O R C A E X P L O R A T I O N G R O U P
I N C .
2014
ANNUAL
REPORT
Orca Exploration Group Inc. is an international public company
engaged in hydrocarbon exploration, development and supply of gas in
Tanzania and oil appraisal and gas exploration in Italy. Orca Exploration trades
on the TSXV under the trading symbols ORC.B and ORC.A.
FINANCIAL AND OPERATING HIGHLIGHTS . . . . . 1
2014 OPERATING HIGHLIGHTS . . . . . 2
GAS RESERVES . . . . . 6
MANAGEMENT’S DISCUSSION & ANALYSIS . . . . . 7
MANAGEMENT’S REPORT TO SHAREHOLDERS . . . . . 52
AUDITORS’ REPORT . . . . . 53
FINANCIAL STATEMENTS . . . . . 54
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS . . . . . 58
CORPORATE INFORMATION . . . . . 93
GLOSSARY
mcf
Thousands of standard cubic feet
MMcf
Millions of standard cubic feet
Bcf
Tcf
MMcfd
MMbtu
HHV
LHV
Billions of standard cubic feet
Trillions of standard cubic feet
Millions of standard cubic feet per day
Millions of British thermal units
High heat value
Low heat value
1P
2P
3P
Kwh
MW
US$
Proven reserves
Proven and probable reserves
Proven, probable and possible reserves
Kilowatt hour
Megawatt
US dollars
CDN$ Canadian dollars
bar
Fifteen pounds pressure per square inch
Financial and Operating Highlights
US$’000 except where otherwise stated
Financial
Revenue
Loss before tax
Operating netback (US$/mcf)
Cash
Working capital (1)
TANESCO receivable (before impairment) (1)
Shareholders’ equity
Net loss
per share - basic and diluted (US$)
Funds flow from operating activities (2)
per share - basic and diluted (US$)
Cash flows from operating activities
per share - basic and diluted (US$)
Outstanding Shares (‘000)
Class A shares
Class B shares
Options
Operating
Additional Gas sold
– Industrial (MMcf)
– Power (MMcf)
Average daily volume – Industrial (MMcfd)
– Power (MMcfd)
– Total (MMcfd)
Average price per mcf – Industrial (US$/mcf)
– Power (US$/mcf)
– Total (US$/mcf)
Additional Gas Gross Recoverable Reserves to end of licence (BCF) (3)
Proved
Probable
Proved plus probable
Net Present Value, discounted at 10% (US$ millions) (3)
Proved
Proved plus probable
1
YEAR ENDED/AS AT 31 DECEMBER
2014
2013 – restated
% Change
56,607
(26,863)
2.22
57,659
34,148
64,630
76,635
(38,301)
(1.10)
32,436
0.93
29,757
0.85
1,751
33,164
400
4,598
14,823
12.6
40.6
53.2
8.61
3.56
4.76
450
54
504
379
417
53,482
(5,384)
2.20
32,588
20,857
56,608
114,780
(7,640)
(0.22)
32,394
0.93
22,491
0.65
1,751
33,072
1,742
4,478
17,957
12.3
49.2
61.5
8.27
3.76
4.66
476
52
527
365
403
6
(399)
1
77
64
14
(33)
(401)
(400)
–
–
32
31
–
–
(77)
3
(17)
2
(17)
(13)
4
(5)
2
(5)
4
(4)
4
3
(1)
Working capital as at 31 December 2014 includes a TANESCO receivable (excluding interest) of US$7.7 million (31 December 2013: US$9.6 million).
Management has placed a doubtful debt provision against the long-term receivables in excess of 60 days totaling US$52.2 million (31 December 2013:
US$43.3 million). The total of long- and short-term TANESCO receivables, including interest, as at 31 December 2014 was US$64.6 million. The financial
statements do not recognise the interest receivable from TANESCO as it does not meet IAS 18 income recognition criteria. The Company is however actively
pursuing the collection of all the receivables and the interest that has been charged to TANESCO.
(2) See MD&A – Non-GAAP Measures.
(3)
Based on a report prepared by independent petroleum engineers McDaniel & Associates Consultants Ltd., dated 31 December 2014, which was prepared on
28 April 2015 in accordance with National Instrument 51-101 and definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation
Handbook. The 2013 information is based on a report prepared by the Company’s independent reserves evaluator as at 31 December 2013. In accordance
with the National Instrument 51-101 and the Canadian Oil and Gas Evaluation Handbook.
2
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2014 Operating Highlights
• Total Songo Songo field production of
• At 31 December 2014, the Company re-assessed
Protected Gas plus Additional Gas averaged
89.8 million standard cubic feet per day
(“MMcfd”) down 7% from 2013. Additional Gas
sales volumes averaged 53.2 MMcfd, a decrease
of 13% over the prior year (61.5 MMcfd), due
largely to declining field productivity and
reduced takes by TANESCO.
• Production declines, combined with continued
support of hydro power generation in Tanzania
and Q4 TANESCO maintenance, reduced
Power sector nominations during 2014 by
17% to 40.6 MMcfd, compared to 49.2 MMcfd
in 2013. Industrial sales increased 3% to 12.6
MMcfd from 12.3 MMcfd in 2013.
• Total proved reserves of Additional Gas
decreased 5% to 450 Bcf (2013: 476 Bcf)
and total proved plus probable (2P) reserves
decreased 4% to 504 Bcf (2013: 527 Bcf), both
primarily as a result of production of 19.4 Bcf
of gas during the year. The net present value
of the estimated future cash flows of the
2P reserves at a 10% discount rate (“NPV10”)
increased 10% to US$417 million (2013: NPV10
US$403 million), as a result of an optimization
to the capital programme in 2014 which
has resulted in a change in the timing of the
compression requirements, together with the
removal of the abandonment costs from the
reserve reports (as there is no obligation to
undertake abandonment under the PSA).
• Regular weekly payments from TANESCO
commenced in in Q2 2014, but were
discontinued during Q4 2014. Weekly payments
have resumed in 2015 to date with TANESCO
having made a renewed commitment to
remain current for ongoing gas deliveries and
work towards a solution for arrears. At year-end,
TANESCO owed the Company (including
interest) US$64.6 million (2013: US$56.6
million), of which US$52.2 million (2013:
US$51.5 million) were in arrears.
• TANESCO currently owes the Company
US$52.9 million (excluding interest).
the TANESCO arrears in light of (i) the
discontinuance of weekly payments during Q4
2014; (ii) the fact that TANESCO did not pay down
substantially all of the arrears by year-end pursuant
to a formal commitment made earlier during the
year which was tied to World Bank funding; (iii) the
lack of a definitive plan to repay arrears in light of
(ii) above; and (iv) the absence of any evidence of
the availability of external funding for TANESCO,
including World Bank funding. As a result of
increased uncertainty with respect to the timing
and amount of ultimate collection of amounts in
arrears, and the Company recorded a provision
for doubtful accounts against the balance of the
long-term receivable of US$35.1 million as at 31
December 2014.
• Amounts collected with respect to the long-term
receivable in the future will be reflected in earnings
when payment is received. Notwithstanding this
provision, the Company and TANESCO continue
to operate in accordance with the terms of the
Portfolio Gas Supply Agreement whereby natural
gas continues to be delivered by the Company
and TANESCO payments remain current on
current deliveries as agreed during Q2 2013,
this understanding was reconfirmed in Q1 2015.
This provision against the TANESCO long-term
receivable will not prejudice the Company’s rights
to payment in full or its ability to pursue collection
in accordance with the terms of the agreement
with TANESCO.
• Working capital as at 31 December 2014 increased
by 64% to US$34.1 million (2013: US$20.9 million)
but decreased 19% from 30 September 2014
(US$42.0 million) primarily as a result of TANESCO
suspending payments for gas during Q4, an
increase in tax payable in respect of prior years
and a reduction in the amount of prior year tax
recoverable.
• As at 31 December 2014, the Company had
US$57.7 million in cash, US$34.1 million in working
capital (2013: US$32.6 million cash, US$20.9
million working capital) and no debt.
• During the year capital expenditure was US$1.3
million in relation to engineering and planning
relating to well workovers and subsequent drilling
activities.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORT
• Net loss for the year was US$38.3 million or
US$1.10 per share diluted, as opposed to a
loss of US$7.6 million or US$0.22 per share
in 2013. The increase in net loss over 2013
was primarily the result of a US$35.1 million
provision against the remaining TANESCO
net long-term receivable.
• Average gas prices were up 2% in 2014 to
US$4.76/mcf over 2013 (US$4.66/mcf).
Industrial gas prices were up 4% in 2014 to
US$8.61/mcf (2013: US$8.27/mcf). Increases
in annual indexation and a significant
contract renewal offset decreases driven by
lower heavy fuel oil (“HFO”) prices during
the year. Average Power sector gas prices
decreased 5% over the year to US$3.56/mcf
(2013: US$3.76/mcf), largely as a result of
reduced sales volumes to the Power sector
which in turn reduced the amount sales
subject to premium pricing in accordance
with the Portfolio Gas Supply Agreement with
TANESCO more than offsetting the impact of
annual price indexation.
• Revenue was US$56.6 million, an increase
of 6% from 2013 ($53.5 million). Funds
flow from operating activities in 2014 was
US$32.4 million or US$0.93 per share diluted,
no change from 2013 (US$32.4 million or
US$0.93 per share).
• The US$1.2 billion government sponsored
Tanzania National Natural Gas Infrastructure
Project (“NNGIP”) is substantially complete,
with first gas expected by the end of 2015.
During the year, the Mnazi Bay partners and
Kiliwani North partners separately announced
that they had signed gas purchase
agreements with the Tanzania Petroleum
Development Corporation (“TPDC”) for an
initial 80 MMcfd and 20 MMcfd respectively.
Discussions between TPDC, the Ministry of
Energy and Minerals and the Company on
commercial terms for future incremental gas
sales showed no progress during the year.
Commercial terms remain a key condition
to the Company’s commitment to expanded
Songo Songo development for the NNGIP.
3
Additional Gas Volumes
Industrial
Power
2010
2011
2012
2013
2014
Funds flow from
operating activities
Funds Flow
• Despite the stalled efforts
to reach agreement on
commercial terms for
production expansion
to the NNGIP, the
Company advanced
work on Songo Songo
development. Provided
that TANESCO maintain
its weekly payments and
subject to financing,
the Company intends
to proceed the first
phase of a workover
and drilling programme
commencing mid-2015.
The initial US$120
million of the first
US$150 million first
phase expenditure is
intended to maintain
deliverability and provide
sufficient capacity to
fill the existing Songas
infrastructure until the
Company can secure
commercial terms for
additional gas sales to
the NNGIP.
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40,000
30,000
20,000
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•
•
2014
0
2011
2013
2012
2010
International Finance
Corporation (“IFC”) of the
World Bank Group is in the process of receiving
its internal approvals to provide approximately
half the capital cost of the initial phase, or US$60
million, in quasi-equity financing to the Company’s
operating subsidiary, PanAfrican Energy Tanzania
Limited. Definitive terms have yet to be agreed and
any financing will require board approval of both
IFC and the Company and be subject to a number
of terms and conditions, including with respect to
the assurance of ongoing TANESCO payments.
There is no assurance such financing will be
concluded on mutually agreeable terms.
In response to speculation regarding a potential
sale of the Company or a significant transaction, in
mid-July Orca issued a press release advising that
the Company was in discussions with a number
of third parties which have made unsolicited
approaches to the Company relating to the sale of
the Company, a significant asset disposal, strategic
investment or other transaction involving the
Company. As at the date hereof, the Company has
nothing to report.
TANESCO receivables since emergency power plan mid-2011
TANESCO receivable (1)
TANESCO receipts
(monthly)
4
80
70
70
60
60
50
50
40
40
30
30
20
20
10
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Sep-11
Sep-11
Jul-11
Aug-11
Aug-11
Oct-11
Nov-11
Oct-11
Nov-11
Oct-11
Apr-12
May-12
Jul-11
Apr-12
Jul-11
Apr-12
May-12
(1) Total TANESCO receivable at month-end and prior to provisions.
Oct-12
Oct-12
Sep-12
Nov-12
Oct-12
Jul-12
Jul-12
Aug-12
Aug-12
Sep-12
Jan-12
Jan-12
Feb-12
Jan-12
Feb-12
Jan-13
Jan-13
Feb-13
Nov-12
Dec-12
Jun-12
Jun-12
Mar-12
Mar-12
Dec-12
Jan-13
Dec-11
Dec-11
Feb-13
Mar-13
Jul-12
Apr-13
Apr-13
Mar-13
May-13
Apr-13
May-13
Jun-13
Jul-13
Jul-13
Jun-13
Aug-13
Jul-13
Aug-13
Sep-13
Oct-13
Sep-13
Oct-13
Oct-13
Nov-13
Nov-13
Dec-13
Jan-14
Jan-14
Dec-13
Feb-14
Jan-14
Feb-14
Mar-14
Apr-14
Mar-14
Apr-14
Apr-14
May-14
Jul-14
Jun-14
Jul-14
Aug-14
Jul-14
Aug-14
Sep-14
Oct-15
Sep-14
Oct-14
Oct-14
Nov-14
Dec-14
Jan-15
Dec-14
Nov-14
Jan-15
Feb-15
Jan-15
Mar-15
Apr-15
Mar-15
Feb-15
Apr-15
May-14
Jun-14
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORT
5
Gas Reserves
In accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities and the
Canadian Oil and Gas Evaluation Handbook, the independent petroleum engineers, McDaniel & Associates Ltd.
prepared a report dated 28 April 2015 that assessed natural gas reserves of Orca Exploration Group Inc. based
on information on the Songo Songo Field and Songo Songo North as at 31 December 2014 (the “McDaniel
Report”). A summary of the remaining Additional Gas reserves on a life of license and life of field basis are
presented below. The Total Proved (1P) and Proved plus Probable (2P) reserves are based on production to the
end of the license period (October 2026).
During the course of 2014 no significant geological or geophysical data has been acquired on or close to
the Songo Songo field that might allow a re-assessment of the volumetric gas initially in place (“GIIP”) and
reserves. On a Gross Company basis there has been a 5% decrease in Songo Songos’ Total Proved Additional
Gas reserves to the end of the license period, with 2% increase on a life of field basis, with a total Additional Gas
production of 19.4 Bcf during the year. There has been a 4% decrease in the Proved plus Probable Additional
Gas reserves on a Gross Company life of license basis from 527.3 Bcf to 504.4 Bcf. The decrease is due to the
2014 production of Additional Gas.
The gross and net Company Additional Gas reserves to end of license are as follows:
Songo Songo Additional Gas
reserves to October 2026 (Bcf)
Independent reserves evaluation
Proved producing
Proved undeveloped
Total proved (1P)
Probable
Total proved and probable (2P)
Gross (1)
283.6
166.8
450.4
54.0
504.4
2014
Net (2)
194.0
88.9
282.9
37.3
320.2
Gross
304.9
170.8
475.7
51.6
527.3
2013
Net
212.2
100.4
312.6
36.9
349.5
(1) Gross equals the gross reserves that are available for the Company after estimating the effect of the TPDC back in (see below).
(2) Net equals the economic allocation of the Gross reserves to the Company as determined in accordance with the Production Sharing Agreement.
(3) The 2013 information is based on a report prepared by the Company’s independent reserves evaluator as at 31 December 2013, in accordance with the
National Instrument 51-101 and the Canadian Oil and Gas Evaluation Handbook
Songo Songo Additional Gas
reserves to end of field life (Bcf)
Independent reserves evaluation
Proved producing
Proved undeveloped
Total proved (1P)
Probable
Total proved and probable (2P)
Gross (1)
554.2
95.1
649.3
118.4
767.7
2014
Net (2)
359.7
50.9
410.6
76.5
487.1
Gross
573.5
62.3
635.8
113.5
749.3
2013
Net
381.6
39.6
421.2
75.9
497.1
(1) Gross equals the gross reserves that are available for the Company after estimating the effect of TPDC back in (see below).
(2) Net equals the economic allocation of the Gross reserves to the Company as determined in accordance with the Production Sharing Agreement.
(3)
The 2013 information is based on a report prepared by the Company’s independent reserves evaluator as at 31 December 2013, in accordance with the
National Instrument 51-101 and the Canadian Oil and Gas Evaluation Handbook
For the purpose of the reserves certification as at 31 December 2014, the McDaniel Report has assumed that
the Tanzania Petroleum Development Corporation (“TPDC”) will only be able to exercise its right to ‘back
in’ to the new field development plan for Songo Songo and consequently will receive a 20% increase in the
profit share for the production emanating from future production from the new wells SS-12 and SSN-1 wells.
McDaniel treats this ‘back in’ right as a TPDC working interest and therefore the Gross reserves have been
adjusted for the volumes of Additional Gas that are allocated to TPDC for its working interest share. There may
be the need for additional reserve and accounting modifications once the matter is concluded.
6
For the purpose of calculating the Gross Additional Gas reserves, McDaniel has assumed in its 2P case that 130
Bcf (2013: 144 Bcf) or an average of 13.5 Bcf per annum will be required to meet the demands of the Protected
Gas users from 1 January 2015 to 31 July 2024. During 2014, the Protected Gas users consumed 13.4 Bcf.
McDaniel forecast gas sales
prices and volumes
Year
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
Additional Gas price
Gross Additional
Gas volumes
1P
US$/mcf
3.92
4.27
4.45
4.57
4.68
4.79
4.89
4.97
5.05
5.21
5.40
5.51
1P
MMcfd
52.39
97.78
131.09
131.09
131.09
131.09
131.09
112.91
93.34
90.90
98.13
85.33
Additional
Gas price
2P
US$/mcf
3.93
4.32
4.47
4.60
4.73
4.86
4.97
5.08
5.19
5.34
5.51
5.63
Gross Additional
Gas volumes
2P
MMcfd
52.39
115.04
131.09
131.09
131.09
131.09
131.09
131.09
131.09
124.94
129.48
111.69
Present value of reserves
The estimated value of the Company’s net share of Songo Songo reserves on a life of license basis based on
the assumptions on production and pricing are as follows:
US$ millions
Proved producing
Proved undeveloped
Total proved (1P)
Probable
Total proved and
probable (2P)
5%
274.3
233.5
507.8
60.3
10%
195.9
182.9
378.8
38.4
2014
15%
144.3
145.1
289.4
25.4
5%
265.2
237.3
502.5
57.1
10%
186.4
178.8
365.2
37.9
2013
15%
136.0
136.9
272.9
26.8
568.1
417.2
314.8
559.6
403.1
299.7
There has been a 3% increase on the 2P present value at a 10% discount basis from US$403 million to US$417
million on a life of licence basis. There has been an optimization to the capital programme in 2014 which has
resulted in a change in the timing of the compression requirements, which together with the removal of the
abandonment costs from the reserve reports (as there is no obligation to undertake abandonment under the
Production Sharing Agreement) has resulted in an increase in the 2P present value. The valuation contemplates
the roll out of the current Portfolio Gas Sales Agreement (“PGSA”) with TANESCO and is consistent with 2013. It
has been assumed that from the commencement of the National Natural Gas Infrastructure Project (“NNGIP”)
which is contemplated to be on stream by July 2016 future sales to TANESCO will be at the PGSA well head
price. As a consequence no estimate has been made for the transportation tariff under the NNGIP.
It should not be assumed that the estimates of future net revenues presented in the table above represent the
fair market value of the reserves.
O R C A E X P L O R A T I O N G R O U P
I N C .
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTOPERATIONS REPORT 7
O R C A E X P L O R A T I O N G R O U P
I N C .
MANAGEMENT’S
DISCUSSION
& ANALYSIS
8
Management’s Discussion & Analysis
THIS MD&A OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS SHOULD BE IN CONJUNCTION
WITH THE AUDITED CONSOLIDATED FINANCIAL AND NOTES FOR THE YEAR ENDED 31 DECEMBER 2014.
THIS MD&A IS BASED ON THE INFORMATION AVAILABLE ON 6 May 2015.
FORWARD LOOKING STATEMENTS
This management’s discussion and analysis (“MD&A”) contains forward-looking statements or information (collectively,
“forward-looking statements”) within the meaning of applicable securities legislation. More particularly, this MD&A
contains, without limitation, forward-looking statements pertaining to the following: under “Principle Terms of the
Tanzanian PSA and Related Agreements”, the potential that TPDC will seek to amend the PSA and convert its back-in
rights into a carried working interest, the Company’s belief that the parties to the unsigned AGRA will continue to
conduct themselves as through the AGRA is in full force and effect, and the Company’s expectation that, despite the
Re-Rating Agreement being expired, Songas Limited will not de-rate the Songas gas processing plant; under “Songo Songo
Deliverability”, with respect to the NNGIP, the Company’s intention to proceed with the first phase workover and drilling
programme commencing mid 2015 subject to financing; under “Net Finance Costs”, the Company’s belief that the provision
against the TANESCO long-term receivable will not prejudice the Company’s right to payment in full or its ability to pursue
collection in accordance with the terms of the agreement with TANESCO; and management’s expectation to receive the
balance of ‘Other trade debtors’ during the course of Q2 2015; under “Contractual Obligations and Committed Capital
Investment”, the Company’s expectation that it will not have a shortfall during the term of the Protected Gas delivery
obligation to July 2024; the Company’s commitment to fund all future costs relating to the Elsa-2 appraisal well and farm
in permit in Italy in proportion to the Company’s participating interest, and the Company’s expectation that the Elsa-2
appraisal well will be drilled in 2016; the Company intention, subject to financing, to proceed with a workover and drilling
programme offshore Songo Songo in order to maintain deliverability and fill the existing Songas infrastructure to capacity
for the life of the Songo Songo licence, being 2026, and the Company’s estimated spending for the programme between
2015 and 2017; under “Contingencies”, with respect to the TPDC’s audit of the historic Cost Pool, the Company’s intention
to proceed with arbitration with the International Centre for Settlement of Investment Dispute pursuant to the terms of
the PSA, if the matter is not resolved to the Company’s satisfaction; and with respect to the Company’s tax disputes with
the TRA, the Company’s belief that it has a strong case and that, in the event the Company’s 2008 and 2010 objections
are rejected and subsequent appeals are overturned, any additional tax payable will be recoverable from TPDC under the
terms of the PSA; the Company’s belief that there can be no assurance that the rights of the Company under the PSA
will be grandfathered with respect to any future natural gas legislation arising from the National Natural Gas Policy;
the Company’s expectation that the cost of complying with environmental legislation and regulations will increase in the
future and management’s belief that the Company’s operations and facilities are currently in material compliance with
such laws and regulations; and the Company’s commitment to maintain insurance against some but not all potential
risks associated with the exploration for, and the production, storage, transportation and marketing of, oil and gas. In
addition, statements relating to “reserves” are by their nature forward-looking statements, as they involve the implied
assessment, based on certain estimates and assumptions that the reserves described can be profitably produced in the
future. The recovery and reserve estimates of Orca’s reserves provided herein are estimates only and there is no guarantee
that the estimated reserves will be recovered. As a consequence, actual results may differ materially from those anticipated
in the forward-looking statements. Although management believes that the expectations reflected in the forward-looking
statements are reasonable, it cannot guarantee future results, levels of activity, performance or achievement since such
expectations are inherently subject to significant business, economic, operational, competitive, political and social
uncertainties and contingencies.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS 9
These forward-looking statements involve substantial known and unknown risks and uncertainties, certain of which are
beyond Orca’s control, and many factors could cause Orca’s actual results to differ materially from those expressed or
implied in any forward-looking statements made by Orca, including, but not limited to: failure to receive payments from
TANESCO; failure to reach a sales agreement with TPDC for incremental gas volumes; potential negative effect on the
Company’s rights under the PSA as a result of the National Natural Gas Policy; risk that the contingencies related to the
development work for the full field development plan for Songo Songo are not satisfied; risk that the onstream date for the
National Natural Gas Infrastructure Project is delayed; failure to obtain funding for full field development plan for Songo
Songo; risk that, without extending or replacing the Re-Rating Agreement, Songas Limited may de-rate plant capacity back
to the capacity originally agreed to resulting in a material reduction in the Company’s sales volumes of Additional Gas; risk
that the Company will be required to pay additional taxes and penalties; the impact of general economic conditions in the
areas in which Orca 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; competition for, among other things, capital, drilling equipment and skilled personnel;
failure to obtain required equipment for drilling; delays in drilling plans; failure to obtain expected results from drilling of
wells; effect of changes to the PSA on the Company; changes in laws; imprecision in reserve estimates; the production and
growth potential of the Company’s assets; obtaining required approvals of regulatory authorities; risks associated with
negotiating with foreign governments; inability to access sufficient capital; failure to successfully negotiate agreements;
and risk that the Company will not be able to fulfil its obligations. In addition there are risks and uncertainties associated
with oil and gas operations, therefore Orca’s actual results, performance or achievement could differ materially from those
expressed in, or implied by, these forward-looking statements and, accordingly, no assurances can be given that any of the
events anticipated by these forward-looking statements will transpire or occur, or if any of them do so, what benefits Orca
will derive therefrom. Readers are cautioned that the foregoing list of factors is not exhaustive.
Such forward-looking statements are based on certain assumptions made by Orca in light of its experience and perception
of historical trends, current conditions and expected future developments, as well as other factors Orca believes are
appropriate in the circumstances, including, but not limited to that TPDC will exercise its right under the PSA to ‘back in’
for 20% of all new drilling activities in the future as determined by the Company’s current development plan for the Songo
Songo field; that there will continue to be no restrictions on the movement of cash from Mauritius or Tanzania; that the
Company will have sufficient cash flow, debt or equity sources or other financial resources required to fund its capital and
operating expenditures and requirements as needed; that the Company will have adequate funding to continue operations;
that the Company will successfully negotiate agreements; receipt of required regulatory approvals; the ability of Orca to
increase production at a consistent rate; infrastructure capacity; commodity prices will not deteriorate significantly; the
ability of Orca to obtain equipment and services in a timely manner to carry out exploration, development and exploitation
activities; future capital expenditures; availability of skilled labour; timing and amount of capital expenditures;
uninterrupted access to infrastructure; the impact of increasing competition; conditions in general economic and financial
markets; effects of regulation by governmental agencies; that the Company will obtain funding for full field development
plan for Songo Songo; that the Company’s appeal of the tax assessment by the TRA will be successful; that the enactment of
a Gas Act in Tanzania will not impair the Company’s rights under the PSA to develop and market natural gas in Tanzania;
current or, where applicable, proposed industry conditions, laws and regulations will continue in effect or as anticipated
as described herein; and other matters.
The forward-looking statements contained in this MD&A are made as of the date hereof and Orca undertakes no obligation
to update publicly or revise any forward-looking statements or information, whether as a result of new information, future
events or otherwise, unless so required by applicable securities laws.
10
NON-GAAP MEASURES
THE COMPANY EVALUATES ITS PERFORMANCE USING A NUMBER OF NON-GAAP (GENERALLY ACCEPTED
ACCOUNTING PRINCIPLES) MEASURES. THESE NON-GAAP MEASURES ARE NOT STANDARDISED AND THEREFORE
MAY NOT BE COMPARABLE TO SIMILAR MEASUREMENTS OF OTHER ENTITIES.
•
FUNDS FLOW FROM OPERATING ACTIVITIES IS A TERM THAT REPRESENTS CASH FLOW FROM OPERATIONS
BEFORE WORKING CAPITAL CHANGES. IT IS A KEY MEASURE AS IT DEMONSTRATES THE COMPANY’S ABILITY TO
GENERATE CASH NECESSARY TO ACHIEVE GROWTH THROUGH CAPITAL INVESTMENTS.
• OPERATING NETBACKS REPRESENT THE PROFIT MARGIN ASSOCIATED WITH THE PRODUCTION AND SALE
OF ADDITIONAL GAS AND IS CALCULATED AS REVENUES LESS PROCESSING AND TRANSPORTATION TARIFFS,
GOVERNMENT PARASTATAL’S REVENUE SHARE, OPERATING AND DISTRIBUTION COSTS FOR ONE THOUSAND
STANDARD CUBIC FEET OF ADDITIONAL GAS. THIS IS A KEY MEASURE AS IT DEMONSTRATES THE PROFIT
GENERATED FROM EACH UNIT OF PRODUCTION, AND IS WIDELY USED BY THE INVESTMENT COMMUNITY.
•
FUNDS FLOW FROM OPERATING ACTIVITIES PER SHARE IS CALCUALATED ON THE BASIS OF THE FUNDS FLOW
FROM OPERATIONS DIVIDED BY THE WEIGHTED AVERAGE NUMBER OF SHARES.
• CASH FLOW FROM OPERATING ACTIVITIES PER SHARE IS CALCULATED AS CASH FLOW FROM OPERATIONS
DIVIDED BY THE WEIGHTED AVERAGE NUMBER OF SHARES.
ADDITIONAL INFORMATION REGARDING ORCA EXPLORATION IS AVAILABLE UNDER THE COMPANY’S PROFILE ON
SEDAR AT www.sedar.com.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS 11
NATURE OF OPERATIONS
The Company’s principal operating asset is its interest in a Production Sharing Agreement (“PSA”) with the
Tanzania Petroleum Development Corporation (“TPDC”) and the Government of Tanzania in the United
Republic of Tanzania. This PSA covers the production and marketing of certain gas from the Songo Songo
Block offshore Tanzania.
The gas in the Songo Songo field is divided between “Protected Gas” as defined and “Additional Gas” as defined.
The “Protected Gas” is owned by TPDC and is sold under a 20-year gas agreement (until July 2024) to Songas
Limited (“Songas”). Songas is the owner of the infrastructure that enables the gas to be delivered to Dar es
Salaam, which includes a gas processing plant on Songo Songo Island.
Songas utilizes the Protected Gas as feedstock for its gas turbine electricity generators at Ubungo, for onward
sale to the Wazo Hill Cement Plant and for electrification of some villages along the pipeline route. The
Company 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.
Under the PSA, the Company has the right to produce and market all gas in the Songo Songo Block in excess
of the Protected Gas requirements (“Additional Gas”).
The Tanzania Electric Supply Company Limited (“TANESCO”) is a parastatal organization which is wholly-owned
by the Government of Tanzania, with oversight by the Ministry of Energy and Minerals (“MEM”). TANESCO is
responsible for the generation, transmission and distribution of electricity throughout Tanzania. Natural gas
has become an integral component of TANESCO’s power generation fuel mix as a more reliable source of
supply over seasonal hydro power and a more cost effective alternative to liquid fuels. The Company currently
supplies gas directly to TANESCO by way of a Portfolio Gas Supply Agreement (“PGSA”) and indirectly through
the supply of Protected Gas and Additional Gas to Songas which in turn generates and sells power to TANESCO.
The state utility is the Company’s largest customer and the gas supplied by the Company to TANESCO today
fires approximately 60% of the electrical power generated in Tanzania.
In addition to gas supplied to Songas and TANESCO for the generation of power, the Company has developed
and supplies an industrial gas market in the Dar es Salaam area consisting of some 39 industrial customers.
12
PRINCIPAL TERMS OF THE TANZANIAN PSA
AND RELATED AGREEMENTS
The principal terms of the Songo Songo PSA and related agreements are as follows:
Obligations and restrictions
(a) The Company has the right to conduct petroleum operations, market and sell all Additional Gas produced
and share the net revenue with TPDC for a term of 25 years, expiring in October 2026.
(b) The PSA covers the two licenses in which the Songo Songo field is located (“Discovery Blocks”). The
Proven Section is essentially the area covered by the Songo Songo field within the Discovery Blocks.
(c) No sale of Additional Gas may be made from the Discovery Blocks, if in the Company’s reasonable
judgment such sales would jeopardise the supply of Protected Gas. Any Additional Gas contracts entered
into are subject to interruption. Songas has the right to request that the Company and TPDC obtain
security reasonably acceptable to Songas prior to making any sales of Additional Gas from the Discovery
Block to secure the Company’s and TPDC’s obligations in respect of Insufficiency (see (d) below).
(d) “Insufficiency” occurs if there is insufficient gas from the Discovery Blocks to supply the Protected Gas
requirements or if the gas 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 the Company and TPDC from the Discovery
Blocks prior to the occurrence of the Insufficiency, the Company and TPDC shall be jointly liable for the
Insufficiency and shall satisfy its related liability by either replacing the Indemnified Volume (as defined in
(e) below) at the Protected Gas price with natural gas from other sources; or by paying money damages
equal to the difference between: (a) the market price for a quantity of alternative fuel that is appropriate
for the five gas turbine electricity generators at Ubungo without significant modification together with the
costs of any modification; and (b) the sum of the price for such volume of Protected Gas (at US$0.55/
MMbtu escalated) and the amount of transportation revenues previously credited by Songas to the state
electricity utility, the Tanzania Electric Supply Company (“TANESCO”), for the gas volumes.
(e) The “Indemnified Volume” means the lesser of the total volume of Additional Gas sales supplied from the
Discovery Blocks prior to an Insufficiency and the Insufficiency Volume. “Insufficiency Volume” means the
volume of natural gas determined by multiplying the average of the annual Protected Gas volumes for the
three years prior to the Insufficiency by 110% and multiplied by the number of remaining years (initial term
of 20 years) of the power purchase agreement entered into between Songas and TANESCO in relation to
the five gas turbine electricity generators at Ubungo from the date of the Insufficiency.
Access and development of infrastructure
(f) The Company is able to utilise the Songas infrastructure including the gas processing plant and main
pipeline to Dar es Salaam. Access to the pipeline and gas processing plant is open and can be utilised by
any third party who wishes to process or transport gas. Ndovu Resources Limited, a subsidiary of Aminex
PLC (“Aminex”), with support from TPDC and MEM, had previously indicated that it wished to tie into the
gas processing plant on Songo Songo Island and sell up to 10 MMcfd from its Kiliwani North field. Aminex
announced in in 2014 that it had agreed commercial terms for a gas sales agreement with TPDC which
would provide for gas from Kilwa North to be tied in to the new National Natural Gas Infrastructure Project
(“NNGIP”) facilities on Songo Songo Island and not be connected into the Songas facilities.
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.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS
13
Revenue sharing terms and taxation
(g) 75% of the gross revenues, less processing and pipeline tariffs and direct sales taxes in any year (“Net
Revenues”), can be used to recover past costs incurred. Costs recovered out of Net Revenues are termed
“Cost Gas”.
The Company pays and recovers costs of exploring, developing and operating the Additional Gas with
two exceptions: (i) TPDC may recover reasonable market and market research costs as defined under
the PSA; 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 an Additional Gas
plan (“Additional Gas Plan”) as submitted to MEM, subject to TPDC being able to elect to participate in a
development program only once and TPDC having to pay a proportion of the costs of such development
program by committing to pay between 5% and 20% of the total costs (“Specified Proportion”). If TPDC
does not notify the Company within 90 days of notice from the Company that the MEM has approved
the Additional Gas Plan, then TPDC is deemed not to have elected. If TPDC elects to participate, then it
will be entitled to a rateable proportion of the Cost Gas and their profit share percentage increases by the
Specified Proportion for that development program.
To date, TPDC has neither elected to back in within the prescribed notice period nor contributed any costs
associated with backing in and accordingly the Company has determined that to date there has been no
working interest earned by TPDC. TPDC back-in rights and the potential conversion of these rights into a
carried working interest were discussed with the Government Negotiating Team (“GNT”) along with other
issues; however nothing was agreed between the parties. Until such time as an agreement is reached, the
Company will apply the terms of the original PSA. Should an amendment to the PSA be agreed in future
relating to back-in rights, the impact on reserves and accounting estimates will be assessed at that time
and reflected prospectively. For the purpose of the reserves certification as at 31 December 2014, it was
assumed that TPDC will ‘back-in’ for 20% for all future new drilling activities as determined by the current
development plan and this is reflected in the Company’s net reserve position.
(h) In 2009, the energy regulator, Energy and Water Utility Regulatory Authority (“EWURA”), issued an order that
saw the introduction of a flat rate tariff of US$0.59/mcf from 1 January 2010. The Company’s long-term
gas price to the Power sector as set out in the unsigned ARGA and the Portfolio Gas Supply Agreement
(“PGSA”) is based on the price of gas at the wellhead. As a consequence, the Company is not impacted
by the changes to the tariff paid to Songas or other operators in respect of sales to the Power sector. As
at the date of this report, the ARGA remains an intitialled agreement only, however the parties thereto, in
certain respects are conducting themselves as though the ARGA is in full force and effect.
In 2011, the Company signed a re-rating agreement with TANESCO and Songas (the “Re-Rating
Agreement”) to increase the gas processing capacity to a maximum of 110 MMcfd (the pipeline and
pressure requirements at the Ubungo power plant restrict the infrastructure capacity to a maximum of
102 MMcfd). Under the terms of the Re-Rating Agreement, the Company effectively pays an additional
tariff of US$0.30/mcf for sales between 70 MMcfd and 90 MMcfd and US$0.40/mcf for volumes above
90 MMcfd in addition to the tariff of US$0.59/mcf payable to Songas as set by the energy regulator,
EWURA.
Under the terms of this agreement, the Company agreed to indemnify Songas for damage to its facilities
caused by the re-rating, up to a maximum of US$15 million, but only to the extent that this was not
already covered by indemnities from TANESCO’s or Songas’ insurance policies. The Re-Rating Agreement
expired on 31st December 2012 and in September 2013 was extended by Songas to 31 December 2013
whereupon it expired without renewal. At this time the Company knows of no reason to de-rate the
Songas gas processing plant. Since then production has continued at the higher rated limit and, given
the Government’s interest in pursuing further development and increasing gas production, the Company
expects this to continue. However there are no assurances that this will occur.
(i) The cost of maintaining the wells and flowlines is split between the Protected Gas and Additional Gas
users in proportion to the volume of their respective sales. The cost of operating the gas processing plant
and the pipeline to Dar es Salaam is covered through the payment of the pipeline tariff.
14
(j) 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, based on the higher
the cumulative production or the average daily sales. The Profit Gas share is a minimum of 25% and a
maximum of 55%.
Average daily sales
of Additional Gas
Cumulative sales
of Additional Gas
TPDC’s share
of Profit Gas
Company’s share
of Profit Gas
MMcfd
0 - 20
> 20 <= 30
> 30 <= 40
> 40 <= 50
> 50
Bcf
0 – 125
> 125 <= 250
> 250 <= 375
> 375 <= 500
> 500
%
75
70
65
60
45
%
25
30
35
40
55
For Additional Gas produced outside of the Proven Section, the Company’s Profit Gas share is 55%.
Where TPDC elects to participate in a development program, its profit share percentage increases by the
Specified Proportion (for that development program) with a corresponding decrease in the Company’s
percentage share of Profit Gas.
The Company is liable for income tax in Tanzania. Where income tax is payable, the Company pays the tax
and there is a corresponding deduction in the amount of the Profit Gas payable to TPDC.
(k) “Additional Profits Tax” (or “APT”) is payable when the Company recovers its costs out of Additional Gas
revenues plus an annual operating return under the PSA of 25%, plus the percentage change in the
United States Industrial Goods Producer Price Index (“PPI”); and (ii) the maximum APT rate is 55% of the
Company’s Profit Gas when costs have been recovered with an annual return of 35% plus PPI return.
The PSA is, therefore, structured to encourage the Company to develop the market and the gas fields
in the knowledge that the Profit Gas share can increase with larger daily gas sales and that the costs will
be recovered with a 25% plus PPI annual return before APT becomes payable. APT can have a significant
negative impact on the project economics if only limited capital expenditure is incurred.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS
15
Operatorship
(l) The Company is appointed to develop, produce and process Protected Gas and operate and maintain
the Songas gas production facilities and processing plant, including the staffing, procurement, capital
improvements, contract maintenance, maintain books and records, prepare reports, maintain permits,
handle waste, liaise with the Government of Tanzania and take all necessary safety, health and environmental
precautions, all in accordance with good oilfield practices. In return, the Company is paid or reimbursed
by Songas so that the Company neither benefits nor suffers a loss as a result of its performance.
(m) In the event of loss arising from Songas’ failure to perform and the loss is not fully compensated by
Songas, the Company, or insurance coverage, then the Company is liable to a performance and operation
guarantee of US$2.5 million when (i) the loss is caused by the gross negligence or wilful misconduct of
the Company, its subsidiaries or employees, and (ii) Songas has insufficient funds to cure the loss and
operate the project.
Consolidation
The companies which are 100% owned that are being consolidated are:
Company
Orca Exploration Group Inc.
Orca Exploration Italy Inc.
Orca Exploration Italy Onshore Inc.
PAE PanAfrican Energy Corporation
PanAfrican Energy Tanzania Limited
Orca Exploration UK Services Limited
Incorporated
British Virgin Islands
British Virgin Islands
British Virgin Islands
Mauritius
Jersey
United Kingdom
Results for the year ended 31 December 2014
SUMMARY
The year ended 31 December 2014 saw a decrease in reserves commensurate with production, with the net
present value of reserves increasing as a result of the Company optimising its planned Songo Songo development
programme. Reduced Power sector consumption and field declines contributed to Additional Gas production
volumes being down for the year. A small increase in revenues left funds flow from operations essentially flat year-
over-year. A full provision against all of the TANESCO long-term receivable resulted in a significant loss for the year.
The Company finished 2014 in a strong financial position with US$34 million in working capital and no debt.
16
RESTATEMENT OF PREVIOUSLY ISSUED
CONSOLIDATED STATEMENTS
Orca has restated its consolidated statements of financial position as at 31 December 2013 and 1 January
2013; and its consolidated statement of comprehensive loss, consolidated statement of cash flows and
consolidated statement of changes in shareholders’ equity for the year ended 31 December 2013.
In the course of preparing the Company’s consolidated financial statements for the year ended 31
December 2014, errors were discovered involving the computation of Tanzania income tax from 2005
through and to 30 September 2014. In addition, the Company is correcting reported finance income and
finance costs previously recognized on overdue trade receivables for 2013 and 2014. The restatement
adjustments are described in the paragraphs following the tables below.
The following tables present the impact of the restatement adjustments on the Company’s previously
reported consolidated financial statements as at and for the year ended 31 December 2013, as well as the
impacts on the consolidated statement of financial position as at 1 January 2013. The “Restated” columns
for 2013 reflect final adjusted balances after the restatement.
EFFECT ON CONSOLIDATED STATEMENT
OF COMPREHENSIVE LOSS
(US$000s except per share amounts)
REVENUE
Expenses
Production and distribution expenses
Depletion expense
General and administrative expenses
Exploration asset impairment
Net finance costs
Loss before tax
Income tax expense
Net loss
Foreign currency translation loss from foreign operations
Comprehensive loss
Loss profit after tax per share
Basic and diluted
Weighted average shares outstanding (millions)
YEAR ENDED 31 DECEMBER 2013
As reported
Adjustment
54,718
(1,236)
(4,426)
(12,166)
38,126
(15,428)
(158)
(26,262)
(3,722)
(1,743)
(5,465)
(392)
(5,857)
–
–
(1,236)
(735)
–
309
(1,662)
(513)
(2,175)
–
(2,175)
Restated
53,482
(4,426)
(12,166)
36,890
(16,163)
(158)
(25,953)
(5,384)
(2,256)
(7,640)
(392)
(8,032)
(0.16)
(0.06)
(0.22)
Basic and diluted
34.7
–
34.7
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS
EFFECT ON CONSOLIDATED STATEMENT OF FINANCIAL POSITION
17
AS AT 31 DECEMBER 2013
AS AT 1 JANUARY 2013
As reported Adjustment
Restated As reported Adjustment
Restated
US$’000
ASSETS
Current Assets
Cash
Trade and other receivables
37,215
2,636
39,851
73,495
32,588
–
32,588
16,047
–
–
16,047
73,495
Tax recoverable
Prepayments
Non-Current Assets
14,585
(3,719)
10,866
14,692
(2,483)
12,209
281
–
281
246
–
246
84,669
(1,083)
83,586
104,480
(2,483)
101,997
Long-term trade receivable
29,911
(2,636)
27,275
–
Exploration and evaluation assets
Property, plant and equipment
5,564
90,832
–
–
5,564
5,720
90,832
102,044
126,307
(2,636)
123,671
107,764
–
–
–
–
–
5,720
102,044
107,764
Total Assets
210,976
(3,719)
207,257
212,244
(2,483)
209,761
EQUITY AND LIABILITIES
Current Liabilities
Trade and other payables
Bank loan
Tax payable
Non-Current Liabilites
Deferred income taxes
53,296
857
54,153
45,496
1,166
46,662
1,659
1,958
56,913
4,959
5,816
–
1,659
6,917
5,842
6,322
–
5,842
1,385
7,707
62,729
57,660
2,551
60,211
12,132
(4,063)
8,069
20,399
(1,737)
18,662
Deferred Additional Profits Tax
21,679
–
21,679
8,250
–
8,250
Total Liabilities
Equity
Capital stock
Contributed surplus
Accumulated other
comprehensive income/(loss)
33,811
(4,063)
29,748
28,649
(1,737)
26,912
90,724
1,753
92,477
86,309
814
87,123
85,428
6,482
(303)
–
–
–
85,428
84,983
6,482
6,753
(303)
89
–
–
–
84,983
6,753
89
Accumulated income
28,645
(5,472)
23,173
34,110
(3,297)
30,813
Total Equity and Liabilities
210,976
(3,719)
207,257
212,244
(2,483)
209,761
120,252
(5,472)
114,780
125,935
(3,297)
122,638
18
EFFECT ON CONSOLIDATED STATEMENT OF CASH FLOWS
US$’000
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss
Adjustment for:
Depletion and depreciation
Exploration asset impairment
Provision for doubtful debt / Discount on long-term receivable
Stock-based compensation
Deferred income taxes
Deferred Additional Profits Tax
Interest expense
Unrealised loss/(gain) on foreign exchange
Funds flow from operating activities
Decrease in trade and other receivables
Decrease in tax receivable
Increase in prepayments
Increase in trade and other payables
(Decrease)/increase in taxation payable
(Decrease)/increase in long term receivable
Net cash flows from operating activities
CASH FLOWS USED IN INVESTING ACTIVITIES
Exploration and evaluation expenditures
Property, plant and equipment expenditures
Net cash used in investing activities
CASH FLOWS (USED IN)/FROM FINANCING ACTIVITIES
Bank loan proceeds
Bank loan repayments
Interest paid
Proceeds from exercise of options
Net cash flow used in financing activities
Increase in cash
Cash at the beginning of the year
Effect of change in foreign exchange on cash on hand
Cash at the end of the year
YEAR ENDED 31 DECEMBER 2013
As reported
Adjustment
Restated
(5,465)
(2,175)
(7,640)
12,498
158
27,604
(209)
(8,267)
13,429
678
(586)
39,840
25,845
107
(35)
8,082
(4,364)
(46,984)
22,491
(2)
(1,286)
(1,288)
4,000
(8,183)
(678)
174
(4,687)
16,516
16,047
25
32,588
–
–
(2,636)
–
12,498
158
24,968
(209)
(2,326)
(10,593)
–
–
(309)
(7,446)
–
1,236
–
–
3,574
2,636
13,429
678
(895)
32,394
25,845
1,343
(35)
8,082
(790)
(44,348)
–
22,491
–
–
–
–
–
–
–
–
–
–
–
(2)
(1,286)
(1,288)
4,000
(8,183)
(678)
174
(4,687)
16,516
16,047
25
32,588
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS
EFFECT ON ACCUMULATED INCOME
US$’000
ACCUMULATED INCOME
Balance, beginning of year
Net loss
Balance, end of year
Net changes to prior periods
19
YEAR ENDED 31 DECEMBER 2013
As reported
Adjustment
Restated
34,110
(5,465)
28,645
(3,297)
(2,175)
(5,472)
30,813
(7,640)
23,173
The following is a description of the matters corrected in the restatement adjustments.
Incorrect computation of Tanzania income tax
The Songo Songo PSA, which governs substantially all of the Company’s business in Tanzania, provides
a mechanism to keep the Company whole for income taxes paid in Tanzania. Pursuant to the PSA, the
Company is reimbursed for all income tax payable on income derived from Petroleum Operations (as
defined) by way of an “adjustment factor”, under which the Company is allocated additional Profit Gas
of a value equal to the taxes paid/payable, thus reducing the allocation to the Company’s partner in the
field, the TPDC. The adjustment factor is determined by grossing up tax payable on the current year’s
profit, to the level necessary for the Company to remain neutral in the payment of income tax.
Computation of the adjustment factor, over a number of years, incorrectly included tax paid in respect of
prior years taxes in the gross up calculation. The net effect of which was to overstate reported revenue,
deferred tax expense, net loss and funds flow from operating activities, as well as tax recoverable and
deferred income taxes payable.
In Tanzania, taxpayers are required to pay at least 80% of the estimated year’s taxes in four quarterly
instalments during the year, with a final tax payment for the balance owing to be made in the following
year after completion of the financial statements. The PSA requires that taxable income for any year
include the tax paid in respect of the previous year. The calculation of taxable income for any given year
incorrectly included only the final payment for the previous year, rather than the sum of all of the five
payments. This resulted in the understatement of taxable income.
The combined effect of these errors was an understatement of taxable income and a cumulative under-
payment of tax from 2005 to 31 December 2013 of US$3.5 million, which the Company has reported
and paid. The Tanzania Revenue Authority has the right to assess penalties and interest on overdue
taxes, which if assessed could be up to US$1.6 million and would not be recoverable under the PSA. An
estimate of these penalties and interest has been included in the restatement reflected in the periods for
which they relate.
The cumulative impact of the income tax errors, including applicable penalties and interest, as at 1 January
2013 results in a decrease in accumulated income of US$2.5 million, a decrease in Tax recoverable from
TPDC of US$2.5 million, an increase in tax payable of US$1.4 million, a decrease in deferred income taxes
payable of US$1.4 million.
20
Elimination of Finance Income and Finance Costs relating to TANESCO receivables
In addition, the Company is correcting reported finance income and finance costs previously recognized on
overdue trade receivables for 2013 and 2014. Finance income and finance costs in the amount of $2.6 million
for the year ended 31 December 2013 are eliminated in the restatement. As the finance income was fully
provided for as finance cost, there is no impact on the net loss after tax, accounts receivable or cash flows
from operating activities for 2013. The Company determined that the recognition of finance income, reflecting
interest on amounts overdue from TANESCO, coupled with a full provision of the same amount was in error,
as collection was not probable.
Foreign exchange
In addition, the Company is correcting reported trade and other payables in relation to the calculation of
foreign exchange on amounts due to TPDC whereby payments made to TPDC are required to be made in the
currency collected for gas sales. The cumulative impact of the foreign exchange as at 1 January 2012 results in
an increase in trade and other payables of US$1.2 million, a decrease in accumulated income of US$0.8 million
and an decrease in deferred income taxes of US$0.4 million. The cumulative impact on the 2013 consolidated
financial statements results in an increase in trade and other payables of US$0.9 million, a decrease in net
finance costs of US$0.3 million and a decrease in accumulated income of US$1.2 million.
Cumulative impact of combined income tax, finance income and foreign exchange errors
The cumulative impact of the combined income tax, finance income and foreign exchange errors, including
applicable penalties and interest, on the 2013 consolidated financial statements results in a decrease of
revenue from US$54.7 million to US$53.5 million, an increase in general and administrative expenses from
US$15.4 million to US$16.2 million, a decrease in net finance costs from US$ 26.3 million to US$ 26.0 million,
an increase in income tax expense from US$1.7 million to US$2.3 million, an increase in net loss after tax from
US$5.5 million to US$7.6 million, a decrease in tax recoverable from TPDC from US$14.6 million to US$10.9
million, an increase in trade and other payablss from US$ 53.3 million to US$ 54.2 million, an increase in the
tax payable from US$2.0 million to US$6.9 million, a decrease in deferred income taxes payable from US$12.1
million to US$8.1 million, and a decrease in accumulated income from US$28.6 million to US$23.2 million.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS 21
OPERATING VOLUMES
The total production volume of Protected Gas and Additional Gas for the year ended 31 December 2014 was
32,770 MMcf (2013: 35,153 MMcf) or 89.8 MMcfd (2013: 96.3 MMcfd), net of approximately 0.8 MMcfd (2013:
0.4 MMcfd) consumed locally for fuel gas. The Additional Gas sales volumes for the year were 19,421 MMcf
(2013: 22,435 MMcf) or average daily volumes of 53.2 MMcfd (2013: 61.5 MMcfd). This represents a decrease
in average daily volumes of 13% year on year. Additional Gas sales volumes for Q4 2014 were 4,461 MMcf (Q4
2013: 5,528 MMcf) or average daily volumes of 48.5 MMcfd (Q4 2013: 60.1 MMcfd), a decrease of 19% over
the prior year quarter. The reduction in Additional Gas volumes year/year and quarter/quarter are primarily the
result of declining field productivity and reductions in nominations to TANESCO, marginally offset by increases
in Industrial gas volumes.
The Company’s sales volumes were split between the Industrial and Power sectors as follows:
Gross sales volume (MMcf)
Industrial sector
Power sector
Total volumes
Gross daily sales volume (MMcfd)
Industrial sector
Power sector
Total daily sales volume
QUARTER ENDED
31 DECEMBER
YEAR ENDED
31 DECEMBER
2014
1,084
3,377
4,461
11.8
36.7
48.5
2013
1,143
4,385
5,528
12.4
47.7
60.1
2014
4,598
14,823
19,421
12.6
40.6
53.2
2013
4,478
17,957
22,435
12.3
49.2
61.5
22
Industrial sector
Industrial sales volume increased by 3% to 4,598 MMcf (12.6 MMcfd) from 4,478 MMcf (12.3 MMcfd) in 2013.
Consumption by a major cement producer and a glass company, two major customers accounting for
about 63% of Industrial volumes, remained at the same level as that of 2013. The increase is primarily due to
increased sales to non-textile Industrial customers. A 5% increase in Protected Gas consumption also reduced
the Additional Gas volumes available to the cement producer partly as a result of changes in the gas supply
terms in the renewed sales agreement with the customer made during the year. As part of the new sales
terms, the maximum volume to be supplied at base rate was reduced thus resulted in the customer opting for
maximisation of its Protected Gas allocations.
Fourth quarter Industrial sales volume decreased by 5% to 1,084 MMcf (11.8MMcfd) from 1,143 MMcf (12.4
MMcfd) in the prior year quarter. The decrease is primarily due to a decrease in gas nominations by the cement
producer as a result of changes in gas supply terms in the renewed gas supply agreement that came into effect
in Q3 2014 which offseted increase in gas consumption by the glass company.
Industrial gas volumes decreased by 17% over Q3 2014 (1,304 MMcf or 14.2 MMcfd) primarily due to a decrease
in gas nominations by the cement producer.
Power sector
Power sector sales volumes decreased by 17% to 14,823 MMcf or 40.6 MMcfd, compared to 17,957 MMcf or 49.2
MMcfd in 2013 as a result of a decline in gas production of approximately 8% compared with 2013; increased
availability of hydroelectricity which led to reduction in demand for natural gas-fired power, especially in the
first three quarters of the year, and maintenance work at TANESCO gas fired turbines in the fourth quarter. In
accordance with the PGSA, TANESCO ranks last in the priority list for supply of gas to customers. Declining gas
production therefore impacts most on gas volumes supplied to TANESCO.
Power sector sales volumes decreased by 23% to 3,377 MMcf or 36.7 MMcfd, compared to 4,385 MMcf or
47.7 MMcfd in Q4 2014 as a result of a decline in gas fired power generation of 7% compared with the same
period in 2013. This was the result of TANESCO shutting down a number of gas-fired turbines for maintenance
during Q4 2014 and an increase in Protected Gas nominations by the cement producer following changes in
the terms for supply of gas which came into effect in August 2014. Power sales volumes were down 14% over
Q3 2014 (3,935 MMcf or 42.8 MMcfd) principally as a result of declining gas production, but exacerbated by
maintenance work at TANESCO’s gas-fired turbines and increased Protected Gas nominations by a cement
producer, which reduced Additional Gas volumes available for supply.
SONGO SONGO DELIVERABILITY
As at 31 December 2014, the Company had a field productive capacity of approximately 89 MMcfd, with the
expansion of production volumes limited to 102 MMcfd by the available Songas infrastructure. Production wells
SS-3, SS-5 and SS-9 remain suspended pending workovers. SS-4 continues to be monitored and may have to be
suspended in the future.
There remains no redundant productive capacity until additional wells can be drilled in the field, or existing wells
can be worked over or until refrigeration and compression facilities are installed. A loss or material reduction in
the production of any given well will have a material adverse effect on the total production and funds flow from
operations of the Company.
Significant additional capital expenditure will be required to enable the Songo Songo field to produce 190 MMcfd
in line with the anticipated infrastructure expansion plans of the local government authorities. There are no
contractual commitments either in the PSA or otherwise agreed for capital expenditure at Songo Songo. Any
significant additional capital expenditure by the Company in Tanzania is discretionary and dependent on, among
other things; (i) agreeing commercial terms with TPDC or other buyers regarding the sale of incremental gas
volumes from Songo Songo; (ii) TANESCO receivables being brought up to date, guaranteed or other arrangements
for payment satisfactory to the Company, (iii) the establishment of payment guarantees with the World Bank or
other multi-lateral lending agencies to secure future receipts under any contracts with Government entities; and
(iv) the arrangement of finance with the International Finance Corporation (“IFC”) or other lenders.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS 23
Despite stalled efforts to reach agreement on commercial terms for production expansion to the NNGIP, the
Company advanced work on Songo Songo development. Provided TANESCO maintains its weekly payments
for current deliveries of gas, with any additional amounts to pay down arrears, and subject to financing, the
Company intends to proceed with the first phase workover and drilling programme commencing mid-2015. The
first US$120 million of total Phase I spending of US$150 million is intended to maintain deliverability and provide
sufficient capacity to fill the existing 102 MMcfd Songas infrastructure until the Company can secure commercial
terms for additional gas sales to the NNGIP. See “Contractual Obligations and Committed Capital Investment”.
COMMODITY PRICES
The commodity prices achieved in the different sectors during the year are shown in the table below:
US$/mcf
Average sales price
Industrial sector
Power sector
Weighted average price
QUARTER ENDED
31 DECEMBER
YEAR ENDED
31 DECEMBER
2014
2013
2014
2013
8.24
3.49
4.64
8.38
3.68
4.66
8.61
3.56
4.76
8.27
3.76
4.66
(1)
In Q4 the Company recognized income of US$0.9 million (2014 US$4.2 million) deferred under a take-or-pay provision in an Industrial contract. Under the
contract the customer has three years in which to utilise the deferred income, after which it is released to revenue. These amounts have been deducted from
revenue in calculating the average sales prices achieved.
Industrial sector
The average gas price achieved during the year was US$8.61/mcf up 4% from (2013: US$8.27/mcf). This is a
consequence of (i) an annual price indexation for Industrial customers other than the cement producer, (ii) a
change in the terms under which gas is supplied to the cement producer in Q3 2014, under which the gas price
for the base volume increased by 28%, and (iii) a change in sales mix.
The average Industrial gas price for the fourth quarter was US$8.24/mcf down 2% from Q4 2013 (US$8.38/mcf)
and down 7% from Q3 2014 (US$8.85/mcf). The decrease over the same period for the prior year is the result of
a 17% decrease in heavy fuel oil (“HFO”) prices which offset annual price indexation applied in January each year
and change in gas supply terms to the cement producer in which decrease in nominations in Q4 2014 resulted
in reduced gas volume sold at premium prices. The decrease in Industrial prices from Q3 2014 to Q4 2014 is
a result of a change in sales mix and a 16% decrease in HFO prices. Gas price floors and ceilings incorporated
into Industrial gas sales agreements mitigated the effect of decreases in HFO prices both for the year and for the
quarter.
Power sector
The average sales price to the Power sector was US$3.56/mcf for the year (2013: US$ 3.76 /mcf). The 5%
decrease is due to annual indexation of the base price in July, offset by the impact of a decrease in gas sales
volumes sold at higher marginal prices under the ARGA, which is not in full force and effect, and the Portfolio
Gas Supply Agreement (“PGSA”). As at the date of this report, the ARGA remains an initialled agreement only;
however, the parties thereto, in certain respects, are conducting themselves as though the ARGA is in full force
and effect.
The average sales price to the Power sector in the fourth quarter was US$3.49/mcf, down 5% compared
with US$3.68/mcf in Q4 2013, and down 3% compared to the Q3 2014 price of US$3.60/mcf. The decreases
are the result of reduced sales volumes, which in turn reduced the volumes subject to premium pricing in
accordance with the PGSA and which offset the impact of the annual price indexation which was applied in
July. Higher volumes in both prior comparative periods, Q4 2013 and Q3 2014, resulted in a larger proportion
being sold at a higher price, in accordance with the PGSA.
24
OPERATING REVENUE
Under the terms of the PSA, the Company is responsible for invoicing, collecting and allocating the revenue
from Additional Gas sales.
The Company is able to recover all costs incurred on the exploration, development and operations of the
project out of 75% of the Net Revenues (“Cost Gas”) prior to the distribution of Profit Gas. Any costs not
recovered in any period are carried forward for recovery out of future revenues. Once the Cost Gas has been
recovered, TPDC is able to recover any pre-approved marketing costs.
The Additional Gas sales volumes for 2013 and the first nine months of 2014 were in excess of 50 MMcfd
entitling the Company to a 55% share of Profit Gas revenue (net of Cost Gas recoveries from revenue). In
Q4 2014, Additional Gas sales volumes fell to 48.5 MMcfd and as a result, the Company’s share of Profit Gas
revenue fell to 40%. See “Principal Terms of the Tanzanian PSA and Related Agreements.”
The Company’s share of revenue for the year includes an adjustment to the Cost Pool (as defined herein) in
respect of downstream costs incurred in prior years and a further adjustment relating to non-recoverable items
agreed by the Company in the course of settling the TPDC Cost Pool audit of 2002 to 2009. See “Cost Pool
Adjustments”.
The Company was allocated a total of 63% of Net Revenue in 2014 (2013: 61%), before taking into account the
Cost Pool adjustment as follows:
US$’000
Gross sales revenue
Gross tariff for processing plant and pipeline infrastructure
Gross revenue after tariff
(“Net Revenues”)
Analysed as to:
Company Cost Gas
Company Profit Gas
Cost Pool adjustment
Company operating revenue
TPDC share of revenue
QUARTER ENDED
31 DECEMBER
YEAR ENDED
31 DECEMBER
2014
2013 – restated
2014
2013 – restated
21,601
(3,153)
25,754
(3,854)
96,566
(13,674)
104,474
(16,138)
18,448
21,900
82,892
88,336
3,231
6,902
–
10,133
8,315
18,448
2,040
12,533
–
14,573
7,327
21,900
12,223
37,402
2,994
52,619
30,273
82,892
10,231
43,624
–
53,855
34,481
88,336
The Company’s total revenues for the quarter, and the year ended 31 December 2014, amounted to US$9,645
and US$56,607 respectively, after adjusting the Company’s operating revenues of US$10,133 and US$52,619 by:
i)
subtracting US$941 for income tax for the quarter, and adding US$11,268 for the year. The Company is
liable for income tax in Tanzania, but the income tax is recoverable out of TPDC’s Profit Gas when the tax
is payable. To account for this, revenue is adjusted to include the current income tax charge grossed up at
30%; and,
ii) subtracting US$1,429 and US$7,280 for deferred Additional Profits Tax charged in the quarter and for the
year – this tax is considered a royalty and is presented as a reduction in revenue. The APT charge for the
year includes a reduction in APT of US$936 resulting from the recovery of downstream costs previously
and temporarily excluded from the cost recoverable pool. See note on Cost Pool adjustments below.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS
Revenue presented on the Consolidated Statement of Comprehensive Loss may be reconciled to the operating
revenue as follows:
25
US$’000
Industrial sector
Power sector
Gross sales revenue
Processing and transportation tariff
TPDC share of revenue
Company operating revenue
Additional Profits Tax charge
Current income tax adjustment
Revenue
QUARTER ENDED
YEAR ENDED
December 2013
December 2014
restated December 2014
December
2013 restated
9,825
11,776
21,601
(3,153)
(8,315)
10,133
(1,429)
941
9,645
9,578
16,176
25,754
(3,854)
(7,327)
14,573
(3,025)
3,281
14,829
43,763
52,803
96,566
(13,674)
(30,273)
52,619
(7,280)
11,268
56,607
37,040
67,434
104,474
(16,138)
(34,481)
53,855
(13,429)
13,056
53,482
Company operating revenue decreased 30% in the fourth quarter of 2014 compared with Q4 2013. The
decrease is the result of several factors. A 19% decrease in sales volumes resulted in average daily volumes for
Q4 dropping below 50MMcfd which, in line with the PSA, led to a reduction in the Company’s share of Profit
Gas from 55% to 40%. The reduction in volumes was partially offset by US$0.7 million of deferred income
giving a net 17% drop in gross sales revenue. The increase in TPDC’s share of revenue was almost entirely offset
by a fall in the tariff.
The APT charge for Q4 2014 decreased by 53% compared to Q4 2013; the result of a 45% drop in the
Company’s share of Profit Gas and a decrease in the effective rate of APT to 20.7% (Q3 2013: 24.4%) following
updated reserves data.
The current income tax adjustment includes a prior year reduction and a reduction in the credit for the first
nine months of 2014 resulting from identification of an error in the mechanism for recovery of tax. This has
been adjusted to reflect the prior period impacts.
Company operating revenue for the year ended 31 December 2014 is down 2%, the result of a number factors,
namely a reduction of 13% in sales volumes offset by a 2% increase in the weighted average sales price, a
US$4.0 million credit from deferred income, a US$2.5 million reduction in tariffs due to reduced production
and a credit of the US$3.0 million resulting from the Cost Pool adjustment in Q2 2014.
A reduction of US$6.1 million or 46% in the APT charge for the year is the result of a reduction in the effective
rate from 31.1% to 21.9% and a US$0.9 million credit attributable to the Cost Pool adjustment.
26
COST POOL ADJUSTMENTS
In 2010, following an agreement with TPDC, the Company agreed to temporarily defer the cost recovery of
expenditure associated with development of the downstream network until such time as a mutually acceptable
methodology could be agreed between the Company and TPDC/MEM to unbundle the downstream assets
and related business and to recover the associated cost of the operation outside of the PSA. In 2013 the
Company re-tabled a number of proposals that were economically neutral to the parties; however, these
received no feedback and were subsequently withdrawn. The Company has formally advised TPDC that the
downstream business will remain under the PSA and that related costs would be recovered in accordance with
the terms of the PSA and would no longer be held separately. As a result of recovering this expenditure there
has been a reallocation of Cost Gas and Profit Gas between TPDC and the Company.
During the ongoing discussions concerning the disputed US$34 million TPDC Cost Pool audit claim, items
totalling US$1.0 million were agreed by the Company as non-recoverable and consequently were removed
from the Cost Pool in the second quarter of 2014.
The following table shows the impact on the Company’s operating revenue, for the year to 31 December
2014, of adjusting the Cost Pool. The net amount was recovered from TPDC’s share of revenue in the second
quarter as follows:
US$’000
Non-recoverable costs
Recoverable costs 2011-2013
Cost Gas recorded in the period
Reduction in Profit Gas in the period
Net impact on Company share of operating revenue
YEAR ENDED
31 DECEMBER 2014
(1,024)
7,360
6,336
(3,342)
2,994
PROCESSING AND TRANSPORTATION TARIFF
The Company effectively pays a tariff of US$0.30/mcf for sales between 70 MMcfd and 90 MMcfd and
US$0.40/mcf for volumes above 90 MMcfd in addition to the regulated tariff of US$0.59/mcf payable to
Songas. The charge for the quarter and for the year were US$3.2 million (Q4 2013: US$3.9 million) and US$13.7
million (2013: US$16.1 million) respectively. Reductions in the tariff for the year and the quarter are a result of
lower volumes over the periods.
PRODUCTION AND DISTRIBUTION EXPENSES
Well maintenance costs are allocated between Protected Gas and Additional Gas in proportion to their
respective sales during the period. The total cost of maintenance for the quarter was US$500 (Q4 2013:
US$439) and for the year, US$1,193 (2013: US$863). For the quarter and for the year the amounts allocated for
Additional Gas were US$277 (Q4 2013: US$272) and US$796 (2013: US$546) respectively. The increase in the
year is the result of focusing on engineering and planning in respect of well workovers.
Other field and operating costs include an apportionment of the annual PSA licence costs, regulatory fees,
insurance, some costs associated with the evaluation of the reserves, and the cost of personnel which are not
recoverable from Songas.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS Distribution costs represent the direct cost of maintaining the ring main distribution pipeline and pressure
reduction station (security, insurance and personnel). Ring main distribution costs were US$603 (Q4 2013:
US$315) in the quarter and US$2,323 (2013: US$1,406) for the year. The increase in maintenance costs is due
to pigging operations, for which the Company procured substantial additional spares, and had to carry out
repairs on one of its pressure reduction stations. In addition, meter testing led to the replacement of four
customer meters. These production and distribution costs are summarized in the table below:
27
QUARTER ENDED 31 DECEMBER
YEAR ENDED 31 DECEMBER
2014
277
788
1,065
603
1,668
2013
272
1,275
1,547
315
1,862
2014
796
2,374
3,170
2,323
5,493
2013
546
2,474
3,020
1,406
4,426
Share of well maintenance
Other field and operating costs
Ringmain distribution costs
Production and distribution expenses
OPERATING NETBACKS
The netback per mcf before general and administrative costs, overhead, tax and APT may be analysed as
follows:
US$/mcf
Gas price – Industrial
Gas price – Power
Weighted average price for gas
Tariff
TPDC share of revenue
Net selling price
Well maintenance and other operating costs
Distribution costs
Operating netback
QUARTER ENDED 31 DECEMBER
YEAR ENDED 31 DECEMBER
2014
2013 restated
2014
2013 restated
8.24
3.49
4.64
(0.71)
(1.86)
2.07
(0.24)
(0.14)
1.69
8.38
3.69
4.66
(0.70)
(1.33)
2.63
(0.28)
(0.06)
2.29
8.61
3.56
4.76
(0.70)
(1.56)
2.50
(0.16)
(0.12)
2.22
8.27
3.76
4.66
(0.72)
(1.54)
2.40
(0.14)
(0.06)
2.20
The operating netback for the quarter decreased by 26% from US$2.29/mcf in Q4 2013 to US$1.69/mcf in Q4
2014; this was the result of several factors. Lower Power sales volumes led to a reduction in sales at premium
prices and a 12% drop in the average price, largely offsetting the effect of indexation in July and the effect of a
5% increase in the weighted average Industrial gas price. The 3% increase in the TPDC share of revenue on a
unit basis is a direct result of the lower sales volume.
The operating netback for the year increased 1% to US$2.22/mcf from US$2.20/mcf in 2013. Overall sales
volumes dropped 13%, however the weighted average price for the year rose 2%. On a per Mcf basis TPDC’s
share of revenue rose 1%; this is the net of a reduction to recover downstream costs in Q2 which accounted
for US$0.20/mcf offset by a higher TPDC share resulting from reduced production. The increased netback
resulting from the change in price and sales mix was offset by increases in field operating and distribution
costs.
28
GENERAL AND ADMINISTRATIVE EXPENSES
Administrative expenses (“G&A”) may be analysed as follows:
US$’000
Employee & related costs
Stock based compensation
Office costs
Marketing & business development costs
Reporting, regulatory & corporate
Tax penalties
General and administrative expenses
QUARTER ENDED 31 DECEMBER
YEAR ENDED 31 DECEMBER
2014
2013 restated
2014
2013 restated
2,618
(1,101)
1,060
(25)
466
195
3,213
2,281
82
1,812
38
930
182
5,325
7,115
3,482
3,660
41
3,346
270
17,914
7,399
(209)
4,635
773
2,830
735
16,163
G&A includes the costs of running the natural gas distribution business in Tanzania which is recoverable as
Cost Gas and which is relatively fixed in nature. The increase in reporting, regulatory and corporate expenses
is primarily the result of additional legal costs associated with the various contractual and dispute resolution
matters which are ongoing. The prior period error in computing taxes resulted in the Company underpaying
income tax of US$3.5 million. The Company is liable for penalties and interest for late payment and whilst the
Company has requested the tax authority to exercise its statutory authority to waive same, management has
recognised a provision of US$1.5 million in the G&A expenses across the years affected by the restatement.
Excluding stock based compensation and the tax penalty, G&A averaged US$1.1 million (Q4 2013: US$1.8
million) per month during the quarter and US$1.5 million (2013: US$1.3 million) per month over the year.
STOCK BASED COMPENSATION
The breakdown of the costs incurred in relation to stock based compensation is detailed in the table below:
US$’000
December 2014
December 2013
December 2014
December 2013
QUARTER ENDED
YEAR ENDED
Stock appreciation rights
Restricted stock units
Stock-based compensation
(537)
(564)
(1,101)
82
–
82
1,369
2,113
3,482
(209)
–
(209)
400,000 stock options were outstanding as at 31 December 2014 compared to 1,742,400 at the end of 2013.
No options were granted during the quarter (Q4 2013: nil).
2,910,000 stock appreciation rights (“SARs”) were outstanding as at 31 December 2014 compared to 1,030,000
as at 31 December 2013. 1,780,000 SARs were granted in January with an exercise price of CDN$2.30, a
five-year term and which vest in five equal instalments, the first fifth on the anniversary of the grant date.
In September the Company issued 792,391 Restricted Stock Units (“RSUs”) with an award price of CDN$0.01
As SARs and RSUs are settled in cash, they are re-valued at each reporting date using the Black-Scholes option
pricing model with the resulting liability being recognised in trade and other payables. In the valuation of stock
appreciation rights and restricted stock units at the reporting date, the following assumptions have been made:
a risk free rate of interest of 1.75%; stock volatility of 52.4% to 60.7%; 0% dividend yield; 0% forfeiture; and a
closing price of CDN$2.90 per Class B share.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS As at 31 December 2014, a total accrued liability of US$3.4 million (2013: US$0.4 million) has been recognised
in relation to SARS and RSUs. The Company recognised a credit of US$1.0 million (Q4 2013: expense US$0.1
million) for the quarter and for the year ended 31 December 2014 an expense of US$3.5 million (2013: credit
US$0.2 million). The increase in the cost of SARs year over year is due to the granting of an additional 1.8
million SARs in January 2014 and an increase in the market value of the Company’s shares.
29
NET FINANCE COSTS
The movement in net financing costs is summarized in the table below:
US$’000
Interest charged on overdue trade receivables
Gain on disposal of motor vehicle
Finance income
Interest expense
Net foreign exchange gain/(loss)
Provision for doubtful debts /
Discount on long-term receivable
Finance costs
Net finance income/(expense)
QUARTER ENDED
31 DECEMBER
YEAR ENDED
31 DECEMBER
2014
2013 restated
2014
2013 restated
12
–
12
–
(4,814)
(35,127)
(39,941)
(39,929)
(86)
10
(76)
(92)
596
98
–
98
(24)
(4,437)
–
10
10
(678)
(317)
(7,937)
(7,433)
(7,509)
(37,047)
(24,968)
(41,508)
(41,410)
(25,963)
(25,953)
The decrease in interest expense is the result of repaying the bank loan in full by the end of February 2014.
The foreign exchange gain/loss reflects the impact of movements in the value of the Tanzanian Shilling against
the US Dollar during the period on outstanding customer/supplier balances and bank accounts in Tanzanian
Shillings.
TANESCO
At 31 December 2014, TANESCO owed the Company US$59.8 million excluding interest (of which arrears
were US$52.2 million) compared to US$54.0 million (including arrears of US$44.3 million) as at 31 December
2013. During the year, the Company received a total of US$46.7 million (2013: US$49.6 million) from TANESCO
against sales totaling US$54.7 million (2013: US$72.9 million). Current TANESCO receivables as at 31 December
2014 amounted to US$7.7 million (2013 US$9.6 million). Since the year-end, TANESCO has paid the Company
US$18.7 million in 2015, and as at the date of this report the total TANESCO receivable is US$52.9 million (of
which US$52.2 million has been provided for). The amounts owed do not include interest billed to TANESCO.
Beginning in May 2014, TANESCO commenced a series of payments for current and past gas deliveries of
US$1.8 million received approximately weekly. Management estimated that if these payments continued they
would result in approximately US$1.5 million per month credited against arrears. During Q4 2014 TANESCO
made only one payment, although subsequent to the year-end TANESCO resumed weekly payments and
as of the date of this report the Company has received US$18.7 million in 2015. Whilst weekly payments
against current deliveries have re-commenced, there is still no set schedule or repayment plan for TANESCO
arrears and payments continue to be irregular and unpredictable. As a result, there is significant doubt about
TANESCO’s ability and/or willingness to settle arrears.
Pursuant to its rights under the PGSA, the Company, on 2 April 2014, served a Notice of Dispute to TANESCO
demanding payment in full to collect the arrears, as well examining the Company’s legal and contractual
options to mitigate a further increase in arrears, including but not limited to suspending gas deliveries to
TANESCO. The Notice of Dispute has remained in effect whilst the Company sought a mutually acceptable
payment plan to clear the arrears within an acceptable time frame. In April 2014 and again in May, TANESCO
advised the Company of its intention to make weekly payments of TZS 3.0 billion (approximately US$1.8
million) to the Company against ongoing deliveries of gas as well as continue to seek third-party financing to
30
repay the balance of arrears. TANESCO has confirmed the understanding reached between the parties in Q2
2013 that payments would be applied firstly to pay for the current gas deliveries, and that remaining amounts,
if any, would be applied to the accumulated arrears.
At 31 December 2014, Company has re-assessed the TANESCO arrears in light of (i) the discontinuance of
weekly payments during Q4 2014; (ii) the fact that TANESCO did not pay down substantially all of the arrears
by year-end pursuant to a formal commitment made earlier during the year which was tied to Government
receipt of World Bank funding; (iii) the lack of a definitive plan to repay arrears in light of (ii) above; and (iv) the
absence of any evidence of the availability of external funding for TANESCO, including World Bank funding.
As a result of increased uncertainty with respect to the timing and amount of ultimate collection of amounts
in arrears, the Company recorded a provision for doubtful accounts against the entire long-term receivable of
US$52.2 million as at 31 December 2014. Amounts collected with respect to the long-term receivable in the
future will be reflected in earnings when payment is received. Notwithstanding this provision, the Company
and TANESCO continue to operate in accordance with the terms of the Portfolio Gas Supply Agreement
and in accordance with the understanding between the Company and TANESCO from Q2 2013 whereby
natural gas continues to be delivered by the Company and TANESCO would pay for current deliveries on
a current basis with payments to be applied firstly to pay for the current deliveries and any excess amount
applied to accumulated arrears. This provision against the TANESCO long-term receivable will not prejudice
the Company’s rights to payment in full or its ability to pursue collection in accordance with the terms of the
agreement with TANESCO. Whilst the Company is unable to recognise interest revenue in accordance with
International Accounting Standards 18 – Revenue, it will continue to charge TANESCO interest in accordance
with the terms of the PGSA.
TAXATION
Income Tax
Under the terms of the PSA with TPDC and the Government of Tanzania, the Company is liable for income
tax in Tanzania at the corporate tax rate of 30%. However, the PSA provides a mechanism by which income
tax payable is recovered from TPDC by reducing TPDC’s share of Profit Gas and increasing the allocation to
the Company. This is reflected in the accounts by increasing the Company’s share of revenue by an amount
equivalent to income taxes payable.
As at 31 December 2014, 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$7.6
million (31 December 2013: liability US$8.1 million). During the quarter there was a deferred tax increase of
US$1.3 million compared with a reduction of US$7.2 million in Q4 2013. The deferred tax has no impact on
cash flow until it becomes a current income tax, at which point the tax is paid and recovered from TPDC’s
share of Profit Gas.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS 31
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 (“PPI”), an Additional Profits
Tax is payable.
The timing and the effective rate of APT depends on the realised value of Profit Gas which in turns depends
of the level of expenditure. The Company provides for APT by forecasting annually the total APT payable as a
proportion of the forecast Profit Gas over the term of the PSA. The forecast takes into account the timing of
future development capital spending.
The effective APT rate of 20.7% (Q4 2013: 24.4%) has been applied to Profit Gas of US$6.9 million (Q4 2013:
US$12.5 million) for the quarter, and an average effective rate of 21.9% (2013: 30.8%) has been applied to Profit
Gas of US$37.4 million (2013: US$43.6 million) for the year ended 31 December 2014. Accordingly, US$1.4
million (Q4 2013: US$3.0 million) and US$7.3 million (2013: US$13.4 million) has been netted off revenue for
the quarter and for the year ended 31 December 2014 respectively. The year-to-date APT charge includes a
reduction of US$0.9 million, reflecting the impact of recovering downstream costs on cumulative Profit Gas,
as a result of the US$3.3 million Profit Gas adjustment identified in the Cost Pool adjustment detailed above.
US$’000
Deferred APT
QUARTER ENDED 31 DECEMBER
YEAR ENDED 31 DECEMBER
2014
1,429
2013
3,025
2014
7,280
2013
13,429
DEPLETION AND DEPRECIATION
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 2014 the proven reserves estimated to be produced over the term of the PSA licence, as evaluated
by the independent reservoir engineers, McDaniel & Associates Consultants Ltd., were 450 Bcf (2013: 475.7
Bcf). A depletion expense of US$3.1 million (Q4 2013: US$3.7 million) for the quarter and US$13.6 million
for the year (2013: US$12.2 million) has been recorded in the accounts; the increase for the year is the
result of a 13% decrease in sales volumes and a 30% increase in the average depletion rate to US$0.70/mcf
(2013: US$0.54/mcf).
Non-natural gas properties are depreciated as follows:
Leasehold improvements
Over remaining life of the lease
Computer equipment
Vehicles
Fixtures and fittings
3 years
3 years
3 years
CARRYING AMOUNT 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 impaired
and recorded in earnings.
32
FUNDS FLOW FROM OPERATING ACTIVITIES
Funds flow from operating activities before working capital changes was US$8.7 million for Q4 2014 (Q4 2013:
US$7.4 million) and US$32.4 million (2013: US$32.4 million) for the year.
US$’000
Funds flow from operating activities
Working capital adjustments (1)
Cash flows from operating activities
Cash used in investing activities
Cash from/(used in) financing activities
Increase in cash
Effect of change in foreign exchange on cash in hand
Net (decrease)/increase in cash
(1) See Consolidated Statement of Cash Flows
QUARTER ENDED
31 DECEMBER
YEAR ENDED
31 DECEMBER
2014
2013 restated
2014
2013 restated
8,733
(10,969)
(2,236)
(718)
(9)
(2,963)
(2,494)
(5,457)
7,412
(1,846)
5,566
(136)
(3,157)
2,273
25
32,436
(2,679)
29,757
(1,312)
(1,600)
26,845
(1,774)
32,394
(9,903)
22,491
(1,288)
(4,687)
16,516
25
2,298
25,071
16,541
Operating revenues with respect to TANESCO and Songas are not fully reflected in the overall cash position
as a consequence of the failure of both TANESCO and Songas to pay their invoices in full during the period.
CAPITAL EXPENDITURE
The Company incurred US$0.5 million in relation to engineering and planning relating to planned well
workovers and subsequent drilling activities, plus a further US$0.5 million of drilling materials for use on the
planned 2015 drilling programme.
US$’000
December 2014 December 2013 December 2014 December 2013
QUARTER ENDED
YEAR ENDED
Geological and geophysical and well drilling
Pipelines and infrastructure
Other equipment
522
193
3
718
(1,370)
548
958
136
913
133
266
1,312
(608)
724
1,172
1,288
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS
WORKING CAPITAL
Working capital as at 31 December 2014 was US$34.1 million (31 December 2013: US$20.9 million) and may be
analysed as follows:
33
US$’000
Cash
Trade and other receivables
TANESCO
Songas
Other trade debtors
Songas gas plant operations
Other receivables
Provision for doubtful accounts
Tax recoverable
Prepayments
Trade and other payables
TPDC
Songas
Other trade payables
Deferred income
Accrued liabilities
Bank loan
Tax payable
Working capital (1)
YEAR ENDED 31 DECEMBER
2014
7,671
23,864
7,532
19,300
773
(9,816)
33,409
28,871
1,961
2,780
9,726
57,659
49,324
11,815
642
119,440
76,747
–
8,545
34,148
9,624
11,560
10,874
13,280
2,408
(7,895)
21,501
15,355
3,857
6,271
7,169
2013 restated
32,588
39,851
10,866
281
83,586
54,153
1,659
6,917
20,857
Notes:
(1) Working capital as at 31 December 2014 includes a TANESCO receivable (excluding interest) of US$7.7 million (31 December 2013: US$9.6 million).
Management has placed a doubtful debt provision against the long-term receivables in excess of 60 days totaling US$52.2 million (31 December 2013:
US$43.3 million). The total of long- and short-term TANESCO receivables, including interest, as at 31 December 2014 was US$64.6 million. The financial
statements do not recognise the interest receivable from TANESCO as it does not meet IAS 18 income recognition criteria. The Company is however actively
pursuing the collection of all the receivables and the interest that has been charged to TANESCO.
Working capital as at 31 December 2014 increased by 64% over 31 December 2013 and but fell 23% during
the quarter, primarily as a result of TANESCO suspending weekly payments for gas, together with an increase
in tax payable in respect of prior years. The Company did not incur any major capital expenditure during the
quarter. Other significant points are:
• There are no restrictions on the movement of cash from Mauritius or Tanzania, and currently the majority
of cash is outside of Tanzania. As at the date of this report, approximately 88% of the Company’s cash was
held outside of Tanzania.
•
Since the quarter end the Company has received US$18.7 million from TANESCO.
• Of the US$7.5 million relating to other trade debtors US$7.3 million had been received as at the date of this
report.
• The balance of US$33.4 million payable to TPDC represents the remaining balance of its share of revenue
as at 31 December 2014.
34
BANK LOAN
The loan was fully paid by February 2014. Total payments during the year ended 31 December 2014 were
US$1.7 million (2013: US$8.2 million).
SHAREHOLDERS’ EQUITY AND OUTSTANDING SHARE DATA
There were 34,914,932 million shares outstanding as at 31 December 2014 which may be analysed as follows:
Number of shares (‘000)
Shares outstanding
Class A shares
Class B shares
Class A and Class B shares outstanding
Convertible securities
Options
Fully diluted Class A and Class B shares
Weighted average
Class A and Class B shares
Convertible securities
Options
Weighted average diluted Class A and Class B shares
AS AT 31 DECEMBER
2014
2013
1,751
33,164
34,915
400
35,315
1,751
33,072
34,823
1,742
36,565
34,863
34,719
–
–
34,863
34,719
As at 30 April 2015, there were a total of 1,750,517 Class A Common Voting Shares (“Class A shares”) and
33,147,695 Class B Subordinated Voting Shares (“Class B shares”) outstanding.
RELATED PARTY TRANSACTIONS
One of the non-executive Directors is a partner at a law firm that provides legal advice to the Company and
its subsidiaries. During the quarter, the Company incurred US$0.1 million (Q4 2013: US$nil) and for the year
ended 31 December US$0.2 million (2013: US$0.1 million) to this firm for services provided. The transactions
with this related party were made at the exchange amount. The Chief Financial Officer provided services to
the Company through a consulting agreement with a personal services company. During the quarter the
Company incurred US$0.1 million (Q4 2013 US$0.1 million) and for the year ended 31 December US$0.6
million (2013: US$0.6 million) to this firm for services provided. As at 31 December 2014 the Company has a
total of US$nil (2013: US$nil) recorded in trade and other payables in relation to the related parties.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS
35
CONTRACTUAL OBLIGATIONS
AND COMMITTED CAPITAL INVESTMENT
Protected Gas
Under the terms of the original gas agreement for the Songo Songo project (“Gas Agreement”), in the event
that there is a shortfall/insufficiency in Protected Gas as a consequence of the sale of Additional Gas, then
the Company is liable to pay the difference between the price of Protected Gas (US$0.55/MMbtu escalated)
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 (127.7 Bcf as at 31 December 2014). The Company did not have a shortfall during
the reporting period and does not anticipate a shortfall arising during the term of the Protected Gas delivery
obligation to July 2024.
The Gas Agreement may be superseded by an initialed ARGA. The unsigned ARGA provides clarification of
the Protected Gas volumes and removes all terms dealing with the security of the Protected Gas and contract
terms dealing with the consequences of any insufficiency are dealt with in a new Insufficiency Agreement (“IA”).
The IA specifies terms under which Songas may demand cash security in order to keep it whole in the event of
a Protected Gas insufficiency. Should the IA be signed, it will govern the basis for determining security. Under
the provisional terms of the IA, when it is calculated that funding is required, the Company is required to fund
an escrow account at a rate of US$2.00/MMbtu on all Industrial Additional Gas sales out of its and TPDC’s share
of revenue, and TANESCO shall contribute the same amount on Additional Gas sales to the Power sector. The
funds provide security for Songas in the event of an insufficiency of Protected Gas. The Company is actively
monitoring the reservoir and, supported by the report of its independent engineers, does not anticipate that a
liability will occur in this respect. As at the date of this report, the ARGA remains an intitialled agreement only,
however the parties thereto, in certain respects, are conducting themselves as though the ARGA is in full force
and effect.
Re-Rating Agreement
In 2011, the Company signed a re-rating agreement with TANESCO and Songas (the “Re-Rating Agreement”) to
increase the gas processing capacity to a maximum of 110 MMcfd (the pipeline and pressure requirements at
the Ubungo power plant restrict the infrastructure capacity to a maximum of 102 MMcfd). Under the terms of
the Re-Rating Agreement, the Company effectively pays an additional tariff of US$0.30/mcf for sales between
70 MMcfd and 90 MMcfd and US$0.40/mcf for volumes above 90 MMcfd in addition to the tariff of US$0.59/
mcf payable to Songas as set by the energy regulator, EWURA.
Under the terms of this agreement, the Company agreed to indemnify Songas for damage to its facilities
caused by the re-rating, up to a maximum of US$15 million, but only to the extent that this was not already
covered by indemnities from TANESCO’s or Songas’ insurance policies. The Re-Rating Agreement expired
on 31st December 2012 and in September 2013 was extended by Songas to 31 December 2013. At this time,
the Company knows of no reason to de-rate the Songas plant. Since 31 December 2013 production has
continued within the higher rated limit and, given the Government’s interest in pursuing further development
and increasing gas production, the Company expects this to continue. However there are no assurances that
this will occur.
Portfolio Gas Supply Agreement
On 17 June 2011, a long term (to June 2023) PGSA was signed between TANESCO (as the buyer) and the
Company and TPDC (collectively as the seller). Under the PGSA, the seller is obligated, subject to infrastructure
capacity, to sell a maximum of approximately 37 MMcfd for use in any of TANESCO’s current power plants
except those operated by Songas at Ubungo. Under the agreement, the basic wellhead price of approximately
US$2.88/mcf increased to US$2.93/mcf on 1 July 2014. Any volumes of gas delivered under the PGSA in
excess of 36 MMcfd are subject to a 150% increase in the basic wellhead gas price.
36
Operating leases
The Company has two office rental agreements, one in Dar es Salaam, Tanzania and one in Winchester, United
Kingdom. The agreement in Dar es Salaam was entered into on 1 November 2013 and expires on 31 October
2015 at an annual rent of US$401 thousand. The agreement in Winchester expires on 25 September 2022
and is at an annual rental of GBP35 thousand (US$58 thousand) per annum during 2012 and 2013 and GBP71
thousand (US$115 thousand) per annum thereafter. The costs of these leases are recognised in the General
and Administrative expenses.
Capital Commitments
Italy
On 31 May 2010, the Company signed an agreement with Petroceltic International plc (“Petroceltic”) to farm
in on Petroceltic’s Central Adriatic B.R268.RG Permit offshore Italy. The farm-in commits the Company to
fund 30% of the Elsa-2 appraisal well up to a maximum of US$11.5 million to earn a 15% working interest in the
permit. Thereafter, the Company will fund all future costs relating to the well and the permit in proportion to its
participating interest. The Company has also agreed to pay Petroceltic fifteen per cent (15%) of the back costs
in relation to the well up to a maximum of US$0.5 million.
No activity has occurred on the Adriatic Sea block during 2014. In 2012, a new law modified restrictions on
offshore oil and gas exploration and production originally introduced by DLGS 128/2010 in August 2010. The
Elsa-2 appraisal well is now expected to be drilled in 2016 following finalisation of an environmental impact
study. The Company will not be liable to any costs associated with the drilling of Elsa-2 until a rig contract is
signed. As of the date of this report, there is no rig contract. There are no further capital commitments in Italy.
Songo Songo
There are no contractual commitments for exploration or development drilling or other field development
either in the PSA or otherwise agreed which would give rise to significant capital expenditure at Songo Songo.
Any significant additional capital expenditure in Tanzania is discretionary and dependent on, among other
things: (i) agreeing commercial terms with TPDC or other buyers regarding the sale of incremental gas volumes
from Songo Songo; (ii) TANESCO receivables being brought up to date, guaranteed or other arrangements for
payment satisfactory to the Company, (iii) the establishment of payment guarantees with the World Bank or
other multi-lateral lending agencies to secure future receipts under any contracts with Government entities;
and (iv) the arrangement of financing with the IFC or other lenders.
Significant additional capital expenditure will be required to both maintain production levels and fill the existing
Songas infrastructure to 105 MMscfd capacity, as well as enable the Songo Songo field to produce 190 MMcfd
in line with gas supply requirements of the NNGIP anticipated to be commissioned in 2015. In the absence of
a commercial agreement with TPDC for volumes dedicated to the NNGIP, and with TANESCO maintaining its
weekly payments for current gas deliveries and a small amount towards arrears, the Company intends, subject
to finance, to proceed with the first phase of a discretionary workover and drilling programme to maintain
deliverability and fill the existing Songas infrastructure to capacity for the life of the Songo Songo licence
(2026). Phase I spending is estimated to be approximately US$150 million, of which the first US$120 million
to be spent on offshore workovers and drilling (the “Offshore Programme”) is expected to be spent over 2015
to 2017, which spending would be intended to restore field deliverability and provide sufficient natural gas
production to fill the Songas plant and pipeline to capacity for the greater portion of the remaining life of the
Songo Songo licence. When commercial terms are agreed with TPDC for the supply of gas to the NNGIP, and
in so doing justify bringing field production to approximately 190 MMscfd, the Company would contemplate
undertaking the balance of Phase I at an additional cost estimated to be approximately US$30 million.
The Offshore Programme is estimated to be approximately US$120 million of which the Company is seeking
finance for half. There is no assurance that financing is available and on acceptable commercial terms.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS 37
Summary of planned capital expenditure
(US$ millions)
Well workovers
Development drilling
Exploration/appraisal drilling
Refrigeration and facilities
G&G/Other
Total capital spending
Tanzania – Songo Songo
Offshore
Programme
Onshore
Programme
75.4
32.6
–
8.5
3.8
120.3
26.0
–
–
4.0
30.0
Italy
Elsa (1)
–
–
12.3
–
–
12.3
Total
101.4
32.6
12.3
12.5
3.8
162.6
1) The expenditure in relation to Elsa is not discretionary after a rig contract is signed. At the date of this report no rig contract has been signed.
CONTINGENCIES
Downstream unbundling
The separation or unbundling of the downstream assets currently in the PSA has been an objective of TPDC
and MEM for some time. Unbundling was an issue raised by TPDC in the 2012 GNT negotiations and by MEM
in the National Natural Gas Policy issued in 2013, which contemplates TPDC as a monopoly aggregator and
distributor of gas. In the context of the gas policy, TPDC and MEM have indicated that they wish the Company
to unbundle the downstream distribution business in Tanzania. The methodology for this has been discussed
with TPDC in the course of GNT negotiations. During 2013, the Company tabled a proposal with alternative
mechanisms to unbundle the downstream from the PSA which were economically neutral to the parties.
TPDC did not respond to the proposal and it was later withdrawn by the Company in connection with the
termination of negotiations arising from the GNT, and TPDC was advised that the downstream would remain
in the PSA until mutually agreed otherwise. The disposition of the downstream business will be addressed at
such a time as there is a conflict between new legislation and the Company’s rights under the PSA. The results
for the year reflect the impact of fully recovering downstream costs previously and temporarily excluded from
the cost recoverable pool pending resolution of the unbundling of the downstream business and the related
assets – see Cost Pool Adjustments.
TPDC Back-in
TPDC has previously indicated a wish to exercise its right under the PSA to ‘back in’ to the Songo Songo field
development and a further wish to convert this into a carried working interest in the PSA. The current terms
of the PSA require TPDC to provide formal notice in a defined period and contribute a proportion of the costs
of any development, sharing in the risks in return for an additional share of the gas. To date, TPDC has not
contributed any costs. TPDC back-in rights and the potential conversion of these rights into a carried working
interest were discussed along with other issues, however there were no amendments made to the PSA. As
such the Company continues to stand behind the original terms of the PSA. Should an amendment to the PSA
be agreed in future relating to back-in rights, the impact on reserves and accounting estimates will be assessed
at that time and reflected prospectively.
For the purpose of the reserves certification as at 31 December 2014, it was assumed that TPDC will elect to
‘back-in’ for 20% for all future new drilling activities with-in the prescribed period as determined by the current
development plan and this is reflected in the Company’s net reserve position.
38
Cost recovery
TPDC conducted an audit of the historic Cost Pool and in 2011 disputed approximately US$34 million of costs
that had been recovered from the Cost Pool from 2002 through to 2009. The Company has contended
that the disputed costs were appropriately incurred on the Songo Songo project in accordance with the
terms of the PSA. Undertakings to resolve this matter were an outcome of negotiations and the matter was
referred to the Controller and Auditor General (“CAG”), head of the National Audit Office of Tanzania. With no
progress on resolving the matter, the Company served a Notice of Dispute on TPDC to put the matter to a
definitive timeline for resolution, following which the CAG appointed an international independent audit firm
to review the disputed costs. The work of the CAG has been completed and TPDC has reviewed its findings.
TPDC and Company senior management have held discussions, and currently await the appointment of an
independent specialist to assist the parties in reaching agreement on costs that are still subject to dispute. The
Company has agreed a number of small adjustments, totaling approximately US$1.0 million, and these were
removed from the Cost Pool during the year– see “Cost Pool Adjustments.” If the matter is not resolved to
the Company’s satisfaction, it intends to proceed to arbitration via the International Centre for Settlement of
Investment Disputes (“ICSID”) pursuant to the terms of the PSA.
TPDC marketing costs
Under the PSA, all reasonable marketing costs including those incurred by TPDC, with the prior approval
by the Company, are recoverable. TPDC has to date attempted to claim US$3.6 million in marketing costs
from the Company. Management reviewed the claims and can demonstrate that there was no prior approval
for such costs, no supporting documentation provided evidencing the expenditure, and further believes the
nature of the costs to be unreasonable and not related to marketing the downstream business. Accordingly
the Company has rejected the claim by TPDC.
Taxation
During 2013 the Company received a number of assessments for additional tax from the Tanzania Revenue
Authority (“TRA”), which together with interest penalties total US$16.9 million. Management, together with
tax advisors, have reviewed each of the assessments and believe them to be without merit. The Company
has appealed against assessments for additional withholding tax and employment related taxes, and has filed
formal objections against TRA’s claims for additional corporation tax and VAT. If the Company is unsuccessful
in its appeals against these assessments, the amounts of interest and penalties could be materially higher.
The Tax Revenue Appeals Board (“TRAB”) considered the Company’s appeal against a withholding tax
assessment of US$2.2 million in March 2013 and upheld the assessment. The Company then appealed to
Tax Revenue Appeals Tribunal whose decision is awaited. Although a similar appeal to the Tribunal has been
decided in favour of TRA, management continues to believe this assessment is flawed and, if necessary, will
pursue the case in the Court of Appeal where a similar case is currently being heard.
The Company, based on legal counsel’s advice, believes it has a strong case, on the basis of tax legislation
and the terms of the PSA, for its objection to the additional income tax assessment of US$7.1 million, including
penalties. During the year, TRA notified the Company that TRA would not accept the objection relating to 2009
and issued a notice confirming the assessment for US$2.3 million. The Company has lodged an appeal against
this assessment with the TRAB. In the event that the Company’s 2008 and 2010 objections are rejected and
subsequent appeals are overturned, any additional tax payable will be recoverable from TPDC under the terms
the PSA.
The Company has filed an objection against a further assessment of VAT, which together with penalties totals
US$6.9 million. Again, the Company, based on legal counsel’s advice, believes that it has strong grounds for
objecting to this assessment and accordingly has made no provision.
The Company has received an assessment of US$0.7 million in respect of employment related taxes which
TRA believe to have been underpaid. The Company does not accept TRA’s finding and has appealed.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS 39
Management continues to review the progress of the above appeals and objections and, as of the date of this
report, does not believe any provision is required.
During the year TRA conducted an audit of the Company’s tax returns for 2011 and issued their audit findings
which indicated that additional taxes amounting to US$1.1 million should be paid in respect of employment
costs, income and withholding taxes. Management and reviewed the findings which it considers to be without
merit and is preparing to respond to TRA.
NEW ACCOUNTING POLICIES
On 1 January, 2014 the Company adopted new standards with respect to Employee Contributions (Amendments
to IAS 19), Offsetting Financial Assets and Financial Liabilities (Amendments to IAS 32) and Liability for Levies
(IFRIC 21). The adoption of these amendments and standards had no impact on the amounts recorded in the
consolidated financial statements or on the comparative periods.
IFRS 9 Financial Instruments (2014) is effective 1 January, 2018 with early adoption permitted. IFRS 9 provides
guidelines for recognizing and measuring financial assets and liabilities and other contracts to buy or sell
non-financial items. The objective is to provide readers with information for the assessment of amounts,
timing and probability of the entity’s future cash flows. This Standard replaces IAS 39 Financial Instruments:
Recognition and Measurement. The Company is currently evaluating the impact that the standard will have on
its results of operations and financial position and is assessing when adoption will occur.
IFRS 15 Revenue from Contracts with Customers is effective for fiscal periods ending on or after 31 December
2017 with early adoption permitted. IFRS 15 provides guidelines for reporting information to readers about
the nature, amount, timing and uncertainty of revenue and cash flows arising from an entity’s contracts with
customers. The Company intends to adopt IFRS 15 for the annual period beginning on 1 January, 2017. The
Company is currently evaluating the impact that the standard will have on its results of operations and financial
position.
Financial instrument classification and measurement
The Company classifies the fair value of financial instruments according to the following hierarchy based on
the amount of observable inputs used to value the instrument:
Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.
Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing
information on an ongoing basis.
Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are
either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including
expected interest rate, share prices, and volatility factors, which can be substantially observed or corroborated
in the marketplace.
Level 3 – Valuation in this level are those with inputs for the asset or liabilities that are not based on observable
market data.
40
SUMMARY QUARTERLY RESULTS OUTSTANDING
The following is a summary of the results for the Company for the last eight quarters:
(US$’000 except where
otherwise stated)
Financial
Revenue
Net (loss)/profit
Earnings/(loss) per
share - diluted (US$)
Funds flow from
operating activities
Funds flow per share
- diluted (US$)
Operating netback (US$/mcf)
2014
2013
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
restated
restated
restated
restated
restated
restated
restated
9,645
14,631
18,854
13,477
14,829
14,260
11,596
6,137
1,939
(3,867)
1,383
(7,519)
12,797
2,363
(46,381)
(1.32)
4
–
0.17
0.05
(0.11)
0.04
(0.20)
0.05
8,733
6,641
11,651
5,411
7,412
10,131
7,449
7,402
0.25
1.69
0.19
2.12
0.33
2.92
0.15
2.03
0.22
2.29
0.29
2.26
0.22
2.10
0.21
2.15
Working capital
34,148
42,001
30,399
12,783
20,857
22,896
15,056
48,506
Shareholders’ equity
76,635
123,004
123,019
116,752
114,780
118,992
117,407
125,177
Capital expenditures
Geological and geophysical
and well drilling
Pipeline and infrastructure
Other equipment
Operating
Additional Gas sold
– industrial (MMcf)
Additional Gas sold
– power (MMcf)
Average price per mcf
– industrial (US$)
Average price per mcf
– power (US$)
522
193
3
273
12
39
9
(270)
48
109
198
176
(1,370)
397
1,111
391
296
57
103
31
4
268
–
–
1,084
1,304
1,046
1,164
1,143
1,092
1,067
1,176
3,377
3,935
3,503
4,008
4,385
4,959
4,250
4,363
8.24
8.85
9.27
8.11
8.38
8.43
8.60
7.78
3.49
3.60
3.65
3.52
3.68
4.10
3.63
3.55
Prior Eight Quarters
Throughout the two-year period, TANESCO payments have been irregular and have affected cash and
receivables. From no receipts in Q1 2013, through significant single payments related to World Bank and
external funding in Q2 and Q4 2013, the commencement of weekly payments in Q2 and Q3 2014 and the
cessation of these payments in Q4 2014, overall the TANESCO receivable built from US$48.8 million at the end
of Q1 2013 to US$58.9 million (excluding interest) as at 31 December 2014. The financial statements do not
recognise the interest receivable from TANESCO as it does not meet IAS 18 income recognition criteria. The
Company is however actively pursuing the collection of interest that has been charged to TANESCO.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS
41
Working capital declined significantly in Q2 2013 over Q1 2013 commensurate with the reclassification of
US$34.9 million in TANESCO receivables as long-term and a provision of US$7.9 million applied to reflect the
timing and uncertainty of collection. The provision had a significant impact on earnings period over period,
with an additional provision in Q3 2013, together with a final provision against the remainder of the TANESCO
receivable during Q4 2014, all affecting earnings over the periods. With minimal capital spending over the
two-year period, the Company’s cash balances have overall increased. The US$8.1 million decrease in working
capital in Q1 2014 over Q4 2013 to due to a US$12.0 million rise in the TANESCO long-term receivable with
the resultant TPDC share of Profit Gas being recorded as a current liability.
Revenues over the two-year period fluctuated quarter over quarter due to overall sales volumes, changing
demand for Power sector and Industrial sector volumes, which in turn reflected the average price received
for natural gas in each period, and declining productive capacity at Songo Songo. Greater access to hydro
power beginning in Q1 2014 served to reduce demand by TANESCO, and continued throughout much of
the year. Overall Power sector sales were declining quarter over quarter during 2014, with the exception
of a 13% increase in Q3, reflecting the seasonally higher demand. Maintenance at TANESCO facilities also
reduced Power sector volumes during Q4 2014. Reduced sales volumes to TANESCO results in a reduction
in the amount of gas which is sold at premium pricing under the PGSA. Despite the precipitous drop in global
crude oil prices in mid-2014, Industrial sector gas prices, linked to landed HFO prices and subject to certain
contractual floors and ceilings, have maintained.
In Q4 2014, with declining productivity of the Songo Songo field, the average Additional Gas volumes fell
below 50 MMcfd to 48.5 MMcfd and accordingly the Profit Gas share fell from 55% to 40% for the first time
since Q2 2011 when the additional volumes sold to TANESCO under the PGSA were brought onstream (see
“Principal Terms of the Tanzanian PSA and Related Agreements”), reducing revenue, funds flow and earnings.
SELECTED FINANCIAL INFORMATION
Selected annual financial information derived from the audited consolidated financial statements for the years
ended 31 December 2012, 2013 and 2014 is set out below:
Figures in US$’000 except per share amount
2014
2013 restated
2012 restated
Revenue
Funds flow from operating activities
Cash flows from operating activities
Net loss
Total assets
(Loss)/earnings per share:
Basic and diluted
56,607
32,436
29,757
(38,301)
198,492
53,482
32,394
22,491
(7,640)
207,257
74,776
42,081
30,568
15,032
209,761
(1.10)
(0.22)
0.53
Revenue increased by 6% to US$56.6 million in 2014 from US$53.5 million in 2013. The sales volumes were
13% lower in 2014 than 2013, with the weighted average price increasing from US$4.66/mcf to US$4.76/mcf.
The tax payable in respect of 2014 is US$11.9 million (2013: US$12.8 million). Of this, US$7.9 million (2013:
US$9.1 million) relating to the current year’s profit is, in accordance with the terms of the PSA, recoverable
from TPDC. Consequently revenue in 2014 has been uplifted by the gross amount of US$11.3 million (2013:
US$13.1 million).
The level of Industrial volumes increased by 3% to 4,598 MMcf in 2014 from 4,478 MMcf in 2013, mainly
as a consequence of reducing supplies of Protected Gas whilst Songas carried out maintenance on power
generating turbines.
The level of Power volumes decreased by 17% to 14,823 MMcf (2013: 17,957 MMcf). The decrease in Power
sales is attributable to increased demand for gas from TANESCO.
42
BUSINESS RISKS
Additional Financing
The ability of the Company to arrange financing in the future will if necessary depend in part upon the prevailing
capital market conditions as well as the business performance of the Company. There can be no assurance
that the Company would be successful in its efforts to arrange additional financing on terms satisfactory to the
Company. If additional financing is raised by the issuance of shares from treasury of the Company, control of
the Company may change and shareholders may suffer additional dilution.
From time to time the Company 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
the Company’s debt levels above industry standards.
Collectability of Receivables
The Company evaluates the collectability of its receivables on the basis of payment history, frequency and
predictability, as well as Management’s assessment of the customer’s willingness and ability to pay. Both
Songas and the Company have been impacted by TANESCO’s inability to pay.
Amounts collected with respect to the long-term receivable in the future will be reflected in earnings when
payment is received. Notwithstanding this provision, the Company and TANESCO continue to operate in
accordance with the terms of the Portfolio Gas Supply Agreement whereby natural gas continues to be
delivered by the Company and TANESCO payments remain current on current deliveries. This provision against
the TANESCO net long-term receivable will not prejudice the Company’s rights to payment in full or its ability
to pursue collection in accordance with the terms of the agreement with TANESCO.
As at 31 December 2014, Songas owed the Company US$43.2 million (Q4 2013: US$24.8 million), whilst the
Company owed Songas US$30.4 million (Q4 2013: US$16.9 million); there was no contractual right to offset
these amounts. Since 31 December 2014 the Company has settled the outstanding pipeline tariff charges of
US$28.9 million and Songas has settled outstanding gas sales invoices of US$$23.9 million. US$19.3 million (Q4
2013: US$13.3 million) remains outstanding in respect of the gas plant operation, which should be conducted
at cost and the charges are billed to Songas on a flow through basis without profit margin. Management has
placed a provision of US$9.8 million against this debt.
The “Tax Recoverable” figure carried on the balance sheet arises from the revenue sharing mechanism within
the PSA which entitles the Company to recover from TPDC, by way of a deduction from TPDC’s Profit Gas
share, an amount “the adjustment factor” equal to the actual income taxes payable by the Company. Recovery,
by offset against TPDC’s share of revenue is dependent only payment of income taxes relating to prior period
adjustment factors as they are assessed.
Operating Hazards and Uninsured Risks
The business of the Company is subject to all of the operating risks normally associated with the exploration
for, and the production, storage, transportation and marketing of oil and gas. These risks include blowouts,
explosions, fire, gaseous leaks, downhole design and integrity, migration of harmful substances and oil spills,
any of which could cause personal injury, result in damage to, or destruction of, oil and gas wells or formations
or production facilities and other property, equipment and the environment, as well as interrupt operations. In
addition, all of the Company’s operations will be subject to the risks normally incident to drilling of natural gas
wells and the operation and development of gas properties, including encountering unexpected formations
or pressures, premature declines of reservoirs, blowouts, equipment and tubing failures and other accidents,
sour gas releases, uncontrollable flows of oil, natural gas or well fluids, adverse weather conditions, pollution
and other environmental risks. Drilling conducted by the Company 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 the Company is increased due to the fact that the Company
currently only has one producing property. The Company 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 the Company’s financial condition, results of operations and cash flows.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS 43
Furthermore, the Company cannot predict whether insurance will continue to be available at a reasonable
cost or at all.
Foreign Operations
The Company’s operations and related assets are located in Italy and Tanzania which may be considered
to be politically and/or economically unstable. Exploration or development activities in Tanzania and Italy
may require protracted negotiations with host governments, national oil companies and third parties and
are frequently subject to economic and political considerations, such as, the risks of war, actions by terrorist
or insurgent groups, expropriation, nationalization, creeping nationalization, renegotiation or nullification
of existing contracts and production sharing agreements, taxation policies, foreign exchange restrictions,
changing political conditions, international monetary fluctuations, currency controls and foreign governmental
regulations that favour or require the awarding of drilling and construction contracts to local contractors
or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. In
addition, if a dispute arises with foreign operations, the Company may be subject to the exclusive jurisdiction
of foreign courts.
In Tanzania the state retains ownership of the minerals and consequently retains control of, the exploration
and production of hydrocarbon reserves. Accordingly, these operations may be materially affected by
the Government through royalty payments, export taxes and regulations, surcharges, value added taxes,
production bonuses and other charges. The Government of Tanzania issued a National Natural Gas Policy in
2013, which policy contemplates greater government control over the industry and in some areas conflicts
with the Company’s rights under the Songo Songo PSA. There can be no assurance that the rights of the
Company under the PSA will be grandfathered with respect to any future natural gas legislation arising from
this policy.
The Company’s development properties and its current proved natural gas reserves located offshore on the
Songo Songo Island in Tanzania, are subject to regulation and control by the government of Tanzania and
certain of its national and parastatal organizations including the energy regulator, EWURA and TPDC. The
Company and its predecessors have operated in Tanzania for a number of years and believe that it has had
reasonably good relations with the current Tanzanian Government. However, there can be no assurance that
present or future administrations or governmental regulations in Tanzania will not materially adversely affect
the operations or future cash flows of the Company.
Corruption remains an issue in Tanzania, the country ranking 119 out of 175 on the Transparency International
Corruption Index. At the end of 2014, there was a significant corruption scandal in Tanzania’s energy sector
involving a number of senior government officials, including senior officials from MEM. Having assessed
the Company’s exposure to corruption in Tanzania, it was concluded that the risk of the Company and/
or its subsidiaries violating applicable laws prohibiting corrupt activities are mitigated or unlikely given the
Company’s controls relating to such risks and their effective operation. There can be no assurance, however
that corruption may indirectly affect or otherwise impair the Company’s ability to operate in Tanzania and
effectively pursue its business plan in that country.
The Tanzania Revenue Authority (“TRA”) is responsible for the collection of taxes in Tanzania. TRA is not party
to the Songo Songo PSA and there is no assurance that the TRA will consider itself bound by its terms.
Accordingly, there is a risk that the TRA will take interpretations of issues distinct from the PSA and result in
assessments, penalties and fines which have not been contemplated by the Company and result in additional
costs which are not recoverable under the PSA. The TRA has significant powers in Tanzania and is capable of
causing the Company’s operations in that country to cease.
The Company requires additional gas processing and transportation infrastructure to allow additional
development and the ultimate monetisation of the Company’s reserves through additional gas sales. In 2012,
the Government of Tanzania announced a US$1.2 billion natural gas infrastructure expansion project, the
over two years of negotiations with TPDC, there has been no progress on commercial terms for the sale
of incremental gas volumes and there is no assurance that the Company’s gas could be processed and
transported to markets on economic terms.
44
PSA Negotiations
In November 2011 Parliament passed a resolution advising the Government to terminate the Company’s Songo
Songo PSA on the grounds of an allegation by TPDC that the Company had over recovered approximately
US$21 million in Cost Gas revenue. On the recommendation of MEM in February 2012, the Government
announced that it was establishing a Government Negotiating Team (“GNT”) to discuss a number of issues
raised in Parliament in relation to the Company’s Songo Songo PSA. In Tanzania, government negotiating teams
are a common mechanism to negotiate with business. The scope of the GNT was to discuss a number of
issues that were raised by the Parliamentary Committee for Energy into the workings of the PSA. This included,
but is not limited to, TPDC back in rights, profit sharing arrangements, the unbundling of the downstream
assets, cost recovery and the Company’s management of the upstream operations. A conditional agreement
in principle was been reached in mid-2012 on a number of major points to resolve the issues. The GNT
completed its mandate, and the responsibility for finalisation, documentation and implementation moved
back to MEM. The conditional agreement in principle contemplated completion of this process by the end of
2012 as well as a number of deliverables from TPDC and the Government. As at the date of this report none of
the TPDC or Government undertakings have been met and other than the alleged US$21 million over recovery
discussed below, none of the issues have been resolved.
In response to a Notice of Dispute delivered by the Company, in March 2014 TPDC retracted its claim that
the Company had over-recovered approximately US$21 million in Cost Gas, which management believes
has substantially exonerated the Company of allegations made by Parliament. Accordingly, the Company
continues to rely upon its rights under the existing PSA and has initiated notices of dispute to resolve any
remaining issues.
Access to Songas processing and transportation
Whilst the Company operates the Songo Songo gas processing plant, Songas is the owner of plant and pipeline
system which transports natural gas from Songo Songo to Dar es Salaam. The Company’s ability to deliver gas
to its customers in Dar es Salaam is dependent upon it having access to the Songas infrastructure. Although
there are agreements with Songas to allow the Company to process and transport gas, there is no assurance
that these rights could not be challenged or curtailed by Songas. The inability to access Songas plant and
processing faciities would materially impair the Company’s ability to realise revenue from natural gas sales.
As a result of the Ubungo power plant re-rating that occurred in 2011 pursuant to the Re-Rating Agreement,
the capacity of the Songas gas processing plant was increased to a maximum of 110 MMcfd (restricted to 102
MMcfd because of pipeline and pressure requirements). The Re-Rating Agreement expired on 31 December
2012 and, although it was initially extended to 31 December 2013, no new agreement is currently in place.
Without the Re-Rating Agreement, Songas may de-rate plant capacity to 70 MMcfd (the capacity originally
agreed to), which would result in a material reduction in the Company’s sales volumes of Additional Gas.
Amended and Restated Gas Agreement
The Gas Agreement may be superseded by an initialed ARGA. The unsigned ARGA provides clarification of
the Protected Gas volumes and removes all terms dealing with the security of the Protected Gas and contract
terms dealing with the consequences of any insufficiency are dealt with in a new Insufficiency Agreement
(“IA”). The IA specifies terms under which Songas may demand cash security in order to keep it whole in
the event of a Protected Gas insufficiency. Should the IA be signed, it will govern the basis for determining
security. Under the provisional terms of the IA, when it is calculated that funding is required, the Company is
required to fund an escrow account at a rate of US$2.00/MMbtu on all Industrial Additional Gas sales out of
its and TPDC’s share of revenue, and TANESCO shall contribute the same amount on Additional Gas sales to
the Power sector. The funds provide security for Songas in the event of an insufficiency of Protected Gas. The
Company is actively monitoring the reservoir and, supported by the report of its independent engineers, does
not anticipate that a liability will occur in this respect. As at the date of this report, the ARGA remains an intitialed
agreement only, however the parties thereto, in certain respects, are conducting themselves as though the
ARGA is in full force and effect. Management does not foresee at this time a material risk with the conduct of
the Company’s business with an unsigned ARGA.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS 45
Industry Conditions
The oil and gas industry is intensely competitive and the Company 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, the Company operates the Songo Songo natural gas property and has
earned interests in two permits in Italy. There is a risk that in the future either the operatorship could change
and the property operated by third parties or operations may be subject to control by national oil companies,
Songas, or parastatal organisations and, as a result, the Company 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 the Company
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
the Company and Songas. The ability of the Company to market any natural gas from current or future reserves
in Tanzania may depend upon its ability to develop natural gas markets in Tanzania and the surrounding region,
obtain access to the necessary infrastructure to deliver sales gas volumes, including acquiring capacity on
pipelines which deliver natural gas to commercial markets. The Company 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. The
Company 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 the Company 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
The Company 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 the Company’s ability to produce, transport and sell volumes of
Additional Gas if the Company’s obligations to Songas under the Gas Agreement are not met. In particular,
Songas has the right in specific circumstances to request reasonable security on all Additional Gas sales.
The Government of Tanzania has issued a National Natural Gas Policy in October 2013, which policy
contemplates TPDC becoming sole aggregator of natural gas in the country. This policy objective conflicts
with the Company’s prior right under the PSA to directly market Additional Gas, and there is a risk that this prior
right will not be recognized and that the Company’s ability to maximize revenue on Additional Gas sales may
be impaired by a requirement at law to sell gas to TPDC as aggregator.
Replacement of Reserves
The Company’s natural gas reserves and production and, therefore, its cash flows and earnings are highly
dependent upon the Company developing and increasing its current reserve base and discovering or acquiring
additional reserves. Without the addition of reserves through exploration, acquisition or development activities,
the Company’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, the
Company’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 the Company will be able to find and develop or
acquire additional reserves to replace production at commercially feasible costs.
46
Asset Concentration
The Company’s natural gas reserves are currently limited to one producing property, the Songo Songo field, and
the productive potential from this field is limited to seven wells, of which three are currently suspended. There
has been limited production from the Songo Songo field to date. There is no assurance that the Company will
have sufficient deliverability through the existing wells to provide additional natural gas sales volumes, and that
there may be significant capital expenditures associated with any remedial work, workovers, or new drilling
required to achieve deliverability. In addition, any difficulties relating to the operation or performance of the
field would have a material adverse effect on the Company. The Company is currently producing the existing
wells at maximum capacity. There will be no redundant capacity in the facility or pipeline until workovers of
existing wells can be performed and /or additional wells can be drilled in the field and facilities expanded. A
loss or material reduction in the production of any given well will have a material adverse effect on the total
production and funds flow from operations of the Company. The Italian licences in which the Company has
an interest are currently in the exploration phase of their cycle and it may be several years before the Company
is able to obtain a revenue stream from these assets.
Environmental and Other Regulations
Extensive national, state, and local environmental laws and regulations in foreign jurisdictions will affect nearly
all of the Company’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 the Company will not incur
substantial financial obligations in connection with environmental compliance. Significant liability could be
imposed on the Company 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 the Company or
non-compliance with environmental laws or regulations. Such liability could have a material adverse effect
on the Company. Moreover, the Company 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 the Company for the installation and operation
of systems and equipment for remedial measures, any or all of which may have a material adverse effect on
the Company. As party to various licenses, the Company may have an obligation to restore producing fields
to a condition acceptable to the authorities at the end of their commercial lives. The PSA does not contain
abandonment obligations for the Company. In addition, the Company expects the Songo Songo field to
produce well beyond the term of the current licence.
While management believes that the Company is currently in compliance with environmental laws and
regulations applicable to the Company’s operations in Tanzania and Italy, no assurances can be given that the
Company will be able to continue to comply with such environmental laws and regulations without incurring
substantial costs.
The Company’s petroleum and natural gas operations are subject to extensive governmental legislation and
regulation and increased public awareness concerning environmental protection.
In accordance with the terms of the PSA, no provision has been recognised for future decommissioning costs
in Tanzania as it is forecast that there will still be commercial gas reserves when the Company relinquishes
the license in 2026. The Company 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 the Company to
date. Although management believes that the Company’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.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS 47
Volatility of Oil and Gas Prices and Markets
The Company’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 the Company. Any substantial decline
in the prices of oil and natural gas could have a material adverse effect on the Company 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 the Company.
No assurance can be given that oil and natural gas prices will be sustained at levels which will enable the
Company to operate profitably. From time to time the Company 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.
There has been a significant increase in exploration activity in Tanzania, which has yielded world class
discoveries of natural gas that could, when developed, 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 the Company’s ability
to market its gas production.
Uncertainties in Estimating Reserves and Future Net Cash Flows
There are numerous uncertainties inherent in estimating quantities of proved and probable reserves and cash
flows to be derived therefrom, including many factors beyond the control of the Company. The reserve
and cash flow information contained herein represents estimates only. The reserves and estimated future
net cash flow from the Company’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, TPDC “back-in” methodology
and other government levies that may be imposed over the producing life of the reserves. These assumptions
were based on price forecasts in use at the date of the relevant evaluations were prepared and many of these
assumptions are subject to change and are beyond the control of the Company. Actual production and cash
flows derived therefrom will vary from these evaluations, and such variations could be material.
Title to Properties
Although title reviews have been done and will continue to be done according to industry standards prior to
the purchase of most oil and natural gas producing properties or the commencement of drilling wells, such
reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise to defeat the
claim of the Company which could result in a reduction of the revenue received by the Company.
Acquisition Risks
The Company intends to acquire natural gas infrastructure and possibly additional oil and gas properties.
Although the Company 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, the Company 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 contamination, are
not necessarily observable even when an inspection is undertaken. The Company 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 the Company’s acquisitions will be successful.
48
Reliance on Key Personnel
The Company is highly dependent upon its executive officers and key personnel. The unexpected loss of the
services of any of these individuals could have a detrimental effect on the Company. The Company does not
maintain key life insurance on any of its employees or officers.
Controlling Shareholder
W David Lyons, the Company’s Chairman, and Chief Executive Officer is the beneficial controlling shareholder
of the Company and holds approximately 99.5% of the outstanding Class A shares and approximately 16.5%
of the Class B shares. Consequently, Mr. Lyons is the beneficial holder of approximately 20.6% of the equity
(20.4% fully diluted) and controls 59.4% of the total votes of the Company.
CRITICAL ACCOUNTING ESTIMATES AND JUDGEMENTS
In applying the Company’s accounting policies, which are described in Note 4 to the Consolidated Financial
Statements, management makes estimates and assumptions concerning the future. The resulting accounting
estimates will, by definition, vary to the actual results. The estimates and assumptions that have a significant
risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial
year are discussed below:
i)
Reserves
There are numerous uncertainties inherent in estimating quantities of proved and probable reserves and
cash flows to be derived therefrom, including many factors beyond the control of the Company. The
reserve and cash flow information contained herein represents estimates only. The reserves and estimated
future net cash flow from the Company’s Exploration’s properties have been evaluated by McDaniel &
Associates Consultants Ltd., independent petroleum engineers. 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, TPDC “back-in” methodology and other government levies
that may be imposed over the producing life of the reserves. These assumptions were based on price
forecasts in use at the date of the relevant evaluations were prepared and many of these assumptions
are subject to change and are beyond the control of the Company. For the purpose of the reserves
certification as at 31 December 2014 it was assumed that TPDC will ‘back-in’ for 20% for all future new
drilling activities as determined by the current development plan and this is reflected in the Company’s
net reserve position.
Reserves are integral to the amount of depletion recognised.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS 49
ii)
Carrying value of exploration and evaluation assets and property, plant and equipment
Under the Company’s accounting policy expenditures incurred on the exploration for, and evaluation of,
reserves are capitalized as intangible assets. These intangibles assets are then assessed for impairment on
each balance sheet date to determine if circumstances suggest that the carrying amount may exceed its
recoverable value. Such circumstances include but are not limited to:
•
•
•
•
•
•
the period for which the Company has the right to explore in the specific area has expired during
the period, or will expire in the near future, and is not expected to be renewed;
no further expenditure on exploration and evaluation is budgeted or planned;
no reserves have been encountered;
the evaluation of seismic data indicates that the reserves are unlikely to be of a commercial quantity;
the quantity of hydrocarbon reserves are deemed not to be of commercially viable quantities and
the entity has decided to discontinue further activities; and
sufficient data exists to indicate that, although a development in the specific area is likely to proceed,
the carrying amount of the exploration and evaluation asset is unlikely to be recovered in full from
successful development or by sale.
An assessment for impairment involves estimates as to (i) the likely future commerciality of the asset
and when such commerciality should be determined, (ii) future revenues and costs associated with the
asset, and (iii) the discount rate to be applied to such revenues and costs for the purpose of deriving a
recoverable value.
Exploration and evaluation assets are assessed for impairment if (i) sufficient data exists to determine
technical feasibility and commercial viability, or (ii) facts and circumstances suggest that the carrying
amount exceeds the recoverable amount. For purposes of impairment testing, exploration and evaluation
assets are grouped by concession.
The technical feasibility and commercial viability of extracting a resource is considered to be determin-
able based on several factors including the assignment of proven reserves. A review of each exploration
license or field is carried out, at least annually, to ascertain whether the project is technically feasible
and commercially viable. Upon determination of technical feasibility and commercial viability, intangible
exploration and evaluation assets attributable to those reserves are first tested for impairment and then
reclassified from exploration and evaluation assets to a separate category within property and equipment
referred to as oil and natural gas interests.
Management performs impairment tests on the Company’s property, plant and equipment assets if
indicators of impairment are present. The assessment of impairment indicators is subjective and considers
the various internal and external factors such as the financial performance of individual CGUs, market
capitalization and industry trends. If impairment indictors are present an impairment test is required to
be performed and the CGU is written down to its recoverable amount. Key assumptions to determine
the recoverable amount relate to prices that are based on forward curves, long-term assumptions and
discount rates that are risked to reflect conditions specific to individual assets.
iii) Fair value of stock based compensation
All stock options issued or stock appreciation rights granted by the Company are required to be valued at
their fair value. In assessing the fair value of the equity based compensation, estimates have to be made
as to (i) the volatility in share price, (ii) the risk free rate of interest, and (iii) the level of forfeiture. In the case
of stock options, this fair value is estimated at the date of issue and is not revalued, whereas the fair value
of stock appreciation rights is recalculated at each reporting period.
iv) Cost Recovery
The Company is able to recover reasonable costs incurred on the development of the Songo Songo
project out of 75% of the gross revenues less processing and pipeline tariffs (“Net Revenue”). There are
inherent uncertainties in estimating when costs have been recovered as these costs are subject to audit
by TPDC and potential reassessment in certain circumstances after the elapse of a considerable period
of time. Currently approximately US$34 million in cost recoveries for the period 2002 to 2009 have been
rejected by TPDC, which audit finding is now the subject of a Notice of Dispute by the Company.
50
v) Collectability of Receivables
Management reviews the accounts receivable aging and payment history on a weekly basis. Accounts
which are in excess of 60-days in arrears are identified as potential doubtful accounts. When sustained
arrears performance is exhibited over a quarter, together with an assessment by management of the
customer’s willingness and ability to pay, an account is deemed “doubtful” and a provision against that
account is made for the reporting period based on an assessment of that amount of arrears which are
unlikely to be paid in the immediate future. Both Songas and the Company have been impacted by
TANESCO’s inability to pay.
Notwithstanding the previous reclassification of TANESCO arrears as a long-term receivable and the
subseqent provision against same (see Note 13 – Trade and Other Receivables), the Company and
TANESCO continue to operate in accordance with the terms of the PGSA and in accordance with the
understanding between the Company and TANESCO whereby natural gas continues to be delivered by
the Company and TANESCO would pay for current deliveries on a current basis with payments to be
applied firstly to pay for the current deliveries and excess amounts applied to accumulated arrears.
Historically, TANESCO has paid outstanding quarterly balances in full subsequent to each quarter.
The delays in payments from TANESCO first began in late 2011 as a result of TANESCO experiencing
financial difficulties due to its dependence on high cost power generation based on liquid fuels following
severe draughts in Tanzania. TANESCO’s financial difficulties increased as a result being mandated by
the Government under an Emergency Power Plan to provide additional power generation. Whilst the
Company received assurances from the Government of Tanzania that it was arranging financing for
TANESCO, the receivables continued to build to levels where it became apparent in 2013 that some time
would be required for the ultimate payment of the arrears.
In Q2 2013 the Company reclassified all amounts of the TANESCO receivable in excess of 60 days in
arrears as a long-term receivable. Having established a long-term receivable, the Company then estimated
the discount to apply reflecting the estimated cost of the delay in timing of receipts. In parallel with the
reclassification, the Company, through a series of meetings with TANESCO, reached an understanding
with the state utility that the Company would continue to supply gas only if TANESCO remained current
on payments for current gas deliveries, and any excess payments received over and above the current
balances would be applied to the arrears balance.
In late 2013, the Company issued formal demands to TANESCO for payment, and in April 2014 issued a
formal Notice of Dispute as a first step in the collection process set out in the PGSA.
In April 2014 and again in May, TANESCO advised the Company of its intention to make weekly payments
of TZS 3 billion (approximately US$1.8 million) against ongoing deliveries of gas, and undertook to obtain
outside financing and pay the balance of the arrears by the end of 2014. Weekly payments substantially
ceased during Q4 and TANESCO failed to clear the arrears by year-end 2014. Following certain changes
to senior officials within TANESCO and the Ministry of Energy and Minerals (which has statutory oversight
of TANESCO), weekly payments resumed in Q1 2015. TANESCO has confirmed its understanding with
the parties that payments would be applied firstly to pay for the current gas deliveries and that remaining
amounts, if any, would be applied to the accumulated arrears.
The Company has a substantial “Tax Recoverable” balance. This arises from the revenue sharing
mechanism within the PSA which entitles the Company to a share of revenue equivalent to its tax charge,
grossed up at the prevailing rate. These amounts are collected by way of an offset against TPDC’s share
of revenue, as and when the Company pays its tax.
O R C A E X P L O R A T I O N G R O U P
I N C .
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS 51
O R C A E X P L O R A T I O N G R O U P
I N C .
FINANCIAL
STATEMENTS
& NOTES
52
Management’s Report to Shareholders
The accompanying consolidated financial statements of Orca Exploration Group Inc. are the responsibility of
Management. 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, audited the consolidated
financial statements in accordance with the Canadian Generally Accepted Auditing Standards to enable them
to express an opinion on the fairness of the consolidated financial statements in accordance with International
Financial Reporting Standards.
The Board of Directors carries out its responsibility for the financial reporting and internal controls of the
Company principally through an Audit Committee. The committee has met with the 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.
W. David Lyons
Chairman and Chief Executive Officer
Robert S. Wynne
Chief Financial Officer and Director
6 May 2015
6 May 2015
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTMANAGEMENT’S DISCUSSION & ANALYSIS
53
Independent Auditors’ Report
To the Shareholders of Orca Exploration Group Inc.
We have audited the accompanying consolidated financial statements of Orca Exploration Group Inc., which
comprise the consolidated statements of financial position as at December 31, 2014, December 31, 2013 and
January 1, 2013, the consolidated statements of comprehensive loss, changes in shareholders’ equity and cash
flows for the years ended December 31, 2014 and December 31, 2013, and notes, comprising a summary of
significant accounting policies and other explanatory information.
Management’s Responsibility for the Consolidated Financial Statements
Management is responsible for the preparation and fair presentation of these consolidated financial statements
in accordance with International Financial Reporting Standards as issued by the International Accounting
Standards Board, and for such internal control as management determines is necessary to enable the
preparation of consolidated financial statements that are free from material misstatement, whether due to
fraud or error.
Auditors’ Responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards
require that we comply with ethical requirements and plan and perform the audit to obtain reasonable
assurance about whether the consolidated financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the
consolidated financial statements. The procedures selected depend on our judgment, including the assessment
of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error.
In making those risk assessments, we consider internal control relevant to the entity’s preparation and fair
presentation of the consolidated financial statements in order to design audit procedures that are appropriate
in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s
internal control. An audit also includes evaluating the appropriateness of accounting policies used and the
reasonableness of accounting estimates made by management, as well as evaluating the overall presentation
of the consolidated financial statements.
We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a
basis for our audit opinion.
Opinion
In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated
financial position of Orca Exploration Group Inc. as at December 31, 2014, December 31, 2013 and January 1,
2013 and its consolidated financial performance and its consolidated cash flows for the years ended December
31, 2014 and December 31, 2013 in accordance with International Financial Reporting Standards.
Comparative Information
Without modifying our opinion, we draw attention to Note 2 to the consolidated financial statements which
indicates that the comparative information presented as at and for the year ended December 31, 2013 has
been restated and that the comparative information presented as at January 1, 2013 has been derived from the
consolidated financial statements as at and for the year ended December 31, 2012.
Chartered Accountants
6 May 2015
Calgary, Canada
54
Consolidated Statement of Comprehensive Loss
ORCA EXPLORATION GROUP INC.
US$’000s except per share amounts
REVENUE
Expenses
Production and distribution expenses
Depletion expense
General and administrative expenses
Exploration asset impairment
Net finance costs
Loss before tax
Income tax
Net loss
Foreign currency translation gain/(loss) from foreign operations
Comprehensive loss
Loss per share
Basic and diluted
Weighted average shares outstanding (millions)
Basic and diluted
Accompanying notes to the consolidated financial statements.
YEAR ENDED 31 DECEMBER
2013
(restated - note 2)
2014
56,607
53,482
NOTE
7, 8
(5,493)
(13,567)
37,547
(17,914)
(5,086)
(41,410)
(26,863)
(11,438)
(38,301)
73
(38,228)
(4,426)
(12,166)
36,890
(16,163)
(158)
(25,953)
(5,384)
(2,256)
(7,640)
(392)
(8,032)
(1.10)
(0.22)
34.9
34.7
14
10
11
19
19
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTFINANCIAL STATEMENTS Consolidated Statement of Financial Position
55
ORCA EXPLORATION GROUP INC.
US$’000
ASSETS
Current Assets
Cash
Trade and other receivables
Tax recoverable
Prepayments
Non-Current Assets
Long-term trade receivable
Exploration and evaluation assets
Property, plant and equipment
Total Assets
EQUITY AND LIABILITIES
Current Liabilities
Trade and other payables
Bank loan
Tax payable
Non-Current Liabilities
Deferred income taxes
Deferred Additional Profits Tax
Total Liabilities
Equity
Capital stock
Contributed surplus
Accumulated other comprehensive (loss)/income
Accumulated (loss)/income
Total Equity and Liabilities
AS AT 31 DECEMBER
AS AT 1 JANUARY
NOTE
2014
2013
(restated - note 2)
2013
(restated - note 2)
13
11
13
14
15
16
17
11
12
18
57,659
49,324
11,815
642
119,440
634
–
78,418
79,052
198,492
76,747
–
8,545
85,292
7,606
28,959
36,565
121,857
85,637
6,356
(230)
(15,128)
76,635
198,492
32,588
39,851
10,866
281
83,586
27,275
5,564
90,832
123,671
207,257
54,153
1,659
6,917
62,729
8,069
21,679
29,748
92,477
85,428
6,482
(303)
23,173
114,780
207,257
16,047
73,495
12,209
246
101,997
–
5,720
102,044
107,764
209,761
46,662
5,842
7,707
60,211
18,662
8,250
26,912
87,123
84,983
6,753
89
30,813
122,638
209,761
See accompanying notes to the consolidated financial statements.
Nature of Operations (Note 1); Restatement of previously issued consolidated financial statements (Note 2);
Contractual obligations and committed capital investment (Note 21); Contingencies (Note 22).
The consolidated financial statements were approved by the Board of Directors on 6 May 2015.
Director
Director
56
Consolidated Statement of Cash Flows
ORCA EXPLORATION GROUP INC.
US$’000
OPERATING ACTIVITIES
Net loss
Adjustment for:
Depletion and depreciation
Exploration asset impairment
Loss on disposal of fixtures and fittings
Provision for doubtful debt / Discount on long-term receivable
Stock-based compensation
Deferred income taxes
Deferred Additional Profits Tax
Interest expense
Unrealised loss/(gain) on foreign exchange
Funds flow from operating activities
(Increase)/decrease in trade and other receivables
(Increase)/decrease in tax receivable
Decrease in prepayments
Increase/(decrease) in trade and other payables
Increase/(decrease) in tax payable
Increase/(decrease) in long-term receivable
Cash flows from operating activities
INVESTING ACTIVITIES
Exploration and evaluation expenditures
Property, plant and equipment expenditures
Cash used in investing activities
FINANCING ACTIVITIES
Bank loan proceeds
Bank loan repayments
Interest paid
Proceeds from exercise of options
Cash used in financing activities
Increase in cash
Cash at the beginning of the year
Effect of change in foreign exchange on cash in hand
Cash at the end of the year
See accompanying notes to the consolidated financial statements.
YEAR ENDED 31 DECEMBER
NOTE
2014
2013
(restated - note 2)
(38,301)
(7,640)
15
14
15
10
18
11
4, 12
10
14
15
17
17
10
18
14,197
5,086
7
37,047
3,482
(457)
7,280
24
4,071
32,436
(12,840)
(949)
(361)
18,287
1,624
(8,440)
29,757
–
(1,312)
(1,312)
–
(1,659)
(24)
83
(1,600)
26,845
32,588
(1,774)
57,659
12,498
158
–
24,968
(209)
(10,593)
13,429
678
(895)
32,394
25,845
1,343
(35)
8,082
(790)
(44,348)
22,491
(2)
(1,286)
(1,288)
4,000
(8,183)
(678)
174
(4,687)
16,516
16,047
25
32,588
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTFINANCIAL STATEMENTS
Consolidated Statement of
Changes in Shareholders’ Equity
57
Balance as at 31 December 2014
85,637
6,356
(230)
ORCA EXPLORATION GROUP INC.
US$’000
Note
Restated balance as at 1 January 2014
Options exercised
Foreign currency translation
adjustment on foreign operations
Net loss
US$’000
Balance as at 1 January 2013
Net effect of restatement (note 2)
Restated balance as at 1 January 2013
Options exercised
Foreign currency translation
adjustment on foreign operations
Net loss
Capital
stock
Contributed
surplus
Cumulative
Translation
adjustment
Accumulated
(loss)/income
Total
Capital
stock
Contributed
surplus
Cumulative
Translation
adjustment
Accmulated
income
(restated)
18
85,428
209
–
–
6,482
(126)
–
–
84,983
–
84,983
445
–
–
6,753
–
6,753
(271)
–
–
(303)
23,173
114,780
–
73
–
–
–
83
73
(38,301)
(15,128)
(38,301)
76,635
89
–
89
–
(392)
–
(303)
34,110
(3,297)
30,813
–
–
(7,640)
23,173
Total
125,935
(3,297)
122,638
174
(392)
(7,640)
114,780
Restated balance as at 31 December 2013
85,428
6,482
See accompanying notes to the consolidated financial statements.
58
Notes to the Consolidated Financial Statements
General Information
Orca Exploration Group Inc. was incorporated on 28 April 2004 under the laws of the British Virgin Islands.
The Company produces and sells natural gas to the power and industrial sectors in Tanzania and has gas and
oil exploration interests in Italy.
The consolidated financial statements of the Company as at and for the year ended 31 December 2014
comprise accounts of the Company and all its wholly owned subsidiaries (collectively, the “Company” or “Orca
Exploration”) and were authorised for issue in accordance with a resolution of the directors on 6 May 2015.
1
NATURE OF OPERATIONS
The Company’s principal operating asset is its interest in a Production Sharing Agreement (“PSA”) with the
Tanzania Petroleum Development Corporation (“TPDC”) and the Government of Tanzania in the United
Republic of Tanzania. This PSA covers the production and marketing of certain gas from the Songo
Songo Block offshore Tanzania.
The gas in the Songo Songo field is divided between “Protected Gas” as defined and “Additional Gas” as
defined. The “Protected Gas” is owned by TPDC and is sold under a 20-year gas agreement (until July
2024) to Songas Limited (“Songas”). Songas is the owner of the infrastructure that enables the gas to be
delivered to Dar es Salaam, which includes a gas processing plant on Songo Songo Island.
Songas utilizes the Protected Gas as feedstock for its gas turbine electricity generators at Ubungo, for
onward sale to the Wazo Hill Cement Plant and for electrification of some villages along the pipeline
route. The Company 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.
Under the PSA, the Company has the right to produce and market all gas in the Songo Songo Block in
excess of the Protected Gas requirements (“Additional Gas”).
The Tanzania Electric Supply Company Limited (“TANESCO”) is a parastatal organization which is wholly-
owned by the Government of Tanzania, with oversight by the Ministry of Energy and Minerals (“MEM”).
TANESCO is responsible for the generation, transmission and distribution of electricity throughout
Tanzania. The Company currently supplies gas directly to TANESCO by way of a Portfolio Gas Supply
Agreement (“PGSA”) and indirectly through the supply of Protected Gas and Additional Gas to Songas
which in turn generates and sells power to TANESCO. The state utility is the Company’s largest customer
and the gas supplied by the Company to TANESCO today fires approximately 60% of the electrical power
generated in Tanzania. See Note 13 – Trade and Other Receivables.
In addition to gas supplied to Songas and TANESCO for the generation of power, the Company has
developed and supplies an industrial gas market in the Dar es Salaam area consisting of some 39 industrial
customers.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2014 59
2
RESTATEMENT OF PREVIOUSLY ISSUED
CONSOLIDATED STATEMENTS
Orca has restated its consolidated statements of financial position as at 31 December 2013 and 1 January
2013; and its consolidated statement of comprehensive loss, consolidated statement of cash flows and
consolidated statement of changes in shareholders’ equity for the year ended 31 December 2013.
In the course of preparing the Company’s consolidated financial statements for the year ended 31
December 2014, errors were discovered involving the computation of Tanzania income tax from 2005
through and to 30 September 2014. In addition, the Company is correcting reported finance income and
finance costs previously recognized on overdue trade receivables for 2013 and 2014. The restatement
adjustments are described in the paragraphs following the tables below.
The following tables present the impact of the restatement adjustments on the Company’s previously
reported consolidated financial statements as at and for the year ended 31 December 2013, as well as the
impacts on the consolidated statement of financial position as at 1 January 2013. The “Restated” columns
for 2013 reflect final adjusted balances after the restatement.
EFFECT ON CONSOLIDATED STATEMENT
OF COMPREHENSIVE LOSS
(US$000s except per share amounts)
REVENUE
Expenses
Production and distribution expenses
Depletion expense
General and administrative expenses
Exploration asset impairment
Net Finance costs
Loss before tax
Income tax
Net loss
Foreign currency translation loss from foreign operations
Total comprehensive loss
Loss per share
Basic and diluted
Weighted average shares outstanding (millions)
YEAR ENDED 31 DECEMBER 2013
As reported
Adjustment
54,718
(1,236)
(4,426)
(12,166)
38,126
(15,428)
(158)
(26,262)
(3,722)
(1,743)
(5,465)
(392)
(5,857)
–
–
(1,236)
(735)
–
309
(1,662)
(513)
(2,175)
–
(2,175)
Restated
53,482
(4,426)
(12,166)
36,890
(16,163)
(158)
(25,953)
(5,384)
(2,256)
(7,640)
(392)
(8,032)
(0.16)
(0.06)
(0.22)
Basic and diluted
34.7
–
34.7
60
EFFECT ON CONSOLIDATED STATEMENT OF FINANCIAL POSITION
AS AT 31 DECEMBER 2013
AS AT 1 JANUARY 2013
As reported Adjustment
Restated As reported Adjustment
Restated
US$’000
ASSETS
Current Assets
Cash
Trade and other receivables
37,215
2,636
39,851
73,495
32,588
–
32,588
16,047
–
–
16,047
73,495
Tax recoverable
Prepayments
Non-Current Assets
14,585
(3,719)
10,866
14,692
(2,483)
12,209
281
–
281
246
–
246
84,669
(1,083)
83,586
104,480
(2,483)
101,997
Long-term trade receivable
29,911
(2,636)
27,275
–
Exploration and evaluation assets
Property, plant and equipment
5,564
90,832
–
–
5,564
5,720
90,832
102,044
126,307
(2,636)
123,671
107,764
–
–
–
–
–
5,720
102,044
107,764
Total Assets
210,976
(3,719)
207,257
212,244
(2,483)
209,761
EQUITY AND LIABILITIES
Current Liabilities
Trade and other payables
Bank loan
Tax payable
Non-Current Liabilites
Deferred income taxes
53,296
857
54,153
45,496
1,166
46,662
1,659
1,958
56,913
4,959
5,816
–
1,659
6,917
5,842
6,322
–
5,842
1,385
7,707
62,729
57,660
2,551
60,211
12,132
(4,063)
8,069
20,399
(1,737)
18,662
Deferred Additional Profits Tax
21,679
–
21,679
8,250
–
8,250
Total Liabilities
Equity
Capital stock
Contributed surplus
Accumulated other
comprehensive income/(loss)
33,811
(4,063)
29,748
28,649
(1,737)
26,912
90,724
1,753
92,477
86,309
814
87,123
85,428
6,482
(303)
–
–
–
85,428
84,983
6,482
6,753
(303)
89
–
–
–
84,983
6,753
89
Accumulated income
28,645
(5,472)
23,173
34,110
(3,297)
30,813
Total Equity and Liabilities
210,976
(3,719)
207,257
212,244
(2,483)
209,761
120,252
(5,472)
114,780
125,935
(3,297)
122,638
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2014
61
EFFECT ON CONSOLIDATED STATEMENT OF CASH FLOWS
US$’000
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss
Adjustment for:
Depletion and depreciation
Exploration asset impairment
Provision for doubtful debt / Discount on long-term receivable
Stock-based compensation
Deferred income taxes
Deferred Additional Profits Tax
Interest expense
Unrealised loss/(gain) on foreign exchange
Funds flow from operating activities
Decrease in trade and other receivables
Decrease in tax receivable
Increase in prepayments
Increase in trade and other payables
(Decrease)/increase in taxation payable
(Decrease)/increase in long term receivable
Net cash flows from operating activities
CASH FLOWS USED IN INVESTING ACTIVITIES
Exploration and evaluation expenditures
Property, plant and equipment expenditures
Net cash used in investing activities
CASH FLOWS (USED IN)/FROM FINANCING ACTIVITIES
Bank loan proceeds
Bank loan repayments
Interest paid
Proceeds from exercise of options
Net cash flow used in financing activities
Increase in cash
Cash at the beginning of the year
Effect of change in foreign exchange on cash on hand
Cash at the end of the year
YEAR ENDED 31 DECEMBER 2013
As reported
Adjustment
Restated
(5,465)
(2,175)
(7,640)
12,498
158
27,604
(209)
(8,267)
13,429
678
(586)
39,840
25,845
107
(35)
8,082
(4,364)
(46,984)
22,491
(2)
(1,286)
(1,288)
4,000
(8,183)
(678)
174
(4,687)
16,516
16,047
25
32,588
–
–
(2,636)
–
12,498
158
24,968
(209)
(2,326)
(10,593)
–
–
(309)
(7,446)
–
1,236
–
–
3,574
2,636
13,429
678
(895)
32,394
25,845
1,343
(35)
8,082
(790)
(44,348)
–
22,491
–
–
–
–
–
–
–
–
–
–
–
(2)
(1,286)
(1,288)
4,000
(8,183)
(678)
174
(4,687)
16,516
16,047
25
32,588
62
EFFECT ON ACCUMULATED INCOME
US$’000
ACCUMULATED INCOME
Balance, beginning of year
Net loss
Balance, end of year
Net changes to prior periods
YEAR ENDED 31 DECEMBER 2013
As reported
Adjustment
Restated
34,110
(5,465)
28,645
(3,297)
(2,175)
(5,472)
30,813
(7,640)
23,173
The following is a description of the matters corrected in the restatement adjustments.
Incorrect computation of Tanzania income tax
The Songo Songo PSA, which governs substantially all of the Company’s business in Tanzania, provides
a mechanism to keep the Company whole for income taxes paid in Tanzania. Pursuant to the PSA, the
Company is reimbursed for all income tax payable on income derived from Petroleum Operations (as
defined) by way of an “adjustment factor”, under which the Company is allocated additional Profit Gas
of a value equal to the taxes paid/payable, thus reducing the allocation to the Company’s partner in the
field, the TPDC. The adjustment factor is determined by grossing up tax payable on the current year’s
profit, to the level necessary for the Company to remain neutral in the payment of income tax.
Computation of the adjustment factor, over a number of years, incorrectly included tax paid in respect of
prior years taxes in the gross up calculation. The net effect of which was to overstate reported revenue,
deferred tax expense, net loss and funds flow from operating activities, as well as tax recoverable and
deferred income taxes payable.
In Tanzania, taxpayers are required to pay at least 80% of the estimated year’s taxes in four quarterly
instalments during the year, with a final tax payment for the balance owing to be made in the following
year after completion of the financial statements. The PSA requires that taxable income for any year
include the tax paid in respect of the previous year. The calculation of taxable income for any given year
incorrectly included only the final payment for the previous year, rather than the sum of all of the five
payments.. This resulted in the understatement of taxable income.
The combined effect of these errors was an understatement of taxable income and a cumulative under-
payment of tax from 2005 to 31 December 2013 of US$3.5 million, which the Company has reported
and paid. The Tanzania Revenue Authority has the right to assess penalties and interest on overdue
taxes, which if assessed could be up to US$1.6 million and would not be recoverable under the PSA. An
estimate of these penalties and interest has been included in the restatement reflected in the periods for
which they relate.
The cumulative impact of the income tax errors, including applicable penalties and interest, as at 1 January
2013 results in a decrease in accumulated income of US$2.5 million, a decrease in Tax recoverable from
TPDC of US$2.5 million, an increase in tax payable of US$1.4 million, a decrease in deferred income taxes
payable of US$1.4 million.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2014
63
Elimination of Finance Income and Finance Costs relating to TANESCO receivables
In addition, the Company is correcting reported finance income and finance costs previously recognized
on overdue trade receivables for 2013 and 2014. Finance income and finance costs in the amount of $2.6
million for the year ended 31 December 2013 are eliminated in the restatement. As the finance income
was fully provided for as finance cost, there is no impact on the net loss after tax, accounts receivable or
cash flows from operating activities for 2013. The Company determined that the recognition of finance
income, reflecting interest on amounts overdue from TANESCO, coupled with a full provision of the
same amount was in error, as collection was not probable.
Foreign exchange
In addition, the Company is correcting reported trade and other payables in relation to the calculation of
foreign exchange on amounts due to TPDC whereby payments made to TPDC are required to be made
in the currency collected for gas sales. The cumulative impact of the foreign exchange as at 1 January
2012 results in an increase in trade and other payables of US$1.2 million, a decrease in accumulated
income of US$0.8 million and an decrease in deferred income taxes of US$0.4 million. The cumulative
impact on the 2013 consolidated financial statements results in an increase in trade and other payables
of US$0.9 million, a decrease in net finance costs of US$0.3 million and a decrease in accumulated
income of US$1.2 million.
Cumulative impact of combined income tax, finance income and foreign exchange errors
The cumulative impact of the combined income tax, finance income and foreign exchange errors,
including applicable penalties and interest, on the 2013 consolidated financial statements results in a
decrease of revenue from US$54.7 million to US$53.5 million, an increase in general and administrative
expenses from US$15.4 million to US$16.2 million, a decrease in net finance costs from US$26.3 million
to US$26.0 million, an increase in income tax expense from US$1.7 million to US$2.3 million, an increase
in net loss from US$5.5 million to US$7.6 million, a decrease in tax recoverable from TPDC from US$14.6
million to US$10.9 million, an increase in trade and other payables from US$53.3 million to US$54.2
million, an increase in the tax payable from US$2.0 million to US$6.9 million, a decrease in deferred
income taxes payable from US$12.1 million to US$8.1 million, and a decrease in accumulated income
from US$28.6 million to US$23.2 million.
64
3
BASIS OF PREPARATION
These consolidated financial statements have been prepared on a historical cost basis and have been
prepared using the accrual basis of accounting. The consolidated financial statements are presented in
US dollars.
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”).
B) Basis of consolidation
i)
Subsidiaries
The consolidated financial statements include the accounts of Orca Exploration Group Inc.
and all its wholly owned subsidiaries (collectively, the “Company”). Subsidiaries are those
enterprises controlled by the Company. The following companies have been consolidated
within the Orca Exploration financial statements:
Subsidiary
Registered
Holding
Functional
currency
Orca Exploration Group Inc.
British Virgin Islands
Parent Company
US dollar
Orca Exploration Italy Inc.
British Virgin Islands
Orca Exploration Italy Onshore Inc.
British Virgin Islands
PAE PanAfrican Energy Corporation
Mauritius
PanAfrican Energy Tanzania Limited
Jersey
Orca Exploration UK Services Limited United Kingdom
100%
100%
100%
100%
100%
Euro
Euro
US dollar
US dollar
British Pound
Sterling
ii)
Transactions eliminated upon consolidation
Inter-company balances and transactions, and any unrealised gains or losses arising from
inter-company transactions, are eliminated in preparing the consolidated financial statements.
C)
Foreign currency
i)
Foreign currency transactions
Transactions in foreign currencies are recorded at the rate of exchange prevailing at the
date of the transaction. Monetary assets and liabilities in foreign currencies are translated at
period-end rates. Non-monetary items are translated at historic rates, unless such items are
carried at market value, in which case they are translated using the exchange rates that existed
when the values were determined. Any resulting exchange rate differences are recognized in
the profit and loss.
ii)
Foreign currency translation
Orca Exploration Italy Inc. and Orca Exploration Italy Onshore Inc. use the Euro and Orca UK
Services uses British Pound Sterling as their functional currencies. The assets and liabilities of
these companies are translated into U.S. dollars at the period-end exchange rate. The income
and expenses of the companies are translated into U.S. dollars at the average exchange rate
for the period. Translation gains and losses are included in other comprehensive income.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2014
4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The accounting policies set out below have been applied consistently to all periods presented in these
consolidated financial statements.
A) EXPLORATION AND EVALUATION ASSETS, PROPERTY, PLANT AND EQUIPMENT
i)
Exploration and evaluation assets
65
Exploration and evaluation costs are capitalised as intangible assets. Intangible assets includes
lease and license acquisition costs, geological and geophysical costs and other direct costs
of exploration and evaluation which the directors consider to be unevaluated until reserves
are appraised to be commercially viable and technologically feasible as commercial, at which
time they are transferred to property, plant and equipment following an impairment review
and depleted accordingly. Where properties are appraised to have no commercial value or are
appraised at values less than book values, the associated costs are treated as an impairment
loss in the period in which the determination is made.
ii)
Property, plant and equipment
Property, plant and equipment comprises the Company’s tangible natural gas assets,
development wells, together with leasehold improvements, computer equipment, motor
vehicles and fixtures and fittings and are carried at cost, less any accumulated depletion, depre-
ciation and accumulated impairment losses. Cost includes purchase price and construction
costs for qualifying assets. Depletion of these assets commences when the assets are ready
for their intended use. Only costs that are directly related to the discovery and development
of specific oil and gas reserves are capitalised. The cost associated with tangible natural gas
assets are amortised on a field by field unit of production method based on commercial
proven reserves. The calculation of the unit of production amortisation takes into account the
estimated future development cost of the field.
iii)
Impairment of exploration and evaluation assets, property, plant and equipment
At each balance sheet date, the Company reviews the carrying amounts of its property,
plant and equipment and intangible assets to determine whether there is any indication
that those assets have suffered an impairment loss. Individual assets are grouped together
as a cash generating unit (“CGU”) for impairment assessment purposes at the lowest level
at which there are identifiable cash flows that are independent from other group assets. In
the case of exploration and evaluation assets, this will normally be at the CGU level. If any
such indication of impairment exists, the Company makes an estimate of its recoverable
amount. The recoverable amount is the higher of fair value less costs to sell and value in use.
Where the carrying amount of a CGU exceeds its recoverable amount, the CGU is considered
impaired and is written down to its recoverable amount. In assessing the value in use, the
estimated future cash flows are adjusted for the risks specific to the cash generating unit and
are discounted to their present value with a pre-tax discount rate that reflects the current
market indicators. The fair value less costs to sell is the amount that would be obtained from
the sale of a CGU in an arm’s length transaction between knowledgeable and willing parties.
Where an impairment loss subsequently reverses, the carrying amount of the asset CGU is
increased to the revised estimate of its recoverable amount, but so that the increased carrying
amount does not exceed the carrying amount that would have been determined had no
impairment loss been recognised for the CGU in prior years. A reversal of an impairment loss
is recognised as income immediately.
66
B) OPERATORSHIP
The Company operates the Songo Songo gas field, flow lines and gas processing plant. The Songas
wells, flowlines and gas plant are operated by the Company on behalf of Songas on a no cost
no profit basis. The cost of operating and maintaining the wells and flow lines is paid for by the
Company 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. Costs incurred by the
Company in connection with the operatorship of the Songas plant are recorded as receivables,
which are re-charged to Songas. Subsequent payments received from Songas are credited to
receivables. When there are Additional Gas sales, a tariff is paid to Songas as compensation for
using the gas processing plant and pipeline. This tariff is netted against revenue.
C) 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 stock option plan provides for the granting of stock options to directors, Company
officers, key personnel and employees to acquire shares at an exercise price determined by
the market value at the date of grant. The exercise price of each stock option is determined
at the closing market price of the Class B shares on the day prior to the day of grant. Each
stock option granted permits the holder to purchase one Class B share at the stated exercise
price. The Company records a charge to the profit and loss account using the Black-Scholes
fair valuation option pricing model. The valuation is dependent on a number of estimates,
including the risk free interest rate, the level of stock volatility, together with an estimate of the
level of forfeiture. The level of stock volatility is calculated with reference to the historic traded
daily closing share price at the date of issue.
iii)
Stock appreciation rights and restricted stock units
Stock appreciation rights (“SARs”) and restricted stock units (“RSUs”) are issued to certain key
managers, officers, directors and employees. The fair value of SARs and RSUs is expensed
in the profit and loss in accordance with the service period. The fair value of the SARs and
RSUs is revalued every reporting date with the change in the value recognized in the income
statement.
D) ASSET RETIREMENT OBLIGATIONS
No provision has been made for future site restoration costs in Tanzania because the Company
currently has no legal or contractual or constructive obligation under the Songo Songo Production
Sharing Agreement (“PSA”) to restore the fields at the end of their commercial lives, should such
occur within the term of the PSA. At such a time as the Company may be granted an extension of
the term of the PSA, which encompasses the end of the field life, or other amendment to the PSA
which requires the Company to do so, a provision will be made for future site restoration costs.
E) REVENUE RECOGNITION, PRODUCTION SHARING AGREEMENTS AND ROYALTIES
Pursuant to the terms of the PSA , the Company has exclusive rights to (i) to carry on Exploration
Operations in the Songo Songo Gas Field; (ii) to carry on Development Operations in the Songo
Songo Gas Field and (iii) jointly with Tanzania Petroleum Development Corporation (“TPDC”),
a “parastatal entity” to sell or otherwise dispose of Additional Gas. Additional Gas is all the gas
produced in excess of Protected Gas. Songas utilizes the Protected Gas (maximum 45.1 MMcfd on
any given day, non-cumulative) as feedstock for its gas turbine electricity generators at Ubungo,
for onward sale to the Wazo Hill cement plant and for electrification of certain villages along the
pipeline route. The Company receives no revenue for the Protected Gas delivered to Songas.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2014 67
The Company recognises revenue related to Additional Gas sales from the sale of gas to all
customers, including both TANESCO and Songas, when title passes to the customer at fiscal gas
meters which are installed at the respective customer’s plant gate in Dar es Salaam. Under the terms
of the PSA, the Company pays both its share and the parastatal’s share of operating, administra- tive
and capital costs. The Company recovers all reasonably incurred operating, administrative and
capital costs including the parastatal’s share of these costs from future revenues over several years
(“Cost Gas”). The parastatal’s share of operating and administrative costs, are recorded in operating
and general and administrative costs when incurred and capital costs are recorded in ‘Property,
plant and equipment’. All recoveries are recorded as Cost Gas in the year of recovery.
The Company has a gas sales contract under which the customer is required to take, or pay for, a
minimum quantity of gas. In the event that the customer has paid for gas that was not delivered, the
additional income received by the Company is carried on the balance sheet as “deferred income”.
During the following three years, if the customer consumes volumes in excess of the minimum,
it will be charged at the current rate, but may receive a credit for volumes paid but not delivered.
At the end of each reporting period the Company reassesses the volumes for which the customer
may receive credit, any remaining balance is credited to income.
In any given year, the Company is entitled to recover as Cost Gas up to 75% of the net revenue
(gross revenue less processing and pipeline tariffs). Any net revenue in excess of the Cost Gas
(“Profit Gas”) is shared between the Company and TPDC in accordance with the terms of the PSA.
Under the PSA the Company’s share of Profit Gas is further increased by the amount necessary to
fully pay and discharge any liability for taxes on income. Revenue represents the Company’s share
of Profit Gas and Cost Gas during the period.
Historically, TANESCO has paid outstanding quarterly balances in full subsequent to each quarter.
The delays in payments from TANESCO first began in late 2011 as a result of TANESCO experienc-
ing financial difficulties due to its dependence on high cost power generation based on liquid
fuels following severe draughts in Tanzania. TANESCO’s financial difficulties increased as a result
being mandated by the Government under an Emergency Power Plan to provide additional power
generation. Whilst the Company received assurances from the Government of Tanzania that it was
arranging financing for TANESCO, the receivables continued to build to levels where it became
apparent in 2013 that some time would be required for the ultimate payment of the arrears.
In Q2 2013 the Company reclassified all amounts of the TANESCO receivable in excess of 60 days
in arrears as a long-term receivable. Having established a long-term receivable, the Company then
estimated the discount to apply reflecting the estimated cost of the delay in timing of receipts.
In parallel with the reclassification, the Company, through a series of meetings with TANESCO,
reached an understanding with the state utility that the Company would continue to supply gas only
if TANESCO remained current on payments for current gas deliveries, and any excess payments
received over and above the current balances would be applied to the arrears balance.
In late 2013, the Company issued formal demands to TANESCO for payment, and in April 2014
issued a formal Notice of Dispute as a first step in the collection process set out in the PGSA.
In April 2014 and again in May, TANESCO advised the Company of its intention to make weekly
payments of TZS 3 billion (approximately US$1.8 million) against ongoing deliveries of gas, and
undertook to obtain outside financing and pay the balance of the arrears by the end of 2014. Weekly
payments substantially ceased during Q4 and TANESCO failed to clear the arrears by year-end
2014. Following certain changes to senior officials within TANESCO and the Ministry of Energy
and Minerals (which has statutory oversight of TANESCO), weekly payments resumed in Q1 2015.
TANESCO has confirmed the understanding between the parties that payments would be applied
firstly to pay for the current gas deliveries and that remaining amounts, if any, would be applied to
the accumulated arrears. There is no assurance that consistent weekly payments will be made. See
Note 13 – Trade and Other Receivables.
68
F) ADDITIONAL PROFITS TAX
Under the terms of the PSA, in the event that all costs have been recovered with an annual return
from the PSA of 25% plus the percentage change in the United States Industrial Goods Producer
Price Index, an Additional Profits Tax (“APT”) is payable to the Government of Tanzania. This tax is
considered to be a royalty and is netted against revenue. Deferred APT is provided for by forecasting
the total APT payable as a proportion of the forecast Profit Gas over the term of PSA license. The
actual APT that will be paid is dependent on the achieved value of the Additional Gas sales and the
quantum and timing of the operating costs and capital expenditure programme.
The PSA states that APT shall be calculated for each year and shall vary with the real rate of return
earned by the Company on the net cash flow from the Contract Area (as defined). The calculation
of APT includes a working capital adjustment reflecting the effect of the timing of actual receipt of
amounts owing from TANESCO on net cash flow available to APT.
G)
INCOME TAXES
The Company is liable for Tanzanian income tax on the profit for the year; this comprises current
and deferred tax. Where current income tax is payable this is shown as a current tax liability. Deferred
tax is provided using the balance sheet method, providing for temporary differences between the
carrying amounts of assets and liabilities for financial reporting purposes and the amounts used
for taxation purposes. The amount of deferred tax provided is based on the expected manner of
realisation or settlement of carrying amounts of assets and liabilities using tax rates substantively
enacted at the balance sheet date. A deferred tax asset is recognised only to the extent that it is
probable that future taxable profits will be available against which the asset can be utilised. Deferred
tax assets are reduced to the extent that it is no longer probable that the related tax benefits will be
realised.
The Company operates in a jurisdiction with complex tax laws and regulations, which are evolving
over time. The Company has taken certain tax positions in its tax filings and these filings are subject
to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual
income tax impact may differ significantly from that estimated and recorded by management.
H) 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
I)
FINANCIAL INSTRUMENTS
Over remaining life of the lease
3 years
3 years
3 years
All financial instruments are initially recognized at fair value on the consolidated statement of
financial position. The Company has classified each financial instrument into one of the following
categories: (i) fair value through profit and loss, (ii) loans and receivables, and (iii) other financial
liabilities. Subsequent measurement of financial instruments is based on their classification.
Financial assets and liabilities are recognized when the Company becomes a party to the contractual
provisions of the instrument. Financial assets are derecognized when the rights to receive cash
flows from the assets have expired or have been transferred and the Company has transferred
substantially all risks and rewards of ownership. Financial assets and liabilities are offset and the net
amount is reported on the statement of financial position when there is a legally enforceable right
to offset the recognized amounts and there is an intention to settle on a net basis, or realize the
asset and settle the liability simultaneously.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2014 69
Initial recognition
At initial recognition, the Company classifies its financial instruments in the following categories
depending on the purpose for which the instruments were acquired:
(i)
Financial assets and liabilities at fair value through profit and loss:
A financial asset or liability classified in this category is recognized at each period at fair value
with gains and losses from revaluation being recognized in net income. A financial asset
or liability is classified in this category if acquired principally for the purpose of selling or
repurchasing in the short-term. Derivatives are also included in this category unless they are
designated as hedges.
(ii) Loans and receivables:
Loans and receivables are initially measured at fair value plus directly attributable transaction
costs and are subsequently recorded at amortized cost using the effective interest method.
Long-term receivables are non-derivative financial assets with fixed or determinable payments
that are not quoted in an active market. Long-term receivables are initially recognized at fair
value based on the discounted cash flows. The discount rate is based on the credit quality and
term of the financial instrument. The financial instrument is subsequently valued at amortized
costs by accreting the instrument over the expected life of the assets. The accretion associated
with instrument valued at amortized cost is reported on the statement of comprehensive
loss each reporting period. The carrying amount of the long-term receivable less discounts
represents the fair value of the receivable.
The fair value of the Company’s trade and other receivables approximates their carrying
values due to the short-term nature of these instruments.
(iii) Other financial liabilities:
Trade and other payables and the bank loan are classified as other financial liabilities and are
initially measured at fair value less directly attributable transaction costs and are subsequently
recorded at amortized cost using the effective interest method. The fair value of the other
financial liabilities approximates the carrying amounts due to the short-term nature of these
instruments.
Cash and cash equivalents
Cash and cash equivalents include cash on hand, term deposits and short term highly liquid
investments with the original term to maturity of three months or less, which are convertible to
known amounts of cash and which, in the opinion of management, are subject to an insignificant
risk of changes in value. The fair value of cash and cash equivalents approximates their carrying
amount. As at 31 December 2014 US$37.2 million was held in Tanzania and there are no restrictions
on the movement of funds out of Tanzania.
Impairment of financial assets
A financial asset is assessed at each reporting date to determine whether there is any objective
evidence that it is impaired. A financial asset is considered to be impaired if objective evidence
indicates that one or more events have had a negative effect on the estimated future cash flows
of that asset.
An impairment loss in respect of a financial asset measured at amortized cost is calculated as the
difference between its carrying amount and the present value of the estimated future cash flows
discounted at the original effective interest rate. Individually significant financial assets are tested for
impairment on an individual basis. The remaining financial assets are assessed collectively in groups
that share similar credit risk characteristics.
All impairment losses are recognized in profit or loss. An impairment loss is reversed if the reversal
can be related objectively to an event occurring after the impairment loss was recognized. For
financial assets measured at amortized cost the reversal is recognized in profit or loss.
70
J) CONTRIBUTED SURPLUS
This is used to record two types of transactions:
(i)
(ii)
To recognise the fair value of equity settled stock based compensation expensed in the year.
To account for the difference between the aggregated book value of the shares purchased
under the normal course issuer bid and the actual consideration.
K)
EARNINGS OR LOSS PER SHARE (“EPS”)
Basic earnings or loss per share is calculated by dividing profit or loss after tax attributable to owners
of the Company (the numerator) by the weighted average number of ordinary shares outstanding
(the denominator) during the period. The denominator is calculated by adjusting the shares
outstanding at the beginning of the period by the number of shares bought back or issued during
the period, multiplied by a time-weighting factor.
Diluted EPS is calculated by adjusting the earnings and number of shares for the effects of all dilutive
potential ordinary shares deemed to have been converted at the beginning of the period or if later,
the date of issuance. The effects of anti-dilutive potential ordinary shares are ignored in calculating
diluted EPS. All options are considered anti-dilutive when the Company is in a loss position.
L) NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
Changes in accounting policies
On 1 January, 2014, the Company adopted the following new standards and amendments in
accordance with the transition provisions of each standard, which became effective for annual
periods on or after 1 January, 2014:
Amendments to IAS 36, “Impairment of Assets,” the retrospective adoption of these amendments
impacts the Company’s disclosures in the notes to its financial statements in periods when an
impairment loss or impairment reversal is recognised.
Amendments to the recognition, presentation and disclosure to pension accounting under IAS 19
“Employee Benefits”. The adoption of this amendment had no impact on the Company’s consoli-
dated financial statements.
IFRIC 21, “Levies,” the adoption of this standard had no impact on the amounts recorded in the
Company’s consolidated financial statements.
Future accounting policies
In May 2014, the IASB issued IFRS 15, “Revenue from Contracts with Customers,” which replaces
IAS 18 “Revenue,” IAS 11 “Construction Contracts,” and related interpretations. The new standard is
effective for annual periods beginning on or after 1 January, 2017 with earlier adoption permitted.
The Company intends to adopt IFRS 15 in its financial statements for the annual period beginning on
1 January, 2017. The extent of the impact of adoption of the standard has not yet been determined.
On 24 July, 2014, the IASB issued the complete IFRS 9, “Financial Instruments” to replace IAS 39,
“Financial Instruments: Recognition and Measurement”. IFRS 9 is effective for years beginning on or
after 1 January, 2018. Early adoption is permitted if IFRS 9 is adopted in its entirety at the beginning
of a fiscal period. The Company is currently evaluating the impact of adopting IFRS 9 on its consoli-
dated financial statements.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2014 5
USE OF ESTIMATES AND JUDGEMENTS
71
In applying the Company’s accounting policies, which are described in Note 4, management makes
estimates and assumptions concerning the future. The resulting accounting estimates will, by definition,
vary to the actual results. The estimates and assumptions that have a significant risk of causing a
material adjustment to the carrying amounts of assets and liabilities within the next financial year are
discussed below:
I)
RESERVES
There are numerous uncertainties inherent in estimating quantities of proved and probable
reserves and cash flows to be derived therefrom, including many factors beyond the control of the
Company. The reserve and cash flow information contained herein represents estimates only. The
reserves and estimated future net cash flow from the Company’s properties have been indepen-
dently evaluated by McDaniel & Associates Consultants Ltd. (“McDaniel”), independent petroleum
engineers. 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, TPDC “back-in” methodology and other government levies that may be imposed over the
producing life of the reserves. These assumptions were based on price forecasts in use at the date
of the relevant evaluations were prepared and many of these assumptions are subject to change
and are beyond the control of the Company. For the purpose of the reserves certification as at 31
December 2014 it was assumed that TPDC will ‘back-in’ for 20% for all future new drilling activities
as determined by the current development plan and this is reflected in the Company’s net reserve
position.
Reserves are integral to the amount of depletion recognized.
II)
CARRYING VALUE OF EXPLORATION AND EVALUATION ASSETS AND PROPERTY,
PLANT AND EQUIPMENT
Under the Company’s accounting policy expenditures incurred on the exploration for, and
evaluation of, reserves are capitalized as intangible assets. These intangibles assets are then assessed
for impairment when circumstances suggest that the carrying amount may exceed its recoverable
value. Such circumstances include but are not limited to:
•
•
•
•
•
•
the period for which the Company has the right to explore in the specific area has expired
during the period, or will expire in the near future, and is not expected to be renewed;
no further expenditure on exploration and evaluation is budgeted or planned;
no reserves have been encountered;
the evaluation of seismic data indicates that the reserves are unlikely to be of a commercial
quantity;
the quantity of hydrocarbon reserves are deemed not to be of commercially viable quantities
and the entity has decided to discontinue further activities; and
sufficient data exists to indicate that, although a development in the specific area is likely
to proceed, the carrying amount of the exploration and evaluation asset is unlikely to be
recovered in full from successful development or by sale.
The assessment for impairment involves estimates as to (i) the likely future commerciality of the
asset and when such commerciality should be determined, (ii) future revenues and costs associated
with the asset, and (iii) the discount rate to be applied to such revenues and costs for the purpose
of deriving a recoverable value.
Exploration and evaluation assets are assessed for impairment if (i) sufficient data exists to determine
technical feasibility and commercial viability, or (ii) facts and circumstances suggest that the carrying
amount exceeds the recoverable amount. For purposes of impairment testing, exploration and
evaluation assets are grouped by concession.
72
The technical feasibility and commercial viability of extracting a resource is considered to be
determinable based on several factors including the assignment of proven reserves. A review of
each exploration license or field is carried out, at least annually, to ascertain whether the project
is technically feasible and commercially viable. Upon determination of technical feasibility and
commercial viability, intangible exploration and evaluation assets attributable to those reserves are
first tested for impairment and then reclassified from exploration and evaluation assets to a separate
category within property and equipment referred to as oil and natural gas interests.
Management performs impairment tests annually on the Company’s property, plant and equipment
assets and at any time when indicators of impairment are present. The assessment of impairment
indicators is subjective and considers the various internal and external factors such as the financial
performance of individual CGUs, market capitalization and industry trends. If impairment indictors
are present an impairment test is required to be performed and the CGU is written down to its
recoverable amount. Key assumptions to determine the recoverable amount relate to prices that
are based on forward curves, long-term assumptions and discount rates that are risked to reflect
conditions specific to individual assets.
III) FAIR VALUE OF STOCK BASED COMPENSATION
All stock options issued or stock appreciation rights granted by the Company are required to be
valued at their fair value. In assessing the fair value of the equity based compensation, estimates
have to be made as to (i) the volatility in share price, (ii) the risk free rate of interest, and (iii) the level
of forfeiture. In the case of stock options, this fair value is estimated at the date of issue and is not
revalued, whereas the fair value of stock appreciation rights is recalculated at each reporting period.
IV) COST RECOVERY
The Company is able to recover reasonable costs incurred on the development of the Songo
Songo project out of 75% of the gross revenues less processing and pipeline tariffs (“Net Revenue”).
There are inherent uncertainties in estimating when costs have been recovered as these costs are
subject to government audit and in exceptional circumstances a potential reassessment after the
elapse of a considerable period of time. Currently approximately US$34 million in cost recoveries
for the period 2001 to 2009 have been rejected by TPDC, which audit finding is now the subject of
a Notice of Dispute by the Company.
V) COLLECTABILITY OF RECEIVABLES
The Company evaluates the collectability of its receivables on the basis of payment history, frequency
and predictability, as well as Management’s assessment of the customer’s willingness and ability to
pay. Both Songas and the Company have been impacted by TANESCO’s inability to pay.
Notwithstanding the previous reclassification of TANESCO arrears as a long-term receivable and
the subseqent provision against same (see Note 13 – Trade and Other Receivables), the Company
and TANESCO continue to operate in accordance with the terms of the PGSA and in accordance
with the understanding between the Company and TANESCO whereby natural gas continues to
be delivered by the Company and TANESCO would pay for current deliveries on a current basis
with payments to be applied firstly to pay for the current deliveries and excess amounts applied to
accumulated arrears.
In April and in May 2014, TANESCO advised the Company of its intention to make weekly payments
of TZS 3 billion (approximately US$1.8 million) against ongoing deliveries of gas, and undertook to
obtain outside financing and pay the balance of the arrears by the end of 2014. Weekly payments
substantially ceased during Q4 and TANESCO failed to clear the arrears by year-end 2014. Following
certain changes to senior officials within TANESCO and MEM (which has statutory oversight of
TANESCO), weekly payments resumed in Q1 2015. TANESCO has confirmed the understanding
between the parties that payments would be applied firstly to pay for the current gas deliveries and
that remaining amounts, if any, would be applied to the accumulated arrears. There is no assurance
that consistent weekly payments will be made. See also Note 13 – Trade and Other Receivables.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2014 6
RISK MANAGEMENT
73
The Company, by its activities in oil and gas exploration, development and production, is exposed to the
risk associated with the unpredictable nature of the financial markets as well as political risk associated
with conducting operations in an emerging market. The Company seeks to manage its exposure to
these risks wherever possible.
I)
FOREIGN EXCHANGE RISK
Foreign exchange risk arises when transactions and recognised assets and liabilities of the Company
are denominated in a currency that is not the US dollar functional currency.
The Company operates internationally and is exposed to foreign exchange risk arising from
currency exposures to U.S. dollars. The main currencies to which the Company has an exposure
are: Tanzanian shillings, British pounds sterling, Euros and Canadian dollars.
The majority of the expenditure associated with the operation of the gas distribution system is
denominated in Tanzanian shillings. Whilst conversion of Tanzanian shillings into US dollars is un-
restricted, the foreign exchange market for shillings is limited and not highly liquid, reducing the
Company’s ability to convert large amounts of shillings into US dollars at any given time. To mitigate
the risk of shilling devaluation, the Company regularly converts shilling payments into US dollars to
the extent practicable. The majority of the consultants’ contracts are denominated in British pounds
Sterling. All of the capital stock, equity financing and any associated stock based compensation
are denominated in Canadian dollars. All of the operational revenue and the majority of capital
expenditure are denominated in US dollars.
There are no forward exchange rate contracts in place.
A 10% increase in the US dollar against the relevant foreign currency would result in an overall
increase in working capital of US$4.3 million to US$38.4 million and a decrease in the loss before
tax to US$22.6 million. The sensitivity includes only outstanding foreign currency denominated
monetary items and adjusts their translation at period end for a 10% change in the foreign currency
rates. A 10% sensitivity rate is used when reporting foreign currency risk internally to key management
personnel and represents management’s assessment of the reasonable possible change in foreign
exchange rates.
The following balances are denominated in foreign currency (stated in US Dollars at period end
exchange rates):
Balances as at December 31, 2014
US$’000s
Canadian
Dollars
Tanzanian
Shillings
Other
currencies
Cash
Trade and other receivables
Trade and other payables
II)
COMMODITY PRICE RISK
109
–
(177)
(68)
28,450
28,191
(19,285)
39,579
5,731
–
(138)
5,594
Total
34,290
28,191
(19,599)
42,882
The Company negotiated industrial gas sales contracts with gas prices which, subject to certain
floors and ceilings, are determined as a discount toto the lowest cost alternative fuels in Dar es
Salaam, namely Heavy Fuel Oil (“HFO”) and coal. The price of HFO is exposed to the volatility in the
market price of crude oil.
III)
INTEREST RATE RISK
Currently the Company has no interest rate exposures.
74
IV) CREDIT RISK
Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial
instrument fails to meet its contractual obligations, and arises principally from the Company’s
receivables from TANESCO and Songas. The carrying amount of accounts receivable and the
long-term receivable represents the maximum credit exposure. As of December 31, 2014 and 2013,
other than the provisions against the long-term TANESCO receivable and gas plant operations
charges receivable from Songas, the Company does not have an allowance for doubtful accounts
against any other receivables nor was it required to write-off any receivables.
All of the Company’s production is currently derived in Tanzania. The sales are made to the Power
sector and the Industrial sector. In relation to sales to the Power sector, the Company has a contract
with Songas for the supply of gas to the Ubungo power plant and a contract with TANESCO to supply
approximately 37 MMcfd in 2014 to fire 147 MW of TANESCO power generation. The contracts with
Songas and TANESCO accounted for 55% of the Company’s operating revenue during 2014 and
US$83.7 million of the short- and long-term receivables prior to provision at year-end. Songas itself
is heavily reliant on the payment of capacity and energy charges by TANESCO for its liquidity.
TANESCO is in financial difficulty, which has resulted in irregular and inconsistent payments for gas
deliveries, in addition to the provision for the entire amount of arrears due from TANESCO in the
amount of US$52.2 million as at 31 December 2014.
Current TANESCO receivables as at 31 December 2014 amounted to US$7.7 million (Q4 2013
US$9.6 million). Since the year-end TANESCO has paid the Company US$18.7 million, and as at
the date of this report the total TANESCO receivable is US$52.9 million (of which US$52.2 million
is provided for).
Sales to the Industrial sector, currently 39 customers, are subject to an internal credit review to
minimize the risk of non-payment. As of the date of this report, all amounts outstanding at the
year-end have been collected from Industrial customers.
The Company is currently in discussions with TPDC, acting in its proposed capacity as a gas
aggregator, concerning the commercial terms for the sale of gas volumes associated with a planned
expansion of Songo Songo production, the conditions for which are described under V) below. The
Company has no history with TPDC as a debtor. Any contract with TPDC will expose the Company
to additional credit risk with a parastatal entity in Tanzania. Management intends to manage such
credit exposure by securing guarantees against future payments under such contracts from the
World Bank or other institutions.
The Company manages the credit exposure related to cash and cash equivalents by selecting
counterparties based on credit ratings and monitoring all investments to ensure a stable return,
avoiding complex investment vehicles with higher risk such as asset backed commercial paper.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2014 75
V)
LIQUIDITY RISK
Liquidity risk is the risk that the Company will not have sufficient funds to meet its liabilities. Cash
forecasts identifying liquidity requirements of the Company are produced on a regular basis. These
are reviewed to ensure sufficient funds exist to finance the Company’s current operational and
investment cash flow requirements. The Company has US$76.7 million of financial liabilities with
regards to trade and other payables identified in Note 16 of which US$69.1 million is due within one
to three months, nil is due within three to six months, and US$7.6 million is due within six to twelve
months. See Note 16 – Trade and Other Payables. As at year-end the Company had a current tax
liability of US$8.5 million, which after recent payments is US$5.4 million as at the date of this report.
At the year-end a significant proportion of the current liabilities related to Songas and TPDC, though
overall transactions between the Company and Songas showed a net receivable from Songas.
Since the year end Songas and the Company have settled outstanding tariff and gas sales invoices,
leaving a net receivable from Songas in respect of the gas plant operations. The amounts due to
TPDC represent a distribution of its share of Profit Gas; however given the difficulties in collecting
from TANESCO, the Company has been settling and intends to continue to settle these amounts
on a pro rata basis in accordance with amounts received from TANESCO. See Note 13 – Trade and
Other Receivables.
VI) CAPITAL RISK MANAGEMENT
The Company’s objectives when managing capital are to safeguard the Company’s ability to
continue as a going concern in order to provide returns for shareholders and benefits for other
stakeholders and to achieve an optimal capital structure to reduce the cost of capital. The level
of risk currently in Tanzania prohibits the optimisation of capital structure as many sources of
traditional capital are unavailable.
VII) COUNTRY RISK
In late 2011, there was resolution by Parliament advising the Government to terminate the
Company’s Songo Songo PSA on the gounds of an allegation by TPDC that the Company had
over-recovered approximately US$21 million in Cost Gas revenue. Parliament itself does not have
the authority to amend or terminate PSAs in Tanzania and in February 2012 on the recommenda-
tion of MEM, the Government announced that it was establishing a Government Negotiating Team
(“GNT”) to discuss a number of issues raised in parliament in relation to the Company’s Songo
Songo PSA. This included, but is not limited to, TPDC back in rights, profit sharing arrangements,
the unbundling of the downstream assets, cost recovery and the Company’s management of
the upstream operations. In July 2012, a conditional agreement in principle was reached on a
number of major points to resolve the issues. The conditional agreement in principle contemplated
completing this process by the end of 2012 as well as a number of undertakings from TPDC and the
Government. As at the date of this report none of undertakings of the Government or TPDC have
been met and, with the exception of the alleged US$21 million Cost Gas over recovery discussed
below, none of the issues are resolved.
In response to a Notice of Dispute delivered by the Company, in March 2014, TPDC retracted its
claim that the Company had over-recovered approximately US$21 million in Cost Gas, which in the
opinion of management substantially exonerated the Company of allegations made by Parliament.
Accordingly, the Company continues to rely upon its rights under the existing PSA and has initiated
notices of dispute to resolve any remaining issues.
76
VIII) EVOLVING REGULATORY ENVIRONMENT
The fiscal and regulatory environment for oil & gas exploration and development in Tanzania is in
its infancy. Following the discovery of significant offshore natural gas resources by international
exploration and development companies, there was pressure on the Government to create a clear
fiscal and regulatory framework for the industry. In October 2013, the Government of Tanzania
introduced a National Natural Gas Policy. The policy contemplates, among other things, a restruc-
turing of TPDC, increasing government ownership and control over infrastructure and resources,
strategic involvement in the LNG value chain, the establishment of TPDC as monopoly gas
aggregator in the country, and the establishment of Government controlled natural gas prices.
The policy as contemplated conflicts in a number of areas with the rights of the Company under
the PSA and has the potential, if implemented by law in its current form, to materially affect the
Company’s business. The PSA has provisions to cause the parties to meet and agree changes in
terms which would offset any changes in economic entitlement associated with a change in law.
IX) FINANCIAL INSTRUMENT CLASSIFICATION AND MEASUREMENT
The Company classifies the fair value of financial instruments according to the following hierarchy
based on the amount of observable inputs used to value the instrument:
Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the
reporting date. Active markets are those in which transactions occur in sufficient frequency and
volume to provide pricing information on an ongoing basis.
Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1. Prices
in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are
based on inputs, including expected interest rate, share prices, and volatility factors, which can be
substantially observed or corroborated in the marketplace.
Level 3 – Valuation in this level are those with inputs for the asset or liabilities that are not based on
observable market data.
7
SEGMENT INFORMATION
The Company has one reportable industry segment which is international exploration, development and
production of petroleum and natural gas. The Company currently has producing and exploration assets
in Tanzania and had exploration and appraisal interests in Italy.
US$’000
External Revenue
Segment loss
Non-cash charge 1
Depletion &
Depreciation
Exploration asset
impairment
Capital Additions
Total Assets
Total Liabilities
2014
Tanzania
56,607
Total
56,607
(38,295)
(38,301)
37,047
37,047
14,197
14,197
5,086
1,312
196,561
121,585
5,086
1,312
198,492
121,857
Italy
–
(6)
–
–
–
–
1,931
272
2013 restated
Total
53,482
(7,640)
24,968
Tanzania
53,482
(6,964)
24,968
12,498
12,498
–
1,288
207,000
92,256
158
1,288
207,257
92,477
Italy
–
(676)
–
–
158
–
257
221
(1) Non-cash charge represent amounts provided for doubtful accounts receivable from TANESCO and Songas.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2014 8
REVENUE
US$’000
Operating revenue
Current income tax adjustment
Additional Profits Tax (Note 12)
Revenue
77
YEARS ENDED 31 DECEMBER
2014
2013 restated
52,619
11,268
(7,280)
56,607
53,855
13,056
(13,429)
53,482
The Company’s total revenues for the year amounted to US$56,607 after adjusting the Company’s
operating revenue of US$52,619 by:
i)
ii)
adding US$11,268 for income tax for the current year. The Company is liable for income tax in
Tanzania, but the income tax is recoverable out of TPDC’s Profit Gas when the tax is payable. To
account for this, revenue is adjusted to include the current income tax charge grossed up at 30%
(see Note 11); and
subtracting US$7,280 for deferred Additional Profits Tax charged in the year – this tax is considered a
royalty and is presented as a reduction in revenue. The APT charge for the year includes a reduction
in APT of US$936 resulting from the recovery of downstream costs previously and temporarily
excluded from the cost recoverable pool as discussed below.
Cost Pool Adjustments
In 2010, following an agreement with TPDC the Company agreed to temporarily defer the cost recovery
of expenditure associated with development of the downstream network until such time as a mutually
acceptable methodology could be agreed between the Company and TPDC/MEM to unbundle the
downstream assets from the PSA and related business and to recover the associated cost of the operation
outside of the PSA. In 2013 the Company re-tabled a number of proposals that were economically
neutral to the parties; however these received no feedback and were subsequently withdrawn. The
Company has now formally advised TPDC that the downstream business will remain under the PSA and
that related costs would be recovered in accordance with the terms of the PSA and would no longer be
held separately. As a result of recovering this expenditure the results for the year reflect a reallocation of
Cost Gas and Profit Gas between TPDC and the Company.
During the ongoing discussions concerning the disputed US$34 million TPDC Cost Pool audit claim,
items totalling US$1.0 million were agreed by the Company to have been non-recoverable and conse-
quently were removed from the Cost Pool during the year.
The following table shows the impact on the Company’s operating revenue for the year resulting from
adjusting the cost pool. The net amount which is included in the Company’s operating revenue of
US$52,619, has been recovered from TPDC’s share of revenue as follows:
US$’000
Non-recoverable costs
Recoverable costs 2011-2013
Cost Gas recorded in the period
Reduction in Profit Gas in the period
Net impact on Company share of operating revenue
YEAR ENDED 31 DECEMBER
2014
(1,024)
7,360
6,336
(3,342)
2,994
78
9
PERSONNEL EXPENSES
The average number of employees during the year was 94 (2013: 91). The costs are as follows:
US$’000
Wages and salaries
Social security costs
Other statutory costs
Stock based compensation
YEARS ENDED 31 DECEMBER
2014
2013 restated
8,958
8,040
675
321
9,954
3,482
13,436
981
258
9,279
(209)
9,070
Stock based compensation is recorded under general and administrative expenses in the statement
of comprehensive loss. The balance of personnel expenses for 2014 of US$10.0 million (2013: US$9.3
million) is recorded in distribution and production expenses and general administrative expenses at
US$3.0 million (2013: US$2.7 million) and US$7.0 million (2013: US$6.6 million) respectively. Personnel
expenses include Company employees who operate the plant on behalf of Songas, which expenses are
recharged to Songas. The comparative figure has been restated to include Company employees who are
engaged full-time in the operation of the gas plant on behalf of Songas.
10
NET FINANCE COSTS
US$’000
Interest charged on overdue trade receivables
Gain on disposal of motor vehicle
Finance income
Interest expense
Net foreign exchange loss
Provision for doubtful accounts / Discount on long-term receivable
Finance costs
Net finance costs
YEARS ENDED 31 DECEMBER
2014
2013 restated
98
–
98
(24)
(4,437)
(37,047)
(41,508)
(41,410)
–
10
10
(678)
(317)
(24,968)
(25,963)
(25,953)
During 2014, the Company billed TANESCO US$2.2 million (2013: US$2.6 million) of interest for late
payments. The interest income is not recorded in the financial statements because it does not meet IAS
18 revenue recognition criteria. The Company is pursing collection and amounts will be recognised in
earnings when collected.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2014
11
INCOME TAXES
The tax charge is as follows:
US$’000
Current tax
Deferred tax/(recovery)
79
YEARS ENDED 31 DECEMBER
2014
2013 restated
11,895
(457)
11,438
12,849
(10,593)
2,256
Tax of US$1.5 million (2013: US$5.8 million) was paid during the year in relation to the settlement of the
prior year’s tax liability. In addition, provisional tax payments US$8.8 million (2013: US$8.4 million) were
made in respect of the current year. These are presented as a reduction in Tax Payable on the balance
sheet.
Tax Rate Reconciliation
US$’000
Loss before taxation
Provision for income tax calculated at the statutory rate of 30%
Add the tax effect of non-deductible income tax items:
Administrative and operating expenses
Unrealized exchange loss
Tax penalties
Stock-based compensation
Impact of reversing provision against interest (Note 10)
Unrecognized tax asset
Other permanent differences
YEARS ENDED 31 DECEMBER
2014
2013 restated
(26,863)
(8,059)
(5,384)
(1,615)
1,387
349
272
1,045
650
15,646
148
11,438
2,697
(16)
221
(104)
791
–
282
2,256
As at 31 December 2014, the uncertainty with regards to the collection of the TANESCO receivables has
resulted in a US$15,646 unrecognised deferred tax asset.
The deferred income tax asset (liability) includes the following temporary differences:
US$’000
Differences between tax base and carrying value
of property, plant and equipment
Tax recoverable from TPDC
Discount on receivable and provision for doubtful debt
Deferred Additional Profits Tax
Unrealised exchange losses/other provisions
AS AT 31 DECEMBER
2014
2013 restated
(15,498)
(5,116)
2,945
8,688
1,375
(16,980)
(5,852)
7,490
6,504
499
(7,606)
(8,069)
80
Tax Recoverable
The Company has a “Tax Recoverable” balance of US$11.8 million (2013: US$10.9 million). This arises
from the revenue sharing mechanism within the PSA, which entitles the Company to recover from
TPDC, by way of a deduction from TPDC’s Profit Gas share an amount, the “adjustment factor”, equal
to the actual income taxes payable by the Company. The recovery, by deduction from TPDC’s share of
revenue, is dependent upon payment of income taxes relating to prior period adjustment factors as they
are assessed.
US$’000
Tax Recoverable
12
ADDITIONAL PROFITS TAX
AS AT 31 DECEMBER
2014
2013 restated
11,815
10,866
Under the terms of the PSA, in the event that all costs have been recovered with an annual cash return
from the PSA of 25% plus the percentage change in the United States Industrial Goods Producer Price
Index (“PPI”), an Additional Profits Tax (“APT”) is payable.
The Company provides for deferred APT by forecasting the total APT payable as a proportion of the
forecast Profit Gas over the term of the PSA. The effective APT rate of 21.9% (2013: 30.8%) has been
applied to Profit Gas of US$37.4 million (2013: US$43.6 million). Accordingly, US$7.3 million (2013:
US$13.4 million) has been netted off revenue for the year ended 31 December 2014. The APT charge for
the year include a reduction of US$0.9 million, reflecting the impact of recovering downstream costs on
cumulative Profit Gas, as a result of the US$3.3 million Profit Gas adjustment identified in the Cost Pool
adjustment – see Note 8.
US$’000
Deferred APT
AS AT 31 DECEMBER
2014
7,280
2013
13,429
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2014 13
TRADE AND OTHER RECEIVABLES
81
AS AT 31 DECEMBER
2014
2013 restated
Current Receivables
US$’000
TANESCO
Songas
Other debtors
Trade receivables
Songas gas plant operations
Other receivables
Less provision for doubtful accounts
Trade Receivables Age Analysis
US$’000
TANESCO
Songas
Other debtors
Trade receivables
US$’000
TANESCO
Songas
Other debtors
Trade receivables
7,671
23,864
7,532
39,067
19,300
773
(9,816)
49,324
>90
–
20,555
495
21,050
>90
–
8,541
2,728
11,269
9,624
11,560
10,874
32,058
13,280
2,408
(7,895)
39,851
Total
7,671
23,864
7,532
39,067
Total
9,624
11,560
10,874
32,058
AS AT 31 DECEMBER 2014
Current
>30 <60
>60 <90
3,893
1,107
3,469
8,469
3,778
1,067
2,758
7,603
–
1,135
810
1,945
AS AT 31 DECEMBER 2013
Current
>30 <60
>60 <90
5,071
1,076
3,663
9,810
4,553
1,016
2,822
8,391
–
927
1,661
2,588
TANESCO
At 31 December 2014, TANESCO owed the Company US$59.8 million excluding interest (of which
arrears were US$52.2 million) compared to US$54.0 million (including arrears of US$44.3 million) as at
31 December 2013. During the year, the Company received a total of US$46.7 million (2013: US$49.6
million) from TANESCO against sales totaling US$54.7 million (2013: US$72.9 million). Current TANESCO
receivables as at 31 December 2014 amounted to US$7.7 million (2013 US$9.6 million). Since the
year-end, TANESCO has paid the Company US$18.7 million in 2015, and as at the date of this report
the total TANESCO receivable is US$52.9 million (of which US$52.2 million has been provided for). The
amounts owed do not include interest billed to TANESCO (Note 10).
Beginning in May 2014, TANESCO commenced a series of payments for current and past gas deliveries
of US$1.8 million received approximately weekly. Management estimated that if these payments
continued they would result in approximately US$1.5 million per month credited against arrears. During
Q4 2014 TANESCO made only one payment, although subsequent to the year-end TANESCO resumed
weekly payments and as of the date of this report the Company has received US$18.7 million in 2015.
Whilst weekly payments against current deliveries have re-commenced, there is still no set schedule or
repayment plan for TANESCO arrears agreed with the Company and payments continue to be irregular
and unpredictable. As a result, there continues to be significant doubt about TANESCO’s ability to settle
arrears.
82
Pursuant to its rights under the PGSA, the Company, on 2 April 2014, served a Notice of Dispute to
TANESCO demanding payment in full to collect the arrears, as well examining the Company’s legal
and contractual options to mitigate a further increase in arrears, including but not limited to suspending
gas deliveries to TANESCO. The Notice of Dispute has remained in effect whilst the Company sought
a mutually acceptable payment plan to clear the arrears within an acceptable time frame. In April 2014
and again in May, TANESCO advised the Company of its intention to make weekly payments of TZS 3.0
billion (approximately US$1.8 million) to the Company against ongoing deliveries of gas and as continue
to seek third-party financing to repay the balance of arrears. TANESCO has confirmed the understanding
between the parties that payments would be applied firstly to pay for the current gas deliveries, and that
remaining amounts, if any, would be applied to the accumulated arrears.
At 31 December 2014, the Company re-assessed the TANESCO arrears in light of (i) the discontinuance
of weekly payments during Q4 2014; (ii) the fact that TANESCO did not pay down substantially all of the
arrears by year-end pursuant to a formal commitment made earlier during the year which was tied to
Government receipt of World Bank funding; (iii) the lack of a definitive plan to repay arrears in light of (ii)
above; and (iv) the absence of any evidence of the availability of external funding for TANESCO, including
World Bank funding. As a result of increased uncertainty with respect to the timing and amount of ultimate
collection of amounts in arrears, the Company recorded a provision for doubtful accounts against the
entire long-term receivable of US$52.2 million as at 31 December 2014. Amounts collected with respect
to the long-term receivable in the future will be reflected in earnings when payment is received. Not-
withstanding this provision, the Company and TANESCO continue to operate in accordance with the
terms of the Portfolio Gas Supply Agreement and in accordance with the understanding between the
Company and TANESCO whereby natural gas continues to be delivered by the Company and TANESCO
would pay for current deliveries on a current basis with payments to be applied firstly to pay for the
current deliveries and any excess amount applied to accumulated arrears. This provision against the
TANESCO long-term receivable will not prejudice the Company’s rights to payment in full or its ability to
pursue collection in accordance with the terms of the agreement with TANESCO. Whilst the Company
is unable to recognise interest revenue in accordance with International Accounting Standards, it will
continue to charge TANESCO interest in accordance with the terms of the PGSA.
Long-Term Receivables
US$’000
TANESCO receivable > 60 days
Discount on long-term receivable
Provision for doubtful debts
Net TANESCO receivable
VAT bond
Lease deposit
Total long-term receivables
AS AT 31 DECEMBER
2014
52,154
(17,073)
(35,081)
–
369
265
634
2013
44,348
(17,073)
–
27,275
–
–
27,275
Songas
As at 31 December 2014, Songas owed the Company US$43.2 million (2013: US$24.8 million), whilst the
Company owed Songas US$30.4 million (2013: US$16.9 million). There was no contractual right to offset
these amounts at 31 December 2014. Amounts due to Songas primarily relate to pipeline tariff charges of
US$28.9 million (2013: US$15.4 million), whereas the amounts due to the Company are mainly for sales
of gas of US$23.9 million (2013: US$11.6 million) and for the operation of the gas plant for US$19.3 million
(2013: US$13.3 million). The operation of the gas plant is conducted at cost and the charges are billed to
Songas on a flow through basis without profit margin.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2014 83
All amounts due to and from Songas have been summarized in the net Songas balance (see Note 16)
of US$12.7 million (2013: US$7.9 million). A provision for doubtful debts of US$9.8 million (2013: US$7.9
million) has been recognised against the gas plant operation receivable of US$19.3 million (2013 : US$13.3
million).
Following an extended period during which no cash was received and no balances set-off, the Company
was unable to recognise the Songas receivable. Accordingly, as at 31 March 2014 the Company had
fully provided for the net amount due from Songas. However, during the second half of 2014 Songas
began to make payments in respect of the gas plant operations, and in Q4 2014 the Company received
four payments totaling US$1.7 million, bringing the total for the year to US$2.6 million. Subsequent to
year-end, Songas has made a further three payments totaling US$5.7 million.
Management continued to work with Songas throughout 2014 towards an agreement to set-off
outstanding sales, purchases and gas plant operating charges. In February 2015 management decided
that agreement was unlikely to be reached in the short-term, and began to pay the outstanding tariff
charges. Songas responded by commencing settlement of outstanding gas sales invoices. As at the date
of this report the Company has paid US$29.8 million in respect of outstanding tariff charges and has
received US$23.9 million in settlement of outstanding gas sales invoices. Management has reviewed the
current provision of US$9.8 million (2013: US$7.9 million) against the outstanding gas plant operating
charges and has decided to retain the provision pending further progress in resolving disputed charges.
The provision will be released as and when the Company is able to collect the outstanding debt amounts.
Any amounts not agreed will likely be pursued by the Company through the mechanisms provided in its
agreements with Songas.
14
EXPLORATION AND EVALUATION ASSETS
US$’000
Costs
As at 1 January 2014
Impairment
Transfer to Oil & Natural Gas assets
As at 31 December 2014
US$’000
Costs
As at 1 January 2013
Additions
Impairment
As at 31 December 2013
TANZANIA
Italy
Tanzania
Total
–
–
–
–
5,564
(5,086)
(478)
–
5,564
(5,086)
(478)
–
Italy
Tanzania
Total
158
–
(158)
–
5,562
2
–
5,564
5,720
2
(158)
5,564
The exploration and evaluation assets represented site survey costs and materials purchased in preparation
for the drilling of the first Songo Songo West well. The Company has no current plans to drill this well,
therefore the site survey costs of US$5,086 have been impaired and related materials of US$478 available
for use in relation to development drilling and workovers have been transferred to Oil and Natural Gas
interests.
84
15
PROPERTY, PLANT AND EQUIPMENT
Oil and natural
gas interests
Leasehold
improvements
Computer
equipment
Vehicles
Fixtures
& Fittings
Total
US$’000
Costs
As at 1 January 2014
Additions
Transfer from
Exploration &
Evaluation assets
Disposals
139,072
1,103
478
–
As at 31 December 2014
140,653
Depletion and Depreciation
As at 1 January 2014
49,967
Depletion and
depreciation
Cost of disposals
13,567
–
As at 31 December 2014
63,534
Net Book Values
885
72
–
(258)
699
245
183
(258)
170
1,158
75
–
–
1,233
761
194
–
955
137
12
–
–
149
137
(17)
–
120
1,082
50
142,334
1,312
–
(7)
478
(265)
1,125
143,859
392
270
–
662
51,502
14,197
(258)
65,441
As at 31 December 2014
77,119
529
278
29
463
78,418
Oil and natural
gas interests
Leasehold
improvements
Computer
equipment
Vehicles
Fixtures
& Fittings
US$’000
Costs
As at 1 January 2013
138,958
Additions
Disposals
114
–
As at 31 December 2013
139,072
Depletion and Depreciation
As at 1 January 2013
Charge for period
Depreciation
on disposals
37,801
12,166
–
As at 31 December 2013
49,967
Net Book Values
256
629
–
885
219
26
–
245
As at 31 December 2013
89,105
640
833
325
–
1,158
649
112
–
761
397
Total
141,113
1,286
(65)
864
218
–
1,082
142,334
206
186
–
392
39,069
12,498
(65)
51,502
202
–
(65)
137
194
8
(65)
137
–
690
90,832
In determining the depletion charge, it is estimated that future development costs of US$252 million
(31 December 2013: US$239 million) will be required to bring the total proved reserves to production.
During the year the Company recorded depreciation of US$0.6 million (2013: US$0.3 million) in General
and Administrative expenses.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2014 16
TRADE AND OTHER PAYABLES
US$’000
Songas (1)
Other trade payables
Trade payables
TPDC share of Profit Gas
Deferred income
Accrued liabilities
85
AS AT 31 DECEMBER
2014
2013 – restated
28,871
1,961
30,832
33,409
2,780
9,726
15,355
3,857
19,212
21,501
6,271
7,169
76,747
54,153
(1) A summary of all Songas balances is presented below. This shows the opening position, movements during the year and details of post year-end
settlements made in cash by the Company and by Songas. See Note 13 – Trade and Other Receivables.
1 January
2014
Year to date
transactions
Gross balance
31 Dec 2014
Post year-end
payments and
receipts
Outstanding
as at the date
of this report
(15,355)
(13,516)
(28,871)
28,871
11,560
13,280
(1,544)
7,941
12,304
6,020
(30)
4,778
23,864
19,300
(1,574)
12,719
(23,864)
(5,680)
–
(673)
–
–
13,620
(1,574)
12,046
Pipeline tariff - payable
Gas sales - receivable
Gas plant operation - receivable
Other payable
Net balances
17
BANK LOAN
The loan was fully paid by February 2014. Total payments during the year ended 31 December 2014 were
US$1.7 million (2013: US$8.2 milllion).
86
18
CAPITAL STOCK
a) Authorised
50,000,000
100,000,000
100,000,000
Class A Common Shares
No par value
Class B Subordinate Voting Shares No par value
First Preference Shares
No par value
The Class A and Class B shares rank pari passu in respect of dividends and repayment of capital in
the event of winding-up. Class A shares carry twenty (20) votes per share and Class B shares carry
one vote per share. The Class A shares are convertible at the option of the holder at any time into
Class B shares on a one-for-one basis. The Class B shares are convertible into Class A shares on
a one-for-one basis in the event that a take-over bid is made to purchase Class A shares which
must, by reason of a stock exchange or legal requirements, be made to all or substantially all of the
holders of Class A shares and which is not concurrently made to holders of Class B shares.
b) Changes in the capital stock of the Company were as follows:
Number of Shares
Authorised
Issued
Amount
Authorised
Issued
Amount
2014
2013
(000’s)
Class A
(US$’000)
(US$’000)
As at 1 January ‘and 31 December
50,000
1,751
983
50,000
1,751
983
Class B
As at 1 January
100,000
33,072
84,445
100,000
32,892
84,000
Stock options exercised
–
92
209
–
180
445
As at 31 December 2014
100,000
33,164
84,654
100,000
33,072
84,445
First Preference
As at 31 December
Total Class A, Class B
and First Preference shares
100,000
–
–
100,000
–
–
250,000
34,915
85,637
250,000
34,823
85,428
All of the issued capital stock is fully paid.
Stock Options
Thousands of options or CDN$
2014
2013
Options
Exercise Price
Options
Exercise Price
Outstanding as at 1 January
1,742
1.00 to 3.60
1,922
1.00 to 3.60
Forfeited
Exercised
Expired unexercised
Outstanding as at 31 December
(250)
(92)
(1,000)
400
3.60
1.00
1.00
3.18
–
(180)
–
–
1.00
–
1,742
1.00 to 3.60
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2014
87
The weighted average remaining life and weighted average exercise prices of options at 31 December
2014 were as follows:
Exercise Price
2014
2013
(CDN$)
Stock Appreciation Rights
Number
Outstanding
as at
31 Dec 2014
Weighted
Average
Remaining
Contractual Life
Number
Exercisable as at
31 Dec 2014
Weighted
Average
Exercise Price
(‘000)
400
(years)
3.00
2014
(‘000)
400
(CDN$)
3.18
2013
Thousands of stock appreciation rights or CDN$
SAR
Exercise Price
SAR
Exercise Price
Outstanding as at 1 January 2014
1,130
2.12 to 4.20
845
2.35 to 5.30
Expired
Granted (i)
1,780
2.30
(15)
300
5.30
2.12
Outstanding as at 31 December 2014
2,910
2.12 to 4.20
1,130
2.12 to 4.20
(i) A total of 1,780,000 SARs were issued in January 2014 with an exercise price of CDN$2.30. These rights have a term of five years and vest in five
equal instalments, the first tranche vesting on the anniversary of the grant date. There is no maximum liability associated with these rights.
Restricted Stock Units
Thousands of restricted stock units or CDN$
Outstanding as at 1 January
Granted (i)
Exercised
Outstanding as at 31 December
2014
Grant/Exercise
Price
2013
Grant/Exercise
Price
SAR
–
3.70
3.79
2.90
–
–
–
–
–
–
–
–
SAR
–
792
(147)
645
(i) In September the Company issued 792,391 Restricted Stock Units (“RSUs”) with an award price of CDN$0.01.
As SARs and RSUs are settled in cash, they are re-valued at each reporting date using the Black-
Scholes option pricing model with the resulting liability being recognised in trade and other
payables. In the valuation of stock appreciation rights and restricted stock units at the reporting
date, the following assumptions have been made: a risk free rate of interest of 1.75% stock volatility
of 52.4% to 60.7%; 0% dividend yield; 0% forfeiture; a closing stock price of CDN$2.90 per share.
US$’000
SARs
RSUs
YEAR ENDED 31 DECEMBER
2014
1,369
2,113
3,482
2013
(209)
–
(209)
As at 31 December 2014, a total accrued liability of US$3.4 million (2013: US$0.4 million) has
been recognised in relation to SARs and RSUs which is included in other payables. The Company
recognised an expense for the year of US$3.5 million (2013: credit US$0.2 million) in G&A expenses.
The increase over 2013 is the result of the share price increasing to US$2.90 (2013: US$2.35), the
granting in January 2014 of an additional 1.8 million SARS and the issue in September 2014 of 0.8
million RSUs.
88
19
EARNINGS PER SHARE
Number of shares (‘000)
Weighted average number of shares outstanding
Class A and Class B shares
Convertible securities
Stock options
Weighted average diluted Class A and Class B shares
AS AT 31 DECEMBER
2014
2013
34,863
34,719
–
–
34,863
34,719
The calculation of basic earnings per share is based on a net loss for the year of US$38.3 million (2013:
loss US$7.6 million) and a weighted average number of Class A and Class B shares outstanding during the
period of 34,862,588 (2013: 34,718,662).
In computing the diluted earnings per share, the effect of stock options is added to the weighted average
number of common shares outstanding during the year. For 2014 the effective number was nil (2013:
nil) shares, resulting in a diluted weighted average number of Class A and Class B shares of 34,862,588
for the year ended 31 December 2014 (2013: 34,718,662). No adjustments were required to the reported
earnings from operations in computing diluted per share amounts.
20
RELATED PARTY TRANSACTIONS
One of the non-executive Directors is a partner at a law firm. During the year, the Company incurred
US$0.2 million (2013: US$0.1 million) to this firm for services provided. The transactions with this related
party were made at the exchange amount. The Chief Financial Officer provided services to the Company
through a consulting agreement with a personal services company, during the year the Company
incurred US$0.6 million (2013 US$0.6 million) to this firm for services provided. As at 31 December 2014
the Company has a total of US$ nil (2013: US$ nil) recorded in trade and other payables in relation to the
related parties.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2014 21
CONTRACTUAL OBLIGATIONS
AND COMMITTED CAPITAL INVESTMENTS
89
Protected Gas
Under the terms of the original gas agreement for the Songo Songo project (“Gas Agreement”), in the
event that there is a shortfall/insufficiency in Protected Gas as a consequence of the sale of Additional
Gas, then the Company is liable to pay the difference between the price of Protected Gas (US$0.55/
MMbtu escalated) 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 (127.7 Bcf as at 31 December 2014). The Company
did not have a shortfall during the reporting period and does not anticipate a shortfall arising during the
term of the Protected Gas delivery obligation to July 2024.
The Gas Agreement may be superseded by an initialed Amended and Restated Gas Agreement (“ARGA”).
The ARGA, which is currently unsigned, provides clarification of the Protected Gas volumes and removes
all terms dealing with the security of the Protected Gas and contract terms dealing with the conse-
quences of any insufficiency are dealt with in a new Insufficiency Agreement (“IA”). The IA specifies terms
under which Songas may demand cash security in order to keep it whole in the event of a Protected
Gas insufficiency. Should the IA be signed, it will govern the basis for determining security. Under the
provisional terms of the IA, when it is calculated that funding is required, the Company is required to
fund an escrow account at a rate of US$2.00/MMbtu on all Industrial Additional Gas sales out of its and
TPDC’s share of revenue, and TANESCO shall contribute the same amount on Additional Gas sales to the
Power sector. The funds provide security for Songas in the event of an insufficiency of Protected Gas. The
Company is actively monitoring the reservoir and, supported by the report of its independent engineers,
does not anticipate that a liability will occur in this respect. As at the date of this report, the ARGA remains
an intitialled agreement only, however the parties thereto, in certain respects, are conducting themselves
as though the ARGA is in full force and effect.
Re-Rating Agreement
In 2011, the Company signed a re-rating agreement with TANESCO and Songas (the “Re-Rating Agreement”)
to increase the gas processing capacity to a maximum of 110 MMcfd (the pipeline and pressure require-
ments at the Ubungo power plant restrict the infrastructure capacity to a maximum of 102 MMcfd). Under
the terms of the Re-Rating Agreement, the Company effectively pays an additional tariff of US$0.30/mcf
for sales between 70 MMcfd and 90 MMcfd and US$0.40/mcf for volumes above 90 MMcfd in addition
to the tariff of US$0.59/mcf payable to Songas as set by the energy regulator, EWURA.
Under the terms of this agreement, the Company agreed to indemnify Songas for damage to its facilities
caused by the re-rating, up to a maximum of US$15 million, but only to the extent that this was not
already covered by indemnities from TANESCO’s or Songas’ insurance policies. The Re-Rating Agreement
expired on 31st December 2012 and in September 2013 was extended by Songas to 31 December 2013.
At this time, the Company knows of no reason to de-rate the Songas plant. Since 31 December 2013
production has continued within the higher rated limit and, given the Government’s interest in pursuing
further development and increasing gas production, the Company expects this to continue. However
there are no assurances that this will occur.
Portfolio Gas Supply Agreement
On 17 June 2011, a long term (to June 2023) PGSA was signed between TANESCO (as the buyer) and
the Company and TPDC (collectively as the seller). Under the PGSA, the seller is obligated, subject to
infrastructure capacity, to sell a maximum of approximately 37 MMcfd for use in any of TANESCO’s
current power plants except those operated by Songas at Ubungo. Under the agreement, the basic
wellhead price of approximately US$2.88/mcf increased to US$2.93/mcf on 1 July 2014. Any volumes of
gas delivered under the PGSA in excess of 36 MMcfd are subject to a 150% increase in the basic wellhead
gas price.
90
Operating leases
The Company has two office rental agreements, one in Dar es Salaam, Tanzania and one in Winchester,
United Kingdom. The agreement in Dar es Salaam was entered into on 1 November 2013 and expires
on 31 October 2015 at an annual rent of US$401 thousand. The agreement in Winchester expires on 25
September 2022 and is at an annual rental of GBP35 thousand (US$58 thousand) per annum during 2012
and 2013 and GBP71 thousand (US$115 thousand) per annum thereafter. The costs of these leases are
recognised in the General and Administrative expenses.
Capital Commitments
Italy
On 31 May 2010, the Company signed an agreement with Petroceltic International plc (“Petroceltic”)
to farm in on Petroceltic’s Central Adriatic B.R268.RG Permit offshore Italy. The farm-in commits the
Company to fund 30% of the Elsa-2 appraisal well up to a maximum of US$11.5 million to earn a 15%
working interest in the permit. Thereafter, the Company will fund all future costs relating to the well and
the permit in proportion to its participating interest. The Company has also agreed to pay Petroceltic
fifteen per cent (15%) of the back costs in relation to the well up to a maximum of US$0.5 million.
No activity has occurred on the Adriatic Sea block during 2014. In 2012, a new law modified restrictions
on offshore oil and gas exploration and production originally introduced by DLGS 128/2010 in August
2010. The Elsa-2 appraisal well is now expected to be drilled in 2016 following finalisation of an environ-
mental impact study. The Company will not be liable to any costs associated with the drilling of Elsa-2
until a rig contract is signed. As of the date of this report, there is no rig contract. There are no further
capital commitments in Italy.
Tanzania – Songo Songo
Until such a time as the Company enters into a drilling contract for the Phase I development of Songo
Songo, there are no capital commitments in Tanzania.
22
CONTINGENCIES
Downstream unbundling
The separation or unbundling of the downstream assets currently in the PSA has been an objective of
TPDC and MEM for some time. Unbundling was an issue raised by TPDC in the 2012 GNT negotia-
tions and by MEM in the National Natural Gas Policy issued in 2013, which contemplates TPDC as a
monopoly aggregator and distributor of gas. In the context of the gas policy, TPDC and MEM have
indicated that they wish the Company to unbundle the downstream distribution business in Tanzania.
The methodology for this has been discussed with TPDC in the course of GNT negotiations. During 2013,
the Company tabled a proposal with alternative mechanisms to unbundle the downstream from the PSA
which were economically neutral to the parties. TPDC did not respond to the proposal and it was later
withdrawn by the Company in connection with the termination of negotiations arising from the GNT and
TPDC was advised that the downstream would remain in the PSA until mutually agreed otherwise. The
disposition of the downstream business will be addressed at such a time as there is a conflict between
new legislation and the Company’s rights under the PSA. The results for the year reflect the impact of
fully recovering downstream costs previously and temporarily excluded from the cost recoverable pool
pending resolution of the unbundling of the downstream business and the related assets – see Cost Pool
Adjustments Note 8.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2014 91
TPDC Back-in
TPDC has previously indicated a wish to exercise its right under the PSA to ‘back in’ to the Songo Songo
field development and a further wish to convert this into a carried interest in the PSA. The current terms
of the PSA require TPDC to provide formal notice in a defined period and contribute a proportion of the
costs of any development, sharing in the risks in return for an additional share of the gas. To date, TPDC
has not contributed any costs. TPDC back-in rights and the potential conversion of these rights into a
carried working interest were discussed with the GNT along with other issues, however there were no
changes to the PSA agreed between the parties. As such the Company continues to stand behind the
original terms of the PSA. Should an amendment to the PSA be agreed in future relating to back-in rights,
the impact on reserves and accounting estimates will be assessed at that time and reflected prospectively.
For the purpose of the reserves certification as at 31 December 2014, it was assumed that TPDC will elect
to ‘back-in’ for 20% for all future new drilling activities within the prescribed period as determined by the
current development plan and this is reflected in the Company’s net reserve position.
Cost recovery
TPDC conducted an audit of the historic Cost Pool and in 2011 disputed approximately US$34 million
of costs that had been recovered from the Cost Pool from 2002 through to 2009. The Company has
contended that the disputed costs were appropriately incurred on the Songo Songo project in accordance
with the terms of the PSA. Undertakings to resolve this matter were an outcome of GNT negotiations
and the matter was referred to the Controller and Auditor General (“CAG”), head of the National Audit
Office of Tanzania. With no progress on resolving the matter, the Company served a Notice of Dispute
on TPDC to put the matter to a definitive timeline for resolution, following which the CAG appointed
an international independent audit firm to review the disputed costs. The work of the CAG has been
completed and TPDC has reviewed its findings. TPDC and Company senior management have held
discussions, and the Company is awaiting the appointment of an independent specialist to assist the
parties in reaching agreement on costs that are still subject to dispute. The Company has agreed a
number of small adjustments, totaling approximately US$1.0 million, and these were removed from the
Cost Pool during the year. See Note 8 Revenue -- Cost Pool Adjustments. If the matter is not resolved to
the Company’s satisfaction, it intends to proceed to arbitration via the International Centre for Settlement
of Investment Disputes (“ICSID”) pursuant to the terms of the PSA.
TPDC marketing costs
Under the Songo Songo PSA, all reasonable marketing costs including those incurred by TPDC, with the
prior approval by the Company, are recoverable. TPDC has to date attempted to claim US$3.6 million
in marketing costs from the Company. Management reviewed the claims and can demonstrate that
there was no prior approval for such costs, no supporting documentation provided evidencing the
expenditure, and further believes the nature of the costs to be unreasonable and not related to marketing
the downstream business. Accordingly the Company has rejected the claim by TPDC.
Taxation
During 2013 the Company received a number of assessments for additional tax from the Tanzania
Revenue Authority (“TRA”), which together with interest penalties total US$16.9 million. Management,
together with tax advisors, have reviewed each of the assessments and believe them to be without merit.
The Company has appealed against assessments for additional withholding tax and employment related
taxes, and has filed formal objections against TRA’s claims for additional corporation tax and VAT. If the
Company is unsuccessful in its appeals against these assessments, the amounts of interest and penalties
could be materially higher.
The Tax Revenue Appeals Board (TRAB) considered the Company’s appeal against a withholding tax
assessment of US$2.2 million in March 2013 and upheld the assessment. The Company then appealed
to Tax Revenue Appeals Tribunal whose decision is awaited. Although a similar appeal to the Tribunal
has been decided in favour of TRA, management continues to believe this assessment is flawed and, if
necessary, will pursue the case in the Court of Appeal where a similar case is currently being heard.
92
The Company, based on legal counsel’s advice, believes it has strong support, on the basis of tax
legislation and the terms of the PSA, for its objection to the additional income tax assessment of US$7.1
million, including penalties related to 2008, 2009 and 2010 tax years. During the year, TRA notified the
Company that it would not accept the objection relating to 2009 and issued a notice confirming the
assessment for US$2.3 million. The Company has lodged an appeal against this assessment with the
TRAB. In the event that the Company’s 2008 and 2010 objections are rejected and subsequent appeals
are overturned, any additional tax payable will be recoverable from TPDC under the terms the PSA. If the
Company is unsuccessful in its appeals against these assessments, the amounts of interest and penalties
could be materially higher.
The Company has filed an objection against a further assessment of VAT, which together with penalties
totals US$6.9 million. Again, the Company, based on legal counsel’s advice, believes that it has strong
grounds for objecting to this assessment and accordingly has made no provision.
The Company has received an assessment of US$0.7 million in respect of employment related taxes
which TRA believe to have been underpaid. The Company does not accept TRA’s finding and has appealed.
Management continues to review the progress of the above appeals and objections and, as of the date
of this report, does not believe any provision is required.
During the year TRA conducted an audit of the Company’s tax returns for 2011 and issued their audit
findings which indicated that additional taxes amounting to US$1.1 million should be paid in respect of
employment costs, income and withholding taxes. The Company considers it to be without merit and is
preparing to respond to TRA.
23
DIRECTORS AND OFFICERS EMOLUMENTS
US$’000
Directors
Directors
Officers
Officers
Year
2014
2013
2014
2013
Base
1,412
1,454
748
1,227
Share based
Compensation
Expense
2,412
–
334
–
Bonus
660
335
210
175
Total
4,484
1,789
1,292
1,402
The table above provides information on compensation relating to the Company’s officers and directors.
Four officers and two non-executive directors comprised the key management personnel during the
year ended 31 December 2014 (2013: five officers and two non-executive directors). Two of the officers
are also directors and as such their remuneration has been included under directors’ emoluments in the
table above.
ORCA EXPLORATION GROUP INC. | 2014 ANNUAL REPORTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2014 Corporate Information
93
David W. Ross
Non-Executive Director
William H. Smith
Non-Executive Director
Robert S. Wynne
Chief Financial Officer
Calgary, Alberta
Canada
Calgary, Alberta
Canada
Calgary, Alberta
Canada
Robert S. Wynne
Chief Financial Officer
Stephen Huckerby
Chief Accounting Officer
Calgary, Alberta
Canada
St. Peters, Jersey
Channel Islands
David K. Roberts
Vice President of
Operations
Kansas City, Missouri
United States of America
Registered Office
Investor Relations
Orca Exploration
Group Inc.
P.O. Box 3152
Road Town
Tortola
British Virgin Islands
W. David Lyons
Chairman and
Chief Executive Officer
WDLyons@orcaexploration.com
www.orcaexploration.com
Board of Directors
W. David Lyons
Chairman and
Chief Executive Officer
Winchester
United Kingdom
Officers
W. David Lyons
Chairman and
Chief Executive Officer
Winchester
United Kingdom
Operating Office
PanAfrican Energy
Tanzania Limited
Oyster Plaza Building, 5th Floor
Haile Selassie Road
P.O. Box 80139, Dar es Salaam
Tanzania
Tel: + 255 22 2138737
Fax: + 255 22 2138938
International Subsidiaries
PanAfrican Energy
Tanzania Limited
PAE PanAfrican
Energy Corporation
Oyster Plaza Building, 5th Floor
Haile Selassie Road
P.O. Box 80139, Dar es Salaam
Tanzania
Tel: + 255 22 2138737
Fax: + 255 22 2138938
1st Floor
Cnr St George/Chazal Streets
Port Louis
Mauritius
Tel: + 230 207 8888
Fax: + 230 207 8833
Orca Exploration Italy Inc.
Orca Exploration Italy
Onshore Inc.
P.O. Box 3152,
Road Town
Tortola
British Virgin Islands
Engineering Consultants
Auditors
Website
McDaniel & Associates
Consultants Ltd.
Calgary, Canada
KPMG LLP
Calgary, Canada
orcaexploration.com
Lawyers
Burnet, Duckworth
& Palmer LLP
Calgary, Canada
Transfer Agent
CIBC Mellon
Trust Company
Toronto & Montreal, Canada
ORCA EXPLORATION GROUP INC. 2014 ANNUAL REPORT www.orcaexploration.com