O R C A E X P L O R A T I O N G R O U P I N C .
2015
ANNUAL
REPORT
B
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
2015 OPERATING HIGHLIGHTS . . . . . 2
GAS RESERVES . . . . . 4
MANAGEMENT’S DISCUSSION & ANALYSIS . . . . . 7
MANAGEMENT’S REPORT TO SHAREHOLDERS . . . . . 48
AUDITORS’ REPORT . . . . . 49
FINANCIAL STATEMENTS . . . . . 50
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS . . . . . 54
CORPORATE INFORMATION . . . . . 85
GLOSSARY
mcf
Thousands of standard cubic feet
MMcf
Millions of standard cubic feet
Bcf
Tcf
Billions of standard cubic feet
Trillions of standard cubic feet
MMcfd Millions of standard cubic feet per day
MMbtu Millions of British thermal units
1P
2P
3P
Kwh
MW
US$
Proven reserves
Proven and probable reserves
Proven, probable and possible reserves
Kilowatt hour
Megawatt
US dollars
HHV
LHV
High heat value
Low heat value
CDN$ Canadian dollars
bar
Fifteen pounds pressure per square inch
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORT Financial and Operating Highlights
(Expressed in US$ unless indicated otherwise)
OPERATING
Daily average gas delivered and sold (MMcfd)
Protected Gas
Additional Gas
Industrial
Power
Total gas production
Average price (US$/mcf)
Industrial
Power
Total
Operating netback (US$/mcf)
Additional Gas Gross Recoverable Reserves to end of license (Bcf)
Proved
Probable
Proved plus probable
Net Present Value, discounted at 10% (US$ millions)
Proved
Proved plus probable
FINANCIAL
Revenue
Funds flow from operating activities (1)
per share - basic and diluted (US$)
Net cash flows from operating activities
per share - basic and diluted (US$)
Net income (loss)
per share - basic and diluted (US$)
Working capital
Cash
Capital expenditures
Long-term loan
Outstanding Shares ('000)
Class A
Class B
Total shares outstanding
Options
Weighted average diluted Class A and Class B shares
(1) See MD&A - Non-GAAP Measure.
1
fi
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g
h
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h
t
s
Year ended/ as at 31 December
2015
2014
38.8
47.4
11.4
36.0
86.2
7.58
3.54
4.49
2.57
368
49
417
309
357
54,088
26,571
0.76
7,018
0.20
1,533
0.04
32,521
53,797
38,411
18,599
1,751
33,106
34,857
–
34,887
36.6
53.2
12.6
40.6
89.8
8.61
3.56
4.76
2.22
450
54
504
379
417
56,607
32,436
0.93
29,757
0.85
(38,301)
(1.10)
34,148
57,659
1,312
–
1,751
33,164
34,915
400
34,863
2
2015 Operating Highlights
•
•
•
•
Total Songo Songo field Protected Gas plus
Additional Gas deliveries and sales averaged 86.2
standard cubic feet per day (“MMcfd”) a decrease of
3% over the prior year (89.8 MMcfd). Additional Gas
sales volumes averaged 47.4MMcfd, a decrease of
11% over the prior year (53.2 MMcfd) due largely to
declining field productivity for the first nine months
of the year together with reduced nominations
by the Tanzanian Electrical Supply Company
(“TANESCO”) and reduced gas sales to Tanzania
Portland Cement Company (“TPCC”) because of
maintenance issues in the first half of the year.
Power sector sales volumes decreased 11% to 36.0
MMcfd compared to 40.6 MMcfd in the prior year,
as a result of a decrease in production from the
Songo Songo field due to the natural decline in
well deliverability through Q3-2015 and the removal
of two TANESCO power plant delivery points by
order of the Ministry of Energy and Minerals on 9
September 2015. In accordance with the Portfolio
Gas Supply Agreement (“PGSA”) with TANESCO,
a decrease in field gas production impacts on the
volume supplied to the state utility.
Industrial sales volumes decreased 9% to 11.4 MMcfd
compared to 12.6 MMcfd in the prior year. The
decrease is primarily due to a reduction in natural
gas consumption by a cement company in Dar es
Salaam resulting from unscheduled maintenance
and the cessation of gas consumption by a textile
company at the end of its contract period. These
reductions were partly offset by an increase in gas
consumption by edible oil companies.
Average gas prices decreased 6% to US$4.49/
mcf compared to US$4.76/mcf in the prior period.
Industrial gas prices were down 12% to US$7.58/
mcf compared to US$8.61/mcf in the prior year.
The decrease is primarily due to a change in sales
mix together with a 48% decline in heavy fuel oil
(“HFO”) prices (to which a majority of Industrial
contracts are tied). The decline in the price of HFO
is partially mitigated by floor prices in the contracts.
Average Power sector gas prices decreased by 1%
to US$3.54/mcf compared to US$3.56/mcf in the
prior year, the annual indexation increase being
counteracted by no sales to TANESCO having been
made at the premium pricing as a consequence of
decreased nominations.
•
•
Total proved reserves for Additional Gas decreased
18% to 368 Bcf from 450 Bcf in the prior year and
total proved plus probable reserves (“2P”) decreased
17% to 417 Bcf from 504 Bcf in the prior year.
The decrease in both is a consequence of 2015
Additional Gas production of 17.3 Bcf and the slower
anticipated growth in Power demand than previously
communicated to the Company from the Tanzanian
Petroleum Development Corporation (“TPDC”). The
net present value of the estimated future cash flows
of the 2P reserves at a 10% discount rate (“NPV10”)
decreased 14% to US$357 million from US$417
million in the previous year. The decline is a result
of the fall in anticipated growth of the Power sector
revenues which are anticipated to be realized at
lower prices. The Company no longer considers it
to be realistic that the PGSA gas prices will be rolled
out given the industry competition that now exists in
Tanzania.
Revenue decreased 4% to US$54.1 million
from US$56.6 million. The fall in revenue is the
combination of an 11% fall in total Additional Gas
sales volumes, and the 6% fall in the weighted
average sale price. The capital investment in the
workover programme during the year increased the
Company share of net revenue as a consequence
of increased Cost Gas and a smaller Profit Gas
allocation to TPDC. This helped to offset the overall
decline in revenue resulting from the drop in both
volumes and prices. Funds flow from operating
activities decreased 18% to US$26.6 million or
US$0.76 per share basic and diluted, compared to
US$32.4 million or US$0.93 per share basic and
diluted in the prior period, primarily the result of
lower revenue.
• Net income for the year was US$1.5 million or
US$0.04 per share basic and diluted, as compared to
loss of US$38.3 million or loss of US$1.10 per share
in the prior year. The loss in 2014 was primarily due
to a US$35.1 million provision against the receivable
from TANESCO.
• Working capital as at 31 December 2015 decreased
5% to US$32.5 million compared to US$34.1 million
as at 31 December 2014 primarily as a result of
moving forward with the development programme
offset by a US$20 million increase in long-term debt.
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORT 3
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•
Total capital expenditures were US$38.4 million for
the year. In June 2015 the Company entered into a
drilling contract with Paragon Offshore plc for the
use of its M826 Mobile Drilling Workover Rig, as
well the provision of associated services, in order
to execute the offshore phase of the development
programme for the Songo Songo gas field (the
“Offshore Programme”). The Offshore Programme
commenced on 2 September 2015 and included
the workovers on three existing wells (SS-5, SS-7
and SS-9) and drilling of one new well, SS-12. All
workovers were successfully completed during the
year while well SS-12 was successfully completed
in February 2016. Upon completion of the Offshore
Programme, the rig was released.
• On 29 October 2015, the Company and the
International Finance Corporation (“IFC”) completed
a debt financing agreement for the Company’s
operating subsidiary, PanAfrican Energy Tanzania
Limited to borrow up to US$60 million. The
financing is a subordinated, income participating
loan with flexible repayment terms and a maximum
tenure of approximately 10 years. Drawdowns of
the facility are subject to a number of terms and
conditions. As at 31 December 2015, US$20 million
of the facility had been drawn down, with the
remaining US$40 million drawn in February 2016.
The US$1.2 billion government sponsored Tanzania
National Natural Gas Infrastructure Project (“NNGIP”)
is substantially complete, and the NNGIP gas
processing plant on Songo Songo Island is expected
to be able to take first gas by April 2016. The
Company has submitted a draft gas sales agreement
to TPDC to allow direct gas delivery to the NNGIP.
Commercial terms remain a key condition to the
Company’s commitment to expand Songo Songo
natural gas sales beyond the existing Songas
infrastructure and to supply gas to the NNGIP.
At the end of 2014 the Company reached and
confirmed an understanding with TANESCO that
it would only continue to supply gas if TANESCO
remained current with payments for current gas
deliveries. Excess payments received over and above
the current balances would be applied to the arrears
balance. In December 2014 as a result of a review
the Company established a full provision against the
entire long-term receivable of US$52.2 million as at
31 December 2014.
•
•
•
TANESCO payments for 2015 continued to be
irregular. During Q4 2015 TANESCO payments
decreased with only US$4.5 million being received
against sales of US$11.7 million. As at 31 December
2015 Management has reviewed the current
position with TANESCO and feels that the policy
implemented in 2014 is still appropriate and as a
result, has reclassified a further US$9.8 million, the
arrears in excess of 60 days, as long-term debt and
has placed a full provision against this. As at the date
of this report the total receivable is US$75.4 million.
• During the third quarter of 2015, The Petroleum Act,
2015, (the “Act”) was passed into law. The Act repeals
earlier legislation, provides a regulatory framework
over upstream, mid-stream and downstream
gas activity, and consolidates and puts in place a
comprehensive legal framework for regulating the
oil and gas industry in the country. The Act also
provides for the creation of an upstream regulator,
the Petroleum Upstream Regulatory Authority
(PURA). The mid and downstream oil and gas
activities are proposed to be regulated by the current
authority, the Energy and Water Utilities Regulatory
Authority (EWURA). The bill also confers upon on
TPDC, the status of the National Oil Company,
mandated with the task of managing the country’s
commercial interest in petroleum operations as well
as mid and downstream natural gas activities. The
bill vests TPDC with exclusive rights in the entire
petroleum upstream value chain and the natural
gas mid and downstream value chain. However,
the exclusive rights of TPDC do not extend to mid
and downstream petroleum supply operations. The
Company is uncertain regarding the potential impact
on its business in Tanzania. The Act does provide
grandfathering provisions upholding the rights of the
Company under their Production Sharing Agreement
(“PSA”) as it was signed prior to passing of the Act.
However, it is still unclear how the provisions of the
Act will be interpreted and implemented regarding
upstream and downstream activities.
•
The Company has an agreement to farm in on
Central Adriatic B.R268.RG Permit offshore Italy.
Changes in Italian environmental legislation in
late 2015 have resulted in the development of this
permit being postponed indefinitely. As at the date
of this report, the Company has no further capital
commitments in Italy.
4
Gas Reserves
The Company's natural gas reserves as at December 31, 2015 for the period to the end of its license in October 2026
were evaluated by independent petroleum engineering consultants McDaniel & Associates Consultants Ltd. (“McDaniel”) in
accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook
(“COGE Handbook”) and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). The
independent reserves evaluation prepared by McDaniel (the “McDaniel Report”) is dated 24 March 2016 with an effective
date of 31 December 2015. A reserves committee of the Company reviews the qualifications and appointment of the
independent reserves evaluator and reviews the procedures for providing information to the evaluators. Reserves inluded
herein are stated on a company gross basis unless noted otherwise. All the Company's reserves are conventional natural gas
reserves and are located in Tanzania. Additional reserves information required under NI 51-101 are included in Orca's reports
relating to reserves data and other oil and gas information under NI 51-101, which have been filed on its profile on SEDAR at
www.sedar.com.
During 2015 no significant geological or geophysical data was 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. The completion of the SS-12 development
well in February 2016 encountered the top reservoir approximately 100 meters high to prognosis, and the Company is
currently analyzing this new data and its likely impact on the GIIP. The 2015 McDaniel Report has not made any allowance
for any additional reserves associated with SS-12.
On a gross Company basis there has been an 18% decrease in Songo Songo’s Total Proved Additional Gas reserves to the
end of the license period, with no change on a life of field basis, with a total Additional Gas production of 17.3 Bcf during the
year. There has been a 17% decrease in the Proved plus Probable Additional Gas reserves on a Gross Company life of license
basis from 504.4 to 416.9 Bcf with no change on a life of field basis. The decrease is due to the 2015 production of Additional
Gas and the slower anticipated growth in sales of Additional Gas to the NNGIP compared to previous years.
A summary of the remaining Additional Gas reserves on a life of license and life of field basis are presented below:
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)
2015
Gross (1)
Net (2)
Gross
245.9
121.9
367.8
49.1
416.9
158.5
70.5
229.0
40.9
269.9
283.6
166.8
450.4
54.0
504.4
2014
Net
194.0
88.9
282.9
37.3
320.2
(1) Gross equals the gross reserves that are available for the Company after estimating the effect of the TPDC back in (see below).
(2) Net equals the economic allocation of the Gross reserves to the Company as determined in accordance with the PSA.
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORT
5
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Songo Songo
Additional Gas reserves to end of field life (Bcf)
Independent reserves evaluation
Proved producing
Proved undeveloped
Total proved (1P)
Probable
Total proved and probable (2P)
2015
2014
Gross (1)
Net (2)
Gross
Net
598.9
46.5
645.4
116.5
761.9
375.9
28.3
404.2
76.7
480.9
554.2
95.1
649.3
118.4
767.7
359.7
50.9
410.6
76.5
487.1
(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 PSA.
For the reserves certification as at 31 December 2015, the McDaniel Report has assumed that TPDC will exercise its right
to ‘back in’ to any additional new field development plans for Songo Songo and consequently will receive a 20% increase
in the profit share for the future production emanating from the SSN-1 well. McDaniel has taken the view that this ‘back in’
right should be treated as a TPDC working interest and therefore the Gross reserves have been adjusted for the volumes of
Additional Gas that are allocated to TPDC for their working interest share.
For the purpose of calculating the Gross Additional Gas reserves, McDaniel has assumed in its 2P case that 122 Bcf (2014: 130
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 2015, the Protected Gas users consumed 14.2 Bcf.
Additional Gas
price
Gross Additional Gas
volumes
Additional Gas
price
Gross Additional Gas
volumes
Year
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
1P
US$/mcf
3.99
4.10
4.06
4.08
4.18
4.30
4.43
4.56
4.60
4.67
4.96
1P
MMcfd
93.10
93.60
108.90
124.70
128.60
132.90
137.21
141.51
145.82
140.63
121.89
2P
US$/mcf
4.03
4.27
4.27
4.28
4.44
4.63
4.82
4.98
4.98
4.95
4.96
2P
MMcfd
93.75
98.49
115.29
137.17
141.46
146.19
155.80
157.00
159.34
166.80
148.83
6
Gas Reserves
Present value of reserves
The estimated value of the Songo Songo reserves on a life of license basis based on the assumptions on production and
pricing are as follows:
US$ millions
Proved producing
Proved undeveloped
Total proved (1P)
Probable
Total proved and probable (2P)
2015
10%
229.2
79.4
308.6
48.8
357.4
5%
294.6
114.7
409.3
65.9
475.2
15%
184.6
55.5
240.1
37.7
277.8
2014
10%
195.9
182.9
378.8
38.4
417.2
5%
274.3
233.5
507.8
60.3
568.1
15%
144.3
145.1
289.4
25.4
314.8
There has been a 14% decrease in the 2P present value at a 10% discount basis from US$417 million to US$357 million on a
life of license basis.
The decrease in value is predominately a consequence of the slower anticipated power sales to TPDC via the NNGIP
Infrastructure. In order to commission the NNGIP gas processing plant in Mtwara in September 2015, the Company under
a Government of Tanzania directive was requested to allow connection to the NNGIP Infrastructure of two TANESCO
power plants previously supplied under the PGSA contract. The slower than anticipated construction and commissioning of
additional power plants has resulted in the inability of the Company to make additional gas sales despite the completion of
the Company’s offshore component of the development plan jointly approved with TPDC.
Previous reserve reports valuations have been based on the assumption that the PGSA contract would be rolled out for
deliveries to the NNGIP infrastructure. Following the connection of the two PGSA delivery points and the continued supply
of gas to these plants by a third party, this assumption has been revised using the gas price contemplated for future sales
to TPDC for valuation purposes. There is no guarantee that this proposed price will be realized and as such there could be
further adjustments to the Company’s 2P present value once the negotiations are finalised and a new gas sales agreement
is signed with TPDC.
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. | 2015 ANNUAL REPORT 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
THIS MD&A OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS SHOULD BE IN CONJUNCTION WITH THE
AUDITED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES FOR THE YEAR ENDED 31 DECEMBER 2015. THIS MD&A
IS BASED ON THE INFORMATION AVAILABLE ON 14 APRIL 2016.
FORWARD LOOKING STATEMENTS
This management’s discussion and analysis (“MD&A”) contains forward-looking statements or information (collectively, “for-
ward-looking statements”) within the meaning of applicable securities legislation. More particularly, this MD&A contains,
without limitation, forward-looking statements pertaining to the following: the Company's expectations regarding supply
and demand of natural gas; anticipated power sector revenues; potential impact of TPDC future back-in rights on the
economic terms of the PSA; the commissioning of the second gas processing facility on Songo Song Island which is part
of the National Natural Gas Infrastructure Project (“NNGIP”) which included construction and commissioning of two gas
processing facilities, a 505 kilometer pipeline supplying gas from the Mtwara Region of Tanzania to Dar es Salaam and a
28 kilometer pipeline supplying gas from Songo Songo Island to the mainland NNGIP; ability to meet all conditions under
the International Finance Corporation (“IFC”) financing agreement signed on 29 October 2015; the Company’s estimated
spending for the planned Development Programme for 2016 and 2017, which includes construction of the production
platform for well SS-12, tie-in of well SS-12 to the production facilities and implementation of a refrigeration unit to enable
production into the NNGIP; the potential impact of the Petroleum Act 2015 on the Company’s business in Tanzania; the
Company’s belief that the parties to the unsigned Amended and Restated Gas Agreement (“ARGA”) will continue to conduct
themselves in accordance with the ARGA until the new Gas Sales Agreement (“GSA”) is signed; the Company’s expectation
that, despite the Re-Rating Agreement of the gas processing plant owned by Songas Limited (“Songas”) having expired, the
Songas gas processing plant will not be de-rated and the risk that Songas and the Company will not agree on appropriate
terms and sign the GSA in a timely manner; the Company’s expectation that it can expand and maintain the deliverability
of gas volumes in excess of the existing Songas infrastructure; the Company’s expectation that the SS-4 well may need
to be suspended in the future; the forward-looking statements 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; and the Company’s expectations in respect of its appeal on the decision of the Tax Revenue Appeals
Tribunal and other statements under “Contingencies - Taxation”. 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 the Company’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.
These forward-looking statements involve substantial known and unknown risks and uncertainties, certain of which are
beyond the Company’s control, and many factors could cause the Company’s actual results to differ materially from those
expressed or implied in any forward-looking statements made by the Company, including, but not limited to: failure to
receive payments from the Tanzanian Electrical Supply Company (“TANESCO”); risk on timing for the NNGIP to be fully
commissioned; risk that the Tanzanian Production Development Corporation (“TPDC”), the Ministry of Energy and Minerals
(“MEM”) and the Company are unable to agree on commercial terms for future incremental gas sales and consequently
the Company cannot expand the Songo Songo development beyond the existing Songas infrastructure and supply gas
to the NNGIP; risk that additional gas volumes available to the NNGIP from third parties will replace all or a portion of the
volumes currently nominated by TANESCO under the Portfolio Gas Sales Agreement (“PGSA”) until additional gas-fired power
generation is brought on-stream to consume all of the Company’s available gas production; risk that the Development
Programme is not completed as planned and the actual cost to complete the Development Programme exceeds the
Company’s estimates; risk that the remaining well workovers under the Development Programme are unsuccessful or
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTManagement’s Discussion & Analysis 9
determined to be infeasible; risk that the contingencies related to the development work for the full field development plan
for Songo Songo are not satisfied; potential negative effect on the Company’s rights under the Production Sharing Agreement
(“PSA”) and other agreements relating to its business in Tanzania as a result of the recently approved Petroleum Act, 2015, as
well as the risk that such legislation will create additional costs and time connected with the Company’s business in Tanzania;
risk that, without extending or replacing the Re-Rating Agreement, the gas processing plant may be de-rated back to its
original capacity, resulting in a material reduction in the Company’s sales volumes of Additional Gas; risk that the Company
will not fully recover Songas’ share of capital expenditures associated with the workovers of wells SS-5 and SS-9; risk that
the Company will be required to pay additional taxes and penalties; the impact of general economic conditions in the areas
in which the Company operates; civil unrest; industry conditions; changes in laws and regulations including the adoption
of new environmental laws and regulations and changes in how they are interpreted and enforced; increased competition;
the lack of availability of qualified personnel or management; fluctuations in commodity prices, foreign exchange or interest
rates; stock market volatility; 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 satisfy debt obligations and conditions; failure to successfully negotiate agreements;
and risk that the Company will not be able to fulfil its contractual obligations. In addition there are risks and uncertainties
associated with oil and gas operations, therefore the Company’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 the Company 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 the Company in light of its experience and
perception of historical trends, current conditions and expected future developments, as well as other factors the Company
believes are appropriate in the circumstances, including, but not limited to, that the NNGIP is completed; the TPDC, the MEM
and the Company are able to agree on commercial terms for future incremental gas sales and the Company can expand
Songo Songo development beyond the existing Songas infrastructure and supply gas to the NNGIP; the Development
Programme will be completed within the timing anticipated; the actual costs to complete the Development Programme are
in line with estimates; 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 the Company to increase production at a consistent rate; infrastructure capacity; commodity prices will not further
deteriorate significantly; the ability of the Company 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’s appeal of
various tax assessments will be successful; that the enactment of the Petroleum Act, 2015 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 the Company 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.
management's discussion & analysis 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 OPERATING ACTIVITIES 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.
NATURE OF OPERATIONS
The Company’s principal operating asset is its interest in the PSA with 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 PSA defines the gas produced from the Songo Songo field as “Protected Gas” and “Additional Gas”. The Protected Gas
is owned by TPDC and is sold under a 20-year gas agreement (until 31st July 2024) to Songas. Songas is the owner of the
infrastructure that enables the gas to be treated and 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 and for onward sale to
customers. The Company receives no revenue for the Protected Gas delivered to Songas and operates the original wells 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”).
TANESCO is a parastatal organization which is wholly-owned by the Government of Tanzania, with oversight by the 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 40% 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 38 industrial customers.
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTManagement’s Discussion & Analysis
11
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, 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.
Songas is not required to incur capital costs with respect to additional processing and transportation facilities unless the
construction and operation of the facilities are, in the reasonable opinion of Songas, financially viable. If Songas is unable
to finance such facilities, Songas shall permit the seller of the gas to construct the facilities at its expense, provided that,
the facilities are designed, engineered and constructed in accordance with good pipeline and oilfield practices.
Revenue sharing terms and taxation
(g) 75% of the gross revenues, less processing and pipeline tariffs and direct sales taxes in any year (net revenue) can be
used to recover past costs incurred. Costs recovered out of net revenue are termed “Cost Gas”.
management's discussion & analysis
12
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 ratable 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. For the purpose of the reserves certification as at 31 December 2015, it was assumed that TPDC will ‘back-in’
for 20% for all future new drilling activities as determined by the current submitted Additional Gas 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 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 initialed agreement only and the parties are not in agreement
with all the terms in the ARGA, however the parties are conducting themselves in terms of pricing as though the ARGA
is in force. The Company and Songas are currently negotiating a new GSA.
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 31 December 2013. At this time
the Company knows of no reason to de-rate the Songas gas processing plant and continues to produce at the higher
rated limit and the Company expects this to continue. However, there are no assurances that the ability to produce at
the higher rating will continue.
(i) The cost of maintaining the wells and flowlines is split between the Protected Gas and Additional Gas users in proportion
to the volume of their respective sales. The cost of operating the gas processing plant and the pipeline to Dar es Salaam
is covered through the payment of the pipeline tariff.
(j) Profits on sales from the Proven Section (“Profit Gas”) are shared between TPDC and the Company, the 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 of the cumulative
production or the average daily sales. The Profit Gas share is a minimum of 25% and a maximum of 55%.
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTManagement’s Discussion & Analysis
13
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 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.
(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, maintenance of books and records, preparation of reports, maintenance of permits, waste handling,
liaison with the Government of Tanzania and taking 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 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 willful 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 (“PAET”)
Orca Exploration UK Services Limited
Incorporated
British Virgin Islands
British Virgin Islands
British Virgin Islands
Mauritius
Jersey
United Kingdom
management's discussion & analysis
14
Results for the year ended 31 December 2015
SUMMARY
The year ended 31 December 2015 saw a decrease from the prior year in 2P reserve volumes of 17% as a result of gas
produced during the year, combined with slower anticipated growth in power demand that had been assumed based on
forecasts from TPDC. As a result, the net present value of cash flows from 2P reserves at a 10% discount rate decreased
13% compared to the prior year. Production capabilities increased during 2015 as a result of a significant capital expenditure
program of US$38.4 million which included the completion of three successful workovers.
The decrease in revenue for 2015 resulted in funds flow from operating activities declining 18% compared to the prior year.
A further increase in the provision of the TANESCO long-term receivable also affected profitability, however, the Company
was still able to earn a small profit for the year. The Company finished 2015 in a stable financial position with US$32.5 million
in working capital and US$18.6 million in long-term debt as a result of the successful completion of a financing facility with
the International Finance Corporation.
OPERATING VOLUMES
The total volume of Protected Gas and Additional Gas delivered and sold for the year ended 31 December 2015 was
31,485 MMcf (2014: 32,770 MMcf) or 86.2 MMcfd (2014: 89.8 MMcfd), net of approximately 0.5 MMcfd (2014: 0.8 MMcfd)
consumed locally for fuel gas.
The Additional Gas sales volumes for the year were 17,311 MMcf (2014: 19,421 MMcf) or average daily volumes of 47.4 MMcfd
(2014: 53.2 MMcfd). This represents a decrease in average daily volumes of 11% year on year.
Additional Gas sales volumes for Q4 2015 were 4,572 MMcf (Q4 2014: 4,461 MMcf) or average daily volumes of 49.7 MMcfd
(Q4 2014: 48.5 MMcfd), an increase of 2.5% over the prior year quarter.
The decrease in Additional Gas volumes year over year is primarily the result of declining field productivity, reductions in
nominations by TANESCO, and reduced Industrial gas sales volumes during the first nine months of 2015. The increase in
Additional Gas sold quarter over quarter is the result of increasing field production as a consequence of successfully working
over wells SS-5 and SS-9 during the third and fourth quarters of 2015. These wells were put back into production in Q4 2015.
The Company’s sales volumes were split between the Industrial and Power sectors as detailed in the table below:
Gross sales volume (MMcf)
Industrial sector
Power sector
Total volumes
Gross daily sales volume (MMcfd)
Industrial sector
Power sector
Total daily sales volume
THREE MONTHS ENDED
31 DECEMBER
YEAR ENDED
31 DECEMBER
2015
2014
2015
2014
1,089
3,483
4,572
11.8
37.9
49.7
1,084
3,377
4,461
11.8
36.7
48.5
4,166
13,145
17,311
11.4
36.0
47.4
4,598
14,823
19,421
12.6
40.6
53.2
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTManagement’s Discussion & Analysis
15
Industrial sector
Industrial sales volume decreased by 9% to 4,166 MMcf (11.4 MMcfd) from 4,598 MMcf (12.6 MMcfd) in 2014. The decrease is
primarily the result of unscheduled maintenance work by a number of customers together with the cessation of consumption
by a textile company at the end of its contract period in June 2015.
Fourth quarter Industrial sales volume increased by 1% to 1,089 MMcf (11.8 MMcfd) from 1,084 MMcf (11.8 MMcfd) in the
prior year quarter.
Power sector
Power sector sales volumes decreased by 11% to 13,145 MMcf (36.0 MMcfd), compared to 14,823 MMcf (40.6 MMcfd) in
2014 as a result of decreased production from the Songo Songo field due to deliverability constraints during the first three
quarters of 2015, and the decision by TANESCO not to renew a power generation contract with an emergency power plant.
Power sector sales volumes increased by 3% to 3,483 MMcf (37.9 MMcfd), compared to 3,377 MMcf (36.7 MMcfd) in Q4
2014 as a result of an increase in gas production following the successful completion of the well workover programme in
Q4 2015. Under the PGSA Gas supply contract, TANESCO is a swing customer receiving less gas in the event of decline in
gas production. The increase in gas deliverability as a result of successful workovers has resulted in TANESCO increasing gas
consumption levels compared with same quarter in previous year.
SONGO SONGO DELIVERABILITY
As at 31 December 2015, the Company had a field productive capacity of approximately 155 MMcfd, with the expansion of
production volumes limited to 102 MMcfd by the available Songas infrastructure. The increase in field productive capacity
was due to successful workovers on wells SS-5, SS-7 and SS-9 completed during the fourth quarter of 2015. Well SS-3 is
currently suspended and well SS-4 has been shut-in; it is the Company’s intention to undertake workovers on both the wells
in the future. Subsequent to year-end, the Company completed drilling well SS-12, adding a further 35 MMcfd to the field
productive capacity. The SS-12 well cannot be produced until the construction of a platform and flowline to tie the well into
the NNGIP infrastructure.
The Company now has significant redundant productive capacity and is planning the installation of refrigeration and
compression facilities to ensure production capacity can be maintained well in excess of the volumes required to fill the
Songas infrastructure. The Company is currently negotiating an agreement with TPDC for additional gas sales by tying into
the NNGIP. Initial volumes sold to TPDC under this agreement would see a concomitant reduction in volumes through the
existing Songas infrastructure. This would allow the Company to further increase sales volumes to industrial customers as
production capacity would no longer be constrained by the Songas infrastructure.
management's discussion & analysis 16
COMMODITY PRICES
The commodity prices achieved in the different sectors during the year is detailed in the table below:
US$/mcf
Average sales price
Industrial sector
Power sector
Weighted average price
THREE MONTHS ENDED
31 DECEMBER
YEAR ENDED
31 DECEMBER
2015
2014
2015
2014
7.62
3.56
4.51
8.24
3.49
4.64
7.58
3.54
4.49
8.61
3.56
4.76
i)
In Q4 2015 the Company recognised income of US$0.7 million (Q4 2014: US$0.9 million), and for the year to 31 December 2015 US$2.1
million (2014: US$4.2 million), deferred under a take-or-pay provision in an Industrial contract. Under the terms of 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 in the quarter and the year ended 31 December 2015.
Industrial sector
The average gas price achieved during the year was US$7.58/mcf down 12% from (2014: US$8.61/mcf). This is a consequence
of several factors (i) a 48% decline in the Heavy fuel Oil (“HFO”) prices in the world market has offset the impact of annual
price indexation for Industrial customers and has resulted in the majority of Industrial customers sales, whose prices are tied
to HFO prices, being at the contractual floor in accordance with their contracts. The contractual pricing floors having helped
to mitigate the impact of a falling HFO price, (ii) the impact of a decline in gas prices on the majority of industrial customers
has offset a contractual step change in the gas price to the cement company that came into effect on 1 January 2015, and
(iii) a change in the overall sales mix.
The average Industrial gas price for the fourth quarter was US$7.62/mcf down 8% from Q4 2014 (US$8.24/mcf). The impact
of prices indexation in January of each year was offset by a decline in HFO prices in the world market. A 1% decrease in the
average price in Q4 2015 from the Q3 2015 price of US$7.67/mcf was due to a change in the sales mix.
Power sector
The average sales price to the Power sector was US$3.54/mcf for the year (2014: US$ 3.56 /mcf) a decrease of 1%. The fall
in price despite the annual indexation rise of 2% each July under contractual arrangements is a consequence of decreased
nominations by TANESCO resulting in fewer sales being made at the premium marginal prices under the PGSA.
The average sales price to the Power sector in the fourth quarter was US$3.56/mcf, up 2% compared with US$3.49/mcf in
Q4 2014. The increase is due to annual indexation of the base price in July. The average price for the fourth quarter is down
2% compared to the Q3 2015 price of US$3.62/mcf as a result of a reduction in the volume sold at premium marginal prices
under the PGSA.
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTManagement’s Discussion & Analysis 17
OPERATING REVENUE
Under the terms of the PSA, the Company is responsible for invoicing, collecting and allocating the revenue from Additional
Gas sales.
The Company is able to recover all costs incurred on the exploration, development and operations of the project up to a
maximum of 75% of the net revenue (“Cost Gas”) prior to the distribution of Profit Gas. Any costs not recovered in any period
are carried forward for recovery out of future revenues. Once the Cost Gas has been recovered, TPDC is able to recover any
pre-approved marketing costs.
The Additional Gas sales volumes for 2015 were below 50 MMcfd and, as a consequence, the Company was only entitled
to a 40% share of Profit Gas revenue for the year as opposed to a 55% share (net of Cost Gas recoveries from revenue). See
“Principal Terms of the Tanzanian PSA and Related Agreements.” The Company’s share of Profit Gas for the first nine months
of 2014 entitled the Company to a 55% share of Profit Gas, this fell to 40% in Q4 2014.
The Company was allocated a total of 74 % of net revenue in 2015 (2014: 63%):
US$’000
Gross sales revenue
Gross tariff for processing plant and pipeline infrastructure
Gross revenue after tariff (net revenue)
Analysed as to:
Company Cost Gas
Company Profit Gas
Cost pool adjustment
Company operating revenue
TPDC share of revenue
THREE MONTHS ENDED
31 DECEMBER
YEAR ENDED
31 DECEMBER
2015
2014
2015
2014
21,288
(3,229)
18,059
13,544
1,806
–
15,350
2,709
18,059
21,601
(3,153)
18,448
3,231
6,902
–
10,133
8,315
18,448
79,885
(12,282)
67,603
38,689
11,565
–
50,254
17,349
67,603
96,566
(13,674)
82,892
12,223
37,402
2,994
52,619
30,273
82,892
The Company’s total revenues for the quarter and the year ended 31 December 2015 amounted to US$15.9 million and
US$54.1 million respectively, after adjusting the Company’s operating revenues of US$15.3 million and US$50.3 million by:
i)
ii)
adding US$0.9 million for income tax for the quarter and US$6.2 million 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,
subtracting US$0.3 million and US$2.4 million 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 prior year includes
a reduction in APT of US$0.9 million resulting from the recovery of downstream costs previously and temporarily
excluded from the cost recoverable pool. See note on Cost Pool adjustments below.
management's discussion & analysis
18
Revenue presented on the Consolidated Statement of Comprehensive Income (Loss) may be reconciled to the operating
revenue as follows:
US$’000
Industrial sector
Power sector
Gross sales revenue
Processing and transportation tariff
Net revenue
TPDC share of revenue
Company operating revenue
Additional Profits Tax charge
Current income tax adjustment
Revenue
THREE MONTHS ENDED
31 DECEMBER
YEAR ENDED
31 DECEMBER
2015
8,794
12,494
21,288
(3,229)
18,059
(2,710)
15,349
(335)
858
15,872
2014
9,825
11,776
21,601
(3,153)
18,448
(8,315)
10,133
(1,429)
941
9,645
2015
33,164
46,721
79,885
(12,282)
67,603
(17,349)
50,254
(2,355)
6,189
54,088
2014
43,763
52,803
96,566
(13,674)
82,892
(30,273)
52,619
(7,280)
11,268
56,607
Company operating revenue increased 65% in the fourth quarter of 2015 compared with Q4 2014. The increase is primarily
due to a capital program to workover three offshore wells and to drill a new offshore well, which commenced in the third
quarter of the year. The expenditures substantially increased the pool of recoverable costs. This entitled the Company to
75% of net revenue as Cost Gas in the quarter and the corresponding reduction in Profit Gas also reduced the Profit Gas
attributable to TPDC by 67%.
Company operating revenue for the year ended 31 December 2015 is down 4%, being the result of a number of factors.
Sales volumes fell 11% which, combined with a 6% reduction in the weighted average sales price, resulted in a 17% drop in
gross sales revenue. The processing and transportation tariff was US$1.4 million lower, in line with the reduction in sales
volume, giving net revenue of US$67.6 million (2014: US$82.9 million).
In 2015 the Company was able to claim 57% or US$38.7 million (2014: 15% or US$12.2 million) of net revenues as Cost Gas,
the increase resulting directly from the workover and drilling program. This increase in Cost Gas is responsible for almost
entirely offsetting the effect of reduced prices and sales volumes.
A reduction of US$4.9 million or 67% in the APT charge for the year is the result of a reduction in the effective rate from 21.9%
to 20.2% compounded by a fall of 69% in the Company’s share of Profit Gas to US$11.6 million (2014: US$37.4 million) on
which it is based. The drop in Profit Gas is a direct result of capital expenditure increasing Cost Gas.
The Company’s share of revenue in 2014 included an adjustment to the Cost Pool (as defined herein) in respect of downstream
costs incurred in prior years, and a further adjustment relating to non-recoverable items agreed by the Company in the
course of settling the TPDC Cost Pool audit of 2002 to 2009 is detailed in the table below:
US$’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
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTManagement’s Discussion & Analysis 19
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 2014: US$3.2 million) and US$12.3 million (2014: US$13.7 million) respectively. The
reduction in the tariff for the year is the result of lower volumes during 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$84 thousand (Q4 2014: US$500 thousand) and for
the year, US$425 thousand (2014: US$1.2 million). Amounts allocated for Additional Gas for the quarter and for the year were
US$47 thousand (Q4 2014: US$277 thousand) and US$233 thousand (2014: US$796 thousand), respectively. The decrease
in the year is the result of reduced activity as a consequence of the additional workload associated with the workover
programme carried out in the second half of 2015.
Other field and operating costs include an apportionment of the annual PSA license costs, regulatory fees, insurance, some
costs associated with the evaluation of the reserves, and the cost of personnel which are not recoverable from Songas.
Distribution costs represent the direct cost of maintaining the ring main distribution pipeline and pressure reduction station
(security, insurance and personnel). Ring main distribution costs were US$512 thousand (Q4 2014: US$603 thousand) for
the quarter and US$1.9 million (2014: US$2.3 million) for the year. The decrease in maintenance and operating costs is
the result of the elimination of the CNG trucking costs for the Mikocheni network. TPDC completed the construction and
commissioning of the trunk line from the the Company's Ubungo pressure reducing station (‘’PRS’’) to the Company's
Mikocheni distribution network in June 2014. The Company signed an agreement with TPDC for the use of their trunk line
in June 2014 and pay an interim tariff of $0.52/GJ for the transportation of the natural gas through the TPDC trunk-line. The
production and distribution costs are detailed in the table below:
US$’000
Share of well maintenance
Other field and operating costs
Ring main distribution costs
Production and distribution expenses
THREE MONTHS ENDED
31 DECEMBER
YEAR ENDED
31 DECEMBER
2015
47
251
298
512
810
2014
277
788
1,065
603
1,668
2015
233
1,594
1,827
1,924
3,751
2014
796
2,374
3,170
2,323
5,493
management's discussion & analysis
20
OPERATING NETBACKS
The netback per mcf before general and administrative costs, overhead, tax and APT is detailed in the table below:
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
Ring main distribution costs
Operating netback
THREE MONTHS ENDED
31 DECEMBER
YEAR ENDED
31 DECEMBER
2015
7.62
3.56
4.51
(0.71)
(0.59)
3.21
(0.07)
(0.11)
3.03
2014
8.24
3.49
4.64
(0.71)
(1.86)
2.07
(0.24)
(0.14)
1.69
2015
7.58
3.54
4.49
(0.71)
(1.00)
2.78
(0.13)
(0.08)
2.57
2014
8.61
3.56
4.76
(0.70)
(1.56)
2.50
(0.16)
(0.12)
2.22
The operating netback increased by 79% from US$1.69/mcf in Q4 2014 to US$3.03/mcf in Q4 2015. The primary reason for
the increase was the 67% decrease in TPDC share of revenue as a consequence of an increase in the Cost Gas recovered,
mainly as a result of the workover and drilling programme. In addition, there was a decrease in well maintenance and other
operating and distribution costs, largely as a consequence of the work-over activity. This was offset slightly by lower average
industrial gas sales prices as a result of a significant decrease in the price of HFO at the world market that has offset the
annual price indexation for both industrial and power gas prices, resulting in a decrease in the weighted average price of gas
by 3%.
The operating netback for the year increased 16% to US$2.57/mcf from US$2.22/mcf in 2014. The decrease in the weighted
average price for the year of 6% was a consequence of a 48% decrease in the price of HFO at the world market and a change
in sales mix was offset by a decrease in TPDC’s share of revenue on a per MCF basis of 36%, and a decrease in field operating
and distribution costs.
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTManagement’s Discussion & Analysis
21
GENERAL AND ADMINISTRATIVE EXPENSES
General and administrative expenses are detailed in the table below:
US$’000
Employee and related costs
Stock based compensation (recovery)
Office costs
Marketing and business development costs
Reporting, regulatory and corporate
Other
General and administrative expenses
THREE MONTHS ENDED
31 DECEMBER
YEAR ENDED
31 DECEMBER
2015
2,796
(87)
916
6
1,067
–
4,698
2014
2,618
(1,101)
1,060
(25)
466
195
2015
7,001
(244)
3,366
214
3,271
–
3,213
13,608
2014
7,115
3,482
3,660
41
3,346
270
17,914
General and administrative expenses include the costs of running the natural gas distribution business in Tanzania which is
recoverable as Cost Gas and is relatively fixed in nature. Excluding stock based compensation and other expenses, general
and administrative expenses averaged US$1.6 million (Q4 2014: US$1.4 million) per month during the quarter and US$1.1
million (2014: US$1.2 million) per month over the year.
STOCK BASED COMPENSATION
The breakdown of the costs incurred in relation to stock based compensation is detailed in the table below:
US$’000
Stock appreciation rights
Restricted stock units
Stock-based compensation (recovery)
THREE MONTHS ENDED
31 DECEMBER
YEAR ENDED
31 DECEMBER
2015
463
(550)
(87)
2014
(537)
(564)
(1,101)
2015
(266)
22
(244)
2014
1,369
2,113
3,482
No stock options were outstanding as at 31 December 2015 compared to 400,000 at the end of 2014. No options were
granted during the quarter (Q4 2014: nil).
As at 31 December 2015 a total of 3,100,000 stock appreciation rights (“SARs”) were outstanding compared to 2,910,000
as at 31 December 2014. A total of 490,000 SARs were granted in during the year with exercise prices of CDN$3.02 to
CDN$3.25, the newly granted SARs have terms of one to five years and vest in equal annual instalments beginning on the
first anniversary of the grant date. No RSUs remain outstanding as at 31 December 2015 (2014: 645,199).
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 1.5%;
stock volatility of 48.9% to 51.6%; 0% dividend yield; 5% forfeiture; and a closing price of CDN$2.75 per Class B share.
As at 31 December 2015, a total accrued liability of US$1.6 million (2014: US$3.4 million) has been recognised in relation to
SARS and RSUs. The Company recognised a credit of US$0.1 million (Q4 2014: credit US$1.0 million) for the quarter and for
the year ended 31 December 2015 a credit of US$0.2 million (2014: expense US$3.5 million).
management's discussion & analysis 22
NET FINANCE EXPENSE
The movement in net finance expense is detailed in the table below:
US$’000
Finance income
Interest expense
Net foreign exchange loss
Financing fee
Provision for doubtful accounts
Finance expense
Net finance expense
THREE MONTHS ENDED
31 DECEMBER
YEAR ENDED
31 DECEMBER
2015
2014
2015
2014
20
(117)
(370)
250
(10,731)
(10,968)
(10,948)
12
–
43
(117)
98
(24)
(4,814)
(2,677)
(4,437)
–
(35,127)
(39,941)
(39,929)
(16)
(11,178)
(13,988)
(13,945)
–
(37,047)
(41,508)
(41,410)
The increase in interest expense is a consequence of drawing US$20 million of the IFC loan facility in December 2015.
The foreign exchange 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 2015, TANESCO owed the Company US69.7 million, excluding interest, (of which arrears were US$61.9
million) compared to US$59.8 million (including arrears of US$52.2 million) as at 31 December 2014. During the year, the
Company received a total of US$34.1 million (2014: US$46.7 million) from TANESCO against sales totaling US$43.6 million
(2014: US$54.7 million). Current TANESCO receivables as at 31 December 2015 amounted to US$7.8 million (2014 US$7.7
million). Since the year-end, TANESCO has paid the Company US$4.1 million in 2016, and as at the date of this report the
total TANESCO receivable is US$75.4 million (of which US$61.9 million has been provided for). The amounts owed do not
include interest billed to TANESCO.
The Company has reached an understanding with TANESCO that it would only continue to supply gas if TANESCO remained
reasonably current with payments for current gas deliveries. Excess payments received over and above the current balances
would be applied to the arrears balance. TANESCO payments for 2015 continued to be irregular but were sufficient to cover
current gas deliveries until the third quarter when payments again were not sufficient to cover current gas deliveries. During
Q4 2015 TANESCO payments decreased further with only US$4.5 million being received against sales of US$11.7 million.
Management has reviewed the current position with TANESCO and concluded that the policy to reclassify all amounts
receivable from TANESCO in excess of 60 days, and in arrears, as a long-term receivable is still appropriate. As a result, the
Company has classified US$9.8 million, the arrears in excess of 60 days, as long-term debt and has recorded a full provision
against this.
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTManagement’s Discussion & Analysis 23
Management concluded that the continued recognition of TANESCO revenue is appropriate. In arriving at this conclusion
management has taken account of:
•
•
Recent discussions with the World Bank, the IMF and IFC during which the Company found strong support for funding
to be directed at TANESCO, supported by a recent announcement from the IMF stating the need to address TANESCO
debt.
TANESCO, according to the World Bank, is now making a small profit. With the seasonal increase in available hydro
power and new gas to power facilities coming on line later this year, the need for expensive liquid fuel will significantly
reduce.
• Most recently, TPDC has co-signed with the Company a commitment from TANESCO establishing a payment plan
going forward. This plan was agreed between the Company and TANESCO at the beginning of December 2015, and
countersigned by TPDC in January 2016. TANESCO has fallen behind the agreed schedule of payments, but with TPDC
signing the agreement and supporting the Company, the Company has a much stronger legal position to pursue
collection of arrears.
management's discussion & analysis 24
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 2015, 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$9.1 million (2014: US$7.3 million). During the
year there was a deferred tax charge of US$1.7 million compared with a recovery of US$0.5 million in 2014. 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.
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 18.6% (Q4 2014: 20.7%) has been applied to Profit Gas of US$1.8 million (Q4 2014: US$6.9 million)
for the quarter, and an average effective rate of 20.2% (2014: 21.9%) has been applied to Profit Gas of US$11.6 million (2014:
US$37.4 million) for the year ended 31 December 2015. Accordingly, US$0.3 million (Q4 2014: US$1.4 million) and US$2.4
million (2014: US$7.3 million) has been netted off revenue for the quarter, and for the year ended 31 December 2015,
respectively. The 2014 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
THREE MONTHS ENDED
31 DECEMBER
YEAR ENDED
31 DECEMBER
2015
335
2014
1,429
2015
2,355
2014
7,280
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTManagement’s Discussion & Analysis
25
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 2015 the proven
reserves estimated to have been produced over the term of the PSA license, as evaluated by the independent reservoir
engineers, McDaniel & Associates Consultants Ltd., were 368 Bcf (2014: 450 Bcf). A depletion expense of US$2.6 million
(Q4 2014: US$3.1 million) for the quarter and US$11.9 million for the year (2014: US$13.6 million) has been recorded in the
accounts; the decrease for the year is the result of an 11% decrease in sales volumes and a 1% decrease in the average
depletion rate to US$0.69/mcf (2014: US$0.70/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.
FUNDS FLOW FROM OPERATING ACTIVITIES
Funds flow from operating activities before working capital changes was US$8.5 million for Q4 2015 (Q4 2014: US$8.7
million) and US$26.6 million (2014: US$32.4 million) for the year and is detailed in the table below:
US$’000
Funds flow from operating activities
Working capital adjustments (1)
Net cash flows from operating activities
Net cash used in investing activities
Net cash from (used in) financing activities
(Decrease) increase in cash
Effect of change in foreign exchange on cash
Net (decrease) increase in cash
(1) See Consolidated Statement of Cash Flows
THREE MONTHS ENDED
31 DECEMBER
YEAR ENDED
31 DECEMBER
2015
8,508
(3,058)
5,450
(19,539)
18,482
4,393
(136)
4,257
2014
8,733
2015
26,571
(10,969)
(19,553)
(2,236)
7,018
(718)
(9)
(2,963)
(2,494)
(5,457)
(29,950)
18,324
(4,608)
746
(3,862)
2014
32,436
(2,679)
29,757
(1,312)
(1,600)
26,845
(1,774)
25,071
management's discussion & analysis 26
CAPITAL EXPENDITURES
During 2015 the Company incurred US$38.4 million (2014: US$0.5 million) in capital expenditures relating to the workover
of wells SS-5, SS-7, SS-9 and drilling of well SS-12, improvement of Songo Songo infrastructure, and purchase of other
equipment. The 2015 capital expenditures are net of recharges of US$11.2 million to Songas for its share of costs on wells
SS-5 and SS-9.
US$’000
Geological and geophysical and well drilling
Pipelines and infrastructure
Other equipment
THREE MONTHS ENDED
31 DECEMBER
YEAR ENDED
31 DECEMBER
2015
23,099
1,382
59
24,540
2014
522
193
3
718
2015
35,796
2,359
256
38,411
2014
913
133
266
1,312
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTManagement’s Discussion & Analysis
27
WORKING CAPITAL
Working capital as at 31 December 2015 was US$32.5 million (31 December 2014: US$34.1 million) and is detailed in the
table below:
US$’000
Cash
Trade and other receivables
TANESCO
Songas
Industrial customers
Songas gas plant operations
Songas well workover programme
Other receivables
Provision for doubtful accounts
Tax recoverable
Prepayments
Trade and other payables
TPDC share of Profit Gas
Songas
Other trade payables
Deferred income
Accrued liabilities
Tax payable
Working capital (1)
AS AT 31 DECEMBER
2015
2014
53,797
25,391
57,659
49,324
7,831
2,178
6,894
5,631
11,209
1,604
(9,956)
28,208
1,071
11,234
667
8,351
4,519
1,118
84,825
49,531
7,671
23,864
7,532
19,300
–
773
(9,816)
33,409
28,871
1,961
2,780
9,726
11,815
642
119,440
76,747
2,773
32,521
8,545
34,148
Notes
(1) Working capital as at 31 December 2015 includes a TANESCO receivable (excluding interest) of US$7.8 million (31 December 2014: US$7.7
million). Management has recorded a provision for doubtful accounts against the long-term receivables in excess of 60 days totaling US$61.9
million (31 December 2014: US$52.2 million). The total of long and short-term TANESCO receivables, including interest, as at 31 December
2015 was US$76.9 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 2015 decreased by 5% over 31 December 2014 and by 18% during the quarter, primarily
as a result of having reclassified a further US$9.9 million of TANESCO receivables as long-term and an increase in payables
resulting from the 2015 workover and drilling programme. 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 69% of the Company’s cash was held outside of Tanzania.
•
Since the quarter end the Company has received US$4.1 million from TANESCO and US$2.1 million from Songas.
• Of the US$6.9 million relating to other trade debtors US$6.1 million had been received as at the date of this report.
The balance of US$28.2 million payable to TPDC represents the remaining balance of its share of revenue as at
31 December 2015.
management's discussion & analysis
28
LONG TERM LOAN
On the 29th October 2015, the Company entered into an agreement with the IFC, a member of the World Bank Group, to
provide financing of up to US$60 million for the Company’s operating subsidiary, PAET.
The term of the Loan is 10-years, with no required repayment of principal for the first seven years, followed by a three-year
amortization period. The Company may voluntarily prepay all or part of the Loan but must simultaneously pay any accrued
base interest costs related to the principal amount being prepaid. If any portion of the Loan is prepaid prior to the fourth
anniversary of the first drawdown, the Company would be required to pay the accrued base interest as if the prepaid portion
of the Loan had remained outstanding for the full four years. The Loan is an unsecured subordinated obligation of PAET and
is guaranteed by the Company to a maximum of US$30 million. The guarantee may only be called upon by IFC at maturity
in 2025 and, subject to IFC approval and receipt of all required regulatory approvals, the Company may issue shares in
fulfillment of all or part of the guarantee obligation in 2025.
Base interest on the Loan is payable quarterly at 10% per annum on a ‘pay-if-you-can-basis’ using a formula to calculate the net
cash available for such payments as at any given interest payment date. In addition, an annual variable participatory interest
equating to 7% of the cash flow of PAET net of capital expenditures is payable in respect of any given year, commencing with
2016. Such participatory interest survives the repayment and/or maturity of the Loan until 15 October 2026. Dividends and
distributions from PAET to the Company are restricted during the term of the Off-Shore Programme and at any time that any
amounts of unpaid interest, principal or participating interest are outstanding.
On the 14th December 2015 the Company, through PAET, made an initial drawdown of US$20 million from the available
US$60 million. Subsequent to the year-end PAET has drawn the remaining US$40 million. The Offshore Programme was
completed on 11 February 2016.
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTManagement’s Discussion & Analysis 29
SHAREHOLDERS’ EQUITY AND OUTSTANDING SHARE DATA
There were 34,857,110 shares outstanding as at 31 December 2015 as detailed in the table below:
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
2015
2014
1,751
33,106
34,857
–
34,857
1,751
33,164
34,915
400
35,315
34,887
34,863
–
–
34,887
34,863
As at 14 April 2016, there were a total of 1,750,517 Class A common voting shares (“Class A shares”) and 33,105,915 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$0.3 million (Q4 2014: US$0.1 million) and for the year ended 31 December
2015 US$0.6 million (2014: US$0.2 million) to this firm for services provided. The transactions with this related party were
made at the exchange amount.
The former Chief Financial Officer who became an Executive Vice-President in November 2015, provided services to the
Company through a consulting agreement with a personal services company. During the quarter the Company incurred
US$0.2 million (Q4 2014 US$0.1 million) and for the year ended 31 December 2015 US$0.4 million (2014: US$0.6 million) to
this firm for services provided.
As at 31 December 2015 the Company has a total of US$0.4 million (2014: US$nil) recorded in trade and other payables in
relation to the related parties.
management's discussion & analysis 30
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, 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 (145.0 Bcf as at 31
December 2015). 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.
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. The Re-Rating agreement expired on 31 December 2013. 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.
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.
Portfolio Gas Supply Agreement
On 17 June 2011, a long term (to June 2023) PGSA was signed between TANESCO (as the buyer), 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$2.93/mcf increased to US$2.98/mcf on 1 July 2015.
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.
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 2015 and expires on 31 October 2019 at an annual rent
of US$0.4 million. The agreement in Winchester expires on 25 September 2022 and is at an annual rental of US$0.1 million
per annum. The costs of these leases are recognised in the general and administrative expenses.
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTManagement’s Discussion & Analysis 31
Capital Commitments
Italy
The Company has an agreement to farm in on the 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 fifteen per cent (15%) of the back costs in relation to the well up to a maximum
of US$0.5 million. Changes in Italian environmental legislation in late 2015 have resulted in the development of this permit
being postponed indefinitely. As at the date of this report, the Company has no further capital commitments in Italy.
Tanzania
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.
Given the completion of the Offshore component of Phase I of the Development Programme in February 2016, which has
restored field deliverability and provides sufficient natural gas production to fill the Songas plant and pipeline to capacity
for the greater portion of the remaining life of the production license, the Company does not expect to commit to further
significant capital expenditures until: (i) agreeing commercial terms with TPDC for the supply of gas to the NNGIP regarding
the sale of incremental gas volumes from Songo Songo; and/or (ii) TANESCO arrears have been substantially reduced,
guaranteed or other arrangements for payment made which are satisfactory to the Company; and/or (iii) the establishment
of payment guarantees with the World Bank or other multi-lateral lending agencies to secure future receipts under any new
sales contracts with Government entities.
When conditions are deemed appropriate and there is justification to further improve the reliability/capacity of field
deliverability, the Company may contemplate undertaking the remaining part or all of the Phase I Development Programme.
The additional costs are estimated to be approximately US$30 million. There is no assurance that financing will be available
and on acceptable commercial terms to complete Phase I.
At the date of this report, the Company has no significant outstanding contractual commitments, and has no outstanding
orders for long lead items related to any capital programmes.
management's discussion & analysis 32
CONTINGENCIES
Petroleum Act, 2015
During the third quarter of 2015, The Petroleum Act, 2015, (the “Act”) was passed into law. The Act repeals earlier legislation,
provides a regulatory framework over upstream, mid-stream and downstream gas activity, and consolidates and puts in
place a comprehensive legal framework for regulating the oil and gas industry in the country. The Act also provides for
the creation of an upstream regulator, the Petroleum Upstream Regulatory (PURA). The mid and downstream oil and gas
activities are proposed to be regulated by the current authority, the Energy and Water Utilities Regulatory Authority (EWURA).
The bill also confers upon on TPDC, the status of the National Oil Company, mandated with the task of managing the
country’s commercial interest in petroleum operations as well as mid and downstream natural gas activities. The bill vests
TPDC with exclusive rights in the entire petroleum upstream value chain and the natural gas mid and downstream value
chain. However, the exclusive rights of TPDC do not extend to mid and downstream petroleum supply operations. The
Company is uncertain regarding the potential impact on its business in Tanzania. The Act does provide grandfathering
provisions upholding the rights of the Company under their PSA as it was signed prior to passing of the Act. However, it is still
unclear how the provisions of the Act will be interpreted and implemented regarding upstream and downstream activities
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.
For the purpose of the reserves certification, it is 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. In 2014 TPDC and the Company agreed to remove
approximately US$1.0 million from the Cost Pool. In 2015 there have been no further developments. Under the dispute
mechanism outlined in the PSA, TPDC are to appoint an independent specialist to assist the parties in reaching agreement
on costs that are still subject to dispute. At the time of writing this report no such specialist has been appointed. If the matter
is not resolved to the Company’s satisfaction, the Company intends to proceed to arbitration via the International Centre for
Settlement of Investment Disputes (“ICSID”) pursuant to the terms of the PSA.
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTManagement’s Discussion & Analysis 33
Tax dispute
Disputed amount US$, million
Taxation
Area
PAYE
Period
Reason for dispute
2008-10
WHT
2005-10
Income Tax
2008-13
Pay-As-You-Earn (“PAYE”) withholding
tax on taxable income of employees on
grossed up equivalent of staff salaries,
which are contractually stated as net.
WHT on services by non-resident persons
performed outside of Tanzania.
Deductibility of capital expenditures and expenses
(2009), additional income tax (2008, 2010, 2011),
and foreign exchange rate application (2013).
VAT
2008-10
Output VAT on imported services
and SSI Operatorship services.
Principal
Interest
0.3
–
1.1
5.2
2.8
9.4
0.8
1.4
3.0
5.2
Total
0.3 (1)
1.9(2)
6.6(3)
5.8(4)
14.6
(1) During the year, PAET appealed the Tax Revenue Appeals Board (“TRAB”) ruling that PAET is liable to pay PAYE on grossed up equivalent
of staff salaries. PAET is awaiting appeal date to be set up with the Tax Revenue Appeals Tribunal (“TRAT”);
(2) 2005-2009 (US$1.8 million): During the year, TRAT ruled in favor of PAET. TRA has filed notice of appeal with the Court of Appeal, and PAET
is awaiting decision of the Court of Appeal.
2010 (US$0.1 million): TRAB is awaiting a ruling from the Court of Appeal on the 2005-2009 case, which would influence TRAB decision
on this matter accordingly.
(3) (a) 2009 (US$1.8 million): During the year, TRAB has ruled against PAET with respect to the deductibility of capital expenditures and
expenses. PAET appealed to TRAT and is awaiting hearing date to be scheduled;
(b) 2008, 2010-2011 (US$4.6 million): During the year, PAET filed objections against TRA assessments with respect to additional tax and
is awaiting a response;
(c) 2013 (US$ 0.2 million): During the year, PAET filed objections to TRA assessment with respect to foreign exchange rate application
and is awaiting a response.
(4) In 2014, PAET filed an objection to TRA’s claims and is awaiting a response.
Management, with the advice from its legal counsel, has reviewed the Company’s position on the above objections and
appeals and has concluded that no provision is required with regard to the above matters.
management's discussion & analysis
34
NEW ACCOUNTING POLICIES
On 06 May, 2014, the IASB issued amendments to IFRS 11, “Accounting for Acquisitions of Interests in Joint Operations”. The
Company intends to adopt amendments to IFRS 11 in its financial statements for the annual period beginning on January 1,
2016. The Company is currently evaluating the impact of adopting IFRS 11 on its consolidated financial statements.
On May 28 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
January 1, 2017, with early adoption permitted. The Company intends to adopt IFRS 15 on the finalized adoption date and is
currently evaluating the impact of adopting the standard on its consolidated financial statements.
On July 24, 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 January 1, 2018 and must be applied
retrospectively with some exemptions. 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 consolidated financial statements.
On January 13, 2016, the IASB issued IFRS 16, “Leases”, which replaces IAS 17 “Leases”. The new standard introduces a single
recognition and measurement model for leases, which would require the recognition of assets and liabilities for most leases
with a term of more than twelve months. The new standard is effective for annual periods beginning on or after January 1,
2019. Early adoption is permitted for entities that apply IFRS 15 “Revenue from Contracts with Customers” at or before the
initial adoption date of January 1, 2018. The Corporation intends to adopt IFRS 16 in its financial statements for the annual
period beginning on January 1, 2019. The extent of the impact of the adoption of the standard has not yet been determined.
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.
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTManagement’s Discussion & Analysis 35
SUMMARY QUARTERLY RESULTS OUTSTANDING
The following is a summary of the results for the Company for the last eight quarters:
Funds flow from operating activities
8,508
9,462
4,889
3,712
8,733
6,641
11,651
Figures in US$’000 except
where otherwise stated
Financial
Revenue
Net (loss) income
Earnings (loss) per share
- basic and diluted (US$)
Funds flow per share
– basic and diluted (US$)
Operating netback (US$/mcf)
Working capital
Long-term loan
Shareholders’ equity
Capital expenditures
2015
2014
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
15,872
15,943
12,553
9,720
9,645
14,631
18,854
13,477
restated
restated restated
(6,468)
6,112
3,566
(1,677)
(46,381)
(0.19)
0.18
0.10
(0.05)
(1.32)
4
–
0.17
6,137
1,939
0.24
3.03
0.27
2.65
0.14
2.68
0.11
1.86
0.25
1.69
0.19
2.12
0.33
2.92
32,521
39,660
38,067
34,870
34,148
42,001
30,399
12,783
18,599
–
–
–
–
–
–
–
78,154
84,476
78,480
74,944
76,635
123,004
123,019
116,752
0.05
5,411
0.15
2.03
Geological and geophysical and well drilling
23,099
7,578
4,135
Pipeline and infrastructure
Other equipment
1,382
59
547
150
275
47
984
155
–
522
193
3
273
12
39
9
(270)
48
109
198
176
Operating
Additional Gas sold
– industrial (MMcf)
Additional Gas sold
– power (MMcf)
Average price per mcf
– industrial (US$)
Average price per mcf
– power (US$)
1,089
1,137
1,015
925
1,084
1,304
1,046
1,164
3,483
3,127
3,041
3,494
3,377
3,935
3,503
4,008
7.62
7.67
7.45
7.54
8.24
8.85
9.27
8.11
3.56
3.62
3.47
3.49
3.49
3.60
3.65
3.52
management's discussion & analysis 36
PRIOR EIGHT QUARTERS
The Company’s revenue for the last two years has fluctuated between quarters due to several factors including seasonal
issues such as the availability of hydro power, scheduled and unscheduled maintenance by customers resulting in reduced
demand, declining well production capacity, a drop in world HFO prices and increased competition for supply of gas
within Tanzania. Sales increased in Q4 2015 following completion of the well workover programme which increased the
Company’s well production capabilities.
The drop in sales in Q4 2014 saw the Company’s share of Profit Gas drop from 55% to 40% (see “Principal Terms of the
Tanzanian PSA and Related Agreements”), where it has remained. The increase in revenue in the second half of 2015 is
directly related to the capital expenditure programme which has permitted the Company to take a significantly increased
share of revenue as Cost Gas.
Changes in net income over the last two years have been dominated by TANESCO. In Q4 2014 the Company recorded a
US$52.2 million doubtful debts provision against TANESCO arrears. In Q4 2015 an additional US$9.8 million was provided
against increased TANESCO arrears. Other significant factors affecting the results were:
•
•
•
The collapse of the Tanzanian Shilling led to a Q4 2014 exchange loss of US$4.8 million and a further loss of US$1.8
million in Q1 2015.
In 2014 the Company took a charge of US$3.5 million for stock based compensation, US$4.2 million in Q3.
In Q4 2014 the Company wrote off US$5.1 million relating to site survey costs for an exploration well which it no longer
plans to drill.
Capital expenditure for most of the periods was low. The 2015 workover and drilling programme commenced in Q3 2015
with some preliminary expenditure in Q2.
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTManagement’s Discussion & Analysis 37
SELECTED FINANCIAL INFORMATION
Selected annual financial information derived from the audited consolidated financial statements for the years ended 31
December 2015, 2014 and 2013 is set out below:
Figures in US$’000 except per share amount
Revenue
Funds flow from operating activities
Cash flows from operating activities
Net income (loss)
Total assets
Earnings (loss) in US$ per share:
Basic and diluted
2015
54,088
26,571
7,018
1,533
189,683
2014
56,607
32,436
29,757
(38,301)
198,492
2013
53,482
32,394
22,491
(7,640)
207,257
0.04
(1.10)
(0.22)
Revenue decreased by 4% to US$54.1 million in 2015 from US$56.6 million in 2014. The sales volumes were 11% lower in
2015 than 2014, with the weighted average price decreasing 6% from US$4.76/mcf to US$4.49/mcf.
The tax payable in respect of 2015 is US8.0 million (2014: US$11.9 million). Of this, US$4.5 million (2014: US$7.9 million)
relating to the current year’s profit is, in accordance with the terms of the PSA, recoverable from TPDC. Consequently
revenue in 2015 has been uplifted by the gross amount of US$6.2 million (2014: US$11.3 million).
The level of Industrial volumes decreased by 11% to 4,096 MMcf in 2015 from 4,598 MMcf in 2014, mainly as a consequence
of unscheduled maintenance work by a number of customers.
The level of Power volumes decreased by 11% to 13,215 MMcf (2014: 14,823 MMcf). The decrease in Power sales resulted
from falling gas production and a decision by TANESCO not to renew a contract with an emergency power plant.
management's discussion & analysis 38
BUSINESS RISKS
Financing
The ability of the Company to meet its financing obligations or 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 meet its current commitments or 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 reasonably 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.
At 31 December 2015, TANESCO owed the Company US69.7 million excluding interest (of which arrears were US$61.9
million) compared to US$59.8 million (including arrears of US$52.2 million) as at 31 December 2014. During the year, the
Company received a total of US$34.1 million (2014: US$46.7 million) from TANESCO against sales totaling US$43.6 million
(2014: US$54.7 million). Current TANESCO receivables as at 31 December 2015 amounted to US$7.8 million (2014 US$7.7
million). Since the year-end, TANESCO has paid the Company US$4.1 million in 2016, and as at the date of this report the
total TANESCO receivable is US$75.4 million (of which US$61.9 million has been provided for). The amounts owed do not
include interest billed to TANESCO.
As at 31 December 2015, Songas owed the Company US$19.0 million (2014: US$43.2 million), whilst the Company owed
Songas US$2.6 million (2014: US$30.4 million); there was no contractual right to offset these amounts. Amounts due to
Songas primarily relate to pipeline tariff charges of US$ 1.1 million (2014: US$28.9 million), whereas the amounts due to the
Company are mainly for capital expenditures of US$11.2 million (2014: US$nil), sales of gas of US$2.2 million (2014: US$23.9
million) and for the operation of the gas plant of US$5.6 million (2014: US$19.3 million). The operation of the gas plant is
conducted at cost and the charges are billed to Songas on a flow through basis on a “no profit, no loss” basis.
As at 31 December 2015 the net amount owed by Songas to the Company was US$16.3 million (2014: US$12.7 million).
Although significant progress has been made in settling outstanding balances, a doubtful debt provision of US$9.8 million
is necessary recognizing the pending settlement of the remaining overdue operatorship charges and the Songas share of
the well workover costs. Any significant amounts not agreed to will be pursued through the mechanisms provided in the
agreements with Songas.
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 on payment of income taxes relating to prior period adjustment factors as they are assessed.
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTManagement’s Discussion & Analysis 39
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.
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 na-
tionalization, 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. This policy
was confirmed with the passing of the Petroleum Act, 2015 during the past year. 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.
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. Primarily operations are regulated by
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 117 out of 168 on the 2015 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.
management's discussion & analysis 40
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. The Government of Tanzania is close to
completing the US$1.2 billion NNGIP that comprises two gas processing plants, one being at Songo Songo, and a pipeline
to transport gas from Southern Tanzania to Dar es Salaam. The NNGIP gas processing plant at Songo Songo is expected to
be commissioned in the near future. The Company is currently negotiating on commercial terms for the sale of incremental
gas volumes however there is no assurance that the Company’s gas will be processed and transported to markets on
economic terms.
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 facilities 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 2013 and no new agreement is currently in
place. Without the Re-Rating Agreement, the gas plant capacity may be de-rated to 70 MMcfd (the capacity originally agreed
to), which would result in a material reduction in the Company’s sales volumes of Additional Gas.
The Petroleum Act, 2015
In July 2015 the Tanzania Parliament passed The Petroleum Act, 2015, which was passed into law by Presidential decree on
4 August 2015. The Act repeals earlier legislation, provides a regulatory framework over mid-stream and downstream gas
activity and as well consolidates and puts in place a single, effective and comprehensive legal framework for regulating the
oil and gas industry in the country. The Act also provides for the creation of an upstream regulator, the Petroleum Upstream
Regulatory (PURA). The mid and downstream petroleum as well as gas activities are proposed to be regulated by the current
authority, the Energy and Water Utilities Regulatory Authority (EWURA).
The Act also confers upon TPDC the status of the National Oil Company, mandated with the task of managing the country’s
commercial interest in the petroleum operations as well as mid and downstream natural gas activities. The Act vests TPDC
with exclusive rights in the entire petroleum upstream value chain and the natural gas mid and downstream value chain.
However, the exclusive rights of the National Oil Company does not extended to mid and downstream petroleum supply
operations.
The Act does provide grandfathering provisions upholding the rights of the Company under the PSA as it was signed prior
to passing of the Act. However, it is still unclear how the provisions of the Act will be interpreted and implemented regarding
upstream and downstream activities.
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTManagement’s Discussion & Analysis 41
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 initialed 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.
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. The Company has the right to earn an interest in a permit in Italy; however the changes in Italian
environmental legislation in late 2015 have resulted in the development of the license being postponed indefinitely. 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. The developed natural gas market in Tanzania is in its infancy and there is currently
limited access to 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 process gas and 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.
management's discussion & analysis 42
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.
With the enactment of the Petroleum Act, 2015 TPDC was given significant rights over upstream and downstream operations
in the country and is the sole aggregator of natural gas in the country. The ACT recognises the rights of the Company
pursuant to the PSA, however; some clauses conflict with the Company’s rights to directly market Additional Gas, and
there is a risk that this prior right will not continue to be recognised and that the Company’s ability to maximize revenue on
Additional Gas sales may be impaired by the requirement 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.
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. 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. There will be no
redundant capacity in the production facilities or pipeline until the Company can tie into new facilities or existing facilities are
expanded. A loss or material reduction in production capabilities will have a material adverse effect on the total production
and funds flow from operations of the Company. Changes in Italian environmental legislation in late 2015 have resulted in
the development of the Elsa Italian license being postponed indefinitely.
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 license.
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTManagement’s Discussion & Analysis 43
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 interpre-
tations thereof or the nature of its operations may require the Company to make significant additional capital expenditures
to ensure compliance in the future.
Volatility of Oil and Gas Prices and Markets
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.
management's discussion & analysis 44
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.
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 99.6% of the outstanding Class A shares and approximately 16.5% of the Class B shares.
Consequently, Mr. Lyons is the beneficial holder of approximately 20.7% of the equity (20.7% fully diluted) and controls 59.2%
of the total votes of the Company.
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTManagement’s Discussion & Analysis 45
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 2015 it was assumed that
TPDC will ‘back-in’ for 20% for all future new drilling activities after well SS-12 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 and impairment test.
ii) Carrying value of exploration and evaluation assets and property, plant and equipment
The Company assesses its property, plant and equipment for impairment when events or circumstances indicate that
the carrying amount of its assets may not be recoverable. If any indication of impairment exists, the Company performs
an impairment test on the CGU, which is the lowest level at which there are identifiable cash flows. The carrying
amount of the CGU is compared to its recoverable amount which is defined as the greater of its fair value less cost to
sell and value in use and is subject to management estimates. These estimates include quantities of reserves and future
production, future commodity pricing, development costs, operating costs, and discount rates. Any changes in these
estimates may have an impact on the recoverable amount of the CGU.
Property, plant and equipment is measured at cost less accumulated depreciation, depletion and amortization. The
Company’s oil and natural gas properties are depleted using the unit-of-production method over proved plus probable
reserves. The unit-of-production method takes into account estimates of capital expenditures incurred to date along
with future development capital required to develop both proved plus probable reserves.
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.
management's discussion & analysis
46
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.
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.
TANESCO is, and has been, experiencing financial difficulties since 2011. These have been caused by a combination of
dependence on high cost power generation based on liquid fuels following severe droughts in Tanzania, a government
mandate to provide additional power stations and an inadequate tariff.
The Company has reached an understanding with TANESCO that it would only continue to supply gas if TANESCO
remained reasonably current with payments for current gas deliveries. Excess payments received over and above the
current balances would be applied to the arrears balance. TANESCO payments for 2015 continued to be irregular but
were sufficient to cover current gas deliveries until the third quarter when payments again were not sufficient to cover
current gas deliveries. During Q4 2015 TANESCO payments decreased further with only US$4.5 million being received
against sales of US$11.7 million.
Management has reviewed the current position with TANESCO and feels that the policy implemented in 2014 to
reclassify all amounts receivable from TANESCO in excess of 60 days, and in arrears, as a long-term receivable is still
appropriate.
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTORCA EXPLORATION GROUP INC.Management’s Discussion & Analysis
FINANCIAL
STATEMENTS
& NOTES
ORCA EXPLORATION GROUP INC. 48
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 Professional
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
14 April 2016
Blaine E. Karst
Chief Financial Officer
14 April 2016
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORT
Independent Auditors’ Report
49
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, 2015 and December 31, 2014, the consolidated statements
of comprehensive income (loss), changes in shareholders’ equity and cash flows for the years then ended, and notes,
comprising a summary of significant accounting policies and other explanatory information.
Management’s Responsibility for the Consolidated Financial Statements
Management is responsible for the preparation and fair presentation of these consolidated financial statements in 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, 2015 and December 31, 2014 and its consolidated financial performance
and its consolidated cash flows for the years then ended in accordance with International Financial Reporting Standards.
Chartered Professional Accountants
14 April 2016
Calgary, Canada
financial statements 50
Consolidated Statements of
Comprehensive Income (Loss)
ORCA EXPLORATION GROUP INC.
YEARS ENDED 31 DECEMBER
US$’000
Revenue
Production and distribution
Net production revenue
Operating expenses
General and administrative
Depletion
Asset impairment
Operating income
Net finance expense
Income (loss) before tax
Income tax - current
Income tax - (deferred) recovery
Net income (loss)
Foreign currency translation gain from foreign operations
Comprehensive income (loss)
Net income (loss) per share (US$)
Basic and diluted
Weighted average shares outstanding (millions)
Basic and diluted
See accompanying notes to the consolidated financial statements.
Note
6, 7
14
9
10
10
18
18
2015
54,088
(3,751)
50,337
(13,608)
(11,855)
–
24,874
(13,945)
2014
56,607
(5,493)
51,114
(17,914)
(13,567)
(5,086)
14,547
(41,410)
10,929
(26,863)
(7,691)
(1,705)
1,533
144
1,677
(11,895)
457
(38,301)
73
(38,228)
0.04
(1.10)
34.9
34.9
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORT Consolidated Statements of Financial Position
51
ORCA EXPLORATION GROUP INC.
US$’000
Assets
Current assets
Cash and cash equivalents
Trade and other receivables
Tax recoverable
Prepayments
Non-current assets
Long-term trade receivable
Property, plant and equipment
Total assets
Equity and liabilities
Current liabilities
Trade and other payables
Tax payable
Non-current liabilities
Deferred income taxes
Long-term loan
Deferred Additional Profits Tax
Total liabilities
Equity
Capital stock
Contributed surplus
Accumulated other comprehensive loss
Accumulated loss
AS AT 31 DECEMBER
Note
2015
2014
12
10
12
13
15
10
16
11
17
53,797
25,391
4,519
1,118
57,659
49,324
11,815
642
84,825
119,440
584
104,274
104,858
189,683
49,531
2,773
52,304
9,312
18,599
31,314
59,225
111,529
85,488
6,347
(86)
(13,595)
78,154
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
Total equity and liabilities
189,683
198,492
See accompanying notes to the consolidated financial statements.
Nature of Operations (Note 1); Contractual obligations and committed capital investment (Note 20); Contingencies (Note 21).
The consolidated financial statements were approved by the Board of Directors on 14 April 2016.
Director
Director
financial statements
52
Consolidated Statements of Cash Flows
ORCA EXPLORATION GROUP INC
US$’000
Operating activities
Net Income (loss)
Adjustment for:
Depletion and depreciation
Asset impairment
Loss on disposal of fixtures and fittings
Provision for doubtful debts
Stock-based compensation (recovery)
Deferred income taxes
Deferred Additional Profits Tax
Interest expense
Unrealised (gain) loss on foreign exchange
Funds flow from operating activities
Decrease (increase) in trade and other receivables
Decrease (increase) in tax recoverable
Increase in prepayments
(Decrease) increase in trade and other payables
(Decrease) increase in tax payable
Decrease (increase) in long-term receivable
Net cash flows from operating activities
Investing activities
Property, plant and equipment
Change in working capital related to investing activities
Net cash used in investing activities
Financing activities
Bank loan repayments
Interest paid
Increase in long-term loan
Normal course issuer bid repurchases
Proceeds from exercise of options
Net cash flow from (used in) financing activities
(Decrease) increase in cash
Cash and cash equivalents at the beginning of the year
Effect of change in foreign exchange on cash
Cash and cash equivalents at the end of the year
See accompanying notes to the consolidated financial statements.
YEARS ENDED 31 DECEMBER
Note
2015
2014
1,533
(38,301)
13
14
13
9
17
10
11
9
12,555
–
–
9,908
(244)
1,705
2,355
117
(1,358)
26,571
15,222
7,296
(476)
(35,873)
(5,772)
50
7,018
14,197
5,086
7
37,047
3,482
(457)
7,280
24
4,071
32,436
(12,840)
(949)
(361)
18,287
1,624
(8,440)
29,757
13
(38,411)
(1,312)
8,461
–
(29,950)
(1,312)
9
16
17
–
(117)
18,599
(158)
–
18,324
(4,608)
57,659
746
53,797
(1,659)
(24)
–
–
83
(1,600)
26,845
32,588
(1,774)
57,659
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORT
Consolidated Statements of Changes
in Shareholders’ Equity
53
Balance as at 31 December 2015
85,488
6,347
ORCA EXPLORATION GROUP INC.
US$’000
Note
Balance as at 1 January 2015
Normal course issuer bid repurchases
Foreign currency translation
adjustment on foreign operations
Net income
US$’000
Note
Balance as at 1 January 2014
Options exercised
Foreign currency translation
adjustment on foreign operations
Net loss
Capital stock
Contributed
Surplus
Cumulative
translation
adjustment
Accumulated
Loss
Total
17
85,637
(149)
–
–
6,356
(9)
–
–
17
85,428
209
–
–
6,482
(126)
–
–
(230)
–
144
–
(86)
(15,128)
76,635
–
–
1,533
(158)
144
1,533
(13,595)
78,154
(303)
23,173
114,780
–
73
–
–
–
83
73
(38,301)
(15,128)
(38,301)
76,635
Capital stock
Contributed
surplus
Cumulative
translation
adjustment
Accumulated
(loss)/income
Total
Balance as at 31 December 2014
85,637
6,356
(230)
See accompanying notes to the consolidated financial statements.
financial statements 54
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.
The consolidated financial statements of the Company as at and for the year ended 31 December 2015 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 14 April 2016.
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 (“GoT”) in the United Republic
of Tanzania. This PSA covers the production and marketing of certain gas from the Songo Songo Block offshore
Tanzania.
The PSA defines gas in the Songo Songo field as “Protected Gas” and “Additional Gas”. The “Protected Gas” is owned
by TPDC and is sold under a 20-year gas agreement (until July 2024) to Songas Limited (“Songas”). Songas is the
owner of the infrastructure that enables the gas to be delivered to Dar es Salaam, which includes a gas processing
plant on Songo Songo Island.
Songas utilizes the Protected Gas as feedstock for its gas turbine electricity generators for onward sale to customers.
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 GoT, 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.
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 38 industrial customers.
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTNotes to the Consolidated Financial Statements 55
2
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 (“US$”).
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
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.
Orca Exploration Italy Inc.
Orca Exploration Italy Onshore Inc.
PAE PanAfrican Energy Corporation Mauritius
PanAfrican Energy Tanzania Limited
Orca Exploration UK Services Limited United Kingdom
British Virgin Islands
British Virgin Islands
British Virgin Islands
Jersey
Parent Company
100%
100%
100%
100%
100%
US dollar
Euro
Euro
US dollar
US dollar
British Pound
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 earnings.
ii) Foreign currency translation
Orca Exploration Italy Inc. and Orca Exploration Italy Onshore Inc. has the Euro and Orca UK Services has
British pound sterling as their functional currencies. The assets and liabilities of these companies are translated
into US dollars at the period-end exchange rate. The income and expenses of the companies are translated
into US dollars at the average exchange rate for the period. Translation gains and losses are included in other
comprehensive income.
notes
56
3
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
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 management considers 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, depreciation and accumulated impairment losses. Cost
includes purchase price and construction costs for qualifying assets. Depletion of these assets commences
when the assets are ready for their intended use. Only costs that are directly related to the discovery and
development of specific oil and gas reserves are capitalised. The cost associated with tangible natural gas
assets are amortised on a field by field unit of production method based on commercial proven reserves. The
calculation of the unit of production amortisation takes into account the estimated future development cost
of the field.
iii) Impairment of exploration and evaluation assets, property, plant and equipment
At each balance sheet date, the Company reviews the carrying amounts of its property, plant and equipment
and intangible assets to determine whether there is any indication that those assets have suffered an
impairment loss. Individual assets are grouped together as a cash generating unit (“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 CGU 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.
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTNotes to the Consolidated Financial Statements
57
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 gain no loss’ 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 earnings 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 statement of comprehensive 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 earnings.
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 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.
notes
58
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 TPDC, to sell or otherwise dispose of Additional Gas.
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 TPDC’s share of operating, administrative and capital costs. The Company recovers all reasonably incurred
operating, administrative and capital costs including the parastatal’s share of these costs from future revenues
over several years (“Cost Gas”). TPDC’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”. 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.
Since 2011 TANESCO has experienced financial difficulties due to its dependence on high cost power generation
based on liquid fuels following severe draughts in Tanzania. Whilst the Company has received assurances from
the Government of Tanzania that it was arranging financing for TANESCO, the receivables continued to build.
The Company has reached an understanding with TANESCO that it would only continue to supply gas if
TANESCO remained reasonably current with payments for current gas deliveries. Excess payments received over
and above the current balances would be applied to the arrears balance. TANESCO payments for 2015 continued
to be irregular but were sufficient to cover current gas deliveries until the third quarter when payments again were
not sufficient to cover current gas deliveries. During Q4 2015 TANESCO payments decreased further with only
US$4.5 million being received against sales of US$11.7 million. Management has reviewed the current position
with TANESCO and feels that the policy implemented in 2014 to reclassify all amounts receivable from TANESCO
in excess of 60 days, and in arrears, as a long-term receivable is still appropriate. As a result, the Company has
classified a further US$9.8 million, the arrears in excess of 60 days, as long-term debt and has placed a full
provision against this (see Note 12). The current total provision is US$61.9 million (2014: US$52.2 million).
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTNotes to the Consolidated Financial Statements 59
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 income 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 earnings on a straight line basis over the estimated
useful economic lives of each class of asset. The estimated useful lives are as follows:
Leasehold improvement
Over remaining life of the lease
Computer equipment
Vehicles
Fixtures and fittings
3 years
3 years
3 years
I. Financial instruments
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
the statement of comprehensive income (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.
notes 60
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 statement of comprehensive 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 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 long-term 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 trade and other payables approximates the carrying
amounts due to the short-term nature of these instruments. The fair value of the long-term loan approximates
its carrying value as there has been no significant change in interest rates since the Company finalized the
loan. The loan interest rate is fixed at 10%.
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. 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 earnings. 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 earnings .
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTNotes to the Consolidated Financial Statements
61
J. Contributed surplus
This is used to record two types of transactions:
i) To recognise the fair value of equity settled stock based compensation expensed in the year.
ii)
To account for the difference between the aggregated book value of the shares purchased under the normal
course issuer bid and the actual consideration.
K. Earnings or loss per share (”EPS”)
Basic earnings or loss per share is calculated by dividing net income (loss) 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
On May 28 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 January 1, 2017, with early adoption permitted. The Company intends to adopt
IFRS 15 on the finalized adoption date and is currently evaluating the impact of adopting the standard on its
consolidated financial statements.
On July 24, 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 January 1, 2018
and must be applied retrospectively with some exemptions. 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 consolidated financial statements.
On January 13, 2016, the IASB issued IFRS 16, "Leases", which replaces IAS 17 "Leases". The new standard introduces
a single recognition and measurement model for leases, which would require the recognition of assets and
liabilities for most leases with a term of more than twelve months. The new standard is effective for annual
periods beginning on or after January 1, 2019. Early adoption is permitted for entities that apply IFRS 15 "Revenue
from Contracts with Customers" at or before the initial adoption date of January 1, 2018. The Corporation intends
to adopt IFRS 16 in its financial statements for the annual period beginning on January 1, 2019. The extent of the
impact of the adoption of the standard has not yet been determined.
notes 62
4
USE OF ESTIMATES AND JUDGEMENTS
In applying the Company’s accounting policies, which are described in Note 3, 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:
A. 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 independently 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 2015 it was assumed that TPDC will elect to ‘back-in’ for
20% for all future new drilling activities after well SS-12 and this is reflected in the Company’s net reserve position.
As at the time of writing this report TPDC have made no such election.
Reserves are integral to the amount of depletion recognized and impairment test.
B. Carrying value of exploration and evaluation assets and property, plant and equipment
The Company assesses its property, plant and equipment for impairment when events or circumstances indicate
that the carrying amount of its assets may not be recoverable. If any indication of impairment exists, the Company
performs an impairment test on the CGU, which is the lowest level at which there are identifiable cash flows. The
carrying amount of the CGU is compared to its recoverable amount which is defined as the greater of its fair value
less cost to sell and value in use and is subject to management estimates. These estimates include quantities of
reserves and future production, future commodity pricing, development costs, operating costs, and discount rates.
Any changes in these estimates may have an impact on the recoverable amount of the CGU.
Property, plant and equipment is measured at cost less accumulated depreciation, depletion and amortization.
The Company’s oil and natural gas properties are depleted using the unit-of-production method over proved plus
probable reserves. The unit-of-production method takes into account estimates of capital expenditures incurred to
date along with future development capital required to develop both proved plus probable reserves.
C. 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. Management
performs impairment tests each period on the Company’s current and long-term receivables (see Note 12).
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTNotes to the Consolidated Financial Statements 63
D. 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.
E. 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.
F. 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.
notes 64
5
RISK MANAGEMENT
The Company, by its activities in oil and gas exploration, development and production, is exposed to the risk associated
with the unpredictable nature of the financial markets 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.
A. 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 US 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 Tanzanian shillings is limited and not highly liquid, reducing the Company’s ability to convert
large amounts of Tanzanian shillings into US dollars at any given time. To mitigate the risk of Tanzanian shilling
devaluation, the Company regularly converts Tanzanian shilling receipts 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 (defined as current assets less current liabilities) of US$0.7 million to US$33.1 million and an increase in
the income before tax to US$11.1 million. The sensitivity includes only outstanding foreign currency denominated
monetary items and adjusts their translation at period end for a 10% change in the foreign currency rates.
A 10% sensitivity rate is used when reporting foreign currency risk internally to key management personnel and
represents management’s assessment of the reasonable possible change in foreign exchange rates.
The following balances are denominated in foreign currency (stated in US dollars at period end exchange rates):
Balances as at December 31, 2015
US$’000
Cash
Trade and other receivables
Trade and other payables
B. Commodity price risk
Canadian
dollars
Tanzanian
shillings
Euros
Other
Total
0.4
–
(2.0)
(1.6)
2.0
4.9
(2.4)
4.5
0.8
0.1
(0.9)
–
3.8
0.9
(0.1)
4.6
7.0
5.9
(5.4)
7.5
The Company negotiated industrial gas sales contracts with gas prices which, subject to certain floors and
ceilings, are determined as a discount to 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.
C. Interest rate risk
Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates.
The Company has minimal exposure to interest rates as the long-term loan has a fixed interest rate and interest
received on cash balances is not significant.
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTNotes to the Consolidated Financial Statements 65
D. 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, 2015 and 2014, other than the provisions against the long-term TANESCO
receivable and gas plant operations charges/capital expenditure receivables 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 (see Note 12).
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 of gas. The
contracts with Songas and TANESCO accounted for 58% of the Company’s operating revenue during 2015 and
US$71.9 million of the short and long-term receivables prior to provision at year-end.
TANESCO has continued to experience financial difficulties during 2015, which has resulted in irregular and
inconsistent payments for gas deliveries. As a result management has placed a provision for doubtful debts
against the entire amount of arrears due from TANESCO in the amount of US$61.9 million as at 31 December
2015 (31 December 2014 US$52.2 million).
Sales to the Industrial sector, currently 38 customers, are subject to an internal credit review to minimize the risk
of non-payment.
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. The Company’s cash resources are placed with
reputable financial institutions with no history of default.
E. 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$49.5 million of financial liabilities with regards to trade and other payables of which US$48.6
million is due within one to three months, nil is due within three to six months, and US$0.9 million is due within
six to twelve months (see Note 15). As at year-end the Company had a current tax liability of US$2.4 million.
At the end of the year a significant proportion of the current liabilities relate to TPDC. The amounts due to TPDC
represent 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 12).
F. 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.
G. Country risk
Prior to 2014 an allegation had been made by TPDC that the Company had over-recovered approximately US$21
million in Cost Gas revenue. This resulted in Parliament advising the GoT to take action to terminate the Company’s
PSA. In response to a Notice of Dispute delivered by the Company in March 2014, TPDC retracted the allegation. In
the opinion of management, the retraction exonerated the Company and to this date, no further action has been
taken by Parliament or the Government against the Company related to the allegations. Accordingly, the Company
continues to rely upon its rights under the existing PSA and has initiated notices of dispute to resolve any remaining
issues. The Company has put in place an advisory committee of experienced individuals with significant experience
working with the Tanzanian government to mitigate the risks of doing business in Tanzania.
notes 66
6
SEGMENT INFORMATION
The Company has one reportable industry segment which is international exploration, development and production
of petroleum and natural gas. The Company currently has producing and exploration assets in Tanzania and had
exploration and appraisal interests in Italy (see Note 20).
US$’000
External revenue
Segment income (loss)
Non-cash charge (1)
Depletion & depreciation
Asset impairment
Capital additions
Total assets
Total liabilities
2015
2014
Italy
Tanzania
Total
Italy
Tanzania
Total
–
(167)
–
–
–
–
1,621
131
54,088
1,700
(9,908)
12,555
–
38,411
188,062
111,398
54,088
1,533
(9,908)
12,555
–
38,411
189,683
111,529
–
(6)
–
–
–
–
1,931
272
56,607
(38,295)
37,047
14,197
5,086
1,312
196,561
121,585
56,607
(38,301)
37,047
14,197
5,086
1,312
198,492
121,857
(1) Non-cash charge represent amounts provided for doubtful accounts receivable from TANESCO.
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTNotes to the Consolidated Financial Statements
7
REVENUE
US$’000
Industrial sector
Power sector
Gross sales revenue
Processing and transportation tariff
Net revenue
TPDC share of revenue
Company operating revenue
Additional Profits Tax charge
Current income tax adjustment
Revenue
67
YEARS ENDED 31 DECEMBER
2015
33,164
46,721
79,885
(12,282)
67,603
(17,349)
50,254
(2,355)
6,189
54,088
2014
43,763
52,803
96,566
(13,674)
82,892
(30,273)
52,619
(7,280)
11,268
56,607
The Company’s total revenues for the year amounted to US$54.1 million after adjusting the Company’s operating
revenue of US$50.3 million by:
i)
adding US$6.2 million 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 10); and,
ii)
subtracting US$2.4 million for deferred Additional Profits Tax charged in the year – this tax is considered a royalty
and is presented as a reduction in revenue.
Cost Pool adjustments
In 2014, the Company 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 2014 reflect a reallocation of Cost Gas and Profit Gas
between TPDC and the Company.
The following table shows the impact on the Company’s 2014 operating revenue resulting from adjusting the cost
pool. The net amount which is included in the Company’s operating revenue of US$52.6 million has been recovered
from TPDC’s share of revenue:
US$’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
notes
68
8
PERSONNEL EXPENSES
Personnel costs are as follows:
US$’000
Wages and salaries
Social security costs
Other statutory costs
Stock based compensation
YEARS ENDED 31 DECEMBER
2015
2014
9,037
876
207
10,120
(244)
9,876
8,958
675
321
9,954
3,482
13,436
Stock based compensation is recorded under general and administrative expenses in the statement of comprehensive
income (loss). The balance of personnel expenses for 2015 of US$10.1 million (2014: US$10.0 million) is recorded in
distribution and production expenses and general administrative expenses at US$1.9 million (2014: US$3.0 million)
and US$8.0 million (2014: US$7.0 million) respectively.
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTNotes to the Consolidated Financial Statements 9
NET FINANCE EXPENSE
US$’000
Finance income
Interest expense
Net foreign exchange loss
Financing fee
Provision for doubtful accounts
Finance expense
Net finance expense
69
YEARS ENDED 31 DECEMBER
2015
43
(117)
(2,677)
(16)
(11,178)
(13,988)
(13,945)
2014
98
(24)
(4,437)
–
(37,047)
(41,508)
(41,410)
During 2015, the Company billed TANESCO US$2.4 million (2014: US$2.2 million) of interest for late payments. The
interest income is not recorded in the financial statements because it does not meet the revenue recognition criteria
with respect to assurance of collectability. The Company is pursuing collection and amounts will be recognised in
earnings when collected. The provision for doubtful accounts includes US$9.9 million (2014: US$35.1 million) for
overdue TANESCO receivables and US$1.3 million (2014: US$1.9 million) relates to Songas receivables.
Total amount of interest paid in 2015 was nil (2014: US$17 thousand).
notes
70
10
INCOME TAXES
The tax charge is as follows:
US$’000
Current tax
Deferred tax expense (recovery)
YEARS ENDED 31 DECEMBER
2015
7,691
1,705
9,396
2014
11,895
(457)
11,438
Tax of US$3.0 million (2014: US$1.5 million) was paid during the year in relation to the settlement of the prior year’s
tax liability. The Company paid a further US$3.5 million related to periods from 2005 to 2013. In addition, provisional
tax payments totaling US$6.9 million (2014: US$8.8 million) were made in respect of the current year. These are
presented as a reduction in tax payable on the statement of financial position.
Tax rate reconciliation
US$’000
Income (loss) before tax
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
Foreign exchange loss
Tax penalties
Stock-based compensation (recovery)
TANESCO interest not recognized as interest income (Note 9)
Unrecognized tax asset
Other permanent differences
YEARS ENDED 31 DECEMBER
2015
10,929
3,279
2014
(26,863)
(8,059)
1,552
199
–
(73)
714
2,930
795
9,396
1,387
349
272
1,045
650
15,646
148
11,438
As at 31 December 2015, the provision for doubtful debt from TANESCO has resulted in a US$17.6 million
(2014: US$15.6 million) unrecognised deferred tax asset. If this amount was ultimately not recovered, the Company
would also be entitled to a US$10.5 million recovery of Value Added Tax.
A deferred tax asset of US$2.2 million (2014: US$2.2 million) in respect of Longastrino Italy exploration and evaluation
costs has not been recognised because it is not probable that there will be future profits against which this can be
utilised.
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTNotes to the Consolidated Financial Statements
71
The deferred income tax liability includes the following temporary differences:
US$’000
Differences between tax base and
carrying value of property, plant and equipment
Tax recoverable from TPDC
Provision for doubtful debt
Deferred Additional Profits Tax
Unrealised exchange losses/other provisions
AS AT 31 DECEMBER
2015
2014
(18,185)
(3,442)
2,987
9,394
(66)
(9,312)
(15,498)
(5,116)
2,945
8,688
1,375
(7,606)
Tax recoverable
The Company has a tax recoverable balance of US$4.5 million (2014: US$11.8 million). This arises from the revenue
sharing mechanism within the PSA, which entitles the Company to recover from TPDC, by way of a deduction
from TPDC’s Profit Gas share an amount equal to the actual income taxes payable by the Company. The recovery,
by deduction from TPDC’s share of revenue, is dependent upon payment of income taxes relating to prior period
adjustment factors as they are assessed.
US$’000
Tax recoverable
AS AT 31 DECEMBER
2015
4,519
2014
11,815
notes 72
11
ADDITIONAL PROFITS TAX
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 20.2% (2014: 21.9%) has been applied to Profit Gas of US$11.6
million (2014: US$37.4 million). Accordingly, US$2.4 million (2014: US$7.3 million) has been netted off revenue for
the year ended 31 December 2015. The APT charge for the 2014 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$3.3 million Profit Gas
adjustment identified in the Cost Pool adjustment (see Note 7).
12
TRADE AND OTHER RECEIVABLES
Current receivables
US$’000
Trade receivables
TANESCO
Songas
Industrial customers
Other receivables
Songas gas plant operations
Songas well workover programme
Other
Less provision for doubtful accounts
Trade receivables aged analysis
US$’000
TANESCO
Songas
Industrial customers
US$’000
TANESCO
Songas
Industrial customers
AS AT 31 DECEMBER
2015
2014
7,831
2,178
6,894
16,903
5,631
11,209
1,604
(9,956)
8,488
25,391
>90
–
–
821
821
>90
–
20,555
495
21,050
7,671
23,864
7,532
39,067
19,300
–
773
(9,816)
10,257
49,324
Total
7,831
2,178
6,894
16,903
Total
7,671
23,864
7,532
39,067
AS AT 31 DECEMBER 2015
Current
>30 <60
>60 <90
3,972
1,082
3,317
8,371
3,859
1,096
1,859
6,814
–
–
897
897
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
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTNotes to the Consolidated Financial Statements 73
TANESCO
At 31 December 2015, TANESCO owed the Company US$69.7 million excluding interest (of which arrears were
US$61.9 million) compared to US$59.8 million (including arrears of US$52.2 million) as at 31 December 2014. During
the year, the Company received a total of US$34.1 million (2014: US$46.7 million) from TANESCO against sales
totaling US$43.6 million (2014: US$54.7 million). Current TANESCO receivables as at 31 December 2015 amounted
to US$7.8 million (2014: US$7.7 million). Since the year-end, TANESCO has paid the Company US$4.1 million in 2016,
and as at the date of this report the total TANESCO receivable is US$75.4 million (of which US$61.9 million has been
provided for). The amounts owed do not include interest billed to TANESCO.
The Company has reached an understanding with TANESCO that it would only continue to supply gas if TANESCO
remained reasonably current with payments for current gas deliveries. Excess payments received over and above the
current balances would be applied to the arrears balance. TANESCO payments for 2015 continued to be irregular
but were sufficient to cover current gas deliveries until the third quarter when payments again were not sufficient
to cover current gas deliveries. During Q4 2015 TANESCO payments further decreased with only US$4.5 million
being received against sales of US$11.7 million. Management has reviewed the current position with TANESCO and
concluded that the policy to reclassify all amounts receivable from TANESCO in excess of 60 days, and in arrears, as
a long-term receivable is still appropriate. As a result, the Company has classified US$9.8 million, the arrears in excess
of 60 days, as long-term and has placed a full provision against this amount. The current total provision is US$61.9
million (2014: US$ 52.2 million).
Long-term receivables
US$’000
TANESCO receivable
Provision for doubtful debts
Net TANESCO receivable
VAT bond
Lease deposit
Long-term receivables
Songas
AS AT 31 DECEMBER
2015
2014
61,922
52,154
(61,922)
(52,154)
–
332
252
584
–
369
265
634
As at 31 December 2015, Songas owed the Company US$19.0 million (2014: US$43.2 million), whilst the Company
owed Songas US$2.6 million (2014: US$30.4 million); there is no contractual right to offset these amounts. Amounts
due to Songas primarily relate to pipeline tariff charges of US$ 1.1 million (2014: US$28.9 million), whereas the
amounts due to the Company are mainly for capital expenditures of US$11.2 million (2014: US$nil), sales of gas of
US$2.2 million (2014: US$23.9 million) and for the operation of the gas plant of US$5.6 million (2014: US$19.3 million).
The operation of the gas plant is conducted at cost and the charges are billed to Songas on a flow through basis.
As at 31 December 2015 the net amount owed by Songas to the Company was US$16.3 million (2014: US$12.7
million). Although significant progress has been made in settling outstanding balances, a doubtful debt provision of
US$9.8 million is necessary recognizing the pending settlement of the remaining overdue operatorship charges and
the Songas share of the well workover costs. Any significant amounts not agreed will likely be pursued through the
mechanisms provided in the agreements with Songas.
All amounts due to and from Songas have been summarized in the net Songas balance (see Note 15).
notes
74
13
PROPERTY, PLANT AND EQUIPMENT
US$’000
Costs
Oil & natural
gas interests
Leasehold
improvements
Computer
equipment
Vehicles
Fixtures &
fittings
Total
As at 1 January 2015
Additions
As at 31 December 2015
140,653
38,155
178,808
Accumulated depletion and depreciation
As at 1 January 2014
Depletion and depreciation
As at 31 December 2015
Net book values
63,534
11,855
75,389
As at 31 December 2015
103,419
699
–
699
170
175
345
354
1,233
108
1,341
955
213
1,168
173
149
148
297
120
48
168
129
1,125
143,859
–
38,411
1,125
182,270
662
264
926
65,441
12,555
77,996
199
104,274
Oil & 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
Accumulated depletion and depreciation
As at 1 January 2014
Depletion and depreciation
Disposals
As at 31 December 2014
Net book values
49,967
13,567
–
63,534
885
72
–
(258)
699
245
183
(258)
170
1,158
75
–
–
1,233
761
194
–
955
278
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
29
463
78,418
As at 31 December 2014
77,119
529
In determining the depletion charge, it is estimated that future development costs of US$103.8 million (2014:
US$252 million) will be required to bring the total proved reserves to production. The decrease in estimated future
development costs is a result of the successful workovers completed during the year. This reduced the amount of
capital expenditure required in the future to ensure the Company can produce the required gas volumes to meet its
contractual obligations for the remaining life of the license. During the year the Company recorded depreciation of
US$0.7 million (2014: US$0.6 million) in general and administrative expenses.
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTNotes to the Consolidated Financial Statements 75
14
ASSET IMPAIRMENT
During 2014, site costs of survey and materials purchased in preparation for the drilling of the first Songo Songo West
well of US$5.1 million recorded in exploration and evaluation assets were identified as having been impaired.
15
TRADE AND OTHER PAYABLES
US$’000
Songas (1)
Other trade payables
Trade payables
TPDC share of Profit Gas
Deferred income
Accrued liabilities
AS AT 31 DECEMBER
2015
1,071
11,234
12,305
28,208
667
8,351
49,531
2014
28,871
1,961
30,832
33,409
2,780
9,726
76,747
(1) A summary of all Songas balances is presented below, including 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 12).
Pipeline tariff – payable
Gas sales – receivable
Gas plant operation receivable
Workover programme
Other payable
Net balances
1 January 2015
Year to date
transactions
Gross balance
31 Dec 2015
Post year-end
payments
and receipts
Outstanding
as at the date
of this report
(28,871)
23,864
19,300
–
(1,574)
12,719
27,800
(21,686)
(13,669)
11,209
28
3,682
(1,071)
2,178
5,631
11,209
(1,546)
16,401
1,071
(2,178)
–
–
–
(1,107)
–
–
5,631
11,209
(1,546)
15,294
notes 76
16
LONG-TERM LOAN
On the 29th October 2015, the Company entered into a loan agreement (“Loan”) with the International Finance
Corporation (“IFC”), a member of the World Bank Group, for a US$60 million investment in the Company’s operating
subsidiary, PanAfrican Energy Tanzania Limited (“PAET”).
The term of the Loan is 10-years, with no repayment of principal for the first seven years, followed by a three-year
amortization period. The Loan is an unsecured subordinated obligation of PAET and is guaranteed by the Company
to a maximum of US$30 million. The guarantee may only be called upon by IFC at maturity in 2025 and, subject to
IFC approval and receipt of all required regulatory approvals, the Company may issue shares in fulfillment of all or part
of the guarantee obligation in 2025.
Base interest on the Loan is payable quarterly at 10% per annum on a ‘pay-if-you-can-basis’ using a formula to
calculate the net cash available for such payments as at any given interest payment date. In addition, an annual
variable participatory interest equating to 7% of the cash flow of PAET net of capital expenditures is payable in
respect of any given year, commencing with 2016. Such participatory interest will continue until 15 October 2026
regardless whether the Loan is repaid prior to its contractual maturity date. Dividends and distributions from PAET to
the Company are restricted during the term of the Off-Shore Programme and at any time that any amounts of unpaid
interest, principal or participating interest are outstanding. The Off-Shore Programme was completed subsequent to
year-end.
On the 14th December 2015, PAET made an initial drawdown of US$20 million from the available US$60 million.
Subsequent to the year-end PAET has drawn the remaining US$40 million.
US$’000
Total IFC facility
Loan drawdown
Financing costs
AS AT 31 DECEMBER
2015
2014
60,000
20,000
(1,401)
18,599
–
–
–
–
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTNotes to the Consolidated Financial Statements 77
17
CAPITAL STOCK
A. Authorised
50,000,000
Class A common shares
No par value
100,000,000
Class B subordinate voting shares
No par value
100,000,000
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
2015
2014
Authorised
(000)
Issued
(000)
Amount
(US$’000)
Authorised
(000)
Issued
(000)
Amount
(US$’000)
Class A
As at 1 January and
31 December
Class B
50,000
1,751
983
50,000
1,751
983
As at 1st January
100,000
33,164
84,654
100,000
33,072
Stock options exercised
Normal course issuer
bid repurchases
–
–
–
–
(58)
(149)
–
–
92
–
84,445
209
–
As at 31 December
100,000
33,106
84,505
100,000
33,164
84,654
First preference
As at 31 December
100,000
–
–
100,000
–
–
Total Class A, Class B
and first preference
250,000
34,857
85,488
250,000
34,915
85,637
All of the issued capital stock is fully paid.
Stock Options
Number of options
Outstanding as at 1 January
Forfeited
Exercised
Expired unexercised
Outstanding as at 31 December
2015
2014
Options
Exercise Price
Options
Exercise Price
(000)
400
(400)
–
–
–
CDN$
(000)
CDN$
3.18
3.18
–
–
–
1,742
1.00 to 3.60
(250)
(92)
(1,000)
400
3.60
1.00
1.00
3.18
notes 78
Stock Appreciation Rights (“SARs”)
Number of options
Outstanding as at 1 January
Expired
Granted (i)
2015
SARs
(000)
2014
Exercise
Price
SARs
Exercise Price
(CDN$)
(000)
(CDN$)
2,910
2.12 to 4.20
1,130
2.12 to 4.20
(300)
4.20
490
3.02 to 3.25
–
1,780
–
2.30
Outstanding as at 31 December
3,100
2.12 to 3.25
2,910
2.12 to 4.20
(i) A total of 490,000 SARs were issued during the year with an exercise price from CDN$3.02 to CDN$3.25. These rights have a term of one
to five years and vest in equal annual instalments, the first tranche vesting on the anniversary of the grant date. There is no maximum
liability associated with these rights.
The weighted average remaining life and weighted average exercise prices of SARs at 31 December 2015 were as
follows:
Number outstanding
as at 31 December
(000)
Weighted average
remaining contractual life
(years)
Number exercisable as
at 31 December 2015
(000)
Weighted average
exercise price
(CDN$)
Exercise price
(CDN$)
2.12 to 2.30
2.35 to 2.70
3.02 to 3.25
2.12 to 3.25
Restricted Stock Units (“RSUs”)
Outstanding as at 1 January
Granted
Exercised
Outstanding as at 31 December
2,080
530
490
3,100
2.96
1.86
4.79
3.06
2015
RSUs
(000)
645
–
(645)
–
556
530
–
1,086
2.27
2.48
3.06
2.43
Grant/exercise
price (CDN$)
–
–
2014
Grant/exercise
price (CDN$)
–
3.70
3.79
2.90
RSUs
(000)
–
792
(147)
645
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 recognized 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 1.5%, stock volatility of 48.9% to 51.6%; 0% dividend yield; 5% forfeiture; a closing stock price of CDN$2.75
per share.
US$’000
SARs
RSUs
YEAR ENDED 31 DECEMBER
2015
1,572
–
1,572
2014
1,766
1,613
3,379
As at 31 December 2015, a total accrued liability of US$1.6 million (2014: US$3.4 million) has been recognised in
relation to SARs and RSUs which is included in other payables. The Company recognised a credit for the year of
US$0.2 million (2014: expense US$3.5 million) in general and administrative expenses.
The credit in 2015 was the result of a 5% reduction in the share price to US$2.75 (2014: US$2.90) and a net increase
in SARs of 190,000. The 2014 charge reflected the issue of 792,000 RSUs and 1,780,000 SARs.
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTNotes to the Consolidated Financial Statements 18
EARNINGS PER SHARE
(‘000)
Outstanding shares
Weighted average number of Class A and Class B shares
Weighted average diluted number of Class A and Class B shares
79
AS AT 31 DECEMBER
2015
2014
34,887
34,887
34,863
34,863
The calculation of basic earnings (loss) per share is based on a net income (loss) for the year of US$1.5 million (2014:
loss US$38.3 million) and a weighted average number of Class A and Class B shares outstanding during the period of
34,887,100 (2014: 34,862,588).
19
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. For the year ended 31 December 2015 US$0.6 million (2014: US$0.2 million) was incurred from this firm
for services provided. The transactions with this related party were made at the exchange amount.
The former Chief Financial Officer who became an Executive Vice-President in November 2015, provided services to
the Company through a consulting agreement with a personal services company. For the year ended 31 December
2015 US$0.4 million (2014: US$0.6 million) was incurred from this firm for services provided.
As at 31 December 2015 the Company has a total of US$0.4 million (2014: US$nil) recorded in trade and other
payables in relation to the related parties.
notes 80
20
CONTRACTUAL OBLIGATIONS
& COMMITTED CAPITAL INVESTMENTS
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 (145.0 Bcf as at 31 December 2015). 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
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 initialed 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. The Re-rating agreement expired on 31 December 2013. Since 31 December
2013 production has continued within the higher rated limit and the Company expects this to continue. However,
there are no assurances that the ability to produce at the higher rating will continue.
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$15.0 million, but only to the extent that this was not already covered by
indemnities from TANESCO’s or Songas’ insurance policies.
Portfolio Gas Supply Agreement ("PGSA")
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$2.93/mcf increased to
US$2.98/mcf on 1 July 2015. 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.
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTNotes to the Consolidated Financial Statements
81
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 2015 and expires on 31 October 2019
at an annual rent of US$0.4 million. The agreement in Winchester expires on 25 September 2022 and is at an annual
rental of US$0.1 million per annum. The costs of these leases are recognised in the general and administrative
expenses.
Capital Commitments
Italy
The Company has an agreement to farm in on Central Adriatic B.R268.RG Permit offshore Italy. The farm-in commits
the Company to fund 30% of an 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 fifteen per cent (15%) of the back costs in relation to the
well up to a maximum of US$0.5 million. Changes in Italian environmental legislation in late 2015 have resulted in the
development of this permit being postponed indefinitely. As at the date of this report, the Company has no further
capital commitments in Italy.
Tanzania
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.
Given the completion of the Offshore component of Phase I of the Development Programme in February 2016,
which has improved field deliverability and provides sufficient natural gas production to fill the Songas plant and
pipeline to capacity for the greater portion of the remaining life of the production license, the Company does not
expect to commit to further significant capital expenditures until: (i) agreeing commercial terms with TPDC for the
supply of gas to the NNGIP regarding the sale of incremental gas volumes from Songo Songo; and/or (ii) TANESCO
arrears have been substantially reduced, guaranteed or other arrangements for payment made that are satisfactory to
the Company; and/or (iii) the establishment of payment guarantees with the World Bank or other multi-lateral lending
agencies to secure future receipts under any new sales contracts with Government entities.
When the required conditions are met, and in so doing justify further improving the reliability/capacity of field deliverability,
the Company would contemplate undertaking the remaining part of the Phase I Development Programme. The
additional costs are estimated to be approximately US$30 million. There is no assurance that financing will be available
and on acceptable commercial terms to complete Phase I.
notes 82
21
CONTINGENCIES
Downstream unbundling
The newly passed Petroleum Act, 2015 (the “Act”) was passed into Law by Presidential decree on 4 August 2015. In
relation to the unbundling of the downstream business, the Act vests TPDC with exclusive rights in the distribution
of gas, however, the Act has a provision which recognizes the Company’s PSA within the legislation. The Company
does not expect the new legislation to have a significant impact on the downstream distribution business however it
is still unclear how the provisions of the Act will be interpreted and implemented.
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.
For the purpose of the reserves certification as at 31 December 2015, 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. In 2014 TPDC and the Company agreed to
remove US$1.0 million from the Cost Pool. In 2015 there have been no further developments. Under the dispute
mechanism outlined in the PSA, TPDC are to appoint an independent specialist to assist the parties in reaching
agreement on costs that are still subject to dispute, as at the time of writing this report no such specialist has been
appointed. If the matter is not resolved to the Company’s satisfaction, the Company intends to proceed to arbitration
via the International Centre for Settlement of Investment Disputes (“ICSID”) pursuant to the terms of the PSA.
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTNotes to the Consolidated Financial Statements 83
Tax dispute
Period
Reason for dispute
Disputed amount US$ million
Principal
Interest
Total
Taxation
Area
PAYE
WHT
2008-10 Pay-As-You-Earn (“PAYE”) withholding tax on taxable
income of employees on grossed up equivalent of
staff salaries, which are contractually stated as net.
2005-10 WHT on services by non-resident persons
performed outside of Tanzania.
Income Tax
2008-13 Deductibility of capital expenditures and expenses
(2009), additional income tax (2008, 2010, 2011),
and foreign exchange rate application (2013).
VAT
2008-10 Output VAT on imported services
and SSI Operatorship services.
0.3
1.1
5.2
2.8
9.4
–
0.3 (1)
0.8
1.4
3.0
5.2
1.9 (2)
6.6 (3)
5.8 (4)
14.6
(1) During the year, PAET appealed the Tax Revenue Appeals Board (“TRAB”) ruling that PAET is liable to pay PAYE on grossed up equivalent
of staff salaries. PAET is awaiting appeal date to be set up with the Tax Revenue Appeals Tribunal (“TRAT”);
(2) 2005-2009 (US$1.8 million): During the year, TRAT ruled in favor of PAET. TRA has filed notice of appeal with the Court of Appeal, and PAET
is awaiting decision of the Court of Appeal.
2010 (US$0.1 million): TRAB is awaiting a ruling from the Court of Appeal on the 2005-2009 case, which would influence TRAB decision
on this matter accordingly.
(3) (a) 2009 (US$1.8 million): During the year, TRAB has ruled against PAET with respect to the deductibility of capital expenditures and
expenses. PAET appealed to TRAT and is awaiting hearing date to be scheduled;
(b) 2008, 2010-2011 (US$4.6 million): During the year, PAET filed objections against TRA assessments with respect to additional tax and
is awaiting a response;
(c) 2013 (US$ 0.2 million): During the year, PAET filed objections to TRA assessment with respect to foreign exchange rate application and
is awaiting a response.
(4) In 2014, PAET filed an objection to TRA’s claims and is awaiting a response.
Management, with the advice from its legal counsels, has reviewed the Company’s position on the above objections
and appeals and has concluded that no provision is required with regard to the above matters.
notes
84
22
DIRECTORS AND OFFICERS EMOLUMENTS
US$’000
Directors
Directors
Officers
Officers
Year
Base
Bonus
2015
2014
2015
2014
1,100
1,412
1,469
748
500
660
345
210
Stock based
compensation
expense
1,676
2,412
43
334
Total
3,276
4,484
1,857
1,292
The table above provides information on compensation relating to the Company’s officers and directors. Six officers
and three non-executive directors comprised the key management personnel during the year ended 31 December
2015 (2014: four officers and two non-executive directors). One of the officers is also a director and as such their
remuneration has been included under directors’ emoluments in the table above.
ORCA EXPLORATION GROUP INC. | 2015 ANNUAL REPORTNotes to the Consolidated Financial Statements 85
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Corporate Information
Board of Directors
W. David Lyons
Chairman and
Chief Executive Officer
Queensway
Gibraltar
Officers
W. David Lyons
Chairman and
Chief Executive Officer
Queensway
Gibraltar
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
David W. Ross
Non-Executive Director
William H. Smith
Non-Executive Director
Glenn D. Gradeen
Non-Executive Director
Calgary, Alberta
Canada
Calgary, Alberta
Canada
Calgary, Alberta
Canada
Blaine Karst
Chief Financial Officer
Stephen Huckerby
Chief Accounting Officer
David K. Roberts
Vice President of Operations
Calgary, Alberta
Canada
St. Peters, Jersey
Channel Islands
Kansas City, Missouri
United States of America
Registered Office
Investor Relations
Orca Exploration
Group Inc.
P.O. Box 146
Road Town
Tortola
British Virgin Islands, VG110
W. David Lyons
Chairman and
Chief Executive Officer
WDLyons@orcaexploration.com
www.orcaexploration.com
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
Transfer Agent
Burnet, Duckworth
& Palmer LLP
Calgary, Canada
CST Trust Company
Calgary, Alberta, Canada
www.orcaexploration.com
ORCA EXPLORATION GROUP INC.