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growth
w w w . o r c a e x p l o r a t i o n . c o m
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Orca Exploration Group Inc. is a well-financed,
international public company engaged in hydrocarbon
exploration, development and marketing.
The Company’s operations are directed from offices
in Dar es Salaam, Tanzania.
Orca’s immediate focus is on the exploration,
production, development and marketing
of Tanzanian natural gas.
Orca is also committed to growth in
assets and value through the acquisition
of oil interests with significant
exploration potential.
Orca Exploration trades on the TSXV under
the trading symbols ORC.B and ORC.A.
At the Company’s Annual General Meeting
17 November 2006, shareholders approved
a name change from EastCoast Energy
Corporation to Orca Exploration Group Inc.
This Annual Report contains certain forward-looking statements based on current
expectations, but which involve risks and uncertainties. Actual results may differ
materially. All financial information is reported in U.S. dollars ($US),
unless otherwise noted.
2
President &
CEO’s Letter to
Shareholders
8
Operations
Review
25
Management’s
Discussion
and Analysis
56
Management’s
Report to
Shareholders
57
Auditors’
Report
58
Financial
Statements
62
Notes to the
Consolidated
Financial
Statements
76
Corporate
Information
s Cover Photo:
A rig on contract to Orca Exploration is drilling
a new production well in the Songo Songo field.
When completed SS-10 is expected to increase
field deliverability by 50 mmscf/d.
annual 2006.qxp 5/3/07 10:37 PM Page 1
Financial and Operating Highlights
Year ended 31 December
2006
2005
Change
Financial (US$’000 except where otherwise stated)
Revenue
13,828
5,759
Profit before taxation
Operating netback (US$/mcf)
Cash and cash equivalents
Working capital
Shareholders’ equity
Profit per share – basic (US$)
Profit per share – diluted (US$)
4,261
2.45
20,678
20,430
953
2.11
3,198
2,211
37,889
16,662
0.11
0.10
0.02
0.02
Funds from operations before working capital changes
6,030
2,268
140%
347%
16%
547%
824%
127%
450%
400%
166%
Funds per share from operations
before working capital changes – basic (US$)
0.26
0.10
160%
Funds per share from operations
before working capital changes – diluted (US$)
0.24
0.09
167%
Outstanding Shares (‘000)
Class A shares
Class B shares
Options
Operating
Additional Gas sold – industrial (mmscf)
Additional Gas sold – power (mmscf)
Average price per mcf – industrial (US$)
Average price per mcf – power (US$)
Gross Recoverable Reserves to end of licence (bcf)
Proved
Probable
Proved plus probable
Present Value, discounted at 10% (US$ million)
Proved
Proved plus probable
1,751
1,751
25,023
21,513
2,022
1,987
1,466
3,371
8.22
1.90
266
149
415
109.0
158.7
777
1,672
7.07
1.66
241
79
320
67.7
83.8
–
16%
2%
89%
102%
16%
14%
10%
89%
30%
61%
89%
G L O S S A R Y
Mcf t
Thousands of standard
cubic feet
Mmscf t
Millions of standard
cubic feet
Bcf t
Billions of standard
cubic feet
Tcf t
Trillions of standard
cubic feet
Mmscf/d t
Millions of standard
cubic feet per day
1P t
Proven reserves
2P t
Proven and probable
reserves
3P t
Proven, probable and
possible reserves
GIIP t
Gas initially in place
Kwh t
Kilowatt hour
MW t
Megawatt
US$ t
US dollars
Cdn$ t
Canadian dollars
2006 ANNUAL REPORT
2
President & CEO’s Letter to Shareholders
2006 was another good year for Orca Exploration Group Inc. (formerly
EastCoast Energy Corporation). The Company continued development of the Songo Songo gas field
in Tanzania with positive results. Reserves have increased, a substantial development programme
is underway, sales are ahead of forecast and markets continue to grow as significant gas-fired
generation is installed at Dar es Salaam over the next 12 months.
The Company has also developed a strengthened exploration capability through the recruitment
of key individuals with substantial international oil and gas experience especially in West Africa.
Building on this, the Company has indicated its intention to identify and acquire oil opportunities
by the end of 2007 as well as continuing to develop its existing business in Tanzania.
During 2006 Orca Exploration delivered substantial performance results in all key areas.
a
Increased profit before tax by 347% to US$4.3 million (2005: US$1.0 million) and funds
flow from operations before working capital changes by 166% to US$6.0 million.
a
Produced 18.0 bcf from the Songo Songo field (2005: 14.7 bcf), increasing the volume
produced since the commencement of commercial operations in 2004 to 37.3 bcf.
Over 2006 Orca Exploration did not record any downtime that impacted gas supply to major
customers.
a
Increased the certified gross proved (1P) and proved and probable (2P) recoverable
Additional Gas reserves by 10% to 266 bcf and 30% to 415 bcf respectively.
a
Expanded the Company’s industrial gas distribution network to 28 kilometers by constructing
3 kilometers of new pipeline.
a
Commenced gas sales to six new industrial customers and increased annual sales to the
industrial sector by 89% to an average of 4.0 mmscf/d.
a
Signed a two-year contract to sell Additional Gas to the 48 MWs of emergency power
generation operated by Aggreko plc at Dar es Salaam. In 2006 sales to the power
sector increased 102% to an average of 9.2 mmscf/d.
a
Initiated remedial downhole work on SS-9 to increase Songo Songo
production by 30 mmscf/d. This was successfully completed in Q1 2007.
a
Negotiated a contract for the drilling of a new Songo Songo develop ment
well (SS-10) to further increase production capability in 2007.
a
Raised Cdn$21.5 million gross through a fully subscribed one-for-
seven rights offering of 3.3 million Class B shares.
Market Development
The power and industrial markets continue to develop in line with
expectations with a 102% and 89% increase in volumes respectively.
During 2006 average gas sales increased 98% to 13.3 mmscf/d. By Q4
2006 Additional Gas sales had increased to 17.4 mmscf/d (industrial
sector 4.3 mmscf/d, power sector 13.1 mmscf/d) as a result of the
installation of some emergency power plants. Industrial and power
demand is expected to increase further as new gas fired generation is
installed.
Opposite t
Orca has entered into
negotiations with Songas and
TANESCO for the installation
of a third and fourth gas
processing train at the Songo
Songo Island gas plant.
During 2006 the lower than average rainfalls experienced for the
This emergency generation is now forecast to be operational until
last three years severely impeded TANESCO’s ability to operate
at least the end of 2008. In addition, a Wärtsilä 100 MW unit is
its 561 MWs of installed hydro generation capacity at normal
still on target to be operational by the end of Q3 2007 and a
levels. This restriction, combined with an increase in overall
new 45 MW plant at Tegeta in Dar es Salaam is forecast to be
demand for electricity, led to a significant shortfall in power
operational by mid-2008. If the Dowans emergency units remain
generation and the need to load shed for up to 14 hours a day.
in country after the end of 2008, the conversion of the 100 MW
The Government of Tanzania and TANESCO moved swiftly to
IPTL plant (that currently uses heavy fuel oil) may be delayed.
rectify the problem and entered into two contracts with Aggreko
As a result of the acceleration of the installation of the
plc (“Aggreko”) and Dowans Tanzania Limited (“Dowans”) for
emergency units the Company may be supplying Additional Gas
the supply of 140 MWs of temporary gas-fired generation.
to up to 310 MWs of power generation (including 42 MWs of
Aggreko fulfilled its obligations in October 2006 with the startup
existing generation at the Ubungo Power Plant) by the end of
of 40 MWs of generation (48 MWs installed). Dowans was
2007. At a peak, these units would require approximately 68
contracted to supply the remaining 100 MWs. A 20 MW
mmscf/d (or 41 mmscf/d at a 60% utilisation rate).
temporary generator was installed in January 2007 and a further
60 MWs is currently being assembled and should be operational
during Q3 2007. A final 40 MWs is being shipped to Tanzania and
is expected to be installed during Q4 2007. This will increase the
total installed emergency generation to 168 MWs, of which the
suppliers are obligated to supply 140 MWs.
2006 ANNUAL REPORT
4 PRESIDENT & CEO’S LETTER TO SHAREHOLDERS
The Company is negotiating a long term portfolio contract with the electricity utility, TANESCO, for
the supply of gas to these units. TANESCO is in the process of determining their volume
requirements given the improved hydrology in the country. A contract is forecast to be in place in
the next three months.
Whilst Tanzania will have significant gas fired generation in country by December 2007, above
average rainfall in January 2007 (thought to be attributable to El Nino) significantly changed the
outlook for the 561 MWs of Tanzania’s installed hydro generation. 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 is antic-
ipated that these hydro units will have sufficient water to run at high utilisation rates during 2007
and 2008. The remaining 277 MWs of hydro generation is “run of river” and will only be available
for four to five months of a year based on average rainfalls. Accordingly, the Company is forecast-
ing that sales to the power sector will average approximately 15 - 20 mmscf/d during 2007.
Whilst the power sector provides a solid base load of gas sales, the Company is embarking on an
aggressive programme to increase sales to the industrial sector. The Company now has 13 indus-
trial customers in 15 locations. A 16-kilometer expansion of the existing 28-kilometer distribution
system is planned for 2007 at a cost of US$4.5 million. It is forecast that this will increase indus-
trial sales to 7.5 mmscf/d by the end of 2007.
In addition, the Company, in conjunction with TPDC, is planning to commence the sale of Compressed
Natural Gas (“CNG”) by Q1 2008. The intention is to transport CNG to industrial customers and
markets that are not located near the existing distribution pipeline. This could be an exciting new
market that has the potential to develop to over 10 mmscf/d in the coming years.
The Company is also looking at constructing high pressure pipelines to other industrial towns in
Tanzania including Tanga and Morogoro. Whilst the infrastructure costs will be high and will take
at least two years to develop, the netbacks will be better than sales to the power sector at current
oil prices.
The Company is also reviewing the possibility of applying for an electricity generation licence and
selling power directly to industrial customers. This will be progressed during 2007.
Infrastructure
Planning was initiated in 2006 to expand the infrastructure to meet this forecast increase in
demand. The Company commissioned Petrofac Engineering Limited to undertake a capacity
re-rating and debottlenecking review of the existing Songo Songo gas processing plant to
determine how to meet immediate and future projected demands. As a result of this work, Songas
Limited (“Songas”) appointed Bureau Veritas to re-rate the gas plant capacity. Whilst work is
ongoing and this is still to be agreed with the insurers, the indications are that the gas process-
ing plant could be run at 85 mmscf/d for a short period of time compared with its present
nameplate capacity of 70 mmscf/d.
The Company also entered into discussions with Songas and TANESCO for the installation of a third
and fourth gas processing train. This would lead to in excess of 140 mmscf/d of gas processing
capacity. A Memorandum of Understanding (‘MOU’) was signed with Songas, TANESCO and the
Ministry of Energy and Minerals in December 2006 identifying the key issues that needed to be
addressed to enable the expansion to take place. Under the terms of the MOU, Orca Exploration
will continue to pay 17.5% of the achieved sales price of gas and part of this will be allocated to
Top u Welders connect a pipeline
to supply “Additional Gas” to an
emergency power generation unit
at Dar es Salaam.
Bottom u The Aggreko 48 MW
generation units rely on “Additional
Gas” supplied by Orca Exploration.
Songas to compensate for their investment in the trains. This is
Exploration
still the subject of an application by Songas to the Electricity,
Water, Utilities Regulatory Authority (‘EWURA’) and is also subject
to the agreements of gas terms and prices with TANESCO to
justify the expansion.
The capacity of the 232-kilometer pipeline system to Dar es
Salaam is estimated at 105 mmscf/d and is limited by the 12”
25-kilometer offshore line. Additional compression or a new
offshore pipeline may be required during 2008/2009 to meet
peak loads. Work will be undertaken in 2007 to assess the most
cost effective means of achieving the forecast peak rates.
Reserves Increase
The Songo Songo reservoir continues to perform above expecta-
tions. During the year, further pressure testing has generated
positive results. The independent reserves engineers, McDaniel &
Associates Consultants Ltd, have reviewed all the data and have
assessed that the gross proven and probable reserves (“2P”) for
Reserves and deliverability need to be ahead of demand so that
commitments to power and infrastructure developments can be
planned with greater certainty.
The Company continues to review ways of increasing the reserve
base. The drilling of the Songo Songo West prospect approxi-
mately 2 kilometers west of the existing Songo Songo field is an
excellent target and the Company intends to drill at least one
well on this location as soon as practicable. The well could be
drilled using a jack up rig or a land rig from the same artificial
island that may be used to drill Songo Songo North. Work is
currently being undertaken to assess the feasibility of this
approach as well as identifying a suitable jack up rig.
The Company relinquished seven Adjoining Blocks neighbouring
the Songo Songo field during the year as the only identified lead
was considered small and expensive to drill and therefore less
attractive than the Songo Songo West prospect.
the total field on a life-of-licence basis increased by 14% to 648
New Ventures
The Company recruited several key individuals in 2006 including
James Smith who was integral to the growth of PanOcean Energy
Corporation. The Company is now evaluating several oil oppor-
tunities in sub Saharan Africa with a view to acquiring exploration
and/or development assets by the end of 2007.
bcf (2005: 569 bcf). The proportion in which the Company has a
financial interest, under the Songo Songo PSA (“Additional
Gas”), increased by 30% to 415 bcf (2005: 320 bcf).
A majority of the 2P reserves can be delivered from the existing
well stock. However, to deliver all the reserves will require signif-
icant capital expenditure over the next five years. This includes
the drilling of a well in the northern portion of the field (“Songo
Songo North”) which will require a jack up rig or the drilling of
a deviated well using a land rig from an artificial island.
To meet immediate forecast deliverability requirements, the
Company signed a drilling contract with Caroil SA in February
2007 and commenced the drilling operations in April 2007.
The well is being drilled with a land rig on Songo Songo Island
and will deviate 1 kilometer offshore into the main reservoir.
It should be completed by mid June 2007 and is forecast to add
deliverability of 50 mmscf/d.
In addition, the Company successfully completed the removal of
over 5,000 feet of wireline and two pressure gauges that were
left in the hole in 1997 and which were severely impacting the
deliverability of the SS9 well. The deliverability has subsequently
increased from 20 mmscf/d to a maximum of 50 mmscf/d.
The cost of the remedial work was US$1.9 million.
2006 ANNUAL REPORT
6 PRESIDENT & CEO’S LETTER TO SHAREHOLDERS
2007 Targets
Over 2007, the Company will continue to focus on growth, with an increasing emphasis on new
project development.
a
Negotiate and sign a number of long term contracts to supply gas for use in the 120 MWs
of gas fired plants owned and operated by Dowans, the 100 MW Wärtsilä plant, the 45 MW
Wärtsilä plant at Tegeta and the 42 MW plant that is operational at the Ubungo Power Plant.
a
Expand sales to the industrial markets to 6-7 mmscf/d by Q4 2007 through the construction
of an additional 16 kilometers of the Company’s low pressure distribution system.
a
Prepare for the commencement of CNG sales to industrial and retail customers who are not
located along existing pipeline infrastructure and assess feasibility for the supply of
electricity direct to industrial customers.
a
Finalise drilling plans for the Songo Songo West exploration well and the Songo Songo North
appraisal well.
a
Increase the 2007 deliverability of the Songo Songo gas field from 130 mmscf/d at 31
December 2006 to approximately 210 mmscf/d as a result of the remedial work on SS-9
and the drilling of a new development well, SS-10.
a
Farm-in, licence or acquire high potential oil properties with significant exploration potential.
Over the past two and one half years, the Company has exceeded its targets. This achievement
has been made possible by all those who have stood with us and helped us to achieve the results
that this Annual Report presents. We have relied on the investment of our shareholders; the skill,
dedication and innovative spirit of our employees; the wise counsel of our Board of Directors;
the commitment of our partners; the support of our customers and in particular the opportunities
provided to us by the Government of Tanzania.
Our commitment to growth is based on clear goals, the necessary resources and a deter-
mination to succeed. There is much to be done as we continue to grow through 2007.
Peter R. Clutterbuck
President & CEO
30 April 2007
Top u A land rig was erected on
Songo Songo Island in March 2007
to drill SS-10, a new development
well that is expected to
substantially increase field
deliverability.
Opposite t Additional Gas
supplied by Orca Exploration feeds
emergency power units.
2006 ANNUAL REPORT
8 OPERATIONS REVIEW
Operations Review
Production
ops1
ops2
ops3
ops3
During 2006, 18.0 bcf (2005: 14.7 bcf) of gas was produced from the Songo Songo field offshore
Tanzania or an average of 49.3 mmscf/d (2005: 40.3 mmscf/d). This brings total production since
Cumulative production
from each well
Protected Gas Volumes
Gross Additional Gas reserves
on a life of licence basis
2007 build up of
gas fired generation
not sure
Average daily production
per month in 2006
commercial operations commenced on 20 July 2004 to 37.3 bcf. Production peaked at 66 mmscf/d
in December 2006.
Operatorship
Orca Exploration is the operator of the reservoir, wells and gas processing plant on Songo Songo
Island on behalf of the stakeholders, including Songas Limited (“Songas”). Operatorship is on a
‘no gain/no loss’ basis. Two internationally experienced staff manage the site operations on a
rotational basis with support from the Company’s head office personnel in Dar es Salaam. Twenty-
six Tanzanian technicians operate and maintain the wells, gathering system and processing plant.
Since commencement of commercial operations, there has been 100% uptime in relation to the
f
c
B
supply of gas to major customers in Dar es Salaam.
Songo Songo wells
The production from the five Songo Songo wells was as follows:
Well
SS-3
SS-4
SS-5
SS-7
SS-9
Total
2004
2005
2006
Bcf
0.8
0.6
1.7
1.5
–
4.6
Bcf
1.3
1.9
3.9
3.8
3.8
Bcf
1.5
1.9
8.9
3.2
2.5
14.7
18.0
The total gas production from the Songo Songo field was allocated as follows:
md2
2006 Additional Gas industrial and power sales volumes
2004
Bcf
4.1
0.1
0.4
4.6
2005
Bcf
11.9
2.5
0.3
14.7
2006
Bcf
13.0
4.8
0.2
18.0
700
Protected Gas sales
Additional Gas sales
Flare, generator at the processing
plant and line pack
600
Total
500
400
300
narrower copy of below
200
100
0
J
a
n
F
e
b
M
a
r
A
p
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M
a
y
J
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J
u
l
A
u
g
S
e
p
O
c
t
N
o
v
D
e
c
Industrial
Power
Total
Bcf
3.6
4.4
14.5
8.5
6.3
37.3
Total
Bcf
29.0
7.4
0.9
37.3
16,000
14,000
12,000
10,000
8,000
6,000
4,000
2,000
0
0
0
0
$
S
U
f
c
s
M
M
700
600
500
400
300
200
100
0
16
14
12
10
8
6
4
2
0
SS-3
SS-4
SS-5
SS-7
SS-9
2004
2005
2006
2004
2005
2006
J
a
n
F
e
b
M
a
r
c
h
A
p
r
i
l
M
a
y
J
u
n
e
J
u
l
y
A
u
g
S
e
p
O
c
t
N
o
v
D
e
c
Month
Wazo Hill
Ubungo Power Plant
d
/
f
c
s
M
M
56
54
52
50
48
46
44
42
40
200
s
W
M
150
350
300
250
100
50
0
3
1
-
D
e
c
-
0
6
Q
1
2
0
0
7
Q
2
2
0
0
7
Q
3
2
0
0
7
Q
4
2
0
0
7
Ubungo 42 MW
Aggreko 48 MW
Dowans 20 MW
Dowans 60 MW
Wartsila 100 MW
Dowans 40 MW
2007
2006
2005
2004
2003
2002
2001
2000
1999
1998
1997
1996
1995
1994
1993
1992
1991
1990
14000
12000
10000
f
c
s
m
M
8000
6000
4000
2000
0
Probable
Proven
300
f
c
b
500
400
200
100
0
2007
4
0
0
2
2 0 0 5
2006
)
s
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t
e
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(
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e
v
e
l
a
e
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e
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b
a
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L
700
699
698
697
696
695
694
693
692
691
690
689
688
687
f
c
s
M
M
200
180
160
140
120
100
80
60
40
20
0
md1
Revenue
md4
2006 Additional Gas Prices
Power
Industrial
Opposite y
A major workover
of the SS-9 offshore well was
completed in early 2007.
2006 ANNUAL REPORT
f
c
m
/
$
S
U
10
9
8
7
6
5
4
3
2
1
0
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
2005
2006
J
a
n
F
e
b
M
a
r
A
p
r
M
a
y
J
u
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J
u
l
A
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g
S
e
p
O
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t
N
o
v
D
e
c
md2
md3
2006 Additional Gas industrial and power sales volumes
2006 Additional Gas industrial sales
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Industrial
Power
Nampak
Nida
ECO&F
Bora
Murzah III
Murzah II
Murzah I
Lakhani
Mukwano
TCC
Chinese
ALAF
TBL
Kioo
Karibu
700
699
698
697
696
695
694
693
692
691
690
689
688
687
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
10 OPERATIONS REVIEW
Protected Gas production
Under the terms of a Gas Agreement signed in 2001, the Protected Gas from Songo Songo is
100% owned by the Tanzanian Petroleum Development Corporation (“TPDC”) and is sold to
Songas under a 20 year Gas Agreement for the operation of five turbines at the Ubungo Power
Plant or for onward sale to the Wazo Hill cement plant or village electrification.
Over the year ended 31 December, 2006, the Protected Gas utilisation rate was 80% (2005: 73%).
The Protected Gas was allocated as follows:
Year ended 31 December
Protected Gas Volumes
Protected Gas user
Ubungo Power Plant
Wazo Hill Cement Plant
Village Electrification Programme
Total consumption
2006
Protected Gas
consumed
Utilisation
rate
2005
Utilisation
rate
Bcf
mmscf/d
11.4
31.3
1.6
–
4.3
–
13.0
35.6
%
81
73
–
80
%
74
73
–
73
Protected Gas utilisation in 2006 at the Ubungo Power Plant increased primarily because the fifth
turbine was operational from March 2005 and the severe drought in Tanzania in 2006 required
the turbines to be dispatched at higher rates. There was some considerable downtime at the plant
caused by problems with the 34 MW fifth and 42 MW sixth turbines in September 2006. Since
commercial operations commenced, the Protected Gas utilisation at the Ubungo Power Plant has
been 76%.
At the Wazo Hill Cement Plant, the monthly utilisation ranged from 52% to 86% over 2006 and
averaged 73% (2005: 73%). This plant is intending to expand its capacity in 2009 and this should
lead to some Additional Gas sales. Since commercial operations commenced, the Protected Gas
utilisation at the Wazo Hill cement plant has been 68%.
The Village Electrification Program was not operational in 2006 and is now due to commence in
the second half of 2007.
The maximum gas required for the Protected Gas users over the remaining 17 years and seven
months of the Gas Agreement was reduced to 289 bcf as at 31 December 2006. For the purposes
of calculating the level of gas available as Additional Gas, an assumption has to be made as to
the expected utilisation of the Protected Gas over the remaining term of the Gas Agreement.
2004
2005
2006
These assumptions 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:
f
c
s
m
M
14000
12000
10000
8000
6000
4000
2000
0
Wazo Hill
Ubungo Power Plant
Protected Gas consumer
Six gas turbines at the Ubungo Power Plant
Theoretical
maximum 100%
load factor
Mmscf/d
Most likely
Mmscf/d
Utilisations
in 2006
Mmscf/d
47.4
(9.2)
38.2
5.9
1.0
45.1
38.9
(7.6)
31.3
4.3
1.0
36.6
38.9
(7.6)
31.3
4.3
–
35.6
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)
289
233
The forecast theoretical maximum of Protected Gas is estimated at 45.1 mmscf/d based on
technical tests of the Ubungo turbines and the Wazo Hill plant. The ‘most likely’ utilisation
including the village electrification programme is forecast to be 81% over the remaining term of
the Gas Agreement. This compares with an actual utilisation rate of 80% in 2006 and a cumula-
tive utilisation of 73% since commercial operations commenced.
Additional Gas Production
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. The details of the 2006 Additional Gas sales are set out under ‘Markets’ below.
Flare, generator and line pack requirements
A relatively small amount of gas is required to be used in local electricity generation on Songo
Songo Island. Gas is also required to maintain the Songo Songo Island gas plant flare at all times.
This leads to a small loss of gas each year.
There are also fluctuations in the line pack in the 232 kilometer pipeline to Dar es Salaam. The line
is estimated to hold a maximum of 85 mmscf of gas. At current production levels the line pack
holds sufficient gas for approximately a day of Protected and Additional Gas sales in Dar es Salaam.
Songo Songo field
During 2006, Orca Exploration focussed on utilising the 2005 remapping and reservoir geology
studies combined with pressure data from the wells to construct a series of numerical simulation
models to assist in evaluating subsurface sensitivities, in planning gas offtake rates and in fore-
casting likely future investments to maintain and increase deliverability.
Songo Songo remapping
In 2005, geophysical work concentrated on reviewing 569 kilometers of reprocessed 2D seismic
and 212 kilometers of newly acquired 2D seismic gathered over the main Songo Songo field. In
2006, this new and reprocessed dataset has allowed a considerably improved subsurface mapping
which has been integrated with petrophysical analyses of the wells, revised biostratigraphic corre-
lation and evaluation of core data to create a detailed, static reservoir model for each of the two
main reservoir intervals in the field. The assessed GIIP is consistent with the values of GIIP used
by McDaniel & Associates Consultants Ltd. (“McDaniel”) in their independent reserve evaluation.
During Q1 2007, 30 kilometers of transition zone seismic was shot primarily over the northern
aspect of the Songo Songo field. This is currently being interpreted.
Reservoir surveillance and management
In 2006, the Company continued to acquire excellent information on the Songo Songo field from
the down hole gauges that were installed in all wells (except SS-9). These highly accurate gauges
record pressure changes and allow the Company to estimate the volume of gas in contact with
each well and to calibrate dynamic models to optimise production strategies. The pressure gauges
were most recently retrieved from the wells during December 2006 and will be re-installed to
allow further evaluation in 2007. Additionally, it is intended to install gauges in SS9 now that the
downhole debris has been removed.
Top u
Gas piping at Songo Songo Island
feeds well production to the gas
plant for processing and
compression.
Bottom u
Large manufacturing operations,
like Nida Textiles, are befitting
from the availability of natural gas
to replace the use of fuel oil.
2006 ANNUAL REPORT
12 OPERATIONS REVIEW
Above u
TANESCO’s Ubungo plant at Dar es Salaam
produces electrical power from six units.
Shown above is UGT6, the most recent
addition to the plant. 19.5% of the natural
gas used at Ubungo is Additional Gas
supplied by Orca Exploration.
annual 2006.qxp 5/3/07 10:37 PM Page 13
To predict the well performance and allow planning of gas offtake and future deliverability
investments such as wells and wellhead compression, the static reservoir model was imported
into reservoir simulation software to history match production rates and pressures recorded for
each well. A good match has been obtained with the static GIIP determined in the geological
and geophysical model, leading to confidence in the simulation model as a reservoir management
tool. Future work will focus on analysing the pressure transients obtained from production and the
downhole pressure data, and the incorporation of these data into revised material balance models.
The simulation model has been used to assess the likely well response to uncertainties such as
the rate of aquifer influx and extent of reservoir compartmentalisation, if any. So far, the pressure
behaviour of the wells is not showing evidence of any material compartmentalisation or aquifer influx,
and pressure data suggests a likely GIIP towards the upper end of the Company’s computed range.
Based on preliminary reservoir material balance calculations, the field’s GIIP was computed in
2005 to be 1,080 bcf (most likely) to 1,224 bcf, dependent on aquifer behaviour. Orca Exploration’s
2006 evaluation of static GIIP ranges from 1,071 to 1,184 bcf (including the northern portion of
the field which may not be drained by the existing well stock) and compares favourably with the
1,215 bcf computed by McDaniels in its independent reserve report as at 31 December 2006 for
the 3P case. Both McDaniel and Orca Exploration’s static GIIP are based on volumetric structural
mapping of the different reservoir zones rather than relying on the pressure data at this early
stage in the field’s development.
To obtain the most reliable data for reservoir management, the Songo Songo gas plant is equipped
with a test separator that allows production from individual wells to be measured and important
surface pressures and temperatures to be captured using Keller wellhead gauges. This information
has been combined with the results of the downhole pressure gauges to show that SS-3, SS-4,
SS-5 and SS-9 demonstrate conclusive evidence of communication with other wells. There is the
possibility that SS-7 may be partially isolated from the other wells and this will continue to be
monitored during 2007, although compartmentalisation is not expected to be material.
The flow rates of the wells based on the requirement to have 1,600 pounds per square inch of
pressure in the gas processing plant are as follows:
Songo Songo wells
SS-3
SS-4
SS-5
SS-7
SS-9 (Note 1)
Total
Maximum Protected Gas demand
Available for Additional Gas
Well flow rates (mmscf/d)
1997
initial capacity
31
December
2005
capacity
31
December
2006
capacity
10
10
60
20
40
140
(45)
95
18
17
63
22
25
145
(45)
100
16
12
62
20
20
130
(45)
85
Note 1: Remedial work was performed on SS-9 subsequent to the year end. This led to an increase in its maximum
deliverability to 50 mmscf/d.
2006 ANNUAL REPORT
14 OPERATIONS REVIEW
The Songo Songo wells showed an 8% decline over the course of 2006, in line with or slightly
better than expectations. With the inclusion of productivity arising from remedial work on SS-9,
performed after year-end, the deliverability is sufficient to enable 115 mmscf/d of Additional Gas
production above the peak demand for Protected Gas. This will allow the Company to produce
more than 50 mmscf/d of Additional Gas for a period of time even if the largest well, SS-5,
becomes unavailable at peak demand. Because of the possibility of interference between
producing wells, this sort of flow rate with the largest well off-line is unlikely to be sustainable
over the medium term.
Additional 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 2007 that assessed
not sure
the Orca Exploration natural gas reserves based on information on the Songo Songo field as at
ops3
31 December 2006 (the “McDaniel Report”).
2007 build up of
gas fired generation
Average daily production
per month in 2006
Over the course of 2006, there has been a 10% increase in Songo Songo’s gross 1P reserves from
240.6 bcf to 265.8 bcf despite Additional Gas sales of 4.8 bcf being produced in 2006. Gross 2P
350
56
reserves increased 30% from 320.0 bcf to 415.1 bcf. The reserves summary to the end of the
license period (October 2026) for the gross Additional Gas was as follows:
54
300
Songo Songo Additional Gas reserves to
October 2026 (Bcf)
Independent reserves evaluation
250
Proved producing
Proved undeveloped
200
Total proved (1P)
Probable
s
W
M
Total proved and probable (2P)
150
2006
Gross (1)
2006
Net (2)
52
2005
Gross
219.5
46.3
265.8
149.3
415.1
129.4
56.0
d
/
f
185.4
c
s
M
M
98.9
284.3
50
48
179.9
60.7
240.6
79.4
320.0
2005
Net
108.5
44.0
152.5
72.3
224.8
(1) Gross reserves are based on 100% of the property’s gross Additional Gas reserves (excluding Protected Gas).
(2) Net reserves are based on the Company’s share of the Cost Gas and Profit Gas revenues.
46
The McDaniel Report has assumed that TPDC will exercise their right to ‘back in’ to the field devel-
44
100
opment by contributing 20% of the costs of the future wells including SS-10 in return for a 20%
increase in the profit share for the production emanating from these wells. This impacts the net
reserves. The implications and workings of the ‘back in’ are still to be discussed in detail with TPDC.
42
40
For the purpose of calculating the gross Additional Gas reserves, McDaniel has assumed that 233
bcf or an average of 13.4 bcf per annum will be required to meet the demands of the Protected
A
u
g
J
u
l
y
S
e
p
F
e
b
J
a
n
O
c
t
M
a
y
J
u
n
e
N
o
v
D
e
c
M
a
r
c
h
A
p
r
i
l
Gas users from 1 January 2007 to October 2026. This compares with 249 bcf as at 1 January 2006.
Month
3
1
-
D
e
c
-
0
6
Q
1
2
0
0
7
Q
2
2
0
0
7
Q
3
2
0
0
7
Q
4
2
0
0
7
During 2006 Protected Gas users consumed 13.0 bcf.
50
0
Ubungo 42 MW
Aggreko 48 MW
Dowans 20 MW
Dowans 60 MW
Wartsila 100 MW
Dowans 40 MW
2007
2006
2005
2004
2003
2002
2001
2000
1999
1998
1997
1996
1995
1994
1993
1992
1991
1990
md2
2006 Additional Gas industrial and power sales volumes
700
600
500
400
300
200
100
0
narrower copy of below
J
a
n
F
e
b
M
a
r
A
p
r
M
a
y
J
u
n
J
u
l
A
u
g
S
e
p
O
c
t
N
o
v
D
e
c
Industrial
Power
f
c
s
m
M
14000
12000
10000
8000
6000
4000
2000
0
f
c
m
/
$
S
U
10
9
8
7
6
5
4
3
2
1
0
f
c
B
16
14
12
10
8
6
4
2
0
0
0
0
$
S
U
16,000
14,000
12,000
10,000
8,000
6,000
4,000
2,000
0
f
c
s
M
M
700
600
500
400
300
200
100
0
ops1
ops2
ops3
Cumulative production
from each well
Protected Gas Volumes
Gross Additional Gas reserves
on a life of licence basis
Probable
Proven
500
400
300
f
c
b
200
100
0
2004
2005
2006
Wazo Hill
Ubungo Power Plant
SS-3
SS-4
SS-5
SS-7
SS-9
2004
2005
2006
md1
Revenue
md4
2006 Additional Gas Prices
Power
Industrial
2007
4
0
0
2
2 0 0 5
2006
)
s
r
e
t
e
m
(
l
e
v
e
l
a
e
s
e
v
o
b
a
l
e
v
e
L
700
699
698
697
696
695
694
693
692
691
690
689
688
687
f
c
s
M
M
200
180
160
140
120
100
80
60
40
20
0
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
2005
2006
J
a
n
F
e
b
M
a
r
A
p
r
M
a
y
J
u
n
J
u
l
A
u
g
S
e
p
O
c
t
N
o
v
D
e
c
md2
md3
2006 Additional Gas industrial and power sales volumes
2006 Additional Gas industrial sales
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Industrial
Power
Nampak
Nida
ECO&F
Bora
Murzah III
Murzah II
Murzah I
Lakhani
Mukwano
TCC
Chinese
ALAF
TBL
Kioo
Karibu
700
699
698
697
696
695
694
693
692
691
690
689
688
687
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
annual 2006.qxp 5/3/07 10:37 PM Page 15
The principal assumptions used by McDaniel in its evaluation of the Tanzanian PSA are as follows:
Year
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
Gross
Additional
Additional
Gas price Gas volumes
1P
1P
Gross
Additional
Additional
Gas Price Gas volumes
2P
2P
Brent
crude
Annual
inflation
US$/BBL
US$/mcf
mmscf/d
US$/mcf
mmscf/d
%
60.5
59.2
57.7
56.3
54.6
55.8
56.8
58.0
59.2
60.3
61.6
62.8
64.1
65.3
66.7
68.0
69.4
70.8
72.2
73.6
3.65
3.43
3.34
3.42
3.56
3.64
3.72
3.80
3.89
3.98
4.19
4.31
4.41
4.51
4.61
4.71
4.82
4.93
5.04
5.15
21.0
33.0
45.0
52.5
55.0
55.0
55.0
55.0
55.0
55.0
50.0
36.0
36.0
25.8
17.0
9.4
2.9
15.6
29.1
25.0
3.52
3.38
3.25
3.23
3.36
3.54
3.62
3.71
3.79
3.87
3.96
3.82
4.25
4.35
4.45
4.55
4.65
4.76
4.86
4.97
23.0
39.0
56.5
74.5
77.5
80.0
80.0
80.0
80.0
80.0
80.0
75.0
55.0
55.0
41.8
30.5
28.8
30.8
42.0
35.9
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
Additional Gas reserves reconciliation
Bcf
Gross Gross proved
proved and probable
Net
Net proved
proved and probable
Reserves at 1 January 2006
240.6
320.0
152.5
224.8
Extensions
Improved recovery
Technical revisions
Discoveries
Acquisitions
Dispositions
Economic factors
Production
–
–
–
–
–
–
–
–
30.0
99.9
35.2
62.7
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
(4.8)
(4.8)
(3.2)
(3.2)
Reserves at 31 December 2006
265.8
415.1
184.5
284.3
There was no drilling activity on the Songo Songo field during 2006. The increase in the proven and
probable reserves has arisen from improved volumetric structural mapping, the 2006 pressure and
gas production data and the acceleration of field depletion through greater capital expenditure.
Above u
Natural gas deliverability
was increased in early
2007 by the workover of
the SS-9 well offshore
Songo Songo Island.
2006 ANNUAL REPORT
16 OPERATIONS REVIEW
It is expected that the 2007 work program, including the acquisition of 30 kilometres of 2D
transitional zone seismic will help to delineate the structure to the north of the field.
Present value of reserves
The estimated value of the Songo Songo reserves based on the assumptions on production and
pricing are as follows:
US$ millions
Proved producing
Proved undeveloped
Total proved (1P)
Probable
2006
10%
78.1
30.9
5%
113.5
41.4
154.9
109.0
86.8
49.7
15%
58.2
21.4
79.6
28.9
5%
76.4
26.7
103.1
38.1
Total proved and probable (2P)
241.7
158.7
108.5
141.2
2005
10%
47.4
20.3
67.7
16.1
83.8
15%
33.4
13.8
47.2
7.1
54.3
The present values are primarily higher in 2006 due to the increase in the reserves and the fact
that there has been an increase in the forecast capital expenditure which has the effect of
deferring the time when Additional Profits Tax becomes payable.
2007 Development Programme
At the end of 2006, a total of 90 MWs (UGT 6: 42 MWs and Aggreko: 48 MWs) of gas fired gener-
ation was operational in Tanzania. During the course of 2007, it is anticipated that an additional
220 MWs will be introduced onto the system taking the maximum capacity in country to 310 MW.
At full load, 310 MWs would require approximately 68 mmscf/d (or 41 mmscf/d at a 60%
utilisation rate) of Additional Gas.
To ensure there is adequate deliverability to meet any potential gas demand, the Company has
commenced a programme to increase the current deliverability from 130 mmscf/d (85 mmscf/d
available for the Additional Gas) to a forecast 210 mmscf/d (165 mmscf/d for Additional Gas). This
is to be achieved by some remedial work on SS-9 and the drilling of a development well, SS-10.
In January 2007, the Company commenced a US$1.9 million work programme to remove over
5,000 feet of wireline and two gauges that were left downhole in SS-9 at the time of the 1997
well testing programme. This was restricting the flow to 20 mmscf/d. The remedial work has now
been successfully completed with the result that the maximum flow rate has increased from 20
mmscf/d to an estimated 50 mmscf/d.
The Company has signed a contract with Caroil SA for the drilling of a development well, SS-10.
The well will be drilled with a land rig from the Songo Songo Island. It will deviate one kilometre
offshore into the main reservoir. The well was spud in April 2007 and is forecast to be complete
by mid June 2007. This well is forecast to cost in the range of US$11-US$13 million in 2007.
During the year the Company purchased sufficient long lead items to drill a second well. The lead
items will be stored on Songo Songo Island until required for additional drilling activity.
The Company forecasts that another development well will be drilled in 2008/2009 and will
commence planning in 2007. This could either be a deliverability well in the main Songo Songo
field (similar to SS-10) or an appraisal well in the north of the field (“Songo Songo North”) which
may not be drained by the existing well stock. Technically this well is more challenging, as it is
several kilometers from the Songo Songo Island and in water depths that may require a jack up rig.
Exploration
At the beginning of the year, the Company was party to nine licences under the terms of the PSA
with the Tanzanian Petroleum Development Corporation (“TPDC”), namely the two blocks within
which the Songo Songo field lies (“Discovery Blocks”) and seven blocks in adjacent areas
(“Adjoining Blocks”).
During the year, the Company relinquished the Adjoining Blocks as the 377 kilometers of seismic
that was shot in 2005 revealed only a small prospect with some uncertainty with the fault seal.
Discovery Blocks
During Q1 2006, a review of the seismic on the Discovery Blocks identified a promising prospect
approximately 2 kilometers west of the existing Songo Songo field. This has been designated as
Songo Songo West (“SSW”).
The seismic on SSW indicates a tilted fault trap at the same reservoir interval (Neocomian) as the
main field.
Management has estimated the potential for this prospect as follows:
Estimated
Songo Songo West
Minimum Most likely
GIIP
GIIP
Maximum
GIIP
Bcf
90
Bcf
600
Bcf
1,070
The intention is to drill SSW as soon as practicable. SSW lies in 20 meters of water and the
Company is currently considering the following drilling options:
a
a
Drill the prospect with a jack up rig (recognising that there is a shortage of such rigs that
are prepared to mobilise to East Africa);
Construct a man made island on a reef within 2 kilometers of the prospect and then drill
a deviated well utilising a land rig;
a
Use a rig mounted on a barge to drill near, or on location.
These options are being evaluated with the view to drilling the well during 2008/2009.
The total cost of drilling SSW is estimated at US$17 – US$20 million, with an additional US$4
million to complete. In addition, there would be substantial infrastructure costs to tie the well
into the existing gas processing and pipeline system if successful.
Nyuni “A”
In September 2005, Orca Exploration entered into an agreement with Ndovu Resources Limited
(“Ndovu”), a subsidiary of Aminex plc, to farm-in to part of its offshore Nyuni Production Sharing
Agreement (“Nyuni PSA”) adjacent to the producing Songo Songo gas field.
Orca Exploration acquired 328 kilometers of 2D seismic over Nyuni “A” in October 2005 taking
advantage of the cost savings gained by extending the Songo Songo area 2D seismic program.
A few small prospects were identified but were not considered of sufficient size to justify the
Company electing by 30 September 2006 to drill a well in their licence acreage, when SSW in
the Discovery Blocks had greater potential.
In early 2007, Ndovu ran some additional transitional zone seismic over their licence acreage and in
the prospective areas. The Company is still in discussions with Ndovu, but it is considered unlikely at
this stage that the Company will participate in the drilling of two wells on their licence acreage.
Above u
A 2006 seismic program
identified exploration opportunities
for Orca Exploration on lands
adjacent to the Songo Songo field.
2006 ANNUAL REPORT
18 OPERATIONS REVIEW
Infrastructure
The infrastructure that transports the gas from the field to Dar es Salaam was commissioned in July
2004. The current infrastructure configuration has a name plate capacity of approximately 70
mmscf/d, limited by the two gas processing trains that have a design specification of 35 mmscf/d
each and the pipeline system that is assessed by Songas to have a capacity of 105 mmscf/d.
The current forecasts indicate that peak loads of approximately 80 mmscf/d - 90 mmscf/d
(including Protected Gas) will be required in 2007. Orca Exploration commissioned Petrofac Engi-
neering Limited to undertake a capacity re-rating and debottlenecking review of the gas processing
plant to assess how to meet the immediate and future projected demand. As a consequence of
this work, Songas appointed Bureau Veritas to re-rate the capacity of the plant. Whilst work is
ongoing and this is still to be agreed with the insurers, the indications are that the gas process-
ing plant could be run at approximately 85 mmscf/d for a short period of time compared with its
present nameplate capacity of 70 mmscf/d.
The Company also entered into discussions with Songas and TANESCO for the installation of a third
and fourth gas processing train. This would lead to in excess of 140 mmscf/d of gas processing
capacity. A Memorandum of Understanding (‘MOU’) was signed with Songas, TANESCO and the
Ministry of Energy and Minerals in December 2006 identifying the key issues that needed to be
addressed to enable the expansion to take place. Under the terms of the MOU, Orca Exploration
will continue to pay 17.5% of the achieved sales price of gas and part of this will be allocated to
Songas to compensate for their investment in the trains. This is still the subject of an application
by Songas to the Electricity, Water, Utilities Regulatory Authority (‘EWURA’) and is also subject to
the agreements of gas terms and prices with TANESCO to justify the expansion.
The 232 kilometer pipeline system to Dar es Salaam is limited by the 12” 25 kilometer offshore
line at an estimated 105 mmscf/d, though this is still to be tested. It is forecast that compression
or a new offshore line will be required during the latter half of 2008 to meet peak loads. Work will
be undertaken in 2007 to assess the most cost effective means of achieving the forecast peak rates.
At Dar es Salaam, Orca Exploration continued to expand its distribution system during 2006.
The 4 kilometer extension to Lakhani Industries Limited Textile and Murzah Oil Mills Limited was
completed during Q1 2006 and a 3 kilometer extension was constructed to connect Serengeti
Breweries and East Coast Oils and Fats Limited. The Company has committed to increase the
capacity of the existing infrastructure system in the first half of 2007 by installing an additional
pressure reduction station and constructing a further 8 kilometers of pipeline. This is required to
meet the peak demand of the Company’s existing customers between June and September 2007.
In addition, the Company forecasts that a further 8 kilometer extension to the Mwenge area will
be installed during Q4 2007 adding an additional 1-2 mmscf/d of load. The forecast cost of the
capex required in 2007 for the industrial expansion is US$4.5 million.
During 2006, the Company connected 68 MWs of emergency power generation at a cost of
US$0.8 million.
Markets
Current Industrial Sales
The Company continued to expand sales to the industrial sector during 2006. Industrial gas sales
in 2006 averaged 4.0 mmscf/d (2005: 2.1 mmscf/d) and peaked at 5.7 mmscf/d in August 2006
when the textile mills were operating at a higher capacity. As at 31 December 2006, the Company
was selling gas to 13 customers (2005: 7) in 15 locations. The largest customers are Kioo Limited,
Tanzania Breweries Limited, Karibu Textile Mills Ltd, Tanzania China Friendship Textile Co Ltd and
Nida Textile Mills Ltd. In the peak summer months in 2007, the existing industrial customers are
expected to take approximately 6.5 mmscf/d. By the end of 2007, it is forecast that an addi-
tional average load of approximately 1-2 mmscf/d will be added primarily through the extension
of the existing system to the Mwenge area, 8 kilometers north of the Ubungo Power Plant. As a
consequence, the Company is assuming that the average load during the year will be
approximately 6.0 mmscf/d allowing for seasonal variations.
The price achieved for the industrial sales averaged US$8.22/mcf during 2006 (2005:
US$7.07/mcf). The Company sells the gas to the industrial sector at a 20% – 25% discount to the
price of Heavy Fuel Oil (“HFO”) in Dar es Salaam. The price of HFO in Dar is linked to the world
prices for oil with a slight time lag.
Current power sales
During the year, 3.4 bcf of Additional Gas was sold to the power sector at an average of 9.2
mmscf/d.
The Company continued to sell Additional Gas to Songas under an Interim Agreement that states
that 19.5% of all the gas that is supplied to the six turbines at the Ubungo Power Plant is consid-
ered Additional Gas. This percentage represents the volume of gas required for UGT 6 in proportion
to the total consumption of the six turbines. This led to 2.8 bcf being sold at an average of 7.6
mmscf/d (maximum load 9.2 mmscf/d).
In October 2006, the Company commenced sales to the Aggreko 48 MW emergency power plant
(44 units at 1.1 MW each). Under the terms of the power purchase agreement with TANESCO,
Aggreko has to be able to supply 40 MWs. The maximum load for 40 MWs is approximately 11.0
mmscf/d. By 31 December 2006, the Company had sold 0.6 bcf to these units. The average daily
consumption of these units in November and December 2006 was 9.0 mmscf/d.
During 2006, the price of Additional Gas to the power sector averaged US$1.90/mcf (2005:
US$1.66/mcf).
Under the terms of the Interim Agreement, the sales to the Ubungo Power Plant have a maximum
price of US$2.32/mmbtu (US$2.14/mcf) and a minimum of US$0.67/mmbtu (US$0.62/mcf)
depending on the availability of the units at the plant. As a consequence of the failure of certain
turbines during 2006, the price achieved for these sales averaged US$1.85/mcf.
Under the terms of the two year gas supply contract that was signed in December 2006, the
price of Additional Gas to the Aggreko units is set at US$2.22/mcf and this will increase with
consumer price inflation in 2008. There are no liabilities or take or pay provisions in the contract.
Top u
Orca Exploration employees
regularly maintain producing wells
offshore Songo Songo Island.
Bottom u
Orca Exploration's pressure
reduction station feeds Additional
Gas to the company's industrial
customers in the
Dar es Salaam area.
2006 ANNUAL REPORT
20 OPERATIONS REVIEW
Above u
The Aggreko emergency
generation in Dar es Salaam
consumes Additional Gas supplied
by Orca Exploration.
Prospective Markets
Current demand exceeds the reserves as assessed by McDaniel and accordingly new gas reserves
will be needed to satisfy market demand.
In the 2005 annual report, the Company set a target to sell 12.6 mmscf/d of Additional Gas in
2006. The actual results exceeded this target with an average of 13.3 mmscf/d.
The following summarises forecast sales volumes for 2007 and 2008.
MMscf/d
Industrial
Power
Compressed Natural Gas
2007 Target
2008 Target
6.0
(Note 1)
8.0 - 9.0
15.0 - 17.0
30.0 - 39.0
–
1.0
21.0 - 23.0
39.0 - 49.0
Note 1: This is dependent on the signing of the current power contracts under discussion that may or may not
materialise, average hydrology in Tanzania and the installation of two new gas processing trains.
Prospective industrial sales
The Company’s target is to increase industrial gas sales from an average of 4.0 mmscf/d in 2006
to an average of 6.0 mmscf/d during 2007. The current customers are forecast to consume in
excess of 5.0 mmscf/d during 2007 with this increasing to 6.0 mmscf/d in 2008 as a result of the
expansion of their operations. In addition, new customers will be hooked up as a result of the
US$4.5 million, 16 kilometer distribution expansion during 2007. This is expected to add an
average of 1.0 mmscf/d in 2007 and approximately 2.0 - 3.0 mmscf/d in 2008.
The Company is also looking at the possibility of applying for a generation licence in order to
supply electricity directly to large industrial customers located in Dar es Salaam.
There are a number of industries located outside of Dar es Salaam that are commercially
accessible by pipelines in a US$40/barrel environment. Tanga is 300 kilometers north of Dar es
Salaam and only 60 kilometers from the Kenya border. It has approximately 10 mmscf/d of peak
gas demand, including the second largest cement plant in Tanzania. 180 kilometers west of Dar
es Salaam is Morogoro where there are several industries with a forecast peak demand of 7-9
mmscf/d. The Company will assess whether it is more viable to construct pipelines to these
customers or transport Compressed Natural Gas to them.
If there are sufficient gas reserves and infrastructure capacity, there is the potential for 20 - 30
mmscf/d to be sold to the industrial sector in Tanzania.
2006 ANNUAL REPORT
ops1
ops2
ops3
ops3
Cumulative production
from each well
Protected Gas Volumes
22 OPERATIONS REVIEW
14000
f
c
s
m
M
12000
10000
8000
6000
4000
2000
0
SS-3
SS-4
SS-5
SS-7
SS-9
2004
2005
2006
Gross Additional Gas reserves
on a life of licence basis
2007 build up of
gas fired generation
500
400
Probable
Proven
Prospective power sales
350
300
250
As at 31 December 2006, Tanzania had approximately 911 MWs of installed and operational
electrical power generation as follows:
300
Feedstock
f
c
b
Power Plant
Hydro:
200
100
0
Gas fired:
200
s
W
M
Principal
water source
150
Mtera dam
Mtera dam
100
Run of river
Run of river
Run of river
50
Run of river
Kidatu
Mtera
Hale
Pangani Falls
Kihansi
Others
Installed
capacity
MW
204
80
21
68
180
8
561
190
48
Q
3
2
0
0
7
250
12
not sure
Average daily production
per month in 2006
d
/
f
c
s
M
M
56
54
52
50
48
46
44
42
40
Ubungo Power Plant (units 1-6)
0
2004
2005
Aggreko
2006
Mtwara
3
1
-
D
e
c
-
0
6
Q
1
2
0
0
7
Q
2
2
0
0
7
Q
4
2
0
0
7
J
a
n
F
e
b
M
a
r
c
h
A
p
r
i
l
M
a
y
J
u
n
e
J
u
l
y
A
u
g
S
e
p
O
c
t
N
o
v
D
e
c
Month
md2
2006 Additional Gas industrial and power sales volumes
Wazo Hill
Ubungo Power Plant
Other thermal:
Total
Independent Power of
Tanzania Limited (“IPTL”)
Ubungo 42 MW
Aggreko 48 MW
Dowans 20 MW
100
911
md4
Top u
Orca employees installing a new
power cable on the Songo Songo
Gas Processing Plant.
2006 Additional Gas Prices
Power
10
Industrial
Bottom u
The Dowans power generation
plant was under construction
in early 2007.
The majority of Tanzania’s installed generation is hydro, though over the past three years there has
Dowans 60 MW
Wartsila 100 MW
been a rebalancing of the portfolio. The only major water storage is at the Mtera reservoir that
Dowans 40 MW
supplies the 80 MW Mtera and the 204 MW Kidatu hydro plants. 277 MWs of the hydro is primarily
run of river and operational on average for only 4-5 months a year. Accordingly, the level of the
Mtera reservoir is integral to the generation of 284 MWs of electricity.
Mtera Water Levels 1990-2007
)
s
r
e
t
e
m
(
l
e
v
e
l
a
e
s
e
v
o
b
a
l
e
v
e
L
700
699
698
697
696
695
694
693
692
691
690
689
688
687
2007
4
0
0
2
2 0 0 5
2006
2007
2006
2005
2004
2003
2002
2001
2000
1999
1998
1997
1996
1995
1994
1993
1992
1991
1990
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Until December 2006, the lower than average rainfalls had led to the collapse of the output from
the hydro stations and the country was reliant on thermal generation. The level of the Mtera dam
fell to 687 meters above sea level and was shut in. The short rains were significant in January
2007 and led to the Mtera dam rising to its maximum level of 698 meters above sea level and
2005
2006
J
a
n
F
e
b
M
a
r
A
p
r
M
a
y
J
u
n
J
u
l
A
u
g
S
e
p
O
c
t
N
o
v
D
e
c
at the fastest rate since 2001.
md2
md3
2006 Additional Gas industrial and power sales volumes
2006 Additional Gas industrial sales
f
c
s
M
M
200
180
160
140
120
100
80
60
40
20
0
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Industrial
Power
Nampak
Nida
ECO&F
Bora
Murzah III
Murzah II
Murzah I
Lakhani
Mukwano
TCC
Chinese
ALAF
TBL
Kioo
Karibu
700
699
698
697
696
695
694
693
692
691
690
689
688
687
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
f
c
B
16
14
12
10
8
6
4
2
0
md1
Revenue
0
0
0
$
S
U
16,000
14,000
12,000
10,000
8,000
6,000
4,000
2,000
0
f
c
s
M
M
700
600
500
400
300
200
100
0
700
600
500
400
300
200
100
0
narrower copy of below
J
a
n
F
e
b
M
a
r
A
p
r
M
a
y
J
u
n
J
u
l
A
u
g
S
e
p
O
c
t
N
o
v
D
e
c
Industrial
Power
f
c
m
/
$
S
U
9
8
7
6
5
4
3
2
1
0
d
/
f
c
s
M
M
56
54
52
50
48
46
44
42
40
J
a
n
F
e
b
M
a
r
c
h
A
p
r
i
l
M
a
y
J
u
n
e
J
u
l
y
A
u
g
S
e
p
O
c
t
N
o
v
D
e
c
Month
md2
2006 Additional Gas industrial and power sales volumes
700
600
500
400
300
200
100
0
narrower copy of below
J
a
n
F
e
b
M
a
r
A
p
r
M
a
y
J
u
n
J
u
l
A
u
g
S
e
p
O
c
t
N
o
v
D
e
c
Industrial
Power
ops1
Cumulative production
from each well
f
c
B
16
14
12
10
8
6
4
2
0
md1
Revenue
0
0
0
$
S
U
16,000
14,000
12,000
10,000
8,000
6,000
4,000
2,000
0
f
c
s
M
M
700
600
500
400
300
200
100
0
f
c
m
/
$
S
U
10
9
8
7
6
5
4
3
2
1
0
It is now forecast that TANESCO will be able to run the Mtera and Kidatu hydro plants throughout
2007 at high utilisation rates (between 55% and 75%). This is welcome news for Tanzania and
will alleviate some of the financial pressures on TANESCO.
The following sets out the generation that TANESCO has indicated will be installed or decommis-
sioned in Tanzania during 2007 and 2008:
ops2
Feedstock
Estimated
commencement/
termination date
ops3
Term
Years
Gross Additional Gas reserves
on a life of licence basis
Installed generation at 31 December 2006
Protected Gas Volumes
Gas fired:
14000
12000
10000
Dowans
Dowans
Dowans
Wärtsilä
Wärtsilä
Aggreko
Coal fired:
8000
Kiwira
Q1 2007
500
Q3 2007
Q4 2007
Q4 2007
400
Q2 – Q4 2008
Q4 2008
2
2-20
Probable
2-20
Proven
20
2-20
2008/2009
300
20
f
c
s
m
M
Installed generation at 31 December 2008
f
c
b
ops3
2007 build up of
gas fired generation
not sure
Average daily production
per month in 2006
Installed
capacity
MW
911
20
60
40
100
45
(48)
217
350
300
250
50-200
200
1,178 – 1,328
s
W
M
6000
In the 2005 annual report, the Company forecast that 245 MWs of permanent new gas fired
150
100
50
0
3
1
-
D
e
c
-
0
6
Q
1
2
0
0
7
Q
2
2
0
0
7
Q
3
2
0
0
7
Q
4
2
0
0
7
Ubungo 42 MW
Aggreko 48 MW
Dowans 20 MW
Dowans 60 MW
Wartsila 100 MW
Dowans 40 MW
2007
2006
2005
2004
2003
2002
2001
2000
1999
1998
2006 ANNUAL REPORT
1997
1996
1995
1994
1993
1992
1991
1990
4000
2000
0
SS-3
SS-4
SS-5
SS-7
SS-9
generation would be commissioned by the end of 2007. This was assuming that there would be
200
two new permanent plants from Wärtsilä (100 MWs and 45 MWs) and that the 100 MW IPTL plant
would be converted to consume gas. It is now forecast that there will be 268 MWs of new gas
fired generation installed by 31 December 2007 and that IPTL will continue to use HFO.
100
There is still uncertainty as to the length of time that the 120 MWs of emergency power generation
operated by Dowans will remain in country. TANESCO has indicated that some of the units may
remain in Tanzania on a permanent basis.
TANESCO is keen to diversify their generation mix and accordingly it is forecast that up to 200
0
2004
2005
2006
2004
2005
2006
MW of coal fired generation will be installed during the next two/three years.
Wazo Hill
The maximum gas consumption of the 310 MWs of gas fired generation that are forecast to be
in place and supplied with Additional Gas at the end of 2007 is estimated at 68 mmscf/d. Whilst
Ubungo Power Plant
the installation of gas fired generation is ahead of the Company’s forecasts, there is considerable
difficulty in assessing the utilisation of these units during 2007 to 2010 given the improved
hydrology particularly with respect to the Mtera dam and the potential for some coal fired
md4
generation at Kiwira. During the rainy season (approximately 4-5 months of the year), there could
2006 Additional Gas Prices
tional Gas being sold to the power sector in 2007. However, in the first fourteen weeks of 2007,
be sufficient hydro and gas fired generation on Protected Gas to see only small amounts of Addi-
Power
Industrial
an average of approximately 15 mmscf/d was sold to the power sector. This average is expected
to continue, or slightly increase for the remainder of 2007, though there will be some months
when the ‘run of river’ hydros will be operating at a high rate and there will be limited need to
utilise the gas fired generation.
2007
4
0
0
2
2 0 0 5
2006
)
s
r
e
t
e
m
(
l
e
v
e
l
a
e
s
e
v
o
b
a
l
e
v
e
L
700
699
698
697
696
695
694
693
692
691
690
689
688
687
f
c
s
M
M
200
180
160
140
120
100
80
60
40
20
0
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
2005
2006
J
a
n
F
e
b
M
a
r
A
p
r
M
a
y
J
u
n
J
u
l
A
u
g
S
e
p
O
c
t
N
o
v
D
e
c
md2
md3
2006 Additional Gas industrial and power sales volumes
2006 Additional Gas industrial sales
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Industrial
Power
Nampak
Nida
ECO&F
Bora
Murzah III
Murzah II
Murzah I
Lakhani
Mukwano
TCC
Chinese
ALAF
TBL
Kioo
Karibu
700
699
698
697
696
695
694
693
692
691
690
689
688
687
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
annual 2006.qxp 5/3/07 10:37 PM Page 24
24 OPERATIONS REVIEW
Longer term (after 2010) it is forecast that demand will have sufficiently increased whereby gas
fired generation will be base loaded with utilisation rates of circa 70%. Tanzania is expected to
require 50 MWs of new generation per annum to meet demand in country.
Export of power
The reliance on hydro in Kenya and the relatively high cost of alternative oil fired generation, has
increased the likelihood that Dar es Salaam will become the thermal hub for East Africa provided
there are sufficient gas reserves.
Kenya currently has approximately 1,140 MWs of permanent generation (671 MWs hydro, 343
MWs thermal and 126 MWs geothermal) and 100 MWs of emergency generation. Demand is
estimated to be increasing at 150 MWs per annum. At current oil prices, Tanzania could export
electricity at a significantly lower cost than Kenya could generate electricity with oil fired units.
Compressed Natural Gas (“CNG”)
The use of CNG is a proven technology that is widely used around the world including India and
China. To examine the potential to use CNG in Tanzania, the Company and TPDC visited China in
2006 to see how CNG markets have been established and operated. In China, CNG is also used
to supply domestic demand through the establishment of local distribution networks connected
to CNG storage tanks.
In 2007, the Company is looking to accelerate the development of the CNG market. In particular,
the Company targets to:
a
a
Convert one of the industrial customers’ distribution fleet to CNG;
Plan for the selling of CNG to customers in Dar es Salaam who are not located on the existing
pipeline system. This will include the larger hotels as well as industrial customers; and
a
Evaluate whether CNG could be transported in larger volumes to other industrial centres
including Tanga and Morogoro.
The potential CNG market in Tanzania is estimated to be approximately 10 - 15 mmscf/d.
The Company targets to have a market of 1 mmscf/d during 2008.
Opposite t
Crews unload steel casing at
Songo Songo Island for the new
SS-10 well. Orca expects to complete this
development well by the end of Q2 2007.
Management’s Discussion & Analysis
2006 ANNUAL REPORT
26
Management’s Discussion & Analysis
FORWARD LOOKING STATEMENTS
THIS MDA OF FINANCIAL CONDITIONS AND RESULTS OF OPERATIONS SHOULD BE READ IN CONJUNCTION WITH THE
COMPANY’S FINANCIAL STATEMENTS AND NOTES THERETO FOR THE YEAR ENDED 31 DECEMBER 2006. THIS MDA IS BASED
ON THE INFORMATION AVAILABLE ON 30 APRIL 2007. IT CONTAINS CERTAIN FORWARD-LOOKING STATEMENTS THAT INVOLVE
SUBSTANTIAL KNOWN AND UNKNOWN RISKS AND UNCERTAINTIES, CERTAIN OF WHICH ARE BEYOND ORCA EXPLORATION
GROUP INC’S (“ORCA EXPLORATION” OR “THE COMPANY” – FORMERLY EASTCOAST ENERGY CORPORATION) CONTROL,
INCLUDING THE IMPACT OF GENERAL ECONOMIC CONDITIONS IN THE AREAS IN WHICH THE COMPANY 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 AUTHOR-
ITIES. IN ADDITION THERE ARE RISKS AND UNCERTAINTIES ASSOCIATED WITH GAS OPERATIONS. THEREFORE, ORCA
EXPLORATION’S ACTUAL RESULTS, PERFORMANCE OR ACHIEVEMENT COULD DIFFER MATERIALLY FROM THOSE EXPRESSED, 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.
THE COMPANY EVALUATES ITS PERFORMANCE BASED ON EARNINGS AND FUNDS FLOW. FUNDS FLOW FROM OPERATING
ACTIVITIES IS A NON-GAAP (GENERALLY ACCEPTED ACCOUNTING PRINCIPLES) TERM THAT REPRESENTS EARNINGS BEFORE
DEPLETION, DEPRECIATION AND STOCK-BASED COMPENSATION. IT IS A KEY MEASURE AS IT DEMONSTRATES COMPANY’S
ABILITY TO GENERATE CASH NECESSARY TO ACHIEVE GROWTH THROUGH CAPITAL INVESTMENTS. ORCA EXPLORATION ALSO
ASSESSES ITS PERFORMANCE UTILIZING OPERATING NETBACKS. OPERATING NETBACKS REPRESENT THE PROFIT MARGIN
ASSOCIATED WITH THE PRODUCTION AND SALE OF ADDITIONAL GAS AND IS CALCULATED AS REVENUES LESS RINGMAIN
TARIFF, GOVERNMENT PARASTATAL’S REVENUE SHARE, OPERATING AND DISTRIBUTION COSTS FOR ONE THOUSAND
STANDARD CUBIC FEET OF ADDITIONAL GAS. THESE NON-GAAP MEASURES ARE NOT STANDARDISED AND THEREFORE MAY
NOT BE COMPARABLE TO SIMILAR MEASUREMENTS OF OTHER ENTITIES.
ADDITIONAL INFORMATION REGARDING ORCA EXPLORATION GROUP INC. IS AVAILABLE UNDER THE COMPANY’S PROFILE ON
SEDAR AT www.sedar.com.
Background
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 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 utilises the Protected Gas (maximum 45.1 mmscf/d) as feedstock for its gas turbine
electricity generators at Ubungo, for onward sale to the Wazo Hill Cement Plant and for electrifi-
cation of some villages along the pipeline route. Orca Exploration receives no revenue for the
Protected Gas delivered to Songas and operates the field and gas processing plant on a ‘no gain
no loss’ basis.
Orca Exploration has the right to produce and market all gas in the Songo Songo field in excess
of the Protected Gas requirements (“Additional Gas”).
Principal terms of the 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 licences 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 judgement such sales would jeopardise the supply of Protected Gas. Any Addi-
tional Gas contracts entered into prior to 31 July 2009 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 (e) below).
Songas has written to Orca Exploration confirming that, subject to certain conditions, security
will not be required for the supply of Additional Gas to the Ubungo Power Plant, for the
supply of up to 15 mmscf/d for a period of five years for additional power generation and
up to 10 mmscf/d for the industrial sector. As the current emergency power generation
operating in the country could take demand above 15 mmscf/d for power generation,
Songas has confirmed that the Company may sell 17 mmscf/d for power generation over
the next two years without the need for security.
The Company is looking to agree a security mechanism with Songas that provides clear
guidance as to how Songas will operate their rights to security. It is anticipated that, under
certain circumstances, the Company and TPDC may have to allocate a proportion of the
Additional Gas revenues to an escrow account, in the event of a Protected Gas insufficiency.
It is forecast that the security mechanism will be finalised by the end of Q2 2007.
(d) By 31 July 2009, the Government of Tanzania (“GoT”) can request Orca Exploration to sell
100 bcf of Additional Gas for the generation of electricity over a period of 20 years from
the start of its commercial use, subject to a maximum of 6 bcf per annum or 20 mmscf/d
(“Reserved Gas”). In the event that the GoT does not nominate by 31 July 2009, or
consumption of the Reserved Gas has not commenced within three years of the nomina-
tion date, then the reservation shall terminate. Where Reserved Gas is utilised, TPDC and the
Company will receive a price that is no greater than 75% of the market price of the lowest
cost alternative fuel delivered at the facility to receive Reserved Gas or the price of the
lowest cost alternative fuel at Ubungo.
(e) “Insufficiency” occurs if there is insufficient gas from the Discovery Blocks to supply the
Protected Gas requirements 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
2006 ANNUAL REPORT
28 MANAGEMENT’S DISCUSSION & ANALYSIS
replacing the Indemnified Volume (as defined in (f) below) at the Protected Gas price with
natural gas from other sources; or by paying money damages equal to the difference
between: (a) the market price for a quantity of alternative fuel that is appropriate for the
five gas turbine electricity generators at Ubungo without significant modification together
with the costs of any modification; and (b) the sum of the price for such volume of Protected
Gas (at US$0.55/mmbtu) and the amount of transportation revenues previously credited
by Songas to the electricity utility, TANESCO, for the gas volumes.
(f)
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
(where the fifth turbine has been installed, but has not been operational for three years an
imputed amount of annual gas consumption for the fifth turbine is incorporated) 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.
Access and development of infrastructure
(g)
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.
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
(h) 75% of the gross revenues less 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 all 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; 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
Ministry of Energy and Minerals (“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 Ministry of Energy and Minerals 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
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 develop-
ment by contributing 20% of the costs of the future wells including SS-10 in return for a 20%
increase in the profit share for the production emanating from these wells. The implications
and workings of the ‘back in’ are still to be discussed in detail with TPDC. For the purpose
of the reserves certification, it has been assumed that they will ‘back in’ for 20% and this
is reflected in the Company’s net reserve position. However, the financial statements have
not taken account of any re-imbursement for the SS-10 capital expenditure, pending the
finalisation of the terms of the ‘back in’.
(i)
The price payable to Songas for the general processing and transportation of the gas is
17.5% of the price of gas delivered to a third party less any direct taxes payable by the
customer that are included in the gas price less any tariffs paid for non-Songas owned distri-
bution facilities (“Songas Outlet Price”).
In September 2001, the GoT made a formal request to the World Bank for funds to increase
the diameter of the onshore pipeline from 12 inches to 16 inches at a projected incremental
cost of US$3.5 million. The World Bank agreed to finance this increase and accordingly the
pipeline capacity was increased from circa 65 mmscf/d to 105 mmscf/d. The tariff that is
payable to GoT for this incremental capacity has yet to be formally agreed, but the Company
expects it to be 17.5% of the Songas Outlet Price.
17.5% of the Songas Outlet Price is also the rate that is expected to apply to cover the
financing and operating costs of the third and fourth train which will increase the gas
processing capacity to 140 mmscf/d.
(j)
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.
(k)
Profits on sales from the Proven Section (“Profit Gas”) are shared between TPDC and the
Company, the proportion of which is dependent on the average daily volumes of Additional
Gas sold or cumulative production.
The Company receives a higher share of the Net Revenues after cost recovery, the higher
the cumulative production or the average daily sales, whichever is higher. The profit 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
mmscf/d
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 share
increases to 55%.
Where TPDC elects to participate in a development program, their profit share percentage
increases by the Specified Proportion (for that development program) with a corresponding
decrease in the Company’s percentage share of Profit Gas.
2006 ANNUAL REPORT
30 MANAGEMENT’S DISCUSSION & ANALYSIS
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.
(l)
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 all 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 share when costs have been recovered with an annual return of 35%
plus PPI return. The PSA is, therefore, structured to encourage the Company to develop the
market and the gas fields in the knowledge that the profit share can increase with larger
daily gas sales and that the costs will be recovered with a 25% plus PPI annual return before
Additional Profits Tax becomes payable. Additional Profits Tax can have a significant negative
impact on the project economics if only limited capital expenditure is incurred.
Operatorship
(m) 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, procure-
ment, capital improvements, contract maintenance, maintain books and records, prepare
reports, maintain permits, handle waste, liaise with GoT and take all necessary safe, health
and environmental precautions all in accordance with good oilfield practices. In return, the
Company is paid or reimbursed by Songas so that the Company neither benefits nor suffers
a loss as a result of its performance.
(n)
In the event of loss arising from Songas’ failure to perform and the loss is not fully compen-
sated by Songas, Orca Exploration, CDC or insurance coverage, then Orca Exploration is liable
to a performance and operation guarantee of US$2,500,000 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
Incorporated
Orca Exploration Group Inc. (formerly EastCoast Energy Corporation)
British Virgin Islands
PAE PanAfrican Energy Corporation
PanAfrican Energy Tanzania Limited
2006 Results
Revenue and Operating Costs
Mauritius
Jersey
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. During 2006, revenue
less cost recovery was allocated 75% to TPDC and 25% to Orca Exploration (“Profit Gas”).
ops1
ops2
ops3
ops3
Cumulative production
from each well
Protected Gas Volumes
Gross Additional Gas reserves
on a life of licence basis
2007 build up of
gas fired generation
not sure
Average daily production
per month in 2006
f
c
B
16
14
12
10
8
6
4
2
0
SS-3
SS-4
SS-5
SS-7
SS-9
2004
2005
2006
2004
2005
2006
J
a
n
F
e
b
A
p
r
i
l
M
a
y
J
u
n
e
M
a
r
c
h
J
u
l
y
A
u
g
S
e
p
O
c
t
N
o
v
D
e
c
Month
Wazo Hill
Ubungo Power Plant
md1
Revenue
md4
2006 Additional Gas Prices
Power
Industrial
f
c
m
/
$
S
U
10
9
8
7
6
5
4
3
2
1
0
2005
2006
J
a
n
F
e
b
M
a
r
A
p
r
M
a
y
J
u
n
J
u
l
A
u
g
S
e
p
O
c
t
N
o
v
D
e
c
f
c
s
m
M
14000
12000
10000
8000
6000
4000
2000
0
d
/
f
c
s
M
M
56
54
52
50
48
46
44
42
40
200
s
W
M
150
350
300
250
100
50
0
Q
1
2
0
0
7
Q
2
2
0
0
7
Q
3
2
0
0
7
Q
4
2
0
0
7
3
1
-
D
e
c
-
0
6
Ubungo 42 MW
Aggreko 48 MW
Dowans 20 MW
Dowans 60 MW
Wartsila 100 MW
Dowans 40 MW
2007
2006
2005
2004
2003
2002
2001
2000
1999
1998
1997
1996
1995
1994
1993
1992
1991
1990
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Probable
Proven
300
f
c
b
500
400
200
100
0
2007
4
0
0
2
2 0 0 5
2006
)
s
r
e
t
e
m
(
l
e
v
e
l
a
e
s
e
v
o
b
a
l
e
v
e
L
700
699
698
697
696
695
694
693
692
691
690
689
688
687
f
c
s
M
M
200
180
160
140
120
100
80
60
40
20
0
700
699
698
697
696
695
694
693
692
691
690
689
688
687
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
(US$’000)
Industrial sector
Power sector
Gross sales revenue
Processing and transportation tariff
TPDC share of revenue
Operating revenue
Additional Profits Tax
Gross-up for income tax
Revenue
2006
12,048
6,397
18,445
(2,889)
(2,918)
12,638
(183)
1,373
13,828
2005
5,494
2,768
8,262
(1,308)
(1,302)
5,652
(80)
187
5,759
f
c
s
M
M
700
600
500
400
300
200
100
0
md2
md3
2006 Additional Gas industrial and power sales volumes
2006 Additional Gas industrial sales
2006 ANNUAL REPORT
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Industrial
Power
Nampak
Nida
ECO&F
Bora
Murzah III
Murzah II
Murzah I
Lakhani
Mukwano
TCC
Chinese
ALAF
TBL
Kioo
Karibu
Orca Exploration had recoverable costs throughout the year and accordingly was allocated 81.25%
of the Net Revenues as follows:
(US$’000 except production and per mcf data)
Gross sales volume (mmcf):
Industrial sector
Power sector
Total volumes
md2
2006
1,466
3,371
4,837
Average sales price (US$/mcf):
2006 Additional Gas industrial and power sales volumes
Industrial sector
Power sector
Average price
Gross sales revenue
Gross tariff for processing plant
and pipeline infrastructure
Gross revenue after tariff
Analysed as to:
Company Cost Gas
Company Profit Gas
700
600
500
400
Company operating revenue (see Note 1 below)
TPDC Profit Gas
300
narrower copy of below
Production and distribution expenses:
Ring main distribution pipeline costs
Share of well maintenance costs
Other field and operating costs
Production and distribution expenses
Depletion
200
100
0
8.22
1.90
3.81
18,445
2,889
15,556
11,665
973
12,638
2,918
15,556
336
213
244
793
2,027
2005
777
1,672
2,449
7.07
1.66
3.37
8,262
1,308
6,954
5,216
436
5,652
1,302
6,954
187
108
200
495
818
Note 1
M
a
r
The Company’s total revenues for the year amounted to US$13,828,000 after adjusting the Company’s operating
S
e
p
D
e
c
F
e
b
A
p
r
N
o
v
J
u
n
J
a
n
O
c
t
A
u
g
J
u
l
M
a
y
16,000
14,000
12,000
10,000
8,000
6,000
4,000
0
0
0
$
S
U
revenue of US$12,638,000 by:
Industrial
Power
i)
US$1,373,000 for income tax. The Company is liable for income tax in Tanzania but the income tax is
2,000
recoverable out of TPDC’s Profit Gas when the tax is payable. To account for this, revenues are grossed up
for the current income tax;
ii)
US$183,000 for the deferred effect of Additional Profits Tax. This tax is netted off revenue as a royalty.
0
Revenue per the income statements may be reconciled to the operating revenue as follows:
ops1
ops2
Cumulative production
from each well
Protected Gas Volumes
Gross Additional Gas reserves
on a life of licence basis
2007 build up of
2000
gas fired generation
Average daily production
per month in 2006
md2
2006 Additional Gas industrial and power sales volumes
SS-3
SS-4
SS-5
SS-7
SS-9
Probable
Proven
Wazo Hill
Ubungo Power Plant
0
2004
2005
2006
0
2004
2005
2006
J
a
n
F
e
b
M
a
r
c
h
A
p
r
i
l
M
a
y
J
u
n
e
J
u
l
y
A
u
g
S
e
p
O
c
t
N
o
v
D
e
c
Month
ops1
ops2
ops3
ops3
Cumulative production
from each well
Protected Gas Volumes
Gross Additional Gas reserves
on a life of licence basis
2007 build up of
gas fired generation
not sure
Average daily production
per month in 2006
16
14
12
10
8
6
2
0
4
ops3
f
c
B
500
400
100
0
300
md1
f
c
b
Revenue
0
0
0
$
S
U
14,000
12,000
10,000
8,000
6,000
4,000
2,000
14000
12000
10000
f
c
s
m
M
8000
6000
4000
ops3
350
300
250
100
50
0
d
/
f
c
s
M
M
56
54
52
50
48
46
44
42
40
200
s
W
M
150
350
300
250
100
50
0
3
1
-
D
e
c
-
0
6
Q
1
2
0
0
7
Q
2
2
0
0
7
Q
3
2
0
0
7
Q
4
2
0
0
7
Ubungo 42 MW
Aggreko 48 MW
Dowans 20 MW
Dowans 60 MW
Wartsila 100 MW
Dowans 40 MW
Probable
Proven
500
400
300
f
c
b
200
not sure
100
56
54
52
50
48
46
44
42
40
d
/
f
c
s
M
M
700
699
698
697
696
695
694
693
692
691
690
689
688
687
)
s
r
e
t
e
m
(
l
e
v
e
l
a
e
s
e
v
o
b
a
l
e
v
e
L
2007
J
a
n
F
e
b
A
p
r
i
l
M
a
y
J
u
n
e
M
a
r
c
h
J
u
l
y
A
u
g
S
e
p
O
c
t
N
o
v
D
e
c
Month
2 0 0 5
4
0
0
2
2006
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
700
600
500
400
300
100
0
f
c
m
/
$
S
U
10
9
8
7
6
5
4
3
2
1
0
f
c
B
16
14
12
10
8
6
4
2
0
md1
Revenue
0
0
0
$
S
U
16,000
14,000
12,000
10,000
8,000
6,000
4,000
2,000
0
md2
f
c
s
M
M
700
600
500
400
300
200
100
0
f
c
s
m
M
14000
12000
10000
8000
6000
4000
2000
0
md4
200
2006 Additional Gas Prices
s
W
M
Power
150
Industrial
16,000
200
10
SS-3
SS-4
SS-5
SS-7
SS-9
200
2004
2005
2006
2004
2005
2006
f
c
m
/
$
S
U
Q
1
2
0
0
7
Q
2
2
0
0
7
Q
3
2
0
0
7
Q
4
2
0
0
7
3
1
-
D
e
c
-
0
6
narrower copy of below
Wazo Hill
Ubungo Power Plant
J
a
n
F
e
b
M
a
r
A
p
r
M
a
y
J
u
n
J
u
l
A
u
g
S
e
p
O
c
t
N
o
v
D
e
c
md4
Industrial
Power
2006 Additional Gas Prices
Power
Industrial
0
32 MANAGEMENT’S DISCUSSION & ANALYSIS
2005
2006
9
8
7
6
5
4
3
2
1
0
Ubungo 42 MW
Aggreko 48 MW
Dowans 20 MW
Dowans 60 MW
Wartsila 100 MW
Dowans 40 MW
J
a
n
F
e
b
M
a
r
A
p
r
M
a
y
J
u
n
J
u
l
A
u
g
S
e
p
O
c
t
N
o
v
D
e
c
)
s
r
e
t
e
m
(
l
e
v
e
l
a
e
s
e
v
o
b
a
l
e
v
e
L
2007
700
699
698
697
md2
696
Volumes
695
2006 Additional Gas industrial and power sales volumes
4
0
0
2
2 0 0 5
2006
694
693
692
700
600
691
500
400
690
689
f
c
688
s
M
M
687
2007
2006
2005
2004
2003
2002
2001
2000
1999
1998
1997
1996
1995
1994
1993
1992
1991
1990
300
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
200
100
0
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
md3
2006 Additional Gas industrial sales
f
c
s
M
M
200
180
160
140
120
100
80
60
40
20
0
2005
2006
J
a
n
F
e
b
M
a
r
A
p
r
M
a
y
J
u
n
J
u
l
A
u
g
S
e
p
O
c
t
N
o
v
D
e
c
Industrial
Power
Industrial
During the year, the Company commenced gas sales to six new industrial customers. By the year-
end, the Company had thirteen industrial customers who were consuming Additional Gas in fifteen
different locations. Industrial sales averaged 4.0 mmscf/d (2005: 2.1 mmscf/d) and peaked at
5.7 mmscf/d in August 2006.
md3
2006 Additional Gas industrial and power sales volumes
2006 Additional Gas industrial sales
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Industrial
Power
f
c
s
M
M
200
180
160
140
120
100
80
60
40
20
0
Power
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Nampak
Nida
ECO&F
Bora
Murzah III
Murzah II
Murzah I
Lakhani
Mukwano
TCC
Chinese
ALAF
TBL
Kioo
Karibu
An Interim Agreement with Songas for the sale of Additional Gas to Ubungo Power Plant was
signed on 1 October 2005. In accordance with the terms of the Interim Agreement, 19.5% of the
gas volumes supplied to the six turbines at the Ubungo Power Plant are considered Additional
Gas. The Interim Agreement expires on 31 May 2007. This will probably be extended for a short
period after which it is forecast that it will be superceded by a long term contract.
During the year, consumption of Additional Gas at the Ubungo Power Plant increased to 2,774
mmscf (an average of 7.6 mmscf/d) against 1,672 mmscf for the period from 8 June to 31
December 2005 (an average of 8.1 mmscf/d). Despite Tanzania facing severe drought in 2006, a
number of the Songas operated generation units at the Ubungo Power Plant were down for repair
or maintenance during the year and this impacted the consumption.
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Nampak
Nida
ECO&F
Bora
Murzah III
Murzah II
Murzah I
Lakhani
Chinese
ALAF
TBL
Kioo
Mukwano
Karibu
700
TCC
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
2007
2006
2005
2004
2003
2002
2001
2000
1999
1998
1997
1996
1995
1994
1993
1992
1991
1990
699
698
697
696
695
694
693
692
691
690
689
688
687
md2
2006 Additional Gas industrial and power sales volumes
700
600
500
400
300
200
100
0
narrower copy of below
J
a
n
F
e
b
M
a
r
A
p
r
M
a
y
J
u
n
J
u
l
A
u
g
S
e
p
O
c
t
N
o
v
D
e
c
Industrial
Power
700
699
698
697
696
695
694
693
692
691
690
689
688
687
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
ops1
ops2
ops3
ops3
Cumulative production
from each well
Protected Gas Volumes
Gross Additional Gas reserves
on a life of licence basis
2007 build up of
gas fired generation
not sure
Average daily production
per month in 2006
16
14
12
10
8
6
4
2
f
c
B
The severe curtailment of the 561 MWs of hydro generation and the subsequent power rationing
led TANESCO and the Government of Tanzania to enter into two contracts with Aggreko Plc
SS-9
(“Aggreko”) and Dowans Tanzania Limited (“Dowans”) for the installation and supply of a
SS-5
SS-4
SS-7
SS-3
0
md2
guaranteed 140 MWs of gas-fired emergency power plants. Aggreko installed 44 units of 1.1 MWs
each (total 48 MWs) and started to generate power in October 2006. By the year end 597 mmscf
2006 Additional Gas industrial and power sales volumes
of Additional Gas had been consumed or an average of 7.9 mmscf/d. None of the Dowans units
were operational before the year end, but 20 MWs commenced gas consumption in January 2007.
The remainder of the units are forecast to be operational during 2007.
700
600
500
400
300
Pricing
Industrial
md1
Revenue
md4
2006 Additional Gas Prices
The price of gas for the industrial sector continued to be at a discount to the price of Heavy Fuel
Power
Industrial
Oil (“HFO”) in Dar es Salaam. This resulted in average gas prices of US$8.22/mcf (2005:
16,000
10
US$7.07/mcf) during the year. The gas price achieved for the industrial sector will fluctuate with
world oil prices and the discount agreed with the customers. The monthly Additional Gas price
14,000
sold to industrial customers in Dar es Salaam in 2006 ranged from US$7.35/mcf in January 2006
to US$8.96/mcf in June 2006. The price in December 2006 was US$7.70/mcf.
12,000
narrower copy of below
Power
The price of gas to the power sector during the year averaged US$1.90/mcf (2005: US$1.66/mcf).
10,000
0
0
0
$
S
U
200
100
0
J
a
n
F
e
b
M
a
r
The Interim Agreement for the sale of Additional Gas to the Ubungo Power Plant provided for
different gas prices, depending on the average availability of the six turbines, from the minimum
8,000
of US$0.67/mbtu (US$0.62/mcf) to the maximum of US$2.32/mbtu (US$2.15/mcf). UGT5 and
UGT6 developed mechanical problems in Q1 and Q3 but were subsequently repaired. Accordingly,
6,000
in accordance with the terms of the Interim Agreement with Songas, the lower availability of the
units led to prices below US$2.32/mmbtu (US$2.15/mcf) being achieved in four months of the year.
4,000
A
p
r
M
a
y
J
u
n
J
u
l
A
u
g
S
e
p
O
c
t
N
o
v
D
e
c
The supply to the Aggreko 48 MWs emergency unit was at US$2.32/mmbtu (US$2.15/mcf) for
Industrial
Power
October and November 2006 and then increased to US$2.39/mmbtu (US$2.22/mcf) from
2,000
December when a two year contract was signed. The price will increase with US consumer price
inflation on 1 January 2008.
0
The Company is still in negotiations with TANESCO, the Ministry of Energy (“MEM”) and EWURA,
2006
2005
f
c
s
m
M
14000
12000
10000
8000
6000
4000
2000
0
2004
2005
2006
2004
2005
2006
Wazo Hill
Ubungo Power Plant
J
a
n
F
e
b
M
a
r
c
h
A
p
r
i
l
M
a
y
J
u
n
e
J
u
l
y
A
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g
S
e
p
O
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t
N
o
v
D
e
c
Month
d
/
f
c
s
M
M
56
54
52
50
48
46
44
42
40
200
s
W
M
150
350
300
250
100
50
0
3
1
-
D
e
c
-
0
6
Q
1
2
0
0
7
Q
2
2
0
0
7
Q
3
2
0
0
7
Q
4
2
0
0
7
Ubungo 42 MW
Aggreko 48 MW
Dowans 20 MW
Dowans 60 MW
Wartsila 100 MW
Dowans 40 MW
2007
2006
2005
2004
2003
2002
2001
2000
1999
1998
1997
1996
1995
1994
1993
1992
1991
1990
Probable
Proven
300
f
c
b
500
400
200
100
0
2007
4
0
0
2
2 0 0 5
2006
md3
2006 Additional Gas industrial sales
)
s
r
e
t
e
m
(
l
e
v
e
l
a
e
s
e
v
o
b
a
l
e
v
e
L
700
699
698
697
696
695
694
693
692
691
690
689
688
687
f
c
s
M
M
200
180
160
140
120
100
80
60
40
20
0
700
699
698
697
696
695
694
693
692
691
690
689
688
687
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
f
c
m
/
$
S
U
9
8
7
6
5
4
3
2
1
0
J
a
n
F
e
b
M
a
r
A
p
r
M
a
y
J
u
n
J
u
l
A
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g
S
e
p
O
c
t
N
o
v
D
e
c
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
the energy utility regulator, over the long term price to be applied to gas sold to power sector.
In December 2006, the Company and TPDC lodged an application (“Application”) with EWURA
for the supply of gas to the power sector. The price of the gas was divided between the wellhead,
distribution and marketing prices. Subsequent to the submission, EWURA notified the Company
that whilst the regulator had jurisdiction over the downstream distribution and marketing prices,
md2
there was some uncertainty as to whether this also applied to the wellhead price. As a result the
Company withdrew the Application and is currently negotiating the price with TANESCO under the
2006 Additional Gas industrial and power sales volumes
guidance of MEM.
f
c
s
M
M
700
600
500
400
300
200
100
0
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
2006 ANNUAL REPORT
Industrial
Power
Nampak
Nida
ECO&F
Bora
Murzah III
Murzah II
Murzah I
Lakhani
Mukwano
TCC
Chinese
ALAF
TBL
Kioo
Karibu
34 MANAGEMENT’S DISCUSSION & ANALYSIS
Tariff
The tariff is calculated as 17.5% of the price of gas at the Songas main pipeline in Dar es Salaam
(“Songas Outlet Price”). In calculating the Songas Outlet Price for the industrial customers,
US$1.30/mcf (2005: US$0.75/mcf) (“Ringmain Tariff”) has been deducted from the achieved
sales price of US$8.22/mcf (2005: US$7.07/mcf) to reflect the gas price that would be achievable
at the Songas main pipeline. The Ringmain Tariff represents the amount that would be required
to compensate a third party distributor of the gas for constructing the connections from the Songas
main pipeline to the industrial customers. No deduction has been made for sales to the Ubungo
Power Plant or the Aggreko emergency units since the gas is not transported through the
Company’s own infrastructure.
Production and distribution expenses
The cost of maintaining the ring main distribution pipeline and pressure reduction station (security,
insurance and personnel) is forecast to be approximately US$0.3 million per annum in its current form.
The well maintenance costs are allocated between Protected and Additional Gas based on the
proportion of their respective sales during the year. The total costs for the maintenance for the year
was US$627,000 (2005: US$437,000) of which US$213,000 (2005: US$108,000) was allocated for
the Additional Gas.
Other field and operating expenses primarily includes the operating costs for the low pressure
distribution pipeline system and the energy regulator’s fee. The regulator’s fee commenced in
November 2006 and is calculated monthly as to 1% of gross revenue to the Company.
Operating netback
The operating netback per mcf before general and administrative costs, overheads, tax and
Additional Profits Tax may be analysed as follows:
(Amounts in US$/mcf)
Gas price – industrial
Gas price – power
Average price for gas
Tariff (after allowance for the Ringmain Tariff)
TPDC profit share
Net selling price
Well maintenance and other operating costs
Ringmain distribution pipeline costs
Operating netback
2006
8.22
1.90
3.81
(0.60)
(0.60)
2.61
(0.08)
(0.08)
2.45
2005
7.07
1.66
3.37
(0.53)
(0.53)
2.31
(0.12)
(0.08)
2.11
Operating netback was slightly higher in 2006 as a result of the increase in average prices to both
the industrial and power customers. In addition the higher sales volumes have reduced the well
maintenance and other operating costs per mcf.
The operating netback continues to benefit from the recovery of 75% of the Net Revenues as
Cost Gas.
General and Administrative Expenses
The general and administrative expenses (“G&A”) may be analysed as follows:
(Figures in US$’000)
Personnel expenses
Stock based compensation (options)
Consultants
Travel & accommodation
Communications
Office
Insurance
Auditing & taxation
Depreciation
Reporting, regulatory and corporate finance
Marketing costs including legal fees
Directors’ fees
Total general and administrative expenses
2006
1,836
418
1,191
435
128
456
146
96
102
157
1,671
88
6,724
2005
846
383
626
181
75
412
166
97
93
173
434
69
3,555
G&A averaged approximately US$0.56 million per month (2005: US$0.29 million). G&A per mcf
fell to US$1.39/mcf (2005: US$1.45/mcf). Whilst a large proportion of G&A is relatively fixed in
nature and therefore declines on an mcf basis as volumes increase, significant costs are being
incurred in the negotiation of the power contracts. This has led to the G&A costs being relatively
high per mcf. It is expected that these will fall as volumes increase and long term power contracts
are signed.
Personnel expenses
During 2006, the Company implemented a bonus scheme that incorporates some stock
appreciation rights for senior management staff that are still employed by the Company as at 31
December 2007. The value of these stock appreciation rights are calculated using the Black-
Scholes option pricing model and have a maximum pay out of Cdn$1.2 million. US$450,000 has
been expensed during the year and the remainder will be expensed in 2007.
There has also been an increase in the average number of staff paid for by the Company to 15
(2005: 12) and in pay rates. One expatriate, who was one of the site managers at the gas
processing plant and whose employment costs were met by Songas in accordance with the terms
of the Operatorship agreement, was assigned new duties in November 2005 to bolster the
Company’s reserves and engineering capability. Consequently, his expatriate package and other
costs were met by the Company for a longer comparable period in 2006.
Stock based compensation (options)
The Company uses the Black-Scholes option pricing model in determining the fair value of options.
The options which were granted on 1 September 2004 vested in full on 1 September 2006.
On 1 September 2006, the Company issued 200,000 options to a new recruit. These options will
vest in three equal installments starting on 1 September 2007. The Company makes a monthly
charge to the income statement of US$28,000 in respect of these options.
2006 ANNUAL REPORT
36 MANAGEMENT’S DISCUSSION & ANALYSIS
Consultancy costs
During the year, the Company revised the pay rates for its consultants to reflect market rates. The
Company also appointed an exploration and business development consultant with effect from 1
September 2006.
Travel and accommodation
The increase in travel and accommodation costs is primarily due to the increase in number of
business trips to Tanzania by Company officials and other marketing and legal professionals for the
negotiation of the power contracts.
Marketing costs including legal fees
These costs include marketing costs, legal, corporate promotion and cost of training Government
officials in accordance with the terms of the PSA. During the year, higher costs were experienced
in negotiating power contracts with Songas, TANESCO and the regulatory authority, EWURA.
Total marketing and legal costs for the year relating to the negotiation including the drafting of a
power tariff application to EWURA amounted to US$1.3 million.
Taxes
Under the terms of the PSA with TPDC, the Company is liable for income tax in Tanzania at a
corporate tax rate. 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 grossing up the
Company’s revenue for the current income tax.
During the year, the Company paid income tax amounting to US$1,049,000 for the 2006
provisional taxes (against a current tax charge of US$961,000) and US$59,000 final income tax for
2005. The US$88,000 overpayment of the 2006 current tax will be set against future tax liabilities.
The Company has recovered US$954,000 from TPDC’s profit share during 2006 and the remainder
of US$154,000 will be recovered in 2007.
As at 31 December 2006, 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$1.2 million. 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.
Additional Profits Tax
Under the terms of the PSA, in the event that all costs have been recovered with an annual return
of 25% plus the percentage change in the United States Industrial Goods Producer Price Index,
an Additional Profits Tax (“APT”) is payable.
The Company provides for APT by forecasting the total APT payable as a proportion of the forecast
Profit Gas over the term of PSA licence. As at 31 December 2006, the effective APT rate was
calculated to be 20% (2005: 18%). Accordingly, US$183,000 (2005: US$80,000) has been netted
off revenue for the year ended 31 December 2006.
As at 31 December 2006, there were un-recovered costs of US$14.6 million (2005: US$11.6 million).
Management does not anticipate that any APT will be payable in 2007, as the forecast revenues will
not be sufficient to cover the un-recovered costs brought forward as inflated by 25% plus the percent-
age change in the United States Industrial Goods Producer Price Index and the forecast expenditures
for 2007. 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 programme.
The APT can have a significant negative impact on the Songo Songo project economics as
measured by the net present value of the cash flow streams. Higher revenue in the initial years
leads to a rapid payback of the project costs and consequently accelerates the payment of the APT
that can account for up to 55% of the Company’s profit share. Therefore, the terms of the PSA
rewards the Company for taking higher risks by incurring capital expenditure in advance of
revenue generation.
Depletion and Depreciation
The Natural Gas Properties are depleted using the unit of production method based on the
production for the period as a percentage of the total future production from the Songo Songo
proven reserves. As at 31 December 2006, the proven reserves as evaluated by the independent
reservoir engineers, McDaniel & Associates Consultants Ltd. (“McDaniel”) were 265.8 bcf (2005:
240.6 bcf) on a life of licence basis. This leads to a depletion charge of US$0.55/mcf in 2006
(2005: US$0.33/mcf).
Non-Natural Gas Properties are depreciated as follows:
Leasehold improvements
Computer equipment
Vehicles
Fixtures and fittings
Recoverable Costs
Over remaining life of the lease
3 years
3 years
3 years
As at 31 December 2006, the Company had US$14.6 million (2005: US$11.6 million) of costs that
are recoverable out of 75% of the future Net Revenues. The costs associated with the remedial
work on SS-9 are not recoverable as TPDC has stated that the work should have been rectified by
a predecessor company of Orca Exploration at the time of the 1997 work programme. As at 31
December 2006, US$0.3 million was not able to be recovered in this respect.
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 Flow
Funds from operations before working capital changes were US$6.0 million for the year ended 31
December 2006 (2005: US$2.3 million).
(Figures in US$’000)
Profit after taxation
Adjustment for non cash items
Funds from operations before working capital changes
Working capital adjustments
Net cash flows from operating activities
Net cash flows used in investing activities
Net cash flows from financing activities
Increase in cash and cash equivalents
2006
2,577
3,453
6,030
(873)
5,157
(5,909)
18,232
17,480
2005
388
1,880
2,268
(465)
1,803
(5,020)
4,375
1,158
2006 ANNUAL REPORT
38 MANAGEMENT’S DISCUSSION & ANALYSIS
The cash flows generated during the year were reinvested in developing the Songo Songo field
and related infrastructure. Accordingly, the US$17.5 million increase in the net cash and cash
equivalents during the year was primarily due to the net receipt of US$18.1 million from the rights
issue on 29 December 2006.
Capital Expenditures
Capital expenditures amounted to US$6.0 million during the year (2005: US$5.6 million).
The capital expenditure may be analysed as follows:
(Figures in US$’000)
Geological, geophysical and well drilling
Pipelines and infrastructure
Power development
Other equipment
2006
4,460
975
573
35
6,043
2005
2,757
2,090
789
12
5,648
During 2006, the Company commenced preparations to drill the development well, SS-10, to
increase gas deliverability and ensure security of supply in the event of failure of any single well.
The Company purchased US$3.4 million of casing and other long lead items, US$1.6 million of
which was for a potential second development or exploration well that is forecast to be drilled in
2008/2009.
TPDC has indicated that they wish to exercise their right to ‘back in’ to the field development by
contributing 20% of the costs of the future wells including SS-10 in return for a 20% increase in
the profit share percentage for the production emanating from these wells. The implications and
workings of the ‘back in’ are still to be discussed in detail with TPDC. For the purpose of the
reserves certification, it has been assumed that they will ‘back in’ for 20% and this is reflected in
the Company’s net reserve position. However, the financial statements do not take account of any
re-imbursement for the SS-10 capital expenditure, pending the finalisation of the terms of the
‘back in’.
The Company also commenced work to remove over 5,000 feet of wireline and two pressure
gauges that were left downhole in SS-9 at the time of the 1997 well tests. The debris was causing
the well to produce below its production capability at 20 mmscf/d. The remedial work was
successfully completed in Q1 2007 and the well now has a maximum deliverability of 50 mmscf/d.
During the year, the Company completed the processing and interpretation of data from the
seismic acquisition on the Songo Songo licence area and the Nyuni farm-in licence acreage at a
cost of US$0.5 million. The actual seismic work was conducted in 2005.
The Company expanded its gas distribution network by 3 kilometers to 28 kilometers during the
year through the connection of eight additional industrial customers at a cost of US$0.7 million.
Most of the customers connected during the year were located alongside the ringmain. In addition,
the Company started to prepare for an 8 kilometer pipeline extension to the distribution system
and the construction of an additional pressure reduction system (“PRS”). This will improve the
security of supply, enable the Company to hook up 3-4 new customers and increase deliverabil-
ity to its existing industrial base. The Company incurred US$0.3 million in 2006 for this work and
is expected to incur an additional US$1.9 million in 2007.
The Company also completed the installation of a second PRS and a pipeline connection in order
to supply gas to the 48 MW Aggreko power plant that became operational in Q4 2006.
Working Capital
Working capital as at 31 December 2006 was US$20.4 million (31 December 2005: US$2.2 million)
and may be analysed as follows:
(Figures in US$’000)
Cash and cash equivalents
Trade and other receivables
Total current liabilities
Working capital
2006
20,678
4,275
24,953
4,523
20,430
2005
3,198
2,862
6,060
3,849
2,211
The significant increase in the year end cash balance is due to the net receipt of US$18.1 million
from a rights issue on 29 December 2006.
Also included in cash and cash equivalents was US$185,000 advanced by Murzah Oil Industries
Limited, East Coast Oils & Foods Limited, Nampak Tanzania Limited and Yuasa Batteries (East
Africa) Limited as deposits for their connections. This amount will be repaid to the companies
after they have consumed in excess of a total of US$370,000 of Additional Gas. This amount is
shown in current liabilities.
The majority of the cash is held in US and Cdn dollars in Mauritius and in Tanzanian Shillings in
Tanzania bank accounts. 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.
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 2006, US$1.9 million was due for
the month of November and December (including VAT) from the industrial customers. A signifi-
cant part of this amount has been subsequently received. Trade and other receivables also
includes an amount of US$0.7 million due from Songas for the supply of Additional Gas to the
Ubungo Power Plant and US$0.8 million from TANESCO for supply of Additional Gas to the 48 MW
Aggreko units. The contracts with Songas and TANESCO accounted for 35% (2005: 34%) of the
Company’s operating revenue in 2006. Songas’ financial security is, in turn, heavily reliant on the
payment of capacity and energy charges by the electricity utility, TANESCO. Despite the improve-
ment in hydrology, TANESCO is still experiencing financial difficulties. As a result, TANESCO is
dependent on the Government of Tanzania for some of its funding. Whilst some payments have
been delayed, the Company collected all amounts from Songas and US$198,000 remains
outstanding from TANESCO in respect of the amounts due at 31 December 2006.
The level of receivables will be closely monitored to minimise any potential default by any of
the Company’s customers.
2006 ANNUAL REPORT
40 MANAGEMENT’S DISCUSSION & ANALYSIS
Under the terms of the PSA and other Songo Songo agreements:
a
The profit share owed to TPDC is payable within 30 days of each quarter end. Accordingly,
the Company benefits from holding the cash receipts for this period. Under the PSA, income
tax paid by the Company is recoverable from TPDC’s share of profit share. During the year,
the Company paid provisional income tax of US$1,049,000. As at 31 December 2006,
US$154,000 (2005: US$629,000 due to TPDC) was yet to be recovered from TPDC’s profit
share. This was recovered in full in Q1 2007.
a
The tariff for the use of the gas processing plant and pipeline infrastructure is payable to
Songas within 30 days of each month end. As at 31 December 2006 the Company owed
Songas US$605,000 (2005: US$420,000) for the tariff. The amount due at the year end
represents an outstanding balance of two months, which matches the time that Songas is
taking to pay for the Additional Gas used at the Ubungo Power Plant.
Included in the current liabilities is US$0.5 million being an accrual for a bonus scheme introduced
during the year that incorporates stock appreciation rights, and US$0.3 million for the rights issue
costs. Current liabilities also includes US$2.3 million (2005: US$1.8 million) of accrued liabilities.
These include staff and consultants annual bonuses of US$0.6 million, a share of well mainte-
nance and field production cost of US$0.3 million payable to Songas, US$0.3 million for VAT and
other taxes payable to central Government and local authorities, customer deposits of US$0.2
million and other year end accruals.
Per a short term agreement with TANESCO for the supply of gas to the 20 MW Dowans unit,
US$138,000 was due to be received in December 2006 in advance of gas being consumed.
This has been included in current liabilities. The payment has subsequently been received.
Management forecasts that the Company will be able to meet its 2007 capital expenditure
programme through the use of proceeds from the rights issue and self-generated cash flows.
In addition, the Company has no bank borrowings and there is scope for utilising debt funding
once the longer term contracts for the supply of gas to the power sector are in place.
Outstanding Share Capital
There were 26.8 million shares outstanding at 31 December 2006 and 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
Options
2006
2005
1,751
25,023
26,774
2,022
28,796
23,395
1,514
1,751
21,513
23,264
1,987
25,251
22,903
1,419
24,322
Weighted average diluted Class A and Class B shares
24,909
The Company issued 3,345,540 Class B shares at Cdn$6.43 per share following a fully subscribed
rights issue that closed on 29 December 2006. Net proceeds of US$18.1 million were raised for
the Company and collected by 31 December 2006 (gross proceeds US$18.5 million, costs US$0.4
million). The funds will be primarily used for the drilling of the SS-10 development well, the
expansion of the low pressure distribution system and new growth opportunities.
Under the terms of the rights issue:
a
each holder of Class B shares was entitled to receive one right for each Class B held and
seven rights entitled the holder to subscribe for one Class B share at a price of Cdn$6.43.
a
each holder of Class A shares was entitled to receive one right for each Class A share held
and seven rights entitled the holder to subscribe for on Class B share at a price of Cdn$6.43.
a
each holder of rights who exercised all of their rights was entitled to subscribe for additional
Class B shares that had not been subscribed and paid for at the closing date (“Additional
Subscription Privilege”).
The subscription price of Cdn$6.43 represented a 15% discount to the closing price of the Class
B shares on 7 September 2006.
As at 30 April 2007, there were 1,751,195 A shares and 25,253,128 B shares in issue.
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. In accordance with IFRS2, 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.
2,000,000 options were issued to certain Directors and Officers on 1 September 2004 at a price
of Cdn$1.00 per option. These options have a term of 10 years. The fair value of these options
had been expensed in full as at 31 December 2006.
During the year, 165,000 of these 2004 options were exercised at a price of Cdn$1.00 per option.
A total of 1,822,400 of these options remained outstanding at the year end.
On 1 September 2006, 200,000 options were issued at a price of Cdn$6.80 per option.
These options have a term of 5 years and vest in three equal annual instalments starting on
1 September 2007. The fair value of these options were estimated at the grant date using the
Black-Scholes option pricing model with the following assumptions: risk free rate of 2.6% dividend
yield of 0%, expected life of 5 years and volatility of 80%.
As at 30 April 2007, the Company had granted 2,292,400 options. In addition, there were
1,000,000 stock appreciation rights, 400,000 of which are capped.
Contractual Obligations and Committed Capital Investment
During the year, the Company committed to drilling a development well, SS-10 and to undertake
some remedial work on the offshore well, SS-9. Preparations for these operations, including the
purchase of long-lead materials and equipment, started during the year. The remedial work on
SS-9 was successfully completed in Q1 2007. SS-10 was spud in April 2007. The Company has
committed to spend a total of US$12.9-US$14.9 million on these projects.
2006 ANNUAL REPORT
42 MANAGEMENT’S DISCUSSION & ANALYSIS
The Company has committed to the installation of an additional pressure reduction station and
the laying of 8 kilometers of new low pressure pipeline in the first half of 2007. This work is
required to increase security of supply and to meet forecast increases in demand from both
existing and new industrial customers. The work is estimated to cost US$2.2 million. As at the
year end, the Company had already spent US$0.3 million for the purchase of long lead equipment
and project management.
Under the terms of the contracts with Kioo Ltd., Tanzania Breweries Ltd. and Karibu Textile Mills
Ltd., the Company is liable to pay penalties in the event that there is a shortfall in the Additional
Gas supply in excess of 5% of the contracted quantity. The penalties equate to the difference
between the price of gas and an alternative feedstock multiplied by the notional daily quantities.
The maximum penalty for shortfall gas is a total of US$1.1 million for these three contracts and
the remedy is payable as a credit against future monthly invoices.
Under the terms of the PSA, in the event that there is a shortfall in Protected Gas as a conse-
quence 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 (7.4 bcf
as at 31 December 2006). Songas has the right to request reasonable security on all Additional
Gas sales.
Songas has written to Orca Exploration confirming that, subject to certain conditions, security will
not be required for the supply of Additional Gas to the Ubungo Power Plant, for the supply of up
to 15 mmscf/d for additional power generation and up to 10 mmscf/d for the industrial sector,
for a period of five years. As the current emergency power generation operating in the country
could take demand above 15 mmscf/d for power generation, Songas has confirmed that the
Company may sell 17 mmscf/d for power generation over the next two years without the need
for security.
The Company is looking to agree a security mechanism with Songas that provides clear guidance
as to how Songas will operate their rights to security. It is anticipated that, under certain circum-
stances, the Company and TPDC may have to allocate a proportion of the Additional Gas revenues
to an escrow account, in the event of a Protected Gas insufficiency. It is forecast that the security
mechanism will be finalised by the end of Q2 2007.
TPDC has indicated that they wish to exercise their right to ‘back in’ to the field development by
contributing 20% of the costs of the future wells including SS-10 in return for a 20% increase in
the profit share percentage for the production emanating from these wells. The implications and
workings of the ‘back in’ are still to be discussed in detail with TPDC. For the purpose of the
reserves certification, it has been assumed that they will ‘back in’ for 20% and this is reflected in
the Company’s net reserve position. However, the financial statements do not take account of any
re-imbursement for the SS-10 capital expenditure, pending the finalisation of the terms of the
‘back in’.
Management expects to fund its committed capital investments in 2007 from the proceeds of the
rights issue and cash generated from operations.
Post Balance Sheet Events
On 14 January 2007, the Company issued 300,000 options to a newly appointed officer at a price
of Cdn$8.00 per option. These options have a term of 5 years and vest in three equal annual
instalments starting on 14 January 2008. In addition, 300,000 stock appreciation rights were issued
to the same officer at an exercise price of US$8.00 per right. These stock appreciation rights have
a term of 5 years and vest in three equal annual instalments starting on 14 January 2008. In April
2007, 200,000 Treasury Shares were awarded to the same officer. These vest in three equal annual
instalments starting 7 April 2007.
On 2 January 2007, the Company issued 300,000 stock appreciation rights to a consultant at an
exercise price of Cdn$8.70 per right. The consultant is facilitating the search for new venture
opportunities for the Company. These stock appreciation rights have a term of 5 years and vest
in three equal annual instalments starting on 2 January 2008.
In January 2007, the Company initiated a normal course issuer bid to purchase up to 1,085,379
Class B shares between 31 January 2007 and 31 December 2007, subject to a maximum usage
of US$2.2 million of funds.
There are no other Post Balance Sheet Events other than those disclosed under ‘Contractual
Obligations and Committed Capital Investment’.
Off-Balance Sheet Transactions
As at 31 December 2006, the Company had no off-balance sheet arrangements.
Operating Leases
The Company has entered into a five year rental agreement that expires on 30 November 2007
for the use of the offices in Dar es Salaam at a cost of approximately US$102,000 per annum.
Related Party Transactions
The following transactions were carried out with related parties:
i)
During the year, the Company entered into an agreement with a company owned by the
non-Executive Chairman, to underwrite all the rights issue at a fixed fee of US$300,000.
ii)
One of the non executive Directors is a partner at a law firm. During the year, the Company
incurred US$176,000 to this firm for services provided on rights issue and other legal
services.
The transactions with these related parties were made at the exchange amount.
2006 ANNUAL REPORT
44 MANAGEMENT’S DISCUSSION & ANALYSIS
DISCLOSURE CONTROLS AND PROCEDURES
Disclosure controls and procedures are defined Under Multilateral Instrument 52-109 – Certification
of Disclosure Controls in Issuers’ Annual and Interim Filings (“MI 52-109”) as “…controls and
other procedures of an issuer that are designed to provide reasonable assurance that information
required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or
submitted by it under provincial and territorial securities legislation is recorded, processed, summa-
rized and reported within the time periods specified in the provincial and territorial securities
legislation and include, without limitation, controls and procedures designed to ensure that
information required to be disclosed by an issuer in its annual filings, interim filings or other
reports filed or submitted under provincial and territorial securities legislation is accumulated and
communicated to the issuer’s management, including its chief executive officers and chief financial
officers (or persons who perform similar functions to a chief executive officer or a chief financial
officer), as appropriate to allow timely decisions regarding required disclosure.” The Company has
conducted a review and evaluation of its disclosure controls and procedures, with the conclusion
that as at 31 December 2006 the Company has an effective system of disclosure controls and
procedures as defined under MI 52-109. In reaching this conclusion, the Company recognizes that
two key factors must be and are present:
(a)
the Company is dependant upon its advisors and consultants (principally its legal counsels)
to assist in recognizing, interpreting, understanding and complying with the various
securities regulations disclosure requirements; and
(b)
an active Board of Directors and management with open lines of communication.
The Company has a small staff with varying degrees of knowledge concerning the various
regulatory disclosure requirements. In many circumstances, the various regulatory requirements are
relatively new, subject to interpretation, and complex. The Company is not of a sufficient size to
justify a separate department or one or more staff member specialists in this area. Therefore the
Company must rely upon its advisors/consultants to assist it and as such they form part of the
disclosure controls and procedures.
Proper disclosure necessitates that one not only be aware of the pertinent disclosure require-
ments, but one is also sufficiently involved in the affairs of the Company and/or receives the
communication of information to assess any necessary disclosure requirements. Accordingly, it is
essential that there be proper communication among those people who manage and govern the
affairs of the Company, this being the Board of Directors and senior management. The Company
believes this communication exists.
While the Company believes it has adequate disclosure controls and procedures in place, lapses
in the disclosure controls and procedures could occur and/or mistakes could happen. Should such
occur, the Company intends to take whatever steps necessary to minimize the consequences thereof.
INTERNAL CONTROLS OVER FINANCIAL REPORTING
Internal controls over financial reporting are defined in the Multilateral Instrument 52-109 as “…
a process designed by, or under the supervision of, the issuer’s chief executive officers and chief
financial officers, or persons performing similar functions, and effected by the issuer’s board of
directors, management and other personnel, to provide reasonable assurance regarding the reli-
ability of financial reporting and the preparation of financial statements for external purposes in
accordance with the issuer’s GAAP and includes those policies and procedures that:
(a) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect
the transactions and dispositions of the assets of the issuer;
(b) provide reasonable assurance that transactions are recorded as necessary to permit prepa-
ration of financial statements in accordance with the issuer’s GAAP, and that receipts and
expenditures of the issuer are being made only in accordance with authorizations of
management and directors of the issuer; and
(c)
provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use or disposition of the issuer’s assets that could have a material effect on the
annual financial statements or interim financial statements.”
The Company has conducted a review and evaluation of its internal controls over financial
reporting, with the conclusion that as at 31 December 2006 the Company’s system of internal
controls over financial reporting, as defined under MI 52-109, is sufficiently designed to provide
reasonable assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with the Company’s GAAP. During the review of
the design of the Company’s control system over financial reporting it was noted that, due to the
limited number of staff at Orca Exploration, it is not feasible to achieve complete segregation of
incompatible duties. The limited number of staff may also result in identifying weaknesses in
accounting for complex and / or non-routine transactions due to a lack of technical resources
within the Company. While management of Orca Exploration has put in place certain procedures
to mitigate the risk of a material misstatement in the Company’s financial reporting, a system of
internal controls can provide only reasonable, not absolute, assurance that the objectives of the
control system are met, no matter how well conceived or operated.
2006 ANNUAL REPORT
46 MANAGEMENT’S DISCUSSION & ANALYSIS
Summary Quarterly Results
The following is a summary of the results for the Company for the last eight quarters:
(Figures in US$’000 except where otherwise stated)
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
2006
2005
FINANCIAL
Revenue
Profit/(loss) after taxation
Operating netback (US$/mcf)
Working capital
Shareholders’ equity
4,722
1,025
2.13
3,835
3,198
2,073
2,741
2,156
512
350
809
2.88
660
2.71
83
2.05
396
2.51
785
1.68
(275)
(518)
3.86
3.24
20,430
3,298
2,448
2,118
2,211
3,559
2,789
4,895
37,889
18,676
17,715
16,928
16,662
16,096
15,240
15,444
Profit/(loss) per share – basic (US$)
Profit/(loss) per share – diluted (US$)
0.05
0.04
CAPITAL EXPENDITURES
Geological and geophysical and well drilling
2,747
Pipeline and infrastructure
Power development
Other equipment
OPERATING
Additional Gas sold – industrial (mmscf)
Additional Gas sold – power (mmscf)
Average price per mcf – industrial (US$)
Average price per mcf – power (US$)
131
531
–
398
1,206
7.64
1.95
0.03
0.03
473
234
42
–
491
744
8.63
1.69
0.03
0.03
726
305
–
3
347
739
8.69
2.13
–
–
0.02
0.02
0.03
0.03
(0.01)
(0.02)
(0.01)
(0.02)
514
305
–
32
230
682
7.63
1.79
2,000
868
34
(1)
299
766
7.86
2.15
148
110
224
3
261
905
7.26
1.24
520
902
531
5
120
–
88
210
–
5
97
–
6.19
5.23
–
–
The principal developments in Q4 were as follows:
a
Signed a two year contract, connected (US$0.4 million) and commenced the supply of an
average of 6.5 mmscf/d of Additional Gas to the Aggreko emergency gas fired power
units at an average price of US$2.05/mcf. These units can take a maximum of 11.6
mmscf/d and are expected to be operational until December 2008. The price of gas to
these units from 1 January 2007 increased to US$2.22/mcf.
a
Installed the connection to the 20 MW Dowans unit at a cost of US$0.1 million. This unit
commenced commercial operations on 23 January 2007 and has a maximum gas usage
of 6.0 mmscf/d.
a
a
Achieved average Additional Gas sales of 6.4 mmscf/d to the Ubungo Power Plant at an
average price of US$1.80/mcf.
Started Additional Gas supply to two new industrial customers, East Coast Oils & Fats
Limited and Nampak Tanzania Limited. An additional customer connected during the quarter,
Serengeti Breweries Limited, had yet to commence gas consumption by the year end.
a
Incurred capital expenditure of US$3.7 million on the purchase of long lead items for the
drilling of the SS-10 development well that will spud in April 2007 and the remedial work
on the offshore well, SS-9.
a
Continued with preparation to construct a new pressure reduction system and the laying
of 8 kilometers of new low pressure pipeline. US$0.3 million was incurred during the quarter
for the purchase of long lead pipeline.
a
a
Successfully raised US$18.1 million (net) through a one for seven rights issue.
Recruited James Smith as an executive officer and director to head up the Company’s
exploration and new ventures.
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 mmscf/d in Q4 2004 to 4.3 mmscf/d in Q4 2006, peaking at 5.3 mmscf/d in Q3
2006. Industrial sales peak in third quarters of each year as textile customers take advantage of
low cotton prices during the harvest season. At the same time the average price to the industrial
sector has varied in line with the price of crude oil as the gas is priced at a 20% - 25% discount
to the price of Heavy Fuel Oil in Dar es Salaam. The average price ranged from US$5.23/mcf in
Q1 2005 and peaked in Q2 2006 at US$8.69/mcf.
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. The gas price to the power sector
from Q3 2005 to Q3 2006 was set at a sliding scale between US$0.62/mcf and US$2.15/mcf
depending on the availability of gas turbines at the Ubungo Power Plant. The maximum price
was only achieved in Q4 2005 and Q2 2006 as a result of operational problems at Ubungo Power
Plant in other quarters.
In Q4 2006, 48 MWs of emergency power units operated by Aggreko plc commenced commer-
cial operations. These units took an average of 7.9 mmscf/d during Q4 so increasing the volume
of Additional Gas sold.
Revenue in Q4 2006 increased as a result of the commencement of gas sales to the Aggreko
emergency power plant.
Profit/(loss) after taxation
The majority of the Company’s costs are fixed in nature though there have been step changes in
the general and administrative costs as new personnel are recruited to meet the expanding
activities. The Company recorded its first profit in Q3 2005 as a result of commencement of gas
sales to power sector. Profitability in the first and fourth quarters of each year is affected by the
seasonality of gas demand by the textile customers. The increase in profit in Q4 2006 is primarily
the result of the increased sales to the power sector, though this was partially offset by an
increase in costs to negotiate long term power contracts and work performed for the regulator,
EWURA. A detailed Additional Gas price application for the power sector was made to EWURA in
December 2006.
2006 ANNUAL REPORT
annual 2006.qxp 5/3/07 10:37 PM Page 48
48 MANAGEMENT’S DISCUSSION & ANALYSIS
Working capital
The working capital for Q4 2006 increased to US$20.9 million as a result of the receipt of rights
issue proceeds on 29 December 2006.
In Q1 2005, the Company raised US$4.4 million through a rights issue. This helped to increase the
working capital to US$4.9 million over the previous quarter.
Funds raised in Q4 2006 will be primarily used in completing the drilling programme, extending
the low pressure distribution system and in pursuing new options for growth.
SELECTED FINANCIAL INFORMATION
Selected annual financial information derived from the audited consolidated financial statements
for the period ended 31 December 2004 and the years ended 31 December 2005 and 2006 is set
out below:
(Figures in US$’000 except per share amount)
Revenue
Funds from operations
before working capital changes
Profit/(loss) after taxation
Profit/(loss) per share:
Basic
Diluted
Total assets
Year ended
31 December
2006
13,828
Year ended
31 December
2005
5,759
6,030
2,577
0.11
0.10
2,268
388
0.02
0.02
Period ended
31 December
2004
441
(311)
(727)
(0.03)
(0.03)
43,904
21,097
12,781
Revenue increased by 140% compared to 2005. Additional Gas volumes sold increased from 2,449
mmscf in 2005 to 4,837 mmscf in 2006 primarily due to an increase in the number of industrial
customers, a longer comparative period for the sale of Additional Gas to the power sector which
commenced in Q3 2005 and higher industrial prices. An increase of 1,206% in 2005 over 2004 is
primarily the result of a longer comparative period. The 2004 comparatives are for the four months
ended 31 December 2004.
Funds from operations before working capital changes increased by 166% in 2006 and 829% in
2005 primarily as a result of the increase in revenues.
The majority of the Company’s costs are fixed in nature. Therefore costs do not increase in
proportion to the increase in revenues. Accordingly, the increase in profitability is mainly due to
increasing revenues.
annual 2006.qxp 5/3/07 10:37 PM Page 49
The Company’s assets increased by 108% to US$43.9 million (2005: 65% to US$21.1 million) in
the year ended 31 December 2006. The Company’s assets are made up as follows:
(Figures in US$’000)
Cash and cash equivalents
Trade and other receivables
Natural gas properties and other equipment
Year ended
31 December
2006
Year ended
31 December
2005
Period ended
31 December
2004
20,678
4,275
24,953
18,951
43,904
3,198
2,862
6,060
15,037
21,097
2,040
441
2,481
10,300
12,781
The increase in the cash and cash equivalents in 2006 is primarily the result of the net receipt of
US$18.1 million from the one for seven rights issue on 29 December 2006. The increase in 2005
was the result of the one-for-ten rights issue in March 2005.
The increase in trade and other receivables is in line with the increase in trading activities and is
more fully discussed in ‘Working Capital’ above.
In 2006, the Company incurred costs in the preparation for well drilling, expanding its distribution
network including the installation of a second pressure reduction station and the connection of the
Aggreko and Dowans emergency power plants. This is discussed under ‘Capital Expenditure’ above.
The increase in the natural gas properties and other equipment in 2005 was primarily the result
of the US$1.9 million seismic acquisition in 2005 and the US$2.1 million extension of the distri-
bution network around Dar es Salaam.
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, 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 environ-
ment, as well as interrupt operations. In addition, all of Orca Exploration’s operations will be
subject to the risks normally incident to drilling of natural gas wells and the operation and devel-
opment of gas properties, including encountering unexpected formations or pressures, premature
declines of reservoirs, blowouts, equipment failures and other accidents, sour gas releases, uncon-
trollable 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.
Furthermore, Orca Exploration cannot predict whether insurance will continue to be available at
a reasonable cost or at all.
2006 ANNUAL REPORT
50 MANAGEMENT’S DISCUSSION & ANALYSIS
Foreign Operations
All of Orca Exploration's operations and related assets are located in countries which may be
considered to be politically and/or economically unstable. Exploration or development activities
in such countries 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, nationalization,
renegotiation or nullification of existing contracts, 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 contrac-
tors 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 the foreign countries in which Orca Exploration will conduct business, currently limited to
Tanzania, the state generally retains ownership of the minerals and consequently retains control
of (and in many cases, participates in) the exploration and production 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.
All of Orca Exploration's development properties and all of its proved natural gas reserves are
located offshore on the Songo Songo Island in Tanzania, and, consequently, Orca Exploration's
assets will be subject to regulation and control by the government of Tanzania and certain of its
national and parastatal organizations. Orca Exploration and its predecessors have operated in
Tanzania for a number of years and believe that it has good relations with the current Tanzanian
government. However, there can be no assurance that present or future administrations or govern-
mental 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 prevailing capital market conditions as well as the business performance
of Orca Exploration. 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.
From time to time Orca Exploration may enter into transactions to acquire assets or the shares of
other companies. These transactions may be financed partially or wholly with debt, which may
temporarily increase Orca Exploration's debt levels above industry standards.
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 international 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 Exploration operates the Songo Songo natural gas property. 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 organisa-
tions 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.
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 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 Additional 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.
Under the terms of the contracts with Kioo Limited, Tanzania Breweries Limited and Karibu Textile
Mills Ltd, the Company is liable to pay penalties in the event that there is a shortfall in the
Additional Gas supply in excess of 5% of the contracted quantity. The penalties equate to the
difference between the price of gas and an alternative feedstock multiplied by the notional daily
quantities. The maximum penalty for shortfall gas is a total of US$1.1 million for these three
contracts and the remedy is payable as a credit against future monthly invoices.
2006 ANNUAL REPORT
52 MANAGEMENT’S DISCUSSION & ANALYSIS
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 explo-
ration, acquisition or development activities, Orca Exploration's reserves and production will decline
over time as reserves are depleted. To the extent that cash flow from operations 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 production at commercially feasible costs.
Asset Concentration
Orca Exploration's natural gas reserves are limited to one property, the Songo Songo field, and
the production potential from this field is limited to five wells. There has been limited production
from the five 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 or new drilling required to achieve deliverability. In addition, any difficulties relating to the
operation or performance of the field would have a material adverse effect on Orca Exploration.
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 connection 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
environmental 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
EastCoast. 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, 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 regulation and increased public awareness concerning environmental protection.
No provision has been recognised for future decommissioning costs which are anticipated to be
immaterial as it is forecast that there will still be commercial gas reserves once EastCoast relin-
quishes the licence in 2026. EastCoast 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 activities with a view to mitigating its exposure to
the risk of price volatility.
The Songo Songo 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 HFO.
Recently, there has been increased activity in the exploration of oil and gas in Tanzania, with the
result that one well has been drilled on an adjacent prospect to Songo Songo. There has been a
commercial gas discovery in the south of Tanzania at Mnazi Bay and during 2006 Maurel and
Prom had a gas discovery approximately 50 kilometers south of Dar es Salaam. In addition, a
number of Production Sharing Agreements have been negotiated for the drilling onshore and
offshore Tanzania. These developments will be closely monitored by the Company, but could 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. Any significant decline in
the price of oil or gas would adversely affect Orca Exploration's revenues, operating income, cash
flows and borrowing capacity and may require a reduction in the carrying value of Orca
Exploration's gas properties and its planned level of capital expenditures.
2006 ANNUAL REPORT
54 MANAGEMENT’S DISCUSSION & ANALYSIS
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 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, crude oil price differentials to benchmarks, future prices of oil and natural gas,
operating costs, transportation costs, cost recovery provisions and royalties 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 commence-
ment 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 deficiencies and capabilities. Inspections may not be
performed on every well, and structural or environmental problems, such as ground water contam-
ination, are not necessarily observable even when an inspection is undertaken. Orca Exploration
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 unex-
pected 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.
Controlling Shareholder
W David Lyons, the Company’s non-executive Chairman, is the sole controlling shareholder of Orca
Exploration and holds approximately 99.3% of the outstanding Class A shares and approximately
17.5% of the Class B shares. Consequently, Mr. Lyons holds approximately 22.8% of the equity
(24.6% fully diluted) and controls 65.2% of the total votes of Orca Exploration.
Financial Statements
2006 ANNUAL REPORT
56 CONSOLIDATED FINANCIAL STATEMENTS
Management’s Report to Shareholders
The accompanying Consolidated Financial Statements of Orca Exploration Group Inc. (formerly EastCoast Energy Corporation) 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 acceptable 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, examines the Consolidated Financial Statements in accordance with International Financial Reporting Standards and
provides an independent professional opinion.
The Board of Directors carries out its responsibility for the financial reporting and internal controls principally through an Audit
Committee and a Reserves Committee. The committees have 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 Consolidated Financial
Statements have been approved by the Board of Directors on the recommendation of the Audit Committee.
P. R. Clutterbuck
President & Chief Executive Officer
Nigel Friend
Chief Financial Officer
Independent Auditors’ Report
Shareholders
Orca Exploration Group Inc.
Report on the consolidated financial statements
We have audited the accompanying consolidated financial statements of Orca Exploration Group Inc. and its subsidiaries (the ‘Group’), which comprise
the consolidated balance sheet as at 31 December 2006 and 31 December 2005 and the consolidated income statements, cash flow statements
and Statements of Changes in Shareholders’ Equity for the years then ended, and a summary of significant accounting policies and other
explanatory notes.
Management’s responsibility for the financial statements
Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International
Financial Reporting Standards. This responsibility includes: designing, implementing and maintaining internal control relevant to the preparation and
fair presentation of the financial statements that are free from material misstatements, whether due to fraud or error; selecting and applying
appropriate accounting policies; and making accounting estimates that are reasonable in the circumstances.
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 the International Standards on Auditing. Those standards require that we comply with the relevant ethical requirements and plan and perform
the audit to obtain a reasonable assurance whether the financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures
selected depend on our judgement, including the assessments of the risks of material misstatements of the financial statements, whether due to
fraud or error. In making those risk assessments, we consider internal controls relevant to the entity’s preparation and fair presentation of the
financial statements in order 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 principles used
and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.
Opinion
In our opinion, the consolidated financial statements give a true and fair view of the consolidated financial position of the Group as at 31 December
2006 and 31 December 2005, and of its consolidated financial performance and its consolidated cash flow for the years then ended in accordance
with International Financial Reporting Standards.
Calgary, Canada
30 April 2007
COMMENTS BY AUDITORS FOR CANADIAN READERS ON INTERNATIONAL – CANADIAN REFERENCES
Canadian reporting standards may differ from International Standards on Auditing in the form and content of the auditors’ report, depending on the
circumstances. However, had this auditors’ report been prepared in accordance with Canadian reporting standards, there would be no material
differences in the form and content of this auditors’ report. Furthermore, an auditors’ report prepared in accordance with Canadian standards on the
aforementioned consolidated financial statements would not contain a qualification of opinion.
Calgary, Canada
30 April 2007
2006 ANNUAL REPORT
58 CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Income Statements
ORCA EXPLORATION GROUP INC. (formerly EastCoast Energy Corporation)
Y E A R S E N D E D 3 1 D E C E M B E R
(thousands of US dollars except per share amounts)
NOTE
Revenue
COST OF SALES
Production and distribution expenses
Depletion expense
Gross profit
Other income
Administrative expenses
Foreign exchange losses
Profit before taxation
Taxation
Profit after taxation
Profit per share
Basic (US$)
Diluted (US$)
2
7
4
11
See accompanying notes to the consolidated financial statements.
2006
13,828
(793)
(2,027)
11,008
61
(6,724)
(84)
4,261
(1,684)
2,577
0.11
0.10
2005
5,759
(495)
(818)
4,446
64
(3,555)
(2)
953
(565)
388
0.02
0.02
Consolidated Balance Sheets
ORCA EXPLORATION GROUP INC. (formerly EastCoast Energy Corporation)
A S A T 3 1 D E C E M B E R
(thousands of US dollars)
ASSETS
Current assets
Cash and cash equivalents
Trade and other receivables
Natural gas properties and other equipment
LIABILITIES
Current liabilities
Trade and other payables
Non current liabilities
Deferred tax
Additional profits tax
SHAREHOLDERS’ EQUITY
Capital stock
Capital reserve
Accumulated profit/(loss)
Note
2006
2005
5
6
7
8
4
10
20,678
4,275
24,953
18,951
43,904
3,198
2,862
6,060
15,037
21,097
4,523
3,849
1,229
263
34,469
1,182
2,238
37,889
43,904
506
80
16,237
764
(339)
16,662
21,097
Post Balance Sheet Events (Note 14)
Contractual Obligations and Committed Capital Investment (Note 16)
See accompanying notes to the consolidated financial statements.
The consolidated financial statements were approved by the Board on 30 April 2007.
Director
Director
2006 ANNUAL REPORT
annual 2006.qxp 5/3/07 10:38 PM Page 60
60 CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Statements of Cash Flows
ORCA EXPLORATION GROUP INC. (formerly EastCoast Energy Corporation)
Y E A R E N D E D 3 1 D E C E M B E R
(thousands of US dollars)
CASH FLOWS FROM OPERATING ACTIVITIES
Profit after taxation
Adjustments for:
Depletion and depreciation
Stock-based compensation
Deferred taxation
Additional profits tax
Increase in trade and other receivables
Increase in trade and other payables
Net cash flows from operating activities
CASH FLOWS USED IN INVESTING ACTIVITIES
Acquisition of natural gas properties and other equipment
Increase in trade and other payables
Net cash flows used in investing activities
CASH FLOWS FROM FINANCING ACTIVITIES
Net proceeds from rights issue
Proceeds from exercise of options
Net cash flows from financing activities
Increase in cash and cash equivalents
Cash and cash equivalents at the beginning of the year
Cash and cash equivalents at the end of the year
See accompanying notes to the consolidated financial statements.
2006
2,577
2,129
418
723
183
6,030
(1,413)
540
5,157
(6,043)
134
(5,909)
18,087
145
18,232
17,480
3,198
20,678
2005
388
911
383
506
80
2,268
(2,421)
1,956
1,803
(5,648)
628
(5,020)
4,365
10
4,375
1,158
2,040
3,198
Statements of Changes in Shareholders’ Equity
ORCA EXPLORATION GROUP INC. (formerly EastCoast Energy Corporation)
Capital
reserve
Accumulated
profit (loss)
Total
381
(727)
(thousands of US dollars)
Note
Balance as at 31 December 2004
Rights issue net of share issue costs
Options exercised
Profit for the year
Stock-based compensation
Balance as at 31 December 2005
Rights issue
Options exercised
Profit for the year
Stock-based compensation
Capital
stock
10
11,862
4,365
10
–
–
16,237
18,087
145
–
–
Balance as at 31 December 2006
34,469
See accompanying notes to the consolidated financial statements.
–
–
–
383
764
–
–
–
418
1,182
–
–
388
–
(339)
–
–
2,577
–
11,516
4,365
10
388
383
16,662
18,087
145
2,577
418
2,238
37,889
2006 ANNUAL REPORT
62
Notes to the Consolidated Financial Statements
General Information
Orca Exploration Group Inc. (formerly EastCoast Energy Corporation) (“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. The Company’s operations at the Songo Songo gas field in
Tanzania include the operation of five producing wells and two 35 mmscf/d 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 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 can only be used principally 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 PO LICIES
a)
Statement of compliance
The consolidated financial statements have been prepared in accordance with International Financial
Reporting Standards (“IFRS”) issued by the International Accounting Standards Board (“IASB”) and
interpretations issued by the Standing Interpretations Committee of the IASB.
These principles differ in certain respects from those in Canada. These differences are described in note 12.
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
Orca Exploration Group Inc. (formerly
British Virgin Islands
Parent Company
EastCoast Energy Corporation)
PAE PanAfrican Energy Corporation
PanAfrican Energy Tanzania Limited
ii)
Transactions eliminated upon consolidation
Mauritius
Jersey
100%
100%
Inter-company balances and transactions, and any unrealised gains 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 trans-
lated using the exchange rates that existed when the values were determined. Any resulting exchange rate
differences are taken to the income statement.
d) Natural gas properties
The Company follows the full cost method of accounting for natural gas operations. Capitalised costs include
land acquisition, geological and geophysical activities, lease rentals on non-producing properties, drilling
both productive and non-productive wells, pipeline and related gas distribution equipment, and overhead
charges directly related to exploration and development activities.
Costs are depleted on the unit-of-production method based on the estimated proved reserves as estimated
by independent reservoir engineers. Costs of acquiring and evaluating unproved properties are excluded
from costs subject to depletion until it is determined whether or not proved reserves are attributable to the
properties, or impairment occurs.
Costs incurred are not depleted until commercial production commences. These capitalised costs are
periodically assessed to determine whether it is likely that such costs will be recovered in the future.
To the extent that there are costs that are unlikely to be recovered in the future, they are written off and
charged to income. The carrying amounts are assessed to be recoverable when the sum of the undiscounted
cash flows expected from the production of proved reserves exceed the carrying amount of the natural gas
properties. When the carrying amount is not assessed as recoverable, an impairment loss is recognized to
the extent that the carrying amount of the natural gas properties exceeds the sum of the discounted cash
flows from the production of proved and probable reserves. The cash flows are estimated using expected
future product prices and costs and discounted using a risk-free rate.
Proceeds from the sale of natural gas properties are applied against capital costs with no gain or loss
recognized, unless the sale would alter the depletion and depreciation rate by 20% or more.
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 Protected Gas and Additional 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 transportation tariff is paid to Songas as compensation for using the gas
processing plant and pipeline. This transportation tariff is netted off revenue.
f)
Trade and other receivables
Trade and other receivables are stated at cost less impairment losses.
g)
Cash and cash equivalents
Cash and cash equivalents include cash on deposit and highly liquid investments with original maturities of
three months or less.
2006 ANNUAL REPORT
64 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
h)
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 Company. When the options are exercised, equity is increased by the amount of the
proceeds received.
The Company accounts for stock options under the rules of IFRS2, Accounting for Share-Based Payments,
whereby the fair value of such options is expensed to the income statement 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 and employees.
The Company accounts for stock appreciation rights under the rules of IFRS2, Accounting for Share-Based
Payments, whereby the fair value of such rights are expensed to the income statement 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 expensed to the income statement.
i)
Asset retirement obligations
No provision has been made for future site restoration costs since the Company has no obligation under
the PSA to restore the fields at the end of their commercial lives.
j)
Revenue recognition, production sharing agreements and royalties
The Company recognises revenue from natural gas sales when title passes to a customer. The Company
conducts operations jointly with the Tanzanian government and parastatal entities in accordance with produc-
tion 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 the 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 ‘Natural Gas
Properties’. 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, net of the
transportation tariff.
k) 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. APT is provided for by forecasting the total APT payable as a proportion of the forecast
Profit Gas over the term of PSA licence.
l)
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, revenue is grossed up for the tax and the income tax
is shown as current tax.
Deferred tax is provided using the balance sheet asset and liability 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 assets 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.
m) Segmental reporting
No segmental information has been presented, since all the revenue generating operations and assets are
located in Tanzania.
n) Measurement uncertainty
The amounts recorded for depletion and depreciation of natural gas properties and the cost recovery ceiling
test are based on estimates. These estimates include proven and probable reserves, production rates, natural
gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to
measurement uncertainty and the effect of changes in such estimates on the financial statements of future
periods could be significant.
o) 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
Computer equipment
Vehicles
Fixtures and fittings
Over remaining life of the lease
3 years
3 years
3 years
2006 ANNUAL REPORT
66 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
2
REVENUE
Years ended 31 December
Figures in US$’000
Operating revenue
Gross-up for current income tax
Deferred additional profits tax
Revenue
2006
12,638
1,373
(183)
13,828
2005
5,652
187
(80)
5,759
The revenue reported is the Company’s proportionate share of revenue as calculated in accordance with the
accounting policy 1(j).
The Company’s total revenues for the year amounted to US$13,828,000 after adjusting the Company’s operating
revenue of US$12,638,000 by:
i)
US$1,373,000 for income tax. 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, revenues are grossed up
for the current income tax;
ii)
US$183,000 for the deferred effect of Additional Profits Tax. This tax is netted off revenue as a royalty.
3
PERSONNEL EXPENSES
The average number of employees during the year was 15 (2005: 12). The costs are as follows:
Years ended 31 December
Figures in US$’000
Wages and salaries
Social security costs
Other statutory staff costs
4
TAXATION
2006
1,451
159
226
1,836
2005
701
87
58
846
Under the terms of the PSA with TPDC, the Company is liable for income tax in Tanzania at a corporate tax rate
of 30%. However, where income tax is payable, the profit available to TPDC is reduced by this amount. This is
reflected in the accounts by grossing up the amount of the Company’s net revenue for the current income tax and
showing the income tax as a current tax expense.
Under the terms of the Tanzanian Income Tax Act, the Company generated 2006 tax profits and accordingly is
liable to pay income tax. During the year, the Company paid income tax amounting to US$1,049,000 for the 2006
provisional taxes (against a current tax charge of US$961,000) and US$59,000 for the final income tax for 2005.
The US$88,000 overpayment of the 2006 current tax will be set against future tax liabilities. The Company has
recovered US$954,000 from TPDC’s profit share during 2006 and the remainder of US$154,000 will be recovered
in 2007.
The tax charge may be analysed as follows:
Years ended 31 December
Figures in US$’000
Current tax
Deferred tax
Tax Rate Reconciliation
Years ended 31 December
Figures in US$’000
Profit before taxation
Provision for income tax calculated at the statutory rate
Add/(deduct) the tax effect of non-deductible income tax items:
Other income
Administrative and operating expenses
Stock based compensation
Permanent differences
Reversal of previously unrecognised deferred tax asset
2006
961
723
1,684
2006
4,261
1,278
(15)
170
125
126
–
1,684
2005
59
506
565
2005
953
286
(19)
161
115
82
(60)
565
At 31 December 2006, there were temporary differences between the carrying value of the assets and liabilities
for financial reporting purposes and the amounts used for taxation purposes. Accordingly a deferred tax liability
has been recognized for the year ended 31 December 2006.
The deferred income tax liability includes the following temporary differences:
Years ended 31 December
Figures in US$’000
Differences between tax base and carrying value of natural gas properties
Income tax grossed-up in revenue
Provision for stock option bonuses
Additional profits tax
5
CASH AND CASH EQUI VALENTS
As at 31 December
Figures in US$’000
Cash and short term deposits
2006
992
451
(135)
(79)
1,229
2005
474
56
–
(24)
506
2006
20,678
2005
3,198
Included in the cash and cash equivalents are:
-
-
US$36,000 advanced from Songas under the terms of the Operatorship Agreement to pay for the costs of
operating the wells and gas processing plant.
US$185,000 advanced from Murzah Oil Industries Limited, East Coast Oils & Foods Limited, Nampak Tanzania
Limited and Yuasa Batteries (East Africa) Limited, as a deposit for their pipeline connections. This will be
repaid once they have consumed in excess of US$375,000 of Additional Gas.
These amounts are also included in trade and other payables.
2006 ANNUAL REPORT
68 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
6
TRADE AND OTHER RECEIVABLES
As at 31 December
Figures in US$’000
Trade receivables
Prepayments
Other receivables
7
NATURAL GAS PR OPERTIES AND OTHER EQUIPMENT
2006
3,441
159
675
4,275
2005
2,419
150
293
2,862
Figures in US$’000
Costs
As at 1 January 2006
Additions
As at 31 December 2006
Depletion/Depreciation
As at 1 January 2006
Charge for the year
As at 31 December 2006
Net Book Values
As at 31 December 2006
As at 31 December 2005
Natural gas
properties
Leasehold
improvements
Computer
equipment
Vehicles
Fixtures
& fittings
Total
15,693
6,008
21,701
853
2,027
2,880
18,821
14,840
156
–
156
49
45
94
62
107
59
4
63
19
23
42
21
40
38
27
65
13
20
33
32
25
37
4
41
12
14
26
15
25
15,983
6,043
22,026
946
2,129
3,075
18,951
15,037
In determining the depletion charge, it is estimated by the independent reserve engineers that future
development costs of US$123.8 million (2005: US$69.6 million) will be required to bring the total proved reserves
to production.
8
TRADE AND OTHER PAYABLES
As at 31 December
Figures in US$’000
Trade payables
Accrued liabilities
Related party (note 15)
Deferred income
Income tax
Deposits
2006
1,733
2,083
472
138
(88)
185
4,523
2005
1,812
1,750
118
–
59
110
3,849
9
FINANCIAL INSTRUMENTS
The Company is exposed to market risks resulting from fluctuations in commodity prices, foreign exchange rates
and interest rates in its operations.
Credit risk
The Company has a short term contract with Songas for the supply of gas to the Ubungo Power Plant and two
contracts with TANESCO to supply Additional Gas sales to two emergency power plants. The contracts with Songas
and TANESCO accounted for 34.7% of the Company’s operating revenue during 2006 and US$1.5 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. TANESCO is currently experiencing financial difficulties principally caused by the loss of
hydro electricity generation capacity during 2006. Whilst some payments have been delayed, the Company
collected all amounts due from Songas for all gas sales to 31 December 2006. US$198,000 remains outstanding
from TANESCO being the VAT element for the supply of Additional Gas to the emergency power plants. TANESCO
is not disputing this balance and the management believes that the balance is recoverable.
Foreign currency risk
The Company’s exposure to foreign currency risk is limited to exchange rate fluctuations on foreign currency cash
balances and the expenditure in currencies other than the US dollar.
Commodity prices
The Company did not enter into any financial contracts during the year.
Fair values
Financial instruments of the Company carried on the balance sheet consist mainly of current assets and current
liabilities. There were no significant differences between the carrying value of these financial instruments and their
estimated fair value due to their short term to maturity.
10 CAPITAL STOCK
a)
Authorised
50,000,000 Class A Common Shares
50,000,000 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 require-
ments, 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.
2006 ANNUAL REPORT
70 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
b) Changes in the capital stock of the Company were as follows:
Thousands of shares or US$000
Authorised
Issued Valuation
Authorised
Issued Valuation
2006
2005
Class A shares
As at 1 January & 31 December
50,000
1,751
983
50,000
1,751
983
Class B shares
As at 1 January
Issued, net of share issue costs
Options exercised
As at 31 December
50,000
21,513
15,254
50,000
19,386
10,879
–
–
3,345
18,087
165
145
–
–
2,114
4,365
13
10
50,000
25,023
33,486
50,000
21,513
15,254
Total Class A & B shares at 31 December
100,000
26,774
34,469
100,000
23,264
16,237
The Company issued 3,345,540 Class B shares at Cdn$6.43 per share following a successful one for seven rights
issue that completed on 29 December 2006. Net proceeds of US$18.1 million were raised for the Company.
The funds will be primarily used for the drilling of the SS-10 development well, the expansion of the low pressure
distribution system and new growth opportunities.
Under the terms of the rights issue:
a each holder of Class B shares was entitled to receive one right for each Class B held and seven rights entitled
the holder to subscribe for one Class be share at a price of Cdn$6.43.
a each holder of Class A shares was entitled to receive one right for each Class A share held and seven rights
entitled the holder to subscribe for on Class B share at a price of Cdn$6.43.
a each holder of rights who exercised all of their rights was entitled to subscribe for additional Class B shares
that had not been subscribed and paid for at the closing date (“Additional Subscription Privilege”).
The subscription price of Cdn$6.43 represented a 15% discount to the closing price of the Class B shares on
7 September 2006.
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 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. In accordance with IFRS2, 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 movement of share options may be summarised as follows:
Outstanding as at 1 January
Granted
Exercised
2006
2005
Options
1,987,400
200,000
(165,000)
Price
1.00
6.80
1.00
Options
2,000,000
–
(12,600)
Outstanding as at 31 December
2,022,400
1.00 – 6.80
1,987,400
Price
1.00
–
1.00
1.00
2,000,000 options were issued to certain Directors and Officers on 1 September 2004 at a price of Cdn$1.00 per
option. These options have a term of 10 years. US$306,000 was expensed in 2006 (2005: U$383,000) in relation
to these options which are now fully vested.
During the year, 165,000 of these 2004 options were exercised at a price of Cdn$1.00 per option. A total of
1,822,400 of these options remained outstanding at the year end.
On 1 September 2006, 200,000 options were issued at a price of Cdn$6.80 per option. These options have a
term of 5 years and vest in three equal annual instalments starting on 1 September 2007. The fair value of these
options were estimated at the grant date using the Black-Scholes option pricing model with the following assump-
tions: risk free rate of 2.6%, dividend yield of 0%, expected life of 5 years and volatility of 80%. US$112,000
was expensed in 2006 in relation to these options. The total remaining to be expensed at 31 December 2006
amounted to US$899,000.
11 PROFIT PER SHARE
The calculation of basic profit per share is based on the net profit attributable to ordinary shareholders of
US$2,577,000 (2005: US$388,000) and a weighted average number of ordinary shares outstanding during the
period of 24,908,940 (2005: 22,902,699).
In computing the diluted earnings per share, the dilutive effect of the Options was 1,513,463 (2005: 1,418,875)
shares. These were added to the weighted average number of common shares outstanding during the year ended
31 December, 2006. No adjustments were required to reported earnings from operations in computing diluted per
share amounts.
2006 ANNUAL REPORT
72 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
12 RECONCILIATION O F IFRS TO ACCOUNTI NG PR INCIPLES GENERALLY ACCEPTED IN CANADA
The consolidated financial statements have been prepared in accordance with the IFRS basis of accounting, which
differ in some respects from those in Canada.
This reconciliation discloses the differences between IFRS and Canadian Generally Accepted Accounting
Principles (“GAAP”).
On 31 August 2004, the Company was spun off from a predecessor company pursuant to a scheme of arrange-
ment. Under Canadian GAAP, a deferred tax liability has to be recognised for the taxable temporary differences
arising from the initial recognition of an asset or liability under any scenario. IFRS does not permit the setting up
of a deferred tax liability for all taxable temporary differences arising from the initial recognition of an asset or
liability except in a business combination.
The Company has implemented a bonus scheme that incorporates stock appreciation rights ("rights") that have
a maximum pay out of Cdn$ 1.2 million as at 31 December 2007. Under IFRS, the fair value of the rights is
calculated using a Black-Scholes option pricing model every reporting period. Under Canadian GAAP, the fair value
is calculated using the intrinsic value method whereby the rights are valued at the market price less the rights
price at each reporting period. Under both IFRS and Canadian GAAP, the fair value is expensed over the service
period of the rights.
The following are the differences in accounting principles:
As at 31 December
Figures in US$’000
Current assets
Natural gas properties and other equipment
Current liabilities
Non-current liabilities
Capital stock
Reserves
2006
2005
IAS
24,953
18,951
43,904
4,523
1,492
34,469
3,420
43,904
CDN
24,953
20,594
45,547
4,523
3,266
34,469
3,289
45,547
IAS
6,060
15,037
21,097
3,849
586
16,237
425
21,097
CDN
6,060
16,852
22,912
3,849
2,385
16,237
441
22,912
Profit before taxation
4,261
4,114
953
969
13 OP ERATING LEASES
Non-cancellable operating lease rentals are payable as follows:
As at 31 December
Figures in US$’000
Less than one year
Between one and five years
2006
88
–
88
2005
92
107
199
The Company has rented office property under a five year operating lease expiring 30 November 2007.
14 POST BALANCE SHEET EVENTS
On 14 January 2007, the Company issued 300,000 options to a newly appointed officer at a price of Cdn$8.00
per option. These options have a term of 5 years and vest in three equal annual instalments starting on 14
January 2008. In addition, 300,000 stock appreciation rights were issued to the same officer at an exercise price
of US$8.00 per right. These stock appreciation rights have a term of 5 years and vest in three equal annual instal-
ments starting on 14 January 2008. 200,000 Treasury Shares were awarded to the same officer in April 2007.
These vest in three equal annual instalments starting 7 April 2007.
On 2 January 2007, the Company issued 300,000 stock appreciation rights to a consultant at an exercise price of
US$8.70 per right. The consultant is facilitating the search for new venture opportunities for the Company. These
stock appreciation rights have a term of 5 years and vest in three equal annual installments starting on 2 January 2008.
In January 2007, the Company initiated a normal course issuer bid to purchase up to 1,085,379 Class B shares
between 31 January 2007 and 31 December 2007, subject to a maximum usage of US$2.2 million of funds.
There are no other Post Balance Sheet Events other than those disclosed under ‘Contractual Obligations and
Committed Capital Investment’.
15 RELATED PARTY TRANSACTIONS
The following transactions were carried out with related parties:
i)
During the year, the Company entered into an agreement, a company owned by the non-Executive Chairman,
to underwrite all the rights issue at a fixed fee of US$300,000.
ii)
One of the non executive Directors is a partner at a law firm. During the year, the Company incurred
US$176,000 to this firm for services provided on rights issue and other legal services.
The transactions with these related parties were made on the exchange amount.
2006 ANNUAL REPORT
74 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
16 CONTRACTUAL O BLIGATIONS AND COMMITTED CAPITAL INVESTMENT
During the year, the Company committed to drilling a development well, SS-10 and to undertake some remedial
work on the offshore well, SS-9. Preparations for these operations, including the purchase of long-lead materials
and equipment, started during the year. The remedial work on SS-9 was successfully completed in Q1 2007.
SS-10 was spud in April 2007. The Company has committed to spend a total of US$12.9-US$14.9 million on these
projects of which US$3.7 million had already been incurred by 31 December 2006.
The Company has committed to expanding the distribution system including the installation of an additional
pressure reduction station and the laying of 8 kilometers of new low pressure pipeline in the first half of 2007.
This work is required to increase security of supply and to meet forecast increases in demand from both existing
and new industrial customers. The work is estimated to cost US$2.2 million. As at the year end, the Company had
already spent US$0.3 million for the purchase of long lead equipment and project management.
Under the terms of the contracts with Kioo Ltd., Tanzania Breweries Ltd. and Karibu Textile Mills Ltd., the Company
is liable to pay penalties in the event that there is a shortfall in the Additional Gas supply in excess of 5% of the
contracted quantity. The penalties equate to the difference between the price of gas and an alternative feedstock
multiplied by the notional daily quantities. The maximum penalty for shortfall gas is a total of US$1.1 million for
these three contracts and the remedy is payable as a credit against future monthly invoices.
Under the terms of the PSA, in the event that there is a shortfall 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 (7.4 bcf as at 31 December 2006). Songas has the right to request
reasonable security on all Additional Gas sales.
Songas has written to the Company confirming that, subject to certain conditions, security will not be required
for the supply of Additional Gas to the Ubungo Power Plant, for the supply of up to 15 mmscf/d for additional
power generation and up to 10 mmscf/d for the industrial sector for a period of five years. As the current
emergency power generation operating in the country could take demand above 15 mmscf/d for power
generation, Songas has confirmed that the Company may sell 17 mmscf/d for power generation over the next
two years without the need for security.
The Company is looking to agree a security mechanism with Songas that provides clear guidance as to how
Songas will operate their rights to security. It is anticipated that, under certain circumstances, the Company and
TPDC may have to allocate a proportion of the Additional Gas revenues to an escrow account, in the event of a
Protected Gas insufficiency. It is forecast that the security mechanism will be finalised by the end of Q2 2007.
TPDC has indicated that they wish to exercise their right to ‘back in’ to the field development by contributing
20% of the costs of the future wells including SS-10 in return for a 20% increase in the profit share for the produc-
tion emanating from these wells. The implications and workings of the ‘back in’ are still to be discussed in detail
with TPDC. For the purpose of the reserves certification, it has been assumed that they will ‘back in’ for 20%
and this is reflected in the Company’s net reserve position. However, the financial statements do not take account
of any re-imbursement for the SS-10 capital expenditure, pending the finalisation of the terms of the ‘back in’.
17 DIRECTORS AND OFFICERS EMOLUMENTS
USD’000 except no. of share options
Base
compensation
Year
Bonus
Other
compensation
Total
Outstanding
Share options
Directors
W. David Lyons (i)
Chairman
Peter R. Clutterbuck (i)
President and CEO
Nigel A. Friend (i)
Vice President and CFO
John Patterson (i)
Non Executive Director
James Smith (i), (iii)
Non Executive Director
David W. Ross
Non Executive Director
Robert Spence (i), (iv)
Non Executive Director
Other
Pierre Raillard (ii)
Vice President Operations
2006
2005
2006
2005
2006
2005
2006
2005
2006
2005
2006
2005
2006
2005
2006
2005
19
21
406
313
283
220
30
19
8
–
–
–
16
18
182
133
–
–
75
60
55
43
–
–
–
–
–
–
–
–
65
23
–
–
–
–
–
–
–
–
–
–
–
–
–
–
19
21
481
373
338
263
30
19
8
–
–
–
16
18
1,000,000
1,000,000
300,000
400,000
180,000
200,000
50,000
50,000
–
–
–
–
50,000
50,000
30
–
277
156
200,000
200,000
(i)
(ii)
The ‘Base compensation’ for W.D. Lyons, P.R. Clutterbuck, N. Friend, J. Smith, J. Patterson and R. Spence are in respect
of consultancy fees.
In 2005, 50% of the costs of P. Raillard were recharged to Songas for the work undertaken on operating the gas processing
plant and maintaining the wells. Accordingly, the emoluments for 2005 outlined above represent the costs paid directly by
the Company. During 2006, Songas paid the Company a fixed cost of US$28,650 per month for these services.
(iii)
J. Smith was elected to the Board at the Annual General Meeting on 14 November 2006.
(iv) R. Spence did not seek re-election at the Annual General Meeting on 14 November 2006.
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 EXPLORATIONS'S CONTROL, INCLUDING THE IMPACT OF GENERAL ECONOMIC CONDITIONS IN THE AREAS IN WHICH ORCA EXPLORATION
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
Peter R. Clutterbuck, CEO
+44 (0) 7768 120727
nfriend@orcaexploration.com
prclutterbuck@orcaexploration.com
or visit the Company's web site at www.orcaexploration.com.
annual 2006.qxp 5/3/07 10:38 PM Page 76
76
Corporate Information
Board of Directors
W. DAVID LYONS
Non-Executive
Chairman
St. Helier
Jersey
JOHN PATTERSON
Non-Executive Director
Nanoose Bay
Canada
Officers
PIERRE RAILLARD
Vice President
Operations
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
NIGEL A. FRIEND
Chief Financial Officer
London
United Kingdom
JAMES SMITH
Vice President Exploration
Hurst
United Kingdom
PETER R. CLUTTERBUCK
President & Chief
Executive Officer
Haslemere
United Kingdom
DAVID ROSS
Non-Executive Director
Calgary
Canada
DAVID W. ROSS
Company Secretary
Registered Office
ORCA EXPLORATION GROUP INC.
P.O. Box 3152, Road Town
Tortola
British Virgin Islands
Investor Relations
NIGEL A. FRIEND
Chief Financial Officer
Tel: + 255 22 2138737
nfriend@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
Engineering Consultants
McDaniel & Associates
Consultants Ltd.
Calgary
Canada
Auditors
KPMG LLP
Calgary
Canada
Lawyers
Burnet, Duckworth
& Palmer LLP
Calgary
Canada
Transfer Agent
CIBC Mellon Trust Company
Toronto, Montreal
and Calgary,
Canada
2006 ANNUAL REPORT
w w w . o r c a e x p l o r a t i o n . c o m