEMENT’S DISCUSSION & ANALYSIS

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iii)  Fair value of stock based compensation

All stock options issued or stock appreciation rights granted by the Company have to be valued at their fair value. 
In	assessing	the	fair	value	of	the	equity	based	compensation,	estimates	have	to	be	made	as	to	i)	the	volatility	in	
share	price,	ii)	risk	free	rate	of	interest	and	iii)	the	level	of	forfeiture.	In	the	case	of	stock	options,	this	fair	value	is	
estimated at the date of issue and is not revalued, where as the fair value of stock appreciation rights is recalcu-
lated at each reporting period. 

IV)  Cost recovery

The	Company	is	able	to	recover	reasonable	costs	incurred	on	the	development	of	the	Songo	Songo	project	out	of	
75%	of	the	gross	revenues	less	processing	and	pipeline	tariffs	(“Net	Revenue).	There	are	inherent	uncertainties	
in estimating when costs have been recovered as the government has several years to review the reasonableness 
of the costs.

Forward Looking Statements

This disclosure contains certain forward-looking estimates that involve substantial known and unknown risks and uncertainties, certain 
of which are beyond Orca Exploration’s control, including the impact of general economic conditions in the areas in which Orca Explo-
ration operates, civil unrest, industry conditions, changes in laws and regulations including the adoption of new environmental laws and 
regulations and changes in how they are interpreted and enforced, increased competition, the lack of availability of qualified personnel 
or management, fluctuations in commodity prices, foreign exchange or interest rates, stock market volatility and obtaining required 
approvals of regulatory authorities. In addition there are risks and uncertainties associated with oil and gas operations, therefore Orca 
Exploration’s actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-
looking estimates and, accordingly, no assurances can be given that any of the events anticipated by the forward-looking estimates will 

transpire or occur, or if any of them do so, what benefits, including the amounts of proceeds, that Orca Exploration will derive therefrom.

For	further	information	please	contact:	

Nigel A. Friend, CFO 
+255 (0)22 2138737  
nfriend@orcaexploration.com 
or visit the Company’s web site at www.orcaexploration.com

 
 
 
 
 
 
FINANCIAL STATEMENTS & NOTES

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60

MANAGEMENT’S REPORT TO SHAREHOLDERS

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The	 accompanying	 consolidated	 financial	 statements	 of	 Orca	 Exploration	 Group	 Inc.	 are	 the	 responsibility	 of	 the	
Directors.	The	financial	and	operating	information	presented	in	this	annual	report	is	consistent	with	that	shown	in	the	
consolidated financial statements.

The	consolidated	financial	statements	have	been	prepared	by	management,	on	behalf	of	the	Board,	in	accordance	with	
the accounting policies disclosed in the notes to the consolidated financial statements. Where necessary, management 
has	made	informed	judgments	and	estimates	in	accounting	for	transactions	which	were	not	complete	at	the	balance	
sheet	date.	In	the	opinion	of	management,	the	consolidated	financial	statements	have	been	prepared	within	accept-
able	limits	of	materiality	and	are	in	accordance	with	International	Financial	Reporting	Standards	appropriate	in	the	
circumstances.

Management,	 with	 the	 participation	 of	 the	 Chief	 Executive	 Officer	 and	 Chief	 Financial	 Officer,	 has	 evaluated	 the	
effectiveness of the Company’s disclosure controls and procedures and has concluded that such disclosure controls 
and procedures are effective.

Management	 maintains	 appropriate	 systems	 of	 internal	 controls.	 Policies	 and	 procedures	 are	 designed	 to	 give	
reasonable  assurance  that  transactions  are  properly  authorised,  assets  are  safeguarded  and  financial  records  are 
properly  maintained  to  provide  reliable  information  for  the  preparation  of  financial  statements.  An  independent 
firm of Chartered Accountants, as appointed by the Shareholders, audited the consolidated financial statements in 
accordance with the Canadian generally accepted auditing standards to enable them to express an opinion on the fair 
presentation	of	the	consolidated	financial	statements	in	accordance	with	International	Financial	Reporting	Standards.

The	Board	of	Directors	carries	out	its	responsibility	for	the	financial	reporting	and	internal	controls	principally	through	
an	Audit	Committee.	The	Audit	Committee	has	met	with	external	auditors	and	Management	in	order	to	determine	
if	Management	has	fulfilled	its	responsibilities	in	the	preparation	of	the	consolidated	financial	statements.	The	con-
solidated	financial	statements	have	been	approved	by	the	Board	of	Directors	on	the	recommendation	of	the	Audit	
Committee.

W	David	Lyons		
Chairman and Chief Executive Officer  

25 April 2012 

Nigel	Friend 
Chief Financial Officer

25 April 2012

 
 
 
 
	
 
 
 
 
 
 
 
 
AUDITORS’ REPORT

To the Shareholders of Orca Exploration Group Inc.

We	have	audited	the	accompanying	consolidated	financial	statements	of	Orca	Exploration	Group	Inc.	which	comprise	
the	consolidated	statements	of	financial	position	as	at	December	31,	2011	and	2010,	the	consolidated	statements	of	
comprehensive income, changes in shareholders’ equity cash flows for the years then ended, and notes, comprising a 
summary of significant accounting policies and other explanatory information.

Management’s Responsibility for the Consolidated Financial Statements

Management	is	responsible	for	the	preparation	and	fair	presentation	of	these	consolidated	financial	statements	in	ac-
cordance	with	International	Financial	Reporting	Standards	and	for	such	internal	control	as	management	determines	
is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, 
whether due to fraud or error.

Auditors’ Responsibility

Our  responsibility  is  to  express  an  opinion  on  these  consolidated  financial  statements  based  on  our  audits.  
We	conducted	our	audits	in	accordance	with	Canadian	generally	accepted	auditing	standards.	Those	standards	require	
that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether 
the consolidated financial statements are free from material misstatement.

An  audit  involves  performing  procedures  to  obtain  audit  evidence  about  the  amounts  and  disclosures  in  the 
consolidated	 financial	 statements.	 The	 procedures	 selected	 depend	 on	 our	 judgment,	 including	 the	 assessment	 of	
the	risks	of	material	misstatement	of	the	consolidated	financial	statements,	whether	due	to	fraud	or	error.	In	making	
those risk assessments, we consider internal control relevant to the entity’s preparation and fair presentation of the 
consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but 
not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes 
evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by 
management, as well as evaluating the overall presentation of the consolidated financial statements.

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

Opinion 

In	our	opinion,	the	consolidated	financial	statements	present	fairly,	in	all	material	respects,	the	consolidated	financial	
position	of	Orca	Exploration	Group	Inc.	as	at	December	31,	2011	and	2010,	and	its	consolidated	financial	performance	
and	its	consolidated	cash	flows	for	the	years	ended	December	31,	2011	and	2010	in	accordance	with	International	
Financial Reporting Standards.

Calgary, Canada

25 April 2012 

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62

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

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YEARS ENDED 31 DECEMBER

NOTE

2011

2010

(thousands of US dollars except per share amounts)

Revenue 

Cost of sales

Production and distribution expenses

Depletion	expense

General and administrative expenses

Finance income

Finance costs

Profit before taxation

Taxation

Profit after taxation  
and comprehensive income for the year

Earnings per share

Basic 

Diluted	

See accompanying notes to the consolidated financial statements.

5

12

7

7

8

16 

45,893

38,808

(6,088)

(8,092)

31,713

(15,440)

85

 (1,038)

15,320

 (7,334)

(4,879)

(4,839)

29,090

(11,716)

40

(902)

16,512

(6,501)

7,986

10,011

0.23 

0.22

0.33

0.31

 
 
 
 
 
 
 
 
 
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

AS AT 31 DECEMBER

(thousands of US dollars)

ASSETS

Current assets

Cash and cash equivalents

Trade	and	other	receivables

Taxation	receivable

Prepayments

Non-current assets

Exploration and evaluation assets

Property, plant and equipment

	Total	assets

EQUITY AND LIABILITIES

Current liabilities

Trade	and	other	payables

Taxation	payable

Non-current liabilities

Deferred	income	taxes

Deferred	additional	profits	tax

Total	liabilities

Equity 

Capital stock

Contributed surplus

Accumulated income

Total	equity	and	liabilities	

NOTE 

2011 

2010

9

10

11

12

13

8

8

14

15

34,680

40,348

5,880

302

81,210

2,921

67,713

70,634

151,844

22,801

2,403

25,204

15,194

4,787

19,981

45,185

84,610

6,268

15,781

106,659

151,844

45,519

13,583

4,009

409

63,520

942

59,946

60,888

124,408

9,156

2,000

11,156

12,809

2,260

15,069

26,225

85,100

5,288

7,795

98,183

124,408

See accompanying notes to the consolidated financial statements. 
Future operations (Note 3) 
Contractual obligations and committed capital investments (Note 19) 
Contingencies (Note 20)  
Post balance sheet event (Note 21)

The	consolidated	financial	statements	were	approved	by	the	Board	of	Directors	on	25	April	2012.

Director	

Director 

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NOTE

2011

2010

7,986

10,011

64

CONSOLIDATED STATEMENTS OF CASH FLOWS

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YEARS ENDED 31 DECEMBER 

(thousands of US dollars)

CASH FLOWS FROM OPERATING ACTIVITIES

Profit after taxation

Adjustment	for:

	 Depletion	and	depreciation

  Gain on disposal of vehicle

  Stock-based compensation

	 Deferred	income	taxes

	 Deferred	additional	profits	tax

Interest	income

  Unrealised loss on foreign exchange

Increase	in	trade	and	other	receivables

Increase	in	taxation	receivable

Decrease	in	prepayments

Increase	in	trade	and	other	payables

Increase	in	taxation	payable

Net cash flows from operating activities

CASH FLOWS USED IN INVESTING ACTIVITIES

Exploration and evaluation expenditures

Property, plant and equipment expenditures

Interest	received

Proceeds from sale of vehicle

Increase	in	trade	and	other	payables

Net cash used in investing activities

CASH FLOWS (USED IN)/FROM FINANCING ACTIVITIES

Normal course issuer bid

Shares issued

Proceeds from exercise of options

Net cash flow (used in)/from financing activities

(Decrease)/increase in cash and cash equivalents

Cash and cash equivalents at the beginning of the year

Effect of change in foreign exchange

12

11

14

8

5/8

7

11

12

7

14/15

14

Cash and cash equivalents at the end of the year

9

See accompanying notes to the consolidated financial statements.

8,389

(5)

851

2,385

2,527

(5)

530

22,658

(27,171)

(1,871)

107

10,451

403

4,577

(1,979)

(16,156)

5

5

3,541

(14,584)

(681)

–

–

(681)

(10,688)

45,519

(151)

34,680

5,046

–

664

3,741

800

(40)

614

20,836

(6,166)

(3,295)

56

2,103

2,000

15,534

(182)

(3,199)

40

–

418

(2,923)

–

18,471

234

18,705

31,316

14,543

(340)

45,519

 
 
	
 
 
 
 
 
 
 
 
 
 
 
CONSOLIDATED STATEMENT OF CHANGES  
IN SHAREHOLDERS’ EQUITY

(thousands of US dollars)

Note

Balance	as	at	1	January	2010

Shares issued

Stock options exercised

Stock-based compensation

Total	comprehensive	income	for	the	year

Balance	as	at	31	December	2010

Stock-based compensation

Normal course issuer bid

Total	comprehensive	income	for	the	year

Balance	as	at	31	December	2011

CAPITAL STOCK

CONTRIBUTED 
SURPLUS

ACCUMULATED 
INCOME/ (LOSS)

TOTAL

14

66,267

 18,471 

 362 

–

–

 85,100

–

(490)

–

84,610

15 

4,809

–

(128)

 607 

–

5,288 

1,171

(191)

–

6,268

(2,216)

–

– 

–

10,011

7,795

– 

–

7,986

15,781

68,860

18,471 

234 

 607 

10,011

98,183

1,171

(681)

7,986

106,659

See accompanying notes to the consolidated financial statements.

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66

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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General Information

Orca	Exploration	Group	Inc.	(“Orca	Exploration”	or	the	“Company”)	was	incorporated	on	28	April	2004	under	the	
laws	of	the	British	Virgin	Islands.	The	Company	is	a	participant	in	a	gas-to-electricity	project	in	Tanzania	and	has	gas	
and	oil	exploration	interests	in	Italy.

The	Company’s	operations	at	the	Songo	Songo	gas	field	in	Tanzania	include	the	operation	of	five	producing	wells	and	
two	45	MMcfd	dehydration	and	refrigeration	gas	processing	units	on	Songo	Songo	Island	on	behalf	of	Songas	Limited	
(“Songas”).	Gas	produced	and	sold	from	the	Songo	Songo	field	is	classified	as	either	Protected	Gas	or	Additional	
Gas.	Protected	Gas	is	100%	owned	by	Tanzania	Petroleum	Development	Corporation	(“TPDC”)	and	Orca	has	no	
economic interest in it. Protected Gas is sold to Songas under a twenty year Gas Agreement primarily for use at the 
Ubungo	power	plant	and	the	Wazo	Hill	cement	plant.	The	Protected	Gas	is	principally	used	as	feedstock	for	specified	
turbines	and	kilns.	Gas	sales	in	excess	of	the	Protected	Gas	users’	requirements	is	classified	as	Additional	Gas.	The	
Company has the exclusive right to explore, develop, produce and market all Additional Gas. Revenues from the sale 
of	Additional	Gas,	net	of	transportation	tariff,	are	shared	with	TPDC	in	accordance	with	the	terms	of	the	Production	
Sharing	Agreement	(“PSA”)	until	October	2026.	

Basis of preparation 

These	consolidated	financial	statements	are	measured	and	presented	in	US	dollars	as	the	main	operating	cash	flows	
are	linked	to	this	currency	through	the	commodity	price.	Management	is	required	to	make	estimates	and	assumptions	
that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date 
of the financial statements, and the reported amounts of revenue and expenses during the period. Actual results could 
differ from these estimates.

1 

Summary of significant accounting policies

A)  STATEMENT OF COMPLIANCE

The	 consolidated	 financial	 statements	 have	 been	 prepared	 in	 accordance	 with	 International	 Financial	
Reporting	Standards	(“IFRS”)	as	issued	by	the	International	Accounting	Standards	Board	(“IASB”).

B)  BASIS OF CONSOLIDATION

i) 

Subsidiaries

The	 consolidated	 financial	 statements	 include	 the	 accounts	 of	 the	 Company	 and	 all	 its	 wholly	
owned	 subsidiaries	 (collectively,	 the	 “Company”).	 Subsidiaries	 are	 those	 enterprises	 controlled	
by	the	Company.	The	following	companies	have	been	consolidated	within	the	Orca	Exploration	
financial	statements:

Subsidiary

Registered

Holding

Functional 
currency

Orca	Exploration	Group	Inc

British	Virgin	Islands

Parent Company

US dollar

Orca	Exploration	Italy	Inc

British	Virgin	Islands

Orca	Exploration	Italy	Onshore	Inc

British	Virgin	Islands

PAE PanAfrican Energy Corporation Mauritius

PanAfrican	Energy	Tanzania	Limited

Jersey

Orca	Exploration	UK	Services	Limited United	Kingdom

100%

100%

100%

100%

100%

Euro

Euro

US dollar

US dollar

GB Sterling

ii)  Transactions eliminated upon consolidation

Inter-company	balances	and	transactions,	and	any	unrealised	gains	or	losses	arising	from	inter-company	
transactions, are eliminated in preparing the consolidated financial statements.

 
 
 
 
 
 
 
C)   FOREIGN CURRENCY

Foreign currency transactions are recorded at the rate of exchange prevailing at the date of the transaction. 
Monetary	 assets	 and	 liabilities	 in	 foreign	 currencies	 are	 translated	 at	 period-end	 rates.	 Non-monetary	
items are translated at historic rates, unless such items are carried at market value, in which case they are 
translated using the exchange rates that existed when the values were determined. Any resulting exchange 
rate	differences	are	recognized	in	the	profit	and	loss.

D)   EXPLORATION AND EVALUATION ASSETS, PROPERTY, PLANT AND EQUIPMENT

i) 

Exploration and evaluation assets 

Exploration	and	evaluation	costs	are	capitalised	as	intangible	assets.	Intangible	assets	includes	lease	
and license acquisition costs, geological and geophysical costs and other direct costs of exploration 
and evaluation which the directors consider to be unevaluated until reserves are appraised to be 
commercially viable and technologically feasible as commercial, at which time they are transferred 
to property, plant and equipment following an impairment review and depleted accordingly. Where 
properties  are  appraised  to  have  no  commercial  value  or  are  appraised  at  values  less  than  book 
values, the associated costs are treated as an impairment loss in the period in which the determina-
tion is made. 

ii)  Property, plant and equipment

Property, plant and equipment comprises the Company’s tangible natural gas assets, development 
wells,  together  with  leasehold  improvements,  computer  equipment,  motor  vehicles  and  fixtures 
and fittings and are carried at cost, less any accumulated depletion, depreciation and accumulated 
impairment  losses.  Cost  includes  purchase  price  and  construction  costs  for  qualifying  assets. 
Depletion	 of	 these	 assets	 commences	 when	 the	 assets	 are	 ready	 for	 their	 intended	 use.	 Only	
costs that are directly related to the discovery and development of specific oil and gas reserves are 
capitalised.	 The	 cost	 associated	 with	 tangible	 natural	 gas	 assets	 are	 amortised	 on	 a	 field	 by	 field	
unit	of	production	method	based	on	commercial	proven	reserves.	The	calculation	of	the	unit	of	
production amortisation takes into account the estimated future development cost of the field.

iii) 

Impairment of exploration and evaluation assets, property, plant and equipment

At each balance sheet date, the Company reviews the carrying amounts of its property, plant and 
equipment and intangible assets to determine whether there is any indication that those assets have 
suffered	an	impairment	loss.	Individual	assets	are	grouped	together	as	a	cash	generating	unit	for	
impairment assessment purposes at the lowest level at which there are identifiable cash flows that 
are	independent	from	other	group	assets.	In	the	case	of	exploration	and	evaluation	assets,	this	will	
normally	be	at	the	Company’s	field	level.	If	any	such	indication	of	impairment	exists,	the	Company	
makes	 an	 estimate	 of	 its	 recoverable	 amount.	The	 recoverable	 amount	 is	 the	 higher	 of	 fair	 value	
less costs to sell and value in use. Where the carrying amount of a cash generating unit exceeds 
its  recoverable  amount,  the  cash  generating  unit  is  considered  impaired  and  is  written  down  to 
its	recoverable	amount.	In	assessing	the	value	in	use,	the	estimated	future	cash	flows	are	adjusted	
for the risks specific to the cash generating unit and are discounted to their present value with a 
discount rate that reflects the current market indicators. Where an impairment loss subsequently 
reverses, the carrying amount of the asset cash–generating unit is increased to the revised estimate 
of its recoverable amount, but so that the increased carrying amount does not exceed the carrying 
amount that would have been determined had no impairment loss been recognised for the cash 
generating unit in prior years. A reversal of an impairment loss is recognised as income immediately.

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68

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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E)   OPERATORSHIP

The	Company	operates	the	gas	field,	flow	lines	and	gas	processing	plant	on	behalf	of	Songas	at	cost.	The	
cost of operating and maintaining the wells and flow lines is paid for by Orca Exploration and Songas in 
proportion	to	the	respective	volumes	of	Additional	Gas	and	Protected	Gas	sales.	The	costs	of	operating	
and maintaining the wells and flow lines are reflected in the accounts to the extent that the costs were 
incurred	to	accomplish	Additional	Gas	sales.	The	cost	of	operating	the	gas	processing	plant	and	pipeline	
to	 Dar	 es	 Salaam	 is	 paid	 by	 Songas.	 When	 there	 are	 Additional	 Gas	 sales,	 a	 tariff	 is	 paid	 to	 Songas	 as	
compensation	for	using	the	gas	processing	plant	and	pipeline.	This	tariff	is	netted	against	revenue.

F)   EMPLOYMENT BENEFITS

i) 

Pension

The	Company	does	not	operate	a	pension	plan,	but	it	does	make	defined	contributions	to	the	statutory	
pension	fund	for	employees	in	Tanzania.	Obligations	for	contributions	to	the	statutory	pension	fund	are	
recognised as an expense in the income statement as incurred.

ii)   Stock options

The	 share	 option	 plan	 allows	 Company	 officers,	 directors	 and	 key	 personnel	 to	 acquire	 shares	 at	 an	
exercise price determined by the market value at the date of grant. When the options are exercised, equity 
is	increased	by	the	amount	of	the	proceeds	received.	The	fair	value	of	stock	options	is	expensed	in	the	
profit	or	loss	in	accordance	with	the	specific	vesting	periods.	The	fair	value	of	the	options	is	calculated,	on	
the grant date, using the Black-Scholes option pricing model.

iii)  Stock appreciation rights

Stock	appreciation	rights	are	issued	to	certain	key	managers,	officers,	directors	and	employees.	The	fair	
value of stock appreciation rights is expensed in the profit and loss in accordance with the service period. 
The	fair	value	of	the	stock	appreciation	rights	is	revalued	every	reporting	date	with	the	change	in	the	value	
recognized	in	the	income	statement.

G)   ASSET RETIREMENT OBLIGATIONS

No	provision	has	been	made	for	future	site	restoration	costs	in	Tanzania	since	the	Company	has	currently	
no legal or contractual or constructive obligation under the PSA to restore the fields at the end of their 
commercial lives.

H)   REVENUE RECOGNITION, PRODUCTION SHARING AGREEMENTS  

AND ROYALTIES

The	Company	recognises	revenue	related	to	Additional	Gas	sales	when	title	passes	to	a	customer.	The	
Company	 conducts	 operations	 jointly	 with	 the	 Tanzanian	 government	 and	 “parastatal	 entities”	 in	
accordance	with	production	sharing	agreements	(“PSA”).	Under	these	agreements,	the	Company	pays	
both	 its	 share	 and	 the	 parastatal’s	 share	 of	 operating,	 administrative	 and	 capital	 costs.	 The	 Company	
recovers all reasonably incurred operating, administrative and capital costs including the parastatal’s share 
of	these	costs	from	future	revenues	over	several	years	(“Cost	Gas”).	The	parastatal’s	share	of	operating	and	
administrative costs, are recorded in operating and general and administrative costs when incurred and 
capital	costs	are	recorded	in	‘Property,	plant	and	equipment’.	All	recoveries	are	recorded	as	revenue	in	the	
year	of	recovery.	The	Company	is	entitled	to	a	share	of	production	in	excess	of	the	Cost	Gas	(“Profit	Gas”).	
Operating revenue represents the Company’s share of Cost Gas and Profit Gas during the period.

I)   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	to	the	Government	of	Tanzania.	This	tax	is	considered	to	be	a	royalty	and	is	
netted	against	revenue.	Deferred	APT	is	provided	for	by	forecasting	the	total	APT	payable	as	a	proportion	
of	the	forecast	Profit	Gas	over	the	term	of	PSA	license.	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.

 
 
 
 
 
 
 
 
 
 
J)   TAXATION

Income	 tax	 on	 the	 profit	 for	 the	 year	 comprises	 current	 and	 deferred	 tax.	 The	 Company	 is	 liable	 for	
Tanzanian	income	tax,	but	this	is	recovered	from	TPDC	through	the	profit-sharing	arrangement.	Where	
current	income	tax	is	payable,	the	Company’s	revenue	is	adjusted	for	the	amount	of	current	tax	payable	
and	the	income	tax	is	shown	as	current	tax.	Deferred	tax	is	provided	using	the	balance	sheet	method,	
providing for temporary differences between the carrying amounts of assets and liabilities for financial 
reporting	purposes	and	the	amounts	used	for	taxation	purposes.	The	amount	of	deferred	tax	provided	
is based on the expected manner of realisation or settlement of carrying amounts of assets and liabilities 
using tax rates substantively enacted at the balance sheet date. A deferred tax asset is recognised only to the 
extent that it is probable that future taxable profits will be available against which the asset can be utilised. 
Deferred	tax	assets	are	reduced	to	the	extent	that	it	is	no	longer	probable	that	the	related	tax	benefits	will	
be realised.

K)   SEGMENTAL REPORTING

The	Company	has	interests	in	Tanzania	and	Italy.	

L) 

 DEPRECIATION

Depreciation	for	non-natural	gas	properties	is	charged	to	the	income	statement	on	a	straight	line	basis	over	
the	estimated	useful	economic	lives	of	each	class	of	asset.	The	estimated	useful	lives	are	as	follows:

Leasehold	improvement

Over remaining life of the lease

Computer equipment 

Vehicles

Fixtures and fittings

3 years

3 years

3 years

M)   NEW ACCOUNTING STANDARDS AND INTERPRETATIONS 

Certain new accounting standards and interpretations have been published that are not mandatory for 
the	31	December	2011	reporting	period.	The	following	standards	are	to	be	adopted	for	reporting	periods	
beginning	January	1,	2013,	with	the	exception	of	IFRS-9	which	has	an	effective	date	of	January	1,	2015.	

•	

•	

•	

•	

•	

•	

IFRS	 9	 Financial	 Instruments,	 replaces	 the	 guidance	 of	 IAS	 39	 with	 regards	 to	 recognition	 and	
measurement.

IFRS	10	Consolidated	Financial	Statements.	This	standard	provides	a	single	model	to	be	applied	in	
control analysis for all categories of investment.

IFRS	11	Joint	Arrangements	are	classified	into	two	types,	either	joint	operations	or	joint	ventures,	
each	with	their	own	accounting	treatment.	All	joint	arrangements	are	to	be	reassessed	on	transition	
to	IFRS11	to	determine	their	type	in	oerder	to	apply	the	appropriate	accounting	treatment.

IFRS	12	Disclosure	of	Interest	in	Other	Entities,	combines	the	disclosure	requirements	for	subsid-
iaries,	associates	and	joint	operations.

IFRS	 12	 Fair	 Value	 Measurement	 establishes	 a	 framework	 for	 measuring	 fair	 value	 and	 sets	 out	
disclosure requirements.

Amendments	to	IAS	12	Income	taxes	-	Deferred	Tax:	Recovery	of	Underlying	Assets:	effective	for	
annual	periods	beginning	on	or	after	1	January	2012.	Earlier	application	is	permitted;

The	Company	does	not	plan	to	adopt	these	standards	early	and	the	extent	of	their	impact	on	the	financial	
statements has not been determined.

I

O
N
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E
T
R
E
A
S
T
T
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S
H
R
E
E
C
P
O
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N
R
T
S
O
L
D
A
T
E
D
F
I
N
A
N
C
A
L

I

I

S
T
A
T
E
M
E
N
T
S

O
R
C
A

E
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P
L
O
R
A
T

I

O
N

G
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O
U
P

I

N
C

.

2
0
1
1

A
N
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L

R
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O
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T

69

 
 
 
 
 
 
 
 
 
 
 
 
 
 
70

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

T
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L
A
U
N
N
A

1
1
0
2

.

C
N

I

P
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R
G

N
O

I

T
A
R
O
L
P
X
E

A
C
R
O

N)   FINANCIAL INSTRUMENTS

Non-derivative financial instruments include cash and cash equivalents, trade and other receivables, and 
trade	and	other	payables.	Non-derivative	financial	instruments	are	recognized	initially	at	fair	value	plus	
any directly attributable transaction costs.

The	 Company	 has	 reported	 cash	 and	 cash	 equivalents	 at	 fair	 value.	 Cash	 and	 cash	 equivalents	 are	
comprised of cash on hand, term deposits held with banks, and other short-term highly liquid investments 
with original maturities of three months or less. Bank overdrafts that are repayable on demand and form 
an integral part of the Company’s cash management, whereby management has the ability and intent to 
net bank overdrafts against cash, are included as a component of cash and cash equivalents for the purpose 
of	the	statement	of	cash	flows.	The	Company’s	trade	and	other	receivables,	trade	and	other	payables,	are	
classified as other non-derivative financial instruments. Subsequent to the initial recognition, other non-
derivative	financial	instruments	are	measured	at	amortized	cost	using	the	effective	interest	method,	less	
any impairment losses.

2 

CRITICAL ACCOUNTING ESTIMATES

In	applying	the	Company’s	accounting	policies,	which	are	described	in	note	1,	management	makes	estimates	
and	assumptions	concerning	the	future.	The	resulting	accounting	estimates	will,	by	definition,	vary	to	the	actual	
results.	The	estimates	and	assumptions	that	have	a	significant	risk	of	causing	a	material	adjustment	to	the	carrying	
amounts	of	assets	and	liabilities	within	the	next	financial	year	are	discussed	below:

I)  RESERVES

There	are	numerous	uncertainties	inherent	in	estimating	quantities	of	proved	and	probable	reserves	and	
cash	flows	to	be	derived	therefrom,	including	many	factors	beyond	the	control	of	Orca	Exploration.	The	
reserve	and	cash	flow	information	contained	herein	represents	estimates	only.	The	reserves	and	estimated	
future	net	cash	flow	from	Orca	Exploration’s	properties	have	been	independently	evaluated	by	McDaniel	
&	Associates	Consultants	Ltd.	These	evaluations	include	a	number	of	assumptions	relating	to	factors	such	
as initial production rates, production decline rates, ultimate recovery of reserves, timing and amount of 
capital  expenditures,  marketability  of  production,  abandonment  provisions,  crude  oil  price  differentials 
to  benchmarks,  future  prices  of  oil  and  natural  gas,  operating  costs,  transportation  costs,  cost  recovery 
provisions	and	royalties,	TPDC	“back-in”	methodology	and	other	government	levies	that	may	be	imposed	
over	the	producing	life	of	the	reserves.	These	assumptions	were	based	on	price	forecasts	in	use	at	the	date	of	
the	relevant	evaluations	were	prepared	and	many	of	these	assumptions	are	subject	to	change	and	are	beyond	
the control of Orca Exploration. 

Reserves are integral to the amount of depletion charged to the profit or loss.

II)  EXPLORATION AND EVALUATION ASSETS

Under  the  Company’s  accounting  policy  expenditures  incurred  on  the  exploration  for,  and  evaluation 
of,	reserves	are	capitalized	as	intangible	assets.	These	intangibles	assets	are	then	assessed	for	impairment	
when  circumstances  suggest  that  the  carrying  amount  may  exceed  its  recoverable  value.  Such  circum-
stances	include	but	are	not	limited	to:	

•	

•	

•	

•	

•	

•	

the	period	for	which	the	Company	has	the	right	to	explore	in	the	specific	area	has	expired	during	the	
period,	or	will	expire	in	the	near	future,	and	is	not	expected	to	be	renewed;

no	further	expenditure	on	exploration	and	evaluation	is	budgeted	or	planned;

no	reserves	have	been	encountered;	

the	evaluation	of	seismic	data	indicates	that	the	reserves	are	unlikely	to	be	of	a	commercial	quantity;	

the	quantity	of	mineral	reserves	are	deemed	not	to	be	of	commercially	viable	quantities	and	the	
entity	has	decided	to	discontinue	further	activities;	and

sufficient	data	exists	to	indicate	that,	although	a	development	in	the	specific	area	is	likely	to	proceed,	
the carrying amount of the exploration and evaluation asset is unlikely to be recovered in full from 
successful development or by sale.

 
 
 
 
 
 
The	assessment	for	impairment	involves	estimates	as	to	(i)	the	likely	future	commerciality	of	the	asset	
and when such commerciality should be determined, (ii) future revenues and costs associated with the 
asset, and (iii) the discount rate to be applied to such revenues and costs for the purpose of deriving a 
recoverable value.

Exploration  and  evaluation  assets  are  assessed  for  impairment  if  (i)  sufficient  data  exists  to  determine 
technical  feasibility  and  commercial  viability,  or  (ii)  facts  and  circumstances  suggest  that  the  carrying 
amount exceeds the recoverable amount. For purposes of impairment testing, exploration and evaluation 
assets are grouped by concession.

The	technical	feasibility	and	commercial	viability	of	extracting	a	resource	is	considered	to	be	determinable	
based on several factors including the assignment of proven reserves. A review of each exploration license 
or	field	is	carried	out,	at	least	annually,	to	ascertain	whether	the	project	is	technically	feasible	and	commer-
cially viable. Upon determination of technical feasibility and commercial viability, intangible exploration 
and evaluation assets attributable to those reserves are first tested for impairment and then reclassified 
from exploration and evaluation assets to a separate category within property and equipment referred to 
as oil and natural gas interests.

III)  FAIR VALUE OF STOCK BASED COMPENSATION

All stock options issued or stock appreciation rights granted by the Company have to be valued at their 
fair	value.	In	assessing	the	fair	value	of	the	equity	based	compensation,	estimates	have	to	be	made	as	to	i)	
the	volatility	in	share	price,	ii)	risk	free	rate	of	interest	and	iii)	the	level	of	forfeiture.	In	the	case	of	stock	
options, this fair value is estimated at the date of issue and is not revalued, where as the fair value of stock 
appreciation rights is recalculated at each reporting period. 

IV)  COST RECOVERY

The	Company	is	able	to	recover	reasonable	costs	incurred	on	the	development	of	the	Songo	Songo	project	
out	of	75%	of	the	gross	revenues	less	processing	and	pipeline	tariffs	(“Net	Revenue”).	There	are	inherent	
uncertainties in estimating when costs have been recovered as the government has several years to review 
the reasonableness of the costs. 

3 

FUTURE OPERATIONS AND RISK MANAGEMENT

The	Company,	by	its	activities	in	oil	and	gas	exploration,	development	and	production,	is	exposed	to	the	risk	
associated	with	the	unpredictable	nature	of	the	financial	markets.	The	Company	seeks	to	manage	its	exposure	to	
these risks where ever possible.

I) 

FUTURE OPERATIONS

	The	Company	sells	50%	of	its	operating	revenue	(2011	-	US$45.9	million)	to	the	Tanzanian	Electricity	
Supply	Company	(“TANESCO”).	As	at	December	31,	2011,	TANESCO	owes	the	Company	US$24.2	
million of which $11.1 million was collected subsequent to year end. As of the date of this report, the 
Company	has	also	not	received	payments	from	TANESCO	with	respect	to	any	2012	production.	There	
is	a	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.	The	Company	has	been	
assured	by	the	Ministry	of	Energy	that	TANESCO	will	pay	the	outstanding	invoices	as	soon	as	TANESCO	
has	signed	a	new	financing	facility,	and	that	this	process	is	nearing	completion.	In	the	event	that	Company	
does	not	collect	from	TANESCO	the	outstanding	receivables	at	year	end	and	TANESCO	continues	to	
be unable to pay the Company for subsequent 2012 gas deliveries, the Company may need additional 
funding for its ongoing operations and to continue its committed exploration and development program 
in	2012.	There	are	no	guarantees	that	such	additional	funding	will	be	available	when	needed,	or	will	be	
available on suitable terms. 

I

O
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S
O
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D
A
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E
D
F
I
N
A
N
C
A
L

I

I

S
T
A
T
E
M
E
N
T
S

O
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C
A

E
X
P
L
O
R
A
T

I

O
N

G
R
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U
P

I

N
C

.

2
0
1
1

A
N
N
U
A
L

R
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P
O
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T

71

	
 
 
 
 
 
 
 
 
 
 
 
 
 
 
72

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

T
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L
A
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N
N
A

1
1
0
2

.

C
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I

P
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G

N
O

I

T
A
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P
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A
C
R
O

II)  FOREIGN EXCHANGE RISK

Foreign exchange risk arises when transactions and recognised assets and liabilities of the Company are 
denominated in a currency that is not the U.S. dollar functional currency.

The	 Company	 operates	 internationally	 and	 is	 exposed	 to	 foreign	 exchange	 risk	 arising	 from	 currency	
exposures	to	U.S.	dollars.	The	main	currencies	to	which	the	Company	has	an	exposure	are:	Tanzanian	
shillings, British pounds sterling, Euros and Canadian dollars. 

The	 majority	 of	 the	 expenditure	 associated	 with	 the	 operation	 of	 the	 gas	 distribution	 system	 is	
denominated	in	Tanzanian	shillings.	The	majority	of	the	consultants’	contracts	are	denominated	in	British	
pounds sterling. All of the capital stock, equity financing and any associated stock based compensation are 
denominated	in	Canadian	dollars.	All	of	the	operational	revenue	and	the	majority	of	capital	expenditure	
are denominated in US dollars.

There	are	no	forward	exchange	rate	contracts	in	place.

A 10% increase in the U.S. dollars against the relevant foreign currency would result in an overall reduction 
in working capital by US$1.3 million to US$54.7 million and a reduction in profit before tax to US$14.0 
million.	 The	 sensitivity	 includes	 only	 outstanding	 foreign	 currency	 denominated	 monetary	 items	 and	
adjusts	their	translation	at	period	end	for	a	10%	change	in	the	foreign	currency	rates.	A	10%	sensitivity	
rate is used when reporting foreign currency risk internally to key management personnel and represents 
management’s assessment of the reasonable possible change in foreign exchange rates.

III) 

 COMMODITY PRICE RISK

The	Songo	Songo	gas	field	is	the	first	gas	field	to	be	developed	in	East	Africa.	The	Company	has	therefore	
been able to negotiate industrial gas sales contracts with gas prices that are at a discount to the lowest cost 
alternative	fuels	in	Dar	es	Salaam,	namely	Heavy	Fuel	Oil	(“HFO”).	The	price	of	HFO	is	exposed	to	the	
volatility in the market price of oil.

IV) 

 INTEREST RATE RISK

The	Company	currently	does	not	have	any	debt	or	borrowings	so	it	is	therefore	not	exposed	to	any	interest	
rate risk.

V)   CREDIT RISK

All	of	the	Company’s	production	is	currently	derived	in	Tanzania.	The	sales	are	made	to	the	power	sector	
and	the	industrial	sector.	In	relation	to	sales	to	the	power	sector,	the	Company	has	a	short	term	contract	
with	Songas	for	the	supply	of	gas	to	the	Ubungo	power	plant	and	a	contract	with	The	Tanzanian	Electricity	
Supply	Company	(“TANESCO”)	to	supply	a	maximum	of	37	MMcfd	through	to	approximately	2023.	
The	 contracts	 with	 Songas	 and	 TANESCO	 accounted	 for	 60%	 of	 the	 Company’s	 operating	 revenue	
during 2011 and US$28.9 million of the receivables at the year end. Songas itself is heavily reliant on the 
payment	of	capacity	and	energy	charges	by	TANESCO	for	its	liquidity.	Despite	having	a	history	of	delayed	
payments,	TANESCO	has	previously	settled	in	full	subsequent	to	each	year	end.	However	there	is	concern	
that	TANESCO	financial	position	may	be	deteriorating	as	it	funds	the	emergency	oil	fired	generation	at	a	
time of declining receipts for electricity from parastatal bodies. Subsequent to the year end the Company 
has	received	US$11.1	million	from	TANESCO	and	Songas	have	settled	in	full.	Sales	to	industrial	sector	
are	 subject	 to	 an	 internal	 credit	 review	 to	 minimize	 the	 risk	 of	 non	 payment.	 The	 Company	 has	 been	
assured	 by	 the	 Ministry	 of	 Energy	 that	 TANESCO	 will	 pay	 the	 outstanding	 invoices	 as	 soon	 as	 it	 has	
signed	a	new	financing	facility	which	is	nearing	completion.	At	the	date	of	this	report,	TANESCO	owes	
the Company US$22.9 million.

 
 
 
 
 
 
VI)  LIQUIDITY RISK

Liquidity	 risk	 is	 the	 risk	 that	 the	 Company	 will	 not	 have	 sufficient	 funds	 to	 meet	 its	 liabilities.	 Cash	
forecasts	identifying	liquidity	requirements	of	the	Company	are	produced	on	a	regular	basis.	These	are	
reviewed to ensure sufficient funds exist to finance the Company’s current operational and investment 
cash	flow	requirements.	The	Company	has	US$22.8	million	of	financial	liabilities	with	regards	to	trade	and	
other payables indentified in note 13 of which US$17.1 million is due within one to three months, US$4.9 
million	is	due	within	three	to	six	months,	and	US$0.8	million	is	due	within	six	to	twelve	months.	The	
Company	has	a	current	taxation	liability	of	US$2.4	million	payable	within	three	months.	Management	
forecasts that the Company will be able to meet its current liabilities as they fall due through the use of 
existing	cash	balances	and	self	generated	cash	flows.	The	drilling	of	SS-12	is	dependent	on	the	immediate	
receipt	 of	 outstanding	 overdue	 payments	 of	 approximately	 US$20	 million	 from	 TANESCO,	 and	 the	
securing	of	a	US$10	million	overdraft	facility	and	satisfactory	progress	by	the	Tanzanian	Government	
on	the	infrastructure	expansion.	The	drilling	of	Songo	Songo	West	will,	in	addition,	be	dependent	on	the	
completion	of	a	debt	facility	that	is	currently	under	discussion.	This	financing	will	be	dependent	on	the	
satisfactory	 outcome	 of	 discussions	 with	 the	 Government	 Negotiation	 Team	 (‘GNT’)	 that	 was	 set	 up	
in February 2012 to address a number of issues raised by the Parliamentary Committee for Energy and 
Minerals	in	respect	of	the	Company’s	Production	Sharing	Agreement.	

VII)  CAPITAL RISK MANAGEMENT

The	 Company’s	 objectives	 when	 managing	 capital	 are	 to	 safeguard	 the	 Company’s	 ability	 to	 continue	
as a going concern in order to provide returns for shareholders and benefits for other stakeholders and 
to	 maintain	 an	 optimal	 capital	 structure	 to	 reduce	 the	 cost	 of	 capital.	 The	 Company	 currently	 has	 no	
borrowings.

VIII) MATERIAL UNCERTAINTY

A	Government	Negotiation	Team	(‘GNT’)	was	set	up	in	February	2012	to	address	a	number	of	issues	
raised	by	the	Parliamentary	Committee	for	Energy	and	Minerals	in	respect	of	the	Company’s	Production	
Sharing	 Agreement	 (“PSA”).	 This	 includes,	 but	 is	 not	 limited	 to,	 TPDC	 back	 in	 rights,	 profit	 sharing	
arrangements,  the  unbundling  of  the  downstream  assets,  cost  recovery  and  Orca’s  management  of  the 
upstream	operations.	Orca	will	discuss	these	matters	in	good	faith	with	the	GNT	and	will	look	to	reach	a	
satisfactory	agreement	that	may	lead	to	a	material	change	in	the	economic	terms	of	the	PSA.	However,	the	
Company reserves its rights to defend its position should no satisfactory agreement be reached.

4 

Segment Information

The	Company	has	one	reportable	segment	which	is	international	exploration,	development	and	production	of	
petroleum	and	natural	gas.	The	Company	currently	has	producing	assets	in	Tanzania	and	exploration	interests	
in	Italy.

Figures in US$’000

External 
revenue

Segment 
income/(loss)

Total  
assets

Total  
liabilities

Capital 
additions

Depletion & 
depreciation

2011

Tanzania

Italy

2010

Tanzania

Italy

45,893

–

7,986

–

150,933

45,181

911

4

45,893

7,986

151,844

45,185

38,808

10,057

124,408

26,225

–

(46)

–

–

38,808

10,011

124,408

26,225

17,224

911

18,135

3,381

–

3,381

8,389

–

8,389

5,046

–

5,046

I

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A

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.

2
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73

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
74

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

T
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A
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O

5 

Revenue

Years ended 31 December

Figures in US$’000

Operating revenue

Current	income	tax	adjustment

Deferred	additional	profits	tax

Revenue

2011

2010

41,794

6,626

(2,527)

45,893

35,665

3,943

(800)

38,808

The	Company’s	total	revenues	for	the	year	amounted	to	US$45,893,000	after	adjusting	the	Company’s	operating	
revenue	of	US$41,794,000	by:

i)	

ii)	

	US$	6,626,000	for	income	tax	for	the	current	year.	The	Company	is	liable	for	income	tax	in	Tanzania,	
but	the	income	tax	is	recoverable	out	of	TPDC’s	Profit	Gas	when	the	tax	is	payable.	To	account	for	this,	
revenue	is	adjusted	to	reflect	the	current	income	tax	charge	or	loss.

	US$2,527,000	for	the	deferred	effect	of	additional	profits	tax.	This	tax	is	considered	a	royalty	and	is	netted	
against revenue.

6 

Personnel expenses

The	average	number	of	employees	during	the	year	was	43	(2010:	36).	The	costs	are	as	follows:

Years ended 31 December

Figures in US$’000

Wages and salaries

Social security costs

Other statutory costs

Stock based compensation

2011

4,745

677

312

5,734

851

6,585

2010

2,180

416

527

3,123

664

3,787

The	 personnel	 stock	 based	 compensation	 is	 recorded	 under	 general	 and	 administrative	 expenses	 in	 the	
statement	of	comprehensive	income.	The	balance	of	personnel	expenses	for	2011	of	US$5.7	million	(2010:	US$	
3.1million) are recorded in distribution and production expenses and general administrative expenses at US$1.1 
million	(2010:	US$1.0	million)	and	US$4.6	million	(2010:	US$2.1	million)	respectively.

7 

Net financing costs

Years ended 31 December

Figures in US$’000

Finance income

Interest	income

Foreign exchange gain

Finance charges

Overdraft charges

Other finance costs

Foreign exchange loss

Net finance costs 

2011

2010

5

80

85

–

(100)

(938)

(1,038)

(953)

40

–

40

(12)

–

(890)

(902)

(862)

 
 
 
 
 
 
 
 
 
 
8 

Taxation

Under	the	terms	of	the	Production	Sharing	Agreement	with	TPDC,	the	Company	is	liable	to	pay	income	tax	
at	the	corporate	rate	of	30%	on	profits	generated	in	Tanzania.	The	amount	paid	is	then	recovered	in	full	from	
TPDC	by	adjusting	their	share	of	profit	gas	when	the	current	tax	liability	is	paid.

The	tax	charge	is	as	follows:

Years ended 31 December

Figures in US$’000

Current tax

Deferred	tax

2011

4,949

2,385

7,334

2010

2,760

3,741

6,501

Total	taxes	of	US$4.5	million	have	been	paid	during	the	year	in	relation	to	the	settlement	of	the	2010	tax	liability	
and	provisional	payments	for	2011.	Total	provisional	tax	payments	of	US$0.1	million	were	made	in	2010.

Tax Rate Reconciliation

Years ended 31 December

Figures in US$’000

Profit before taxation

Provision for income tax calculated at the statutory rate of 30%

Add	the	tax	effect	of	non-deductible	income	tax	items:

 Administrative and operating expenses

 Stock- based compensation

Other income 

Permanent differences

2011

2010

15,320

4,596

2,042

255

–

441

7,334

16,512

4,954

1,262

199

(6)

92

6,501

As	at	31	December	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. Accordingly a deferred tax liability 
has	been	recognized	for	the	year	ended	31	December	2011.	

No	deferred	tax	asset	has	been	recognized	in	relation	to	Longastrino	Italy.

The	deferred	income	tax	liability	includes	the	following	temporary	differences:

As at 31 December

Figures in US$’000

Differences	between	tax	base	and	carrying	value	of	property,	 
plant and equipment

Income	tax	recoverable

Other liabilities

  Employee bonuses

	 TPDC	Additional	Profit	Gas

Additional profits tax

2011

2010

14,409

2,416

(145)

(50)

(1,436)

15,194

12,194

1,349

(56)

–

(678)

12,809

I

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T
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A
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T
T
O
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H
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E
C
P
O
O
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S
O
L
D
A
T
E
D
F
I
N
A
N
C
A
L

I

I

S
T
A
T
E
M
E
N
T
S

O
R
C
A

E
X
P
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A
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I

O
N

G
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I

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C

.

2
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1

A
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75

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
76

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

T
R
O
P
E
R

L
A
U
N
N
A

1
1
0
2

.

C
N

I

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R
G

N
O

I

T
A
R
O
L
P
X
E

A
C
R
O

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	Deferred	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	of	20%	is	then	applied	to	Profit	Gas	of	US$12.6	million	in	2011	
(2010:	US$3.9	million),	accordingly,	US$2.5	million	(2010:	US$0.8	million)	has	been	netted	off	revenue	for	the	year	
ended	31	December	2011.

Management	does	not	anticipate	that	any	APT	will	be	payable	in	2012,	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	expen-
ditures	for	2012.	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	con-
sequently	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 reward the Company for taking higher risks by incurring capital expenditure in advance of revenue 
generation.

9 

Cash and cash equivalents

As at 31 December

Figures in US$’000

2011

2010

Cash and cash equivalents

34,680

45,519

10 

Trade and other receivables

As at 31 December

Figures in US$’000

Trade	receivables

Other receivables

11  

Exploration and evaluation assets

Figures in US’000

COSTS

As	at	1	January	2011

Additions

As at 31 December 2011

Figures in US’000

COSTS

As	at	1	January	2010

Additions

As at 31 December 2010

2011

2010

35,714

4,634

40,348

11,879

1,704

13,583

Italy 

Tanzania

Total

–

911

911

942

1,068

2,010

942

1,979

2,921

Tanzania

Total

760

182

942

760

182

942

 
 
 
 
 
 
 
TANZANIA

The	exploration	and	evaluation	asset	relates	to	initial	evaluation	of	the	Songo	Songo	West	prospect	which	is	
pending the determination of proven and probable reserves. 

ITALY

During	2010,	the	Company	farmed	in	to	two	exploration	licences	in	Italy.	Capital	costs	of	US$0.8million	were	
incurred	on	Northern	Petroleum	(UK)	Limited’s	Longastrino	Block	in	the	Po	Valley	Basin.	In	accordance	with	
the	farm-in	agreement,	together	with	US$0.1	million	of	capitalized	general	administrative	costs.	All	the	costs	
associated	 with	 the	 negotiation	 of	 the	 farm-in	 in	 2010	 were	 recognized	 in	 the	 statement	 of	 comprehensive	
income during 2010. 

12 

Property, plant and equipment

Tanzania

Leasehold 
improvements

Computer 
equipment

Vehicles

Fixtures & 
Fittings

Total

Figures in US’000

Costs

As	at	1	January	2011

Additions

Disposals

80,323

15,691

–

As at 31 December 2011

96,014

Depletion  
and depreciation

As	at	1	January	2011

Charge for period

Depreciation	 
on disposals

20,741

8,092

–

As at 31 December 2011

28,833

Net Book Value

Figures in US’000

Costs

As	at	1	January	2010

Additions

77,319

3,004

As at 31 December 2010

80,323

Depletion and depreciation

As	at	1	January	2010

Charge for period

As at 31 December 2010

Net Book Value

15,902

4,839

20,741

320

–

–

320

244

27

–

271

509

192

–

701

345

175

–

520

231

47

(29)

249

149

76

(29)

196

108

226

–

334

66

19

–

85

81,491

16,156

(29)

97,618

21,545

8,389

(29)

29,905

265

55

320

220

24

244

455

54

509

230

115

345

161

70

231

102

47

149

92

16

78,292

3,199

108

81,491

45

21

66

16,499

5,046

21,545

As at 31 December 2011

67,181

49

181

53

249

67,713

Tanzania

Leasehold 
improvements

Computer 
equipment

Vehicles

Fixtures & 
Fittings

Total

As at 31 December 2010

59,582

76

164

82

42

59,946

In	determining	the	depletion	charge,	it	is	estimated	by	the	independent	reserve	engineers	that	future	development	
costs	 of	 US$127.8	 million	 (2010:	 US$115.2	 million)	 will	 be	 required	 to	 bring	 the	 total	 proved	 reserves	 to	
production.	During	the	year	the	Company	recognized	depreciation	of	US$0.3	million	(2010:	US$0.2	million)	
in the general and administrative expenses.

I

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77

 
 
 
 
 
 
 
 
 
 
 
 
 
 
78

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

T
R
O
P
E
R

L
A
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N
N
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1
1
0
2

.

C
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N
O

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P
X
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A
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O

13 

Trade and other payables

As at 31 December

Figures in US$’000

Trade	payables

Accrued liabilities

Related party (note 18)

2011

2010

18,735

3,912

154

22,801

5,896

3,260

–

9,156

The	Company’s	exposure	to	credit,	currency	and	interest	risk	related	to	trade	and	other	payables	is	disclosed	in	
note 3. 

14 

Capital stock

a) 

Authorised 
50,000,000 Class A Common Shares 
100,000,000 Class B Subordinate Voting Shares 

No par value 
No par value

The	Class	A	and	Class	B	shares	rank	pari	passu	in	respect	of	dividends	and	repayment	of	capital	in	the	
event of winding-up. Class A shares carry twenty votes per share and Class B shares carry one vote per 
share.	The	Class	A	shares	are	convertible	at	the	option	of	the	holder	at	any	time	into	Class	B	shares	on	
a	one-for-one	basis.	The	Class	B	shares	are	convertible	into	Class	A	shares	on	a	one-for-one	basis	in	the	
event that a take-over bid is made to purchase Class A shares which must, by reason of a stock exchange 
or legal requirements, be made to all or substantially all of the holders of Class A shares and which is not 
concurrently made to holders of Class B shares.

b)		 Changes	in	the	capital	stock	of	the	Company	were	as	follows:

Thousands of shares or US$’000

Authorised

2011

Issued/
Repurchased

2010

Amount Authorised

Issued

Amount

Class A shares

As	at	1	January	and	31	
December

Class B shares 

As	at	1	January

Shares issued net of costs

Stock options exercised

Normal course issuer bid

50,000

1,751

983

50,000

1,751

983

100,000

32,939

84,117

50,000

–

–

–

–

–

–

–

(192)

(490)

–

–

–

27,743

4,956

240

–

65,284

18,471

362

–

As	at	31	December

100,000

32,747

83,627

50,000

32,939

84,117

Total	Class	A	&	B	shares	 
as	at	31	December

150,000

34,498

84,610

100,000

34,690

85,100

All of the issued capital stock is fully paid. A total of 192,000 Class B Subordinated Voting shares were 
repurchased	under	the	Normal	Course	Issuer	Bid	during	2011	at	an	average	price	of	Cdn$3.56.

 
 
 
 
 
 
 
 
 
STOCK-BASED COMPENSATION 

The	stock	option	plan	provides	for	the	granting	of	stock	options	to	directors,	officers	and	employees.	The	exercise	
price of each stock option is determined at the closing market price of the common shares on the day prior to the 
day of grant. Each stock option granted permits the holder to purchase one common share at the stated exercise 
price.	The	Company	records	a	charge	to	the	profit	and	loss	account	using	the	Black-Scholes	fair	valuation	option	
pricing	model.	The	valuation	is	dependent	on	a	number	of	estimates,	including	the	risk	free	interest	rate,	the	level	
of	stock	volatility,	together	with	an	estimate	of	the	level	of	forfeiture.	The	level	of	stock	volatility	is	calculated	
with reference to the historic traded daily closing share price at the date of issue.

Stock Options

Thousands of options or Cdn$

Outstanding	as	at	1	January

Exercised

Issued	

2011

2010

Options

Exercise Price

Options

Exercise Price

2,557

1.00 to 13.55

2,797

1.00 to 13.55

–

–

500

3.60 to 4.75

(240)

–

1.00

–

Outstanding	as	at	31	December

3,057

1.00 to 13.55

2,557

1.00 to 13.55

The	weighted	average	remaining	life	and	weighted	average	exercise	prices	of	options	at	31	December	2011	
were	as	follows:

Exercise Price (Cdn$)

1.00

3.60 to 4.75 

8.00 to 13.55

Number 
Outstanding 
as at  
31 December 
2011

Weighted 
Average 
Remaining 
Contractual 
Life (years)

Number 
Exercisable 
as at  
31 December 
2011

Weighted 
Average 
Exercise Price 
(Cdn$)

1,422

500

1,135

3,057

2.67

4.74

0.36

1,422

500

1,135

3,057

1.00

4.18

11.36

There	were	500,000	new	stock	options	issued	during	the	year	with	a	weighted	average	exercise	price	of	Cnd$4.18.	
The	new	stock	options	vest	on	the	date	of	issue	and	have	a	term	of	five	years.	A	total	charge	of	US$1.2	million	has	
been recognised for the year in relation to the new stock options. 

Stock Appreciation Rights

2011

2010

Thousands of stock appreciation rights or Cdn$

SAR

Exercise Price

SAR

Exercise Price

Outstanding	as	at	1	January

930

4.20 to 13.55

810

8.0 to 13.55

Expired

Granted (i)

–

–

–

–

Outstanding	as	at	31	December	(ii)

930

4.20 to 13.55

(105)

225

930

11.05

4.20

4.20 to 13.55

(i)  

(ii)  

A total of 225,000 stock appreciation rights were issued in June 2010 with an exercise price of Cdn$4.20. These rights 
have a term of five years and vest in five equal instalments, the first fifth vesting on the anniversary of the grant date. 
There is no maximum liability associated with these rights.

A total of 705,000 stock appreciation rights have a term of five years. All of these options vested over a period of three 
years and are now fully vested. There is no maximum liability associated with these rights.

I

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79

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
80

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

T
R
O
P
E
R

L
A
U
N
N
A

1
1
0
2

.

C
N

I

P
U
O
R
G

N
O

I

T
A
R
O
L
P
X
E

A
C
R
O

The	Company	records	a	charge	to	the	income	statement	using	the	Black-Scholes	fair	valuation	option	pricing	
model	 every	 reporting	 period	 with	 a	 resulting	 liability	 being	 recognised	 in	 trade	 and	 other	 payables.	 In	 the	
valuation	of	these	stock	appreciation	rights	at	the	reporting	date,	the	following	assumptions	have	been	made:	a	
risk free rate of interest of 1.50% to 2.50%, stock volatility of 42% to 75%, 0% dividend yield and 0% forfeiture 
with a closing stock price of Cdn$2.90 per share. 

As	at	31	December	2011,	a	total	accrued	liability	of	US$0.2	million	(2010:	US$0.5	million)	has	been	recognised	
in	relation	to	the	stock	appreciation	rights.	The	liability	was	reduced	by	US$0.3	million	during	the	year	as	a	result	
of an overall decline in the valuation of the stock appreciation rights.

15 

Contributed surplus

This	is	used	to	record	two	types	of	transactions:

(i)	 To	recognise	the	fair	value	of	equity	settled	stock	based	compensation	expensed	in	the	year.	

(ii)	

	To	account	for	the	difference	between	the	aggregated	book	value	of	the	shares	purchased	under	the	normal	
course issuer bid and the actual consideration. 

16 

Earnings per share

The	 calculation	 of	 basic	 earnings	 per	 share	 is	 based	 on	 the	 profit	 after	 taxation	 and	 comprehensive	 income	
income	for	the	year	of	US$8.0	million	(2010:	US$10.0	million)	and	a	weighted	average	number	of	Class	A	and	
Class	B	shares	outstanding	during	the	period	of	34,655,656	(2010:	30,795,013).

In	 computing	 the	 diluted	 earnings	 per	 share,	 the	 dilutive	 effect	 of	 the	 stock	 options	 was	 1,176,161	 (2010:	
1,098,391)	shares.	These	are	added	to	the	weighted	average	number	of	common	shares	outstanding	during	the	
year resulting in a diluted weighted average number of Class A and Class B shares of 35,831,817 for the year 
ended	31	December,	2011	(2010:	31,893,104).	No	adjustments	were	required	to	the	reported	earnings	from	
operations in computing diluted per share amounts. 

17  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	recognized	in	the	general	and	
administrative expenses.

As at 31 December

Figures in US$’000

Less	than	one	year

Between one and five years

18 

Related party transactions

2011

2010

222

92

314

232

314

546

One	of	the	non	executive	Directors	is	a	partner	at	a	law	firm.	During	the	year,	the	Company	incurred	US$0.2	
million	(2010:	US$0.3	million)	to	this	firm	for	services	provided.	The	transactions	with	this	related	party	were	
made	at	the	exchange	amount.	As	at	31	December	2011	the	Company	has	a	total	of	US$0.2	million	recorded	in	
trade and other payables in relation to the related party.

 
 
 
 
 
 
 
19 

Contractual obligations and committed capital investments

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	(65.1	Bcf	as	at	31	December	2011).	

The	 Gas	 Agreement	 may	 be	 superseded	 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	insufficiency	of	Protected	Gas.	The	Company	is	actively	
monitoring the reservoir and does not anticipate that a liability will occur in this respect.

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.	

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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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	is	currently	on	hold	and	Orca	is	not	
liable	to	any	costs	associated	with	the	drilling	of	Elsa-2	until	a	rig	contract	is	signed.	It	is	currently	anticipated	
that the Elsa-2 well will be drilled in 2013.

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	is	expected	to	be	drilled	in	July	2012	at	an	estimated	cost	to	the	
Company of US$8 million. 

There	are	no	further	capital	commitments	in	Italy.

Songo Songo deliverability

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.	 In	 October	 a	 new	 corrosion	
logging programme was undertaken to confirm its condition and it is now considered that the well may stay on 
production	until	31	May	2012.	The	Company	will	perform	a	corrosion	log	and	pressure	test	the	annulus/casing	
to	assess	whether	SS-9	can	continue	on	production	after	the	end	of	May	2012.

The	Company	is	currently	drilling	a	new	onshore	deviated	well	(SS-11)	which	is	expected	to	be	connected	to	
the	gas	processing	plant	later	in	2012.	In	the	event	that	SS-9	is	taken	off	production	there	may	be	a	period	where	
the	Company	can	only	deliver	approximately	80	MMcfd	until	SS-11	is	connected	to	the	gas	processing	plant.

Songo Songo commitments

The	 total	 cost	 of	 the	 SS-11	 well	 including	 its	 connection	 to	 the	 gas	 processing	 plant	 is	 estimated	 at	 US$33	
million	and	US$12	million	was	incurred	on	this	prior	to	31	December	2011.	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 in 2012 of US$18 million. 

Additional	 capital	 expenditure	 in	 Tanzania	 is	 dependent	 on	 the	 payments	 from	 TANESCO	 being	 brought	
up	to	date	and	the	satisfactory	conclusion	of	the	GNT,	satisfactory	progress	on	infrastrure	expansion	and	the	
subsequent	raising	of	finance.	The	capital	expenditure	is	required	to	enable	the	Songo	Songo	field	to	be	able	to	
produce	200	MMcfd	in	line	with	the	anticipated	infrastructure	expansion.	

 
 
 
 
 
 
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.	

20  Contingencies

Unbundling

TPDC	and	the	Ministry	of	Energy	and	Mines	(“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	
the	GNT.

Access to infrastructure

Ndovu	Resources	Limited,	with	support	from	TPDC	and	MEM,	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.	It	is	considered	
unlikely that this will occur during 2012. 

Government Negotiation Team

In	February	2012,	the	Government	announced	that	it	was	setting	up	a	Government	Negotiation	Team	(‘GNT’)	
to	 discuss	 a	 number	 of	 issues	 in	 relation	 to	 the	 Company’s	 Production	 Sharing	 Agreement	 (‘PSA’)	 with	 the	
Tanzania	Petroleum	Development	Corporation	that	was	signed	in	October	2001.	

The	scope	of	the	GNT	is	to	discuss	a	number	of	points	that	were	raised	by	the	Parliamentary	Committee	for	
Energy	and	Minerals	into	the	workings	of	the	PSA.	This	includes,	but	is	not	limited	to,	TPDC	back	in	rights,	
profit sharing arrangements, the unbundling of the downstream assets, cost recovery and Orca’s management of 
the	upstream	operations.	Orca	will	discuss	these	matters	in	good	faith	with	the	GNT,	but	reserves	its	rights	to	
defend its position should no satisfactory agreement be reached.

Back in

TPDC	has	indicated	that	they	wish	to	exercise	their	right	to	‘back	in’	to	the	field	development.	The	implications	
and	workings	of	the	‘back	in’	are	currently	being	discussed	with	the	Government	Negotiation	Team	(“GNT”)	
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	2011,	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. 

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.	The	level	of	cost	gas	will	increase	during	2012	as	a	result	
of	 significant	 expenditure	 on	 the	 drilling	 activities.	 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	satisfac-
torily	resolve	the	differences	with	the	GNT,	the	Company	will	utilise	the	extensive	dispute	mechanisms	outlined	
in the PSA which includes international arbitration. 

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84

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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21 

Post balance sheet event

In	February	2012,	the	Government	announced	that	it	was	setting	up	a	Government	Negotiation	Team	(‘GNT’)	
to	 discuss	 a	 number	 of	 issues	 in	 relation	 to	 the	 Company’s	 Production	 Sharing	 Agreement	 (‘PSA’)	 with	 the	
Tanzania	Petroleum	Development	Corporation	that	was	signed	in	October	2001.	

The	scope	of	the	GNT	is	to	discuss	a	number	of	points	that	were	raised	by	the	Parliamentary	Committee	into	
the	workings	of	the	PSA.	This	includes,	but	is	not	limited	to,	TPDC	back	in	rights,	profit	sharing	arrangements,	
the unbundling of the downstream assets, cost recovery and Orca’s management of the upstream operations. 
Orca	will	discuss	these	matters	in	good	faith	with	the	GNT,	but	reserves	its	rights	to	defend	its	position	should	
no satisfactory agreement be reached.

22  Directors and officers emoluments

Figures in US$000

Directors

Directors

Officers

Officers

Year

2011

2010

2011

2010

Base

737

357

1,977

1,549

Share based 
compensation 
expense

–

183

851

481

Bonus

–

–

580

100

Total

737

540 

3,408

2,130 

The	 table	 above	 provides	 information	 on	 compensation	 relating	 to	 the	 Company’s	 officers	 and	 directors.	 
Six officers and six non executive directors comprised the key management personnel during the year ended 31 
December	2011	(2010:	five	officers	and	five	non	executive	directors).

 
 
 
 
 
 
Board of Directors

W. David Lyons 
Chairman and 
Chief Executive Officer

Lord Howard of 
Lympne 
Non-Executive Director

London 
United Kingdom

Robert Wigley 
Non-Executive Director

John Patterson 
Non-Executive Director

Waterlooville, Hampshire 
United Kingdom

Nanoose Bay 
Canada

Winchester 
United Kingdom

David Ross 
Non-Executive 
Director

Calgary 
Canada

Officers

W. David Lyons 
Chairman and 
Chief Executive Officer

Winchester 
United Kingdom

Operating Office

Orca Exploration  
Group Inc.

Barclays House, 5th Floor 
Ohio Street, P.O. Box 80139 
Dar es Salaam 
Tanzania 
Tel: + 255 22 2138737  
Fax: + 255 22 2138938

International Subsidiaries

PanAfrican Energy  
Tanzania Limited

Barclays House, 5th Floor 
Ohio Street, P.O. Box 80139 
Dar es Salaam 
Tanzania 
Tel: + 255 22 2138737  
Fax: + 255 22 2138938

Beer van Straten 
Non-Executive Director

Robin Gaeta 
Non-Executive Director

Molkerum 
Netherlands

Wassenaar 
Netherlands

Nigel A. Friend 
Chief Financial Officer 

London 
United Kingdom

Registered Office

Orca Exploration  
Group Inc.

P.O. Box 3152 
Road Town 
Tortola 
British Virgin Islands

Investor Relations

W.D. Lyons

Chairman and 
Chief Executive Officer

ahanna@orcaexploration.com 
www.orcaexploration.com

PAE PanAfrican 
Energy Corporation

1st Floor 
Cnr St George/Chazal Streets 
Port Louis 
Mauritius 
Tel: + 230 207 8888 
Fax: + 230 207 8833

Orca Exploration Group Inc

Orca Exploration Italy Inc

Orca Exploration Italy Onshore Inc

P.O. Box 3152, 
Road Town 
Tortola 
British Virgin Islands

Engineering Consultants

Auditors

Lawyers

McDaniel & Associates  
Calgary, Canada

KPMG LLP 
Calgary, Canada

Burnet, Duckworth  
& Palmer LLP 
Calgary, Canada

Transfer Agent 

CIBC Mellon  
Trust Company 
Toronto & Montreal, 
Canada

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