O R C A E X P L O R A T I O N G R O U P I N C .
2016
ANNUAL
REPORT
Orca Exploration Group Inc. is an international public company
engaged in hydrocarbon exploration, development and supply of gas in
Tanzania and oil appraisal and gas exploration in Italy. Orca Exploration
trades on the TSXV under the trading symbols ORC.B and ORC.A.
FINANCIAL AND OPERATING HIGHLIGHTS . . . . . 1
2016 OPERATING HIGHLIGHTS . . . . . 2
GAS RESERVES . . . . . 3
MANAGEMENT’S DISCUSSION & ANALYSIS . . . . . 5
MANAGEMENT’S REPORT TO SHAREHOLDERS . . . . . 42
AUDITORS’ REPORT . . . . . 43
FINANCIAL STATEMENTS . . . . . 44
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS . . . . . 48
CORPORATE INFORMATION . . . . . 75
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
Financial and Operating Highlights
(Expressed in US$ unless indicated otherwise)
OPERATING
Daily average gas delivered and sold (MMcfd)
Additional Gas
Industrial
Power
Average price (US$/mcf)
Industrial
Power
Weighted average
Operating netback (US$/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
Net cash flows from operating activities
per share - basic and diluted (US$)
Net income
per share - basic and diluted (US$)
Cash flow from operations (1)
per share - basic and diluted (US$)
Working capital (including cash)
Cash
Capital expenditures
Long-term loan
Outstanding Shares ('000)
Class A
Class B
Total shares outstanding
Weighted average diluted Class A and Class B shares
(1) See MD&A – non-GAAP measures
1
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YEAR ENDED / AS AT DECEMBER 31
2016
2015
44.5
12.5
32.0
7.70
3.56
4.73
3.26
347
58
405
313
363
64,659
19,968
0.57
2,164
0.06
31,855
0.91
71,989
80,895
16,924
58,399
1,751
33,106
34,857
34,857
47.4
11.4
36.0
7.58
3.54
4.49
2.57
368
49
417
309
357
54,088
7,018
0.20
1,533
0.04
26,454
0.76
32,521
53,797
38,411
18,599
1,751
33,106
34,857
34,887
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2016 Operating Highlights
•
•
•
Additional Gas deliveries and sales averaged
44.5 standard cubic feet per day (“MMcfd”) a
decrease of 10% over the prior year (53.2 MMcfd).
The decrease in Additional Gas volumes year
over year is primarily the result of reduced
nominations of natural gas volumes by TANESCO
arising from cessation of a power generation
contract with an independent power producer
who was using the Company’s Additional Gas
combined with the incremental natural gas
supply to TANESCO from other gas suppliers.
Total proved reserves for Additional Gas decreased
6% to 347 Bcf from 368 Bcf in the prior year and
total proved plus probable reserves (“2P”) decreased
3% to 405 Bcf from 417 Bcf in the prior year. The
decrease is a consequence of 2016 Additional
Gas production of 16.3 Bcf off-setting the higher
anticipated growth in Power demand in the latter
half of the licence period. The net present value
of the estimated future cash flows from the 2P
reserves at a 10% discount rate (“NPV10”) increased
1.5% to US$363.0 million from US$357.4 million in
the previous year. The increase is a result of the
higher anticipated growth of the Power sector
in the later part of the licence period and the
deferral of the onshore workover program and
the refrigeration project to 2018 from 2017.
Revenue increased by 20% to US$64.7 million
from US$54.1 million in the prior year. The
increase in revenue is due to the impact
of the capital expenditure associated with
the Offshore Development Program which
commenced in the third quarter of 2015. This
entitled the Company to 85% of the field net
revenue compared to 74% in 2015. This, along
with the 5% increase in the weighted average
price to US$4.73/Mcf from US$4.49/Mcf, more
than offset the decline in sales volume.
• Net income for the year increased by 41% to US$2.2
million or US$0.06 per share basic and diluted
compared to US$1.5 million or US$0.04 per share
in the prior year. The increase of US$10.0 million in
revenue was offset by interest charges on the IFC
loan as well as higher stock based compensation.
• Net cash flow from operating activities increased
by 185% to US$20.0 million (or US$0.57 per
share diluted) from US$7.0 million (or US$0.20
per share diluted) in the prior year. The increase
was primarily the result of higher revenue.
• Cash flow from operations increased by 20%
to US$31.9 million (or US$0.91 per share
diluted) from US$26.5 million (or US$0.76 per
share diluted) in the prior year. The increase
was primarily the result of higher revenue.
• Working capital increased 121% to US$72.0
million compared to US$32.5 million as at
December 31, 2015. The increase is primarily
the consequence of drawing down the US$40
million balance of the IFC loan offset by capital
expenditures associated with the Offshore
Program. The increase in cash to US$80.9
million from US$53.8 million as at December 31,
2015 accounted for 68% of the total increase in
working capital over the twelve month period.
•
•
At December 31, 2016 TANESCO owed the
Company US$80.1 million excluding interest
(including arrears of US$74.4 million) compared
to US$69.8 million (including arrears of US$61.9
million) as at December 31, 2015. Current TANESCO
receivables as at December 31 2016 amounted
to US$5.7 million (2015: US$7.8 million).
Prior to 2016 the Company had reached an
understanding with TANESCO that it would continue
to supply gas if TANESCO remained reasonably
current with payments for gas deliveries. Based on
a review of TANESCO’s payment history for the past
three years performed in Q4 2016, the average cash
received against invoices raised by TANESCO was
80%. Management concluded that this ratio would
present a more accurate position with respect to
TANESCO’s revenue and accounts receivable, and
a decision was made to use this ratio to recognize
TANESCO revenue. Effective October 1, 2016 the
TANESCO accounts receivable will be recorded
at 80% of the value of invoices raised. Since
the year-end, TANESCO has paid the Company
US$12.9 million, and as at the date of this report
the total TANESCO receivable is US$74.8 million
(of which US$74.4 million has been provided for).
ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORT
3
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Gas Reserves
The Company's natural gas reserves as at December 31, 2016 for the period to the end of its licence in October 2026 were
evaluated by independent petroleum engineering consultants 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 is dated March 14, 2017 with the
effective date of December 31, 2016. 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
included 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.
The completion of the SS-12 development well in February 2016 encountered the top reservoir approximately 100 meters
high to prognosis. A petrophysical update was also undertaken taking into account the well results.
On a gross Company basis there has been a 6% 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 16.3 Bcf during the year.
There has been a 3% decrease in the Proved plus Probable Additional Gas reserves on a Gross Company life of license basis
from 416.9 Bcf to 405.3 Bcf with no change on a life of field basis.
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 developed non-producing
Proved undeveloped
Total proved (1P)
Probable
Total proved and probable (2P)
Gross (1)
2016
Net (2)
343.6
209.6
3.8
–
347.4
57.9
405.3
2.2
–
211.8
47.4
259.2
Gross
245.9
–
121.9
367.8
49.1
416.9
2015
Net
158.5
–
70.5
229.0
40.9
269.9
(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.
Songo Songo
Additional Gas reserves to end of field life (Bcf)
Independent reserves evaluation
Proved producing
Proved developed non-producing
Proved undeveloped
Total proved (1P)
Probable
Total proved and probable (2P)
Gross (1)
595.0
47.0
–
642.0
117.5
759.5
2016
Net (2)
365.9
26.5
–
392.4
84.9
477.3
Gross
598.9
–
46.5
645.4
116.5
761.9
2015
Net
375.9
–
28.3
404.2
76.7
480.9
(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.
4
Gas Reserves
For the reserves certification as at December 31, 2016, 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 Songo Songo North well, SSN-1. 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 111 Bcf (2015: 122
Bcf) or an average of 14.5 Bcf per annum will be required to meet the demands of the Protected Gas users from January 1,
2017 to July 31, 2024. During 2016 the Protected Gas users consumed 13.7 Bcf.
Additional Gas
price
1P
US$/mcf
4.33
4.21
4.21
4.29
4.41
4.50
4.60
4.65
4.67
4.77
Year
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
Gross Additional
Gas
volumes
1P
MMcfd
46.93
60.57
78.47
87.84
90.86
99.97
107.36
121.77
145.08
145.08
Additional Gas
price
2P
US$/mcf
4.38
4.19
4.29
4.35
4.44
4.55
4.70
4.76
4.78
4.88
Gross Additional
Gas
volumes
2P
MMcfd
50.30
84.05
89.81
103.23
113.49
121.88
123.40
141.29
164.60
164.60
Present value of reserves
The estimated values of the Songo Songo reserves on a life of license basis are as follows:
US$ millions
Proved producing
Proved developed non producing
Proved undeveloped
Total proved (1P)
Probable
Total proved and probable (2P)
5%
404.6
2.2
–
406.8
63.7
470.5
10%
312.1
1.0
–
313.1
49.9
363.0
2016
15%
247.3
0.3
–
247.6
40.3
287.9
5%
294.6
–
114.7
409.3
65.9
475.2
10%
229.2
–
79.4
308.6
48.8
357.4
2015
15%
184.6
–
55.5
240.1
37.7
277.8
There has been a 1.5% increase in the 2P present value at a 10% discount basis from US$357.4 million to US$363.0 million
on a life of licence basis.
The increase is due to a higher than anticipated growth in sales of Additional Gas to the NNGIP in the latter part of the licence
period, the deferral of the onshore workover program and refrigeration capital expenditure from 2017 to 2018.
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. | 2016 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 .
2016
MANAGEMENT’S
DISCUSSION
& ANALYSIS
6
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 DECEMBER 31, 2016. THIS MD&A
IS BASED ON THE INFORMATION AVAILABLE ON APRIL 12, 2017.
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 Tanzanian Production Development
Corporation (“TPDC”) future back-in rights on the economic terms of the Production Sharing Agreement (“PSA”); ability to
meet all conditions under the International Finance Corporation (“IFC”) financing agreement signed on October 29, 2015;
the Company’s estimated spending for the planned Development Program for 2017 and 2018, 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 National Natural Gas Infrastructure Project (“NNGIP”) which includes two gas processing
facilities and pipelines supplying gas from the Mtwara Region of Tanzania and Songo Songo Island to Dar es Salaam; the
potential impact of the Petroleum Act, 2015 (“Act”) and the Finance Act, 2016 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 (“NGSA”) 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 or production through the plant restricted; the risk that Songas and the
Company will not agree on appropriate terms and sign the NGSA 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 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 that the planned financing solutions
to resolve the TANESCO arrears are not implemented by the Tanzanian government; risk that planned financing provided
by the World Bank will not be completed or funds will not be allocated to resolving TANESCO arrears; risk that 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 Program is not completed as planned and the actual cost to complete the
Development Program exceeds the Company’s estimates; risk that the remaining well workovers under the Development
ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis 7
Program are unsuccessful or determined to be unfeasible; 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 PSA and other agreements relating to its business in Tanzania as a result of the recently approved Act, 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 being processed through the Songas gas processing plant
may be reduced 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 not be successful in appealing claims made by the Tanzanian Revenue
Authority (“TRA”) and may 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, impact of new local content 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, 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 Program will be completed within
the timing anticipated; the actual costs to complete the Development Program 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 Act in Tanzania will not impair the Company’s rights under the PSA to develop and market natural gas
in Tanzania; current or, where applicable, proposed industry conditions, laws and regulations will continue in effect or as
anticipated as described herein; and other matters.
The forward-looking statements contained in this MD&A are made as of the date hereof and 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
8
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.
• CASH FLOW FROM OPERATIONS REPRESENTS NET CASH FLOW FROM OPERATING ACTIVITIES LESS INTEREST PAID
AND BEFORE CHANGES IN NON-CASH WORKING CAPITAL. THIS IS A NEW KEY PERFORMANCE MEASURE THAT
MANAGEMENT BELIEVES REPRESENTS THE COMPANY'S ABILITY TO GENERATE SUFFICIENT CASH FLOW TO FUND
CAPITAL EXPENDITURES AND REPAY DEBT.
• 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.
• CASH FLOW FROM OPERATIONS PER SHARE IS CALCULATED ON THE BASIS OF THE CASH FLOW FROM OPERATIONS
DIVIDED BY THE WEIGHTED AVERAGE NUMBER OF SHARES.
• NET CASH FLOW FROM OPERATING ACTIVITIES PER SHARE IS CALCULATED AS NET CASH FLOW FROM OPERATING
ACTIVITES 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 July 31, 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”) until the PSA expires in October 2026.
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 the PGSA and indirectly through the supply of Protected Gas and Additional Gas to Songas which in turn generates
and sells power to TANESCO. TANESCO is the Company’s largest customer and the gas supplied by the Company to Songas
and TANESCO today fires approximately 35% of the electrical power generated in Tanzania and 55% of the gas utilized for
power generation in the country.
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. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis 9
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
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 jeopardize 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.
management's discussion & analysis 10
Access and development of infrastructure
(f) The Company is able to utilize 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 utilized 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 field revenue, less processing and pipeline tariffs and direct sales taxes in any year (“field net revenue”)
can be used to recover past costs incurred. Costs recovered out of field net revenue are termed “Cost Gas”.
The Company pays and recovers costs of exploring, developing and operating the Additional Gas with two exceptions:
(i) TPDC may recover reasonable market and market research costs as defined under the PSA; and (ii) TPDC has the
right to elect to participate in the drilling of at least one well for Additional Gas in the Discovery Blocks for which there
is a development program as detailed in an Additional Gas plan (“Additional Gas Plan”) as submitted to MEM, subject
to TPDC being able to elect to participate in a development program only once and TPDC having to pay a proportion
of the costs of such development program by committing to pay between 5% and 20% of the total costs (“Specified
Proportion”). If TPDC does not notify the Company within 90 days of notice from the Company that the MEM has
approved the Additional Gas Plan, then TPDC is deemed not to have elected. If TPDC elects to participate, then it will be
entitled to a 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 December 31, 2016, 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 January 1, 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 reviewing the terms of a new sales agreement.
In 2011 the Company signed a re-rating agreement with TANESCO, TPDC and Songas (the “Re-Rating Agreement”)
which evidenced an increase to the gas processing capacity of the Songas facilities 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 paid additional compensation of US$0.30/mcf
for sales between 70 MMcfd and 90 MMcfd and US$0.40/mcf for volumes above 90 MMcfd by issuing credit notes to
TANESCO. This was in addition to the tariff of US$0.59/mcf payable to Songas as set by the energy regulator, EWURA.
In May 2016 the Company notified TANESCO and Songas that the additional compensation for sales over 70 MMcfd
would no longer be paid effective June 2016. The additional compensation was always intended to be temporary in
nature until the expansion of the Songas infrastructure, at which time Songas would apply to EWURA to obtain approval
of a new tariff for the processing of volumes over 70 MMcfd. The PGSA provides for passing on to TANESCO any tariff
to be charged to the Company and in the event that a new tariff is approved.
ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis
11
The parties are seeking to resolve the status of the re-rating agreement. The processing capacity at the Songas facilities
remain unaltered and are fully utilized by the company. Without a new agreement, there are no assurances that Songas
will continue to allow the gas plant to operate above 70 MMcfd. 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
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.
(i) 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 field net revenue 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%.
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.
(j)
“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.
(k) 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.
(l)
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.
management's discussion & analysis
12
Results for the year ended December 31, 2016
SUMMARY
During the year ended December 31, 2016 the Company successfully completed the drilling of well SS-12. This completed
all work-over and drilling activities planned under the Offshore Development Program which commenced in the third
quarter of 2015. Based on our evaluation of the drilling and testing results, the Company estimates that total field production
capabilities will increase to 180 MMcfd once the SS-12 production platform is completed and the well is tied into the NNGIP
infrastructure. Total capital expenditures for the year were US$16.9 million (2015: US$38.4 million).
For the year ended December 31, 2016 there was a decrease of 3% from the prior year in 2P reserve volumes primarily
related to gas produced during the year. Despite the overall decline in sales volume the change in sales mix with increased
forecast industrial sales has resulted in the net present value of cash flows from 2P reserves at a 10% discount rate decreasing
by 1% compared to the prior year.
Despite a 6% decline in the volume of Additional Gas sold there was a 20% increase in revenue for 2016. The increase being
a consequence of the revenue sharing mechanism of the PSA, whereby the Company is entitled to a higher percentage of
total sales due to the recovery of capital costs associated with the Offshore Development Program. The increase in revenue
is a primary factor in the 185% increase in net cash flow from operating activities to US$20.0 million (2015: US$7.0 million)
and a 41% increase in cash flow from operations to US$30.5 million (2015: US$26.5 million).
The Company recorded net income of US$2.2 million (2015: US$1.5 million) for the year despite recording an additional
US$12.4 million provision against the TANESCO long term receivable.
The Company finished 2016 in a stable financial position with US$72.0 million in working capital (2015: US$32.5 million) and
US$58.4 million in long-term debt (2015: US$18.6 million) with the change resulting from drawing down the balance of the
International Finance Corporation financing facility.
OPERATING VOLUMES
The total volume of Protected Gas and Additional Gas delivered and sold for the year was 29,961 MMcf (2015: 31,485 MMcf)
or 82.0 MMcfd (2015: 86.28 MMcfd), net of approximately 0.5 MMcfd (2015: 0.5 MMcfd) consumed locally for fuel gas.
The Additional Gas sales volumes for the year were 16,291 MMcf (2015: 17,311 MMcf) or average daily volumes of 44.5 MMcfd
(2015: 47.4 MMcfd). This represents a decrease in average daily volumes of 6% year on year.
Additional Gas sales volumes for Q4 2016 were 4,121 MMcf (Q4 2015: 4,572 MMcf) or average daily volumes of 44.8 MMcfd
(Q4 2015: 49.7 MMcfd), a decrease of 10% over the prior year quarter.
The decrease in Additional Gas volumes year over year is primarily a result of reduced nominations of natural gas volumes by
TANESCO arising from the cessation of a power generation contract with an independent power producer who was using
the Company’s Additional Gas; incremental natural gas supply to TANESCO from other gas suppliers; and suspension of
power generation by Songas in the early part of Q1 2016 due to issues of non-payment by TANESCO. The decline in natural
gas supplied to the power sector was partially offset by the increase in gas supplied to the industrial customers.
ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis 13
The Company’s gross 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
DECEMBER 31
YEAR ENDED
DECEMBER 31
2016
2015
2016
2015
1,226
2,895
4,121
13.3
31.5
44.8
1,089
3,483
4,572
11.8
37.9
49.7
4,587
11,704
16,291
12.5
32.0
44.5
4,166
13,145
17,311
11.4
36.0
47.4
Industrial sector
Industrial sales volume for the year increased by 10% to 4,587 MMcf (12.5 MMcfd) from 4,166 MMcf (11.4 MMcfd) in 2015.
Fourth quarter Industrial sales volume increased by 13% to 1,226 MMcf (13.3 MMcfd) from 1,089 MMcf (11.8 MMcfd) in the
prior year quarter.
The increased volumes are primarily the result of fewer days of unscheduled maintenance work by cement, textile and
edible oil companies and consumption by new customers connected during the first half of 2016.
Power sector
Power sector sales volumes for the year decreased by 11% to 11,704 MMcf (32.0 MMcfd), compared to 13,145 MMcf
(36.0 MMcfd) in 2015.
Power sector sales volumes decreased by 17% to 2,895 MMcf (31.5 MMcfd), compared to 3,483 MMcf (37.9 MMcfd) in
Q4 2015.
The decrease in volumes over the year is primarily a result of reduced nominations of natural gas volumes by TANESCO arising
from the cessation of a power generation contract with an independent power producer who was using the Company’s
Additional Gas; incremental natural gas supply to TANESCO from other gas suppliers; and suspension of power generation
by Songas during parts of the year due to issues of non-payment with TANESCO.
management's discussion & analysis
14
SONGO SONGO DELIVERABILITY
As at December 31, 2016 the Company had a field productive capacity of approximately 155 MMcfd, with the ability to
expand production capacity to 180 MMcfd with the tie-in of well SS-12. The SS-12 well was successfully completed in the first
quarter of 2016 but is currently suspended awaiting tie-in. Production volumes are currently limited to 102 MMcfd, as only
the Songas infrastructure is available to the Company. The Company now has significant redundant productive capacity.
The 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.
The SS-12 well has been identified for connection to the NNGIP infrastructure subject to the negotiation with TPDC for
additional gas sales. Volumes sold to TPDC under this agreement would initially result in concomitant reduction in volumes
through the existing Songas infrastructure. This would provide the Company the opportunity to increase sales volumes to
industrial customers as production capacity would no longer be constrained by the Songas infrastructure.
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
DECEMBER 31
YEAR ENDED
DECEMBER 31
2016
2015
2016
2015
7.52
3.57
4.75
7.62
3.56
4.51
7.70
3.56
4.73
7.58
3.54
4.49
Industrial sector
The average gas price achieved during the year was US$7.70/mcf up 2% from (2015: US$7.58/mcf). The overall increase in
the average gas price is a consequence of a contractual step change in the gas price to the cement company that came into
effect on January 1, 2016 against a similar mix of sales year over year.
The average industrial price in the fourth quarter was US$7.52/mcf down 1% from Q4 2015 (US$7.62/mcf). The decline in
the average industrial price is the result of re-setting the floor price for a number of industrial customers at the end of the
third quarter.
Power sector
The average sales price to the Power sector was US$3.56/mcf for the year (2015: US$ 3.54 /mcf), an increase of 1%.
The average sales price to the Power sector in the fourth quarter was US$3.57/mcf, compared with US$3.56/mcf in Q4 2015.
ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis 15
OPERATING REVENUE
Under the terms of the PSA, the Company is responsible for invoicing, collecting and allocating the revenue from Additional
Gas sales.
The Company is able to recover all costs incurred on the exploration, development and operations of the project up to a
maximum of 75% of the Net Revenue (“Cost Gas”) prior to the distribution of Profit Gas. Any costs not recovered in any period
are carried forward for recovery out of future revenues. Once the Cost Gas has been recovered, TPDC is able to recover any
pre-approved marketing costs.
The Additional Gas sales volumes for 2016 were below 50 MMcfd and, as a consequence, the Company was entitled to a
40% share of Profit Gas revenue for the year compared to 55% for sales volumes above 50 MMcfd. See “Principal Terms of
the Tanzanian PSA and Related Agreements.”
The Company was allocated a total of 85% of the Songo Songo field net revenue in 2016 (2015: 74%). The increase in
allocation of the net revenue is a consequence of the Offshore Development Program which enabled the Company to
be entitled to the maximum Cost Gas allocation due to the increase in the cost pool. The Offshore Development Program
commenced in the third quarter of 2015 and was completed in the first quarter of 2016.
US$’000
Gross field revenue
Tariff for processing plant and pipeline infrastructure
Field net revenue
Analysed as to:
Company Cost Gas
Company Profit Gas
Company operating revenue
TPDC share of revenue
Field net revenue
THREE MONTHS ENDED
DECEMBER 31
YEAR ENDED
DECEMBER 31
2016
2015
2016
2015
17,920
21,288
75,377
79,885
(2,433)
15,487
(3,229)
18,059
(10,057)
65,320
(12,282)
67,603
11,615
1,549
13,164
2,323
15,487
13,544
1,806
15,350
2,709
18,059
48,990
6,532
55,522
9,798
65,320
38,689
11,565
50,254
17,349
67,603
The Company’s reported revenue for the quarter and the year amounted to US$16.5 million and US$64.7 million respectively,
after adjusting the Company’s operating revenues of US$13.2 million and US$55.5 million by:
i)
Adding US$3.7 million for income tax for the quarter and US$10.4 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
ii) Subtracting US$0.3 million and US$1.2 million for deferred Additional Profits Tax charged in the quarter and for the year.
This tax is considered a royalty and is presented as a reduction in revenue.
management's discussion & analysis
16
Revenue presented on the Consolidated Statements of Comprehensive Income may be reconciled to the operating revenue
as follows:
US$’000
Industrial sector
Power sector
Gross field revenue
Processing and transportation tariff
Field net revenue
TPDC share of revenue
Company operating revenue
Additional Profits Tax charge
Current income tax adjustment
Revenue
THREE MONTHS ENDED
DECEMBER 31
YEAR ENDED
DECEMBER 31
2016
2015
2016
2015
9,506
8,414
17,920
(2,433)
15,487
(2,323)
13,164
(301)
3,670
8,794
12,494
21,288
(3,229)
18,059
(2,709)
15,350
(335)
857
16,533
15,872
35,626
39,751
75,377
33,164
46,721
79,885
(10,057)
(12,282)
65,320
(9,798)
55,522
(1,226)
10,363
64,659
67,603
(17,349)
50,254
(2,355)
6,189
54,088
Prior to 2016 the Company had reached an understanding with TANESCO that it would continue to supply gas if TANESCO
remained reasonably current with payments for gas deliveries. As a result of TANESCO’s inability to fully pay all amounts
invoiced by the Company for the past few years, management of the Company has modified its approach to revenue
recognition as it relates to TANESCO only. Commencing on October 1, 2016 the Company will record 80% of the amounts
invoiced to TANESCO for revenue recognition purposes. The 80% amount was determined by comparison of TANESCO’s
historical payment history to the amounts invoiced by the Company over the past three years. Management believes this
approach provides the best estimate of TANESCO’s ability to pay and remain reasonably current and as well reflects the
economic reality of the situation. This results in a reduction in revenue recognized from the effective date.
For cash received in excess of the revenue recorded from TANESCO in any given period, the additional amounts received
will be recorded as deferred revenue. In periods when cash received is less than revenue recorded, the deferred revenue
will be reduced accordingly. If the deferred revenue amount is reduced to nil, the difference will be recorded as accounts
receivable.
The percentage used to recognize TANESCO revenue will be reviewed on at least a semi-annual basis, more frequently
if circumstances require and if there is a significant difference between the amount of revenue recorded and amounts
received, the percentage used to record revenue as well as any existing receivable or deferred revenue balance will be
revised accordingly.
As a result of recording revenue based on the expected collectability from the effective date, there is the following impact
on the 2016 results:
1) US$1.6 million decrease in revenue,
2) US$1.3 million decrease in long-term receivables and allowance for doubtful accounts,
3) US$0.6 million decrease in current accounts receivable,
4) US$0.3 million decrease in net income and current liabilities.
Company operating revenue decreased by 14% in the fourth quarter of 2016 compared with Q4 2015. The decrease is
primarily due to the adjustment in revenue associated with the modified approach used for TANESCO revenue recognition.
ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis 17
Company operating revenue for the year increased 10% to US$55.5 million compared to US$50.3 million in the prior year.
The 10% increase is due to the impact of the capital expenditures associated with the Offshore Development Program which
commenced in the third quarter of 2015. This entitled the Company to 75% of the field net revenue as Cost Gas for the year
compared to 57% in 2015, the increase in Cost Gas resulting in a corresponding reduction in Profit Gas and a corresponding
decrease in the Profit Gas attributable to TPDC by 42% over the year.
The fall in the level of Profit Gas for the year resulted in a 47% fall in the Additional Profits Tax charge for the year to US$1.2
million from US$2.4 million. The increase in operating revenue and decrease in Additional Profits Tax contributing to the
increase in the current income tax adjustment from US$6.2 million to US$10.4 million.
PROCESSING AND TRANSPORTATION TARIFF
The processing and transportation tariff charge for the quarter and for the year were US$2.4 million (Q4 2015: US$3.2 million)
and US$10.1 million (2015: US$12.3 million), respectively. The reduction in the tariff for the year is a consequence of the
cessation of the additional compensation and lower sales 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$0.2 million (Q4 2015: US$0.1 million) and for the
year, US$0.6 million (2015: US$0.4 million). Amounts allocated for Additional Gas for the quarter and for the year were
US$0.1 million (Q4 2015: US$0.1 million) and US$0.4 million (2015: US$0.2 million), respectively. The increase in the year is
the consequence of increased activity following the completion of the Offshore Development Program at the end of the
first quarter.
Other field and operating costs include an apportionment of the annual PSA licence costs, regulatory fees, insurance, some
costs associated with the evaluation of the reserves, and the cost of personnel which are not recoverable from Songas.
Distribution costs represent the direct cost of maintaining the ring main distribution pipeline and pressure reduction stations
(security, insurance and personnel). Ring main distribution costs were US$0.7 million (Q4 2015: US$0.5 million) for the quarter
and US$2.7 million (2015: US$1.9 million) for the year. The production and distribution costs are detailed in the table below:
US$’000
Share of well maintenance
Other field and operating costs
Ring main distribution costs
Production and distribution expenses
THREE MONTHS ENDED
DECEMBER 31
2016
2015
112
265
377
651
1,028
47
251
298
512
810
YEAR ENDED
DECEMBER 31
2016
351
979
1,330
2,703
4,033
2015
233
1,594
1,827
1,924
3,751
management's discussion & analysis
18
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 (1)
Weighted average price for gas
Tariff
TPDC share of revenue
Net selling price
Well maintenance and other operating costs
Ring main distribution costs
Operating netbacks
THREE MONTHS ENDED
DECEMBER 31
YEAR ENDED
DECEMBER 31
2016
7.52
3.56
4.75
(0.59)
(0.56)
3.60
(0.09)
(0.16)
3.35
2015
7.62
3.56
4.51
(0.71)
(0.59)
3.21
(0.07)
(0.11)
3.03
2016
7.70
3.56
4.73
(0.62)
(0.60)
3.51
(0.08)
(0.17)
3.26
2015
7.58
3.54
4.49
(0.71)
(1.00)
2.78
(0.13)
(0.08)
2.57
(1)
The weighted average sales price is stated before the decrease in TANESCO revenue due to the modified approach used for
revenue recognition purposes and represents the weighted average price of the volumes invoiced and delivered.
The operating netback increased by 11% from US$3.03/mcf in Q4 2015 to US$3.35/mcf in Q4 2016 as a result of the 5%
increase in the weighted average price of gas from US$4.51/mcf in Q4 2015 to US$4.75/mcf in Q4 2016 and the decrease
in compensation to Songas for volumes over 70 MMcfd.
The operating netback for the year increased 27% to US$3.26/mcf from US$2.57/mcf in 2015. The increase in the weighted
average price for the year of 5% was a consequence of the increase in the volume of industrial sales during the year and the
40% decrease in TPDC’s share of revenue per mcf, as a consequence of lower total profit gas resulting from the completion
of the Offshore Development Program during the first quarter of the year.
GENERAL AND ADMINISTRATIVE EXPENSES
General and administrative expenses are detailed in the table below:
US$’000
Employee and related costs
Stock based compensation (recovery)
Office costs
Marketing and business development costs
Reporting, regulatory and corporate
General and administrative expenses
THREE MONTHS ENDED
DECEMBER 31
YEAR ENDED
DECEMBER 31
2016
2,514
556
1,317
42
459
4,888
2015
2,796
(87)
916
6
1,067
4,698
2016
8,050
2,591
3,618
322
1,756
2015
7,001
(244)
3,366
214
3,271
16,337
13,608
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$1.5 million (Q4 2015: US$1.6 million) per month during the quarter and US$1.2
million (2015: US$1.1 million) per month over the year.
ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis 19
STOCK BASED COMPENSATION
The breakdown of the costs incurred in relation to stock based compensation is detailed in the table below:
US$’000
Stock appreciation rights (“SARs”)
Restricted stock units (“RSUs”)
Stock-based compensation (recovery)
THREE MONTHS ENDED
DECEMBER 31
YEAR ENDED
DECEMBER 31
2016
2015
2016
2015
439
117
556
463
(550)
(87)
1,467
1,124
2,591
(266)
22
(244)
As at December 31, 2016 a total of 2,430,000 SARs were outstanding compared to 3,100,000 as at December 31, 2015.
A total of 580,000 SARs with exercise prices ranging from CDN$2.30 to CDN$3.10 were exercised during the year resulting
in a total cash payout of US$0.5 million, with a further 90,000 SARs with an exercise price of CDN$2.30 being forfeited.
No new SARs were granted in the year. As at December 31, 2016 a total of 239,361 RSUs were outstanding compared to zero
at December 31, 2015. During the year a total of 386,420 RSUs were issued. The RSUs vested in full on the date of grant have
an exercise price of CDN$0.001 and have a five year term. A total of 147,059 RSUs were exercised during the year resulting
in a total cash payout of US$0.4 million.
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 0.5%;
stock volatility of 33.5% to 50.7%; 0% dividend yield; 5% forfeiture; and a closing price of CDN$3.86 per Class B share.
As at December 31, 2016 a total accrued liability of US$3.2 million (2015: US$1.6 million) has been recognized in relation to
SARS and RSUs. The Company recognized an expense of US$0.6 million (Q4 2015: credit US$0.1 million) for the quarter and
for the year ended December 31, 2016 an expense of US$2.6 million (2015: credit US$0.2 million). The increased expense
in 2016 is due to the combination of a 40% increase in the share price to CDN$3.86 (2015: CDN$2.75) together with issuing
386,420 fully vested Restrictive Stock Units (“RSUs”) during the first half of the year.
management's discussion & analysis 20
NET FINANCE EXPENSE
The movement in net finance expense is detailed in the table below:
US$’000
Finance income
Interest expense
Net foreign exchange loss
Financing fee
Provision for doubtful accounts
Indirect tax
Finance expense
Net finance expense
THREE MONTHS ENDED
DECEMBER 31
YEAR ENDED
DECEMBER 31
2016
193
(1,567)
(18)
–
2015
20
(117)
(370)
250
2016
383
(5,668)
(24)
–
2015
43
(117)
(2,677)
(16)
(414)
(10,731)
(12,853)
(11,178)
(1,388)
(3,387)
(3,194)
–
(10,968)
(10,948)
(1,392)
(19,937)
(19,554)
–
(13,988)
(13,945)
Total amount of interest paid in 2016 was US$5.7 million (2015: US$0.1).
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.
During 2016 the Company billed TANESCO US$4.2 million (2015: US$2.4 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. In the fourth quarter of 2016 the Company billed TANESCO two additional contractual invoices
totaling US$7.8 million for take or pay gas and excess gas taken over the declared maximum daily quantity. These have not
been included in the financial statements as they do not meet the revenue recognition criteria with respect to assurance
of collectability. The Company is pursuing collection and amounts will be recognized in earnings when collected. The
provision for doubtful accounts includes US$12.4 million (2015: US$9.9 million) for overdue TANESCO receivables, US$0.4
million (2015: US$0.1 million) relates to Industrial customers and US$ nil (2015: US$1.3 million) relates to Songas receivables.
The US$1.4 million is in relation to indirect tax associated with trade receivables not recognized in the financial statements
due to IFRS revenue recognition criteria with respect to assurance of collectability.
TANESCO
At December 31, 2016 TANESCO owed the Company US$80.1 million, excluding interest, (of which arrears were US$74.4
million) compared to US$69.8 million (including arrears of US$61.9 million) as at December 31, 2015. Current TANESCO
receivables as at December 31, 2016 amounted to US$5.7 million (2015 US$7.8 million). Since the year-end, TANESCO has
paid the Company US$12.9 million, and as at the date of this report the total TANESCO receivable is US$74.8 million (of
which US$74.4 million has been provided for). The amounts owed do not include interest billed to TANESCO or debtors not
meeting the revenue recognition criteria with respect to assurance of collectability.
ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis 21
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 December 31, 2016 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 recognized a deferred tax liability of US$12.9 million (2015: US$9.3 million). During the year there
was a deferred tax charge of US$3.7 million compared to US$1.7 million in 2015. 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 realized 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 Company provides for 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 19.4% (Q4 2015: 18.6%) has been applied to Profit Gas of US$1.5 million (Q4 2015: US$1.8
million) for the quarter, and an average effective rate of 18.8% (2015: 20.2%) has been applied to Profit Gas of US$6.5 million
(2015: US$11.6 million) for the year ended December 31, 2016. Accordingly, US$0.3 million (Q4 2015: US$0.3 million) and
US$1.2 million (2015: US$2.4 million) have been netted off against revenue for the quarter, and for the year ended December
31, 2016, respectively.
US$’000
Additional Profits Tax
THREE MONTHS ENDED
DECEMBER 31
YEAR ENDED
DECEMBER 31
2016
301
2015
335
2016
1,226
2015
2,355
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 December 31, 2016 the proven
reserves estimated to have been produced over the term of the PSA licence were 341 Bcf (2015: 368 Bcf). A depletion
expense of US$2.4 million for the quarter (Q4 2015: US$2.6 million) and US$9.2 million for the year (2015: US$11.9 million)
has been recorded in the account at an average depletion rate to US$0.56/mcf (2015: US$0.69/mcf). The decrease in the
depletion rate is the consequence of the successful completion of the Offshore Program at a lower level of expenditure
than planned which in turn reduced expected future development costs from what had been originally forecast at the end
of 2015.
Non-natural gas properties are depreciated as follows:
Leasehold improvements:
Computer equipment:
Vehicles:
Fixtures and fittings:
Over remaining life of the lease
3 years
3 years
3 years
management's discussion & analysis 22
CARRYING AMOUNT OF ASSETS
Capitalized costs are periodically assessed to determine whether it is likely that such costs will be recovered in the future.
To the extent that these capitalized costs are unlikely to be recovered in the future, they are impaired and recorded in earnings.
CASH FLOW FROM OPERATIONS
Cash flow from operations was US$6.2 million for Q4 2016 (Q4 2015: US$8.4 million) and US$31.9 million for the year (2015:
US$26.5 million) and is detailed in the table below:
THREE MONTHS ENDED
DECEMBER 31
YEAR ENDED
DECEMBER 31
2016
6,211
1,567
567
8,345
7
(1,566)
6,786
30
6,816
2015
8,391
117
(3,058)
5,450
(19,539)
18,482
4,393
(136)
2016
31,855
5,668
2015
26,454
117
(17,555)
(19,553)
19,968
7,018
(27,609)
(29,950)
34,132
26,491
607
18,324
(4,608)
746
4,257
27,098
(3,862)
US$’000
Cash flow from operations (1)
Interest paid
Change in non-cash working capital (2)
Net cash flows from operating activities
Net cash used in investing activities
Net cash from (used in) financing activities
Increase in cash
Effect of change in foreign exchange on cash
Net increase in cash
(1) See non-GAAP measures
(2) See Consolidated Statement of Cash Flows
CAPITAL EXPENDITURES
During 2016 the Company incurred US$16.9 million (2015: US$38.4 million) in capital expenditures relating primarily to
the drilling of well SS-12, improvement of Songo Songo infrastructure and purchase of other equipment. The 2016 capital
expenditures are net of recharges of US$1.0 million to Songas for its share of costs on wells SS-5 and SS-9 (2015: US$11.2 million).
US$’000
Geological and geophysical and well drilling
Pipelines and infrastructure
Other equipment
THREE MONTHS ENDED
DECEMBER 31
2016
2015
23,099
1,382
59
32
99
–
131
2016
16,255
565
104
YEAR ENDED
DECEMBER 31
2015
35,796
2,359
256
38,411
24,540
16,924
ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis
23
WORKING CAPITAL
Working capital as at December 31, 2016 was US$72.0 million (December 31 2015: US$32.5 million) and is detailed in the
table below:
US$’000
Cash
Trade and other receivables
TANESCO
Songas
Industrial customers
Songas gas plant operations
Songas well workover program
Other receivables
Provision for doubtful accounts
Tax recoverable
Prepayments
Trade and other payables
TPDC share of Profit Gas (1)
Songas
Other trade payables
Deferred income
Accrued liabilities
Tax payable
Working capital (2)
2016
80,895
27,638
AS AT DECEMBER 31
2015
53,797
25,391
5,749
2,218
7,463
6,601
14,458
1,516
(10,367)
28,319
1,893
3,245
–
6,250
5,402
651
114,586
39,707
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
2,890
71,989
2,773
32,521
Notes
(1) Payable to TPDC for their share of profit gas reflects the total accrued liability based on gas delivered to TANESCO which has
not been paid for. Settlement of this liability is dependent on receipt of payment from TANESCO.
(2)
Working capital as at December 31, 2016 includes a TANESCO receivable (excluding interest) of US$5.7 million (2015: US$7.8
million). Management has recorded a provision for doubtful accounts against the long-term receivables totaling US$74.4
million (2015: US$61.9 million). The total of long and short-term TANESCO receivables as at December 31, 2016, including
interest and unrecorded revenue as a result of issued invoices not meeting revenue recognition criteria, was US$100.8 million.
The financial statements do not recognize the interest receivable from TANESCO as it does not meet revenue recognition
criteria. The Company is actively pursuing the collection of all the receivables including the interest that has been charged to
TANESCO.
Working capital as at December 31, 2016 increased by 121% over December 31, 2015 and by 6% during the quarter. The
increase is primarily a result of having drawn down the balance of the loan from the IFC and the paying down of creditors
associated with the 2015/2016 Offshore Development Program. 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 90% of the Company’s cash is held outside of Tanzania.
• Of the US$7.4 million relating to other trade debtors US$7.4 million had been received as at the date of this report.
The balance of US$28.3 million payable to TPDC represents the remaining balance of its accrued share of revenue as at
December 31, 2016. As a consequence of the contractual arrangements within the PSA, the settlement of the majority of
the liability is dependent upon the receipt of the TANESCO arrears.
management's discussion & analysis
24
LONG TERM LOAN
On October 29, 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 Company has drawn the US$60 million
Loan facility in full, with an initial drawdown of US$20 million on December 14, 2015 followed by an additional draw down
of US$40 million on February 9, 2016.
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 Loan is to be paid out through six semi-annual payments of US$5 million and one final payment
of US$30 million. 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. Subject to receipt of the IFC approval and 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. The Company must provide notice to the
IFC of the amount of any interest which is not to be paid on any interest payment date the unpaid interest is added to the
principal outstanding and may be paid out before or at the time of principal repayment. 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. The participatory interest survives the repayment and/or maturity of the Loan until October 15,
2026. No provision was made for the year ended December 31, 2016 as the 2016 net cash flow from operating activities less
the 2016 net cash used in investing activities is a negative amount. Dividends and distributions from PAET to the Company
are restricted at any time that any amounts of unpaid interest, principal or participating interest are outstanding.
SHAREHOLDERS’ EQUITY AND OUTSTANDING SHARE DATA
There were 34,856,432 shares outstanding as at December 31, 2016 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
Weighted average
Class A and Class B shares
Convertible securities
Options
Weighted average diluted Class A and Class B shares
AS AT DECEMBER 31
2016
2015
1,751
33,106
34,857
1,751
33,106
34,857
34,857
34,887
–
–
34,857
34,887
As at the date of this report, 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.
ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis 25
RELATED PARTY TRANSACTIONS
One of the non-executive Directors is counsel with a law firm that provides legal advice to the Company and its subsidiaries.
For the year ended December 31, 2016 US$0.2 million (2015: US$0.6 million) was incurred from this firm for services provided.
The former Chief Financial Officer provided services to the Company through a consulting agreement with a personal
services company until his resignation on November 2, 2015. For the period from January 1, 2015 to November 2, 2015,
US$0.4 million was incurred from this firm for services provided.
As at December 31, 2016 the Company has a total of US$0.1 million (2015: US$0.4 million) recorded in trade and other
payables in relation to the related parties.
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 (161.2 Bcf as at December
31, 2016). 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, TPDC and Songas (the “Re-Rating Agreement”) which
evidenced an increase to the gas processing capacity of the Songas facilities 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 paid additional compensation of US$0.30/mcf for sales between 70
MMcfd and 90 MMcfd and US$0.40/mcf for volumes above 90 MMcfd by issuing credit notes to TANESCO. This was in
addition to the tariff of US$0.59/mcf payable to Songas as set by the energy regulator, EWURA.
In May 2016 the Company notified TANESCO and Songas that the additional compensation for sales over 70 MMcfd would
no longer be paid effective June 2016. The additional compensation was always intended to be temporary in nature until the
expansion of the Songas infrastructure, at which time Songas would apply to EWURA to obtain approval of a new tariff for
the processing of volumes over 70 MMcfd. The PGSA provides for passing on to TANESCO any tariff to be charged to the
Company and in the event that a new tariff is approved.
The parties are seeking to resolve the status of the re-rating agreement. The processing capacity at the Songas facilities
remain unaltered and are fully utilized by the company. Without a new agreement, there are no assurances that Songas will
continue to allow the gas plant to operate above 70 MMcfd.
Portfolio Gas Supply Agreement
On June 17, 2011, a long term PGSA was signed (to June 2023) 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 36 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 July 1, 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 November 1, 2015 and expires on October 31, 2019 at an annual rent
of US$0.4 million. The agreement in Winchester expires on September 25, 2022 and is at an annual rental of US$0.1 million
per annum. The costs of these leases are recognized in the general and administrative expenses.
management's discussion & analysis 26
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 has 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 licence, 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 would 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.
CONTINGENCIES
Petroleum Act, 2016
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 Act 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 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 TPDC do not extend to mid and downstream petroleum supply operations. 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 and the Company is uncertain regarding the potential impact on its business in Tanzania.
On October 7, 2016, the Government of Tanzania issued the Petroleum (Natural Gas Pricing) Regulation made under Sections
165 and 258 (I) of the Act. Under the Act, Article 260 (3) preserves the Company’s pre-existing right with TPDC to market and
sell Additional Gas together or independently on terms and conditions (including prices) negotiated with third party Natural
Gas customers. The impact of the Natural Gas Pricing Regulation, if any, cannot be determined at this time.
ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis 27
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.
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$1.0 million from the Cost Pool. In 2015 and 2016 there were no further developments. Under the dispute
mechanism outlined in the PSA, TPDC are to appoint an independent specialist to assist the parties in reaching agreement
on costs that are still subject to dispute. At the time of writing this report no such specialist has been appointed. If the matter
is not resolved to the Company’s satisfaction, the Company intends to proceed to arbitration via the International Centre for
Settlement of Investment Disputes (“ICSID”) pursuant to the terms of the PSA.
Tax dispute
Disputed amount US$, million
Period
Reason for dispute
Principal
Interest
Total
Taxation
Area
PAYE
2008-10
WHT
2005-10
Income Tax
2008-15
Pay-As-You-Earn (“PAYE”) on grossed-up
amounts in staff salaries which are
contractually stated as net.
WHT on services performed outside of
Tanzania by non-resident persons.
Deductibility of capital expenditures and
expenses (2009 and 2012), additional
income tax (2008, 2010, 2011 and 2012),
tax on repatriated income (2012), foreign
exchange rate application (2013 and 2015)
and underestimation of tax due (2014).
VAT
2008-10
Output VAT on imported services
and SSI Operatorship services.
0.3
–
0.3(1)
1.1
16.8
2.7
20.9
0.7
10.1
2.9
13.7
1.8(2)
26.9(3)
5.6(4)
34.6
(1)
(2)
In 2015 PAET appealed the Tax Revenue Appeals Board (“TRAB”) ruling that PAET is liable to pay PAYE on grossed-up amounts
in staff salaries. TRAB waived interest assessed thereon. PAET is awaiting ruling of the Tax Revenue Appeals Tribunal (“TRAT”);
(a) 2005-2009 (US$1.7 million): In 2016 the TRA filed an application for review of the Court of Appeal decision in favour
of PAET and later filed another application for leave to amend its earlier application. At the Court of Appeal hearing
subsequent to year-end, TRA withdrew their second application for review. The Court has set April 27, 2017 for hearing
of the first application;
(b) 2010 (US$0.1 million): TRAB is awaiting a ruling from the review by 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): In 2015 TRAB ruled against PAET with respect to the deductibility of capital expenditures and
other expenses. PAET appealed to TRAT and is awaiting a hearing date to be scheduled ;
(b) 2008 and 2011 (US$2.1 million): In 2015 PAET filed objections against TRA assessments with respect to the deductibility
of capital expenditures and other expenses as well as underestimation of interest and is awaiting a response. Subsequent
to year-end, TRA rejected PAET’s objections for 2011 and undertook to issue a final assessment for the year. PAET
intends to appeal the assessment. The 2008 assessment was issued late and is time-barred;
(c) 2010 (US$2.6 million): PAET filed an appeal with TRAB against TRA assessment with respect to the deductibility of capital
expenditures and other expenses as well as underestimation of interest and penalty amounts. PAET is awaiting a hearing
date to be scheduled;
(d) 2013 (US$ 0.2 million): During the year PAET filed objections to TRA assessment with respect to foreign exchange rate
application and is awaiting a response;
management's discussion & analysis
28
(e) 2012 (US$16.3 million): During the year TRA issued two assessments with respect to understated revenue, deductibility
of capital expenditures and expenses, and tax on repatriated income. PAET filed an appeal with TRAB against the TRA
decision to deny PAET a waiver required for its objection to be admitted and is awaiting a hearing date to be scheduled;
(f)
2014 (US$3.5 million): During the year TRA issued an-assessment with respect to underestimation of tax due based on
the provisional quarterly payments made by PAET, delayed filings of returns and late payments. PAET filed objections to
the assessments and is awaiting a response;
(g) 2015 (US$0.4 million): During the year TRA issued a self-assessment. PAET filed an objection to the assessment with
respect to foreign exchange rate application and is awaiting a response;
(4)
During the year TRA responded to PAET’s objection filed in 2014 and issued an assessment in respect of output VAT on
imported services and SSI Operatorship services. PAET filed an appeal with TRAB against TRA assessment and is awaiting a
hearing date to be scheduled.
(5) On March 29, 2017, management received a tax audit findings report from TRA for the years 2012-14. The report requests
the Company to elaborate on the corporation tax, repatriated income, VAT and withholding tax. Management is preparing
its response and expects to submit it to TRA before the deadline of April 19, 2017.
Management, with the advice from its legal advisors, 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.
NEW ACCOUNTING POLICIES
At the date of these financial statements the standards and interpretations listed below were issued but not yet effective.
The adoption of these standards may result in future changes to existing accounting policies and disclosures. The Company
is currently evaluating the impact that these standards will have on results of operations and financial position.
In May 2014, the IASB issued IFRS 15 "Revenue from Contracts with Customers," which replaces IAS 18 "Revenue," IAS
11 "Construction Contracts," and related interpretations. The standard is required to be adopted either retrospectively or
using a modified transition approach for fiscal years beginning on or after January 1, 2018, with earlier adoption permitted.
The Company has commenced the process of identifying and reviewing sales contracts with customers to determine the
extent of the impact, if any, that this standard will have on the consolidated financial statements.
In July 2014, the IASB finalized the remaining elements of IFRS 9 – Financial Instruments, which includes new requirements
for the classification and measurement of financial assets, amends the impairment model and outlines a new general hedge
accounting standard. The mandatory effective date of IFRS 9 is for annual periods on or after January 1, 2018 and must be
applied retrospectively with some exemptions. Early adoption is permitted. The Company is evaluating the impact of this
standard on the consolidated financial statements and does not anticipate material changes to the valuation of its financial
assets.
In January 2016, the IASB issued IFRS 16 Leases, which replaces IAS 17 Leases. For lessees applying IFRS 16, a single
recognition and measurement model for leases would apply, with required recognition of assets and liabilities for most
leases. The standard will come into effect for annual periods beginning on or after January 1, 2019, with earlier adoption
permitted if the entity is also applying IFRS 15 Revenue from Contracts with Customers. The Company is currently identifying
contracts that will be identified as leases and evaluating the impact of the standard on the consolidated financial statements.
There are no other standards and interpretations in issue but not yet adopted that are expected to have a material effect on
the reported earnings or net assets of the Company.
ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis
29
SUMMARY QUARTERLY RESULTS OUTSTANDING
The following is a summary of the results for the Company for the last eight quarters:
Figures in US$’000 except
where otherwise stated
Financial
Revenue
Net income (loss)
Earnings (loss) per share
– basic and diluted (US$)
2016
2015
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
16,533
17,744
14,572
15,810
15,872
15,943
12,553
9,720
1,048
5,302
1,452
(5,638)
(6,468)
6,112
3,566
(1,677)
0.03
0.15
0.04
(0.16)
(0.19)
0.18
0.10
(0.05)
Cash flow from operations (1)
6,211
10,024
6,772
8,848
8,391
9,462
4,889
3,712
Cash flow from operations per share
– basic and diluted (US$)
Net cash flow from (used in)
operating activities
Net cash flows (utilized) per share
– basic and diluted (US$)
Operating netback (US$/mcf)
Working capital
Long-term loan
Shareholders’ equity
Capital expenditures
Geological and geophysical and well drilling
Pipeline and infrastructure
Other equipment
Operating
Additional Gas sold
– industrial (MMcf)
– industrial (MMcfd)
Additional Gas sold
– power (MMcf)
– power (MMcfd)
Average price per mcf
– industrial (US$)
Average price per mcf
– power (US$)
(1) See non-GAAP measures
0.18
0.29
0.19
0.25
0.24
0.27
0.14
0.11
8,345
6,540
6,237
(1,154)
5,450
(2,963)
(2,844)
7,375
0.24
3.35
0.19
3.31
0.18
3.32
(0.03)
3.08
0.16
3.03
(0.09)
(0.08)
2.65
2.68
0.21
1.86
71,989
67,635
58,395
56,340
32,521
39,660
38,067
34,870
58,399
58,398
58,368
58,350
18,599
–
–
–
80,023
79,153
73,887
72,482
78,154
84,476
78,480
74,944
32
99
–
26
(71)
–
2,558
13,639
23,099
7,578
4,135
181
102
356
1,382
2
59
547
150
275
47
984
155
–
1,226
1,238
1,151
13.3
13.5
12.6
972
10.7
1,089
11.8
2,895
3,047
2,521
3,241
3,483
31.5
33.1
27.7
35.6
37.9
1,137
11.9
3,127
34.5
1,015
11.1
925
10.3
3,041
3,494
33.4
38.8
7.52
7.60
7.64
8.15
7.62
7.67
7.45
7.54
3.57
3.57
3.55
3.55
3.56
3.62
3.47
3.49
management's discussion & analysis
30
PRIOR EIGHT QUARTERS
The Company’s revenue for the last six quarters has been reasonably consistent. The increase in revenue from Q2 2015
has been the consequence of the Offshore Development Program which commenced in Q3 2015 and was completed at
the end of Q1 2016. The capital costs associated with the program entitle the Company to a higher proportion of field net
revenue. The fall in revenue from Q3 2016 to Q4 2016 is the consequence of the Company only recognizing 80% of the
TANESCO invoiced amounts for revenue recognition purposes in Q4 2016.
Changes in net income over the last two years were negatively impacted by the impairment provisions relating to TANESCO.
In Q4 2015, Q1 2016, Q2 2016 and Q3 2016 doubtful debt provisions of US$9.8 million, US$8.0 million, US$3.5 million
and US$0.9 million respectively were provided against increased TANESCO arrears. Other significant factors affecting the
results were:
•
•
•
•
•
•
In Q1 2016 the Company took a charge of US$2.8 million for stock based compensation as a consequence of the share
price closing at CDN$4.14 compared to CDN$2.75 at the end of Q4 2015 together with the issuance of new Restrictive
Stock Units.
In Q2 2016 the Company had a decrease in the stock based compensation charge of US$0.7 million as the share price
closed at CN$3.40 at the end of the quarter.
In Q3 2016 the Company recorded a credit of US$0.1 million for stock based compensation compared to a credit of
US$1.1 million in Q3 2015.
In Q4 2016 the Company recorded a stock based compensation charge of US$0.6 million, as a consequence of an
increase in the closing share price to CDN$3.82 from CDN$3.41 at the end of Q3 2016,
In Q4 2016 the Company recognized 80% of the TANESCO invoiced amount for revenue recognition purposes in
accordance with the new estimation procedure which resulted in a net income reduction of US$1.3 million (see
"Operating Revenue").
The Company recorded an interest expense of US$1.6 million in the last three quarters of 2016 and US$1.0 million in Q1
2016.
Differences in cash flow from operations for the last six quarters were primarily a result of changes in revenue during the
periods. The decrease in cash flow from operations in Q4 2016 is a consequence of expensing indirect taxes associated with
sales invoices that have not been recorded in the financial statements because they do not meet the revenue recognition
criteria with respect to assurance of collectability. The increase in cash flow from operations to US$10.0 million in Q3 2016
from US$6.7 million in Q2 2016 is primarily the result of the US$3.3 million increase in revenue over the quarter. In Q2 and
Q1 of 2015, cash flow from operations decreased reflecting the drop in revenue during these periods due to declining well
production and lower Cost Pool levels reducing the Company’s share of revenues.
Changes in net cash flow from operating activities between quarters were primarily a result of the timing of receipt of
payments from TANESCO. The decrease in working capital from Q3 2015 to Q4 2015 was a consequence of the increase
in creditors associated with the workover and drilling program together with the additional bad debt provision against
TANESCO, both of which were offset by the initial draw down of US$18.6 million from the IFC (net of expenses). The
second draw down from the IFC of US$40 million in Q1 2016 has offset the decrease in working capital associated with the
completion of the workover and drilling program from Q4 2015 to Q1 2016. The progressive increase in working capital from
Q1 2016 is mainly the result of US$20.0 million in net cash flow from operating activities being offset by US$3.0 million of
capital expenditure over the same period.
Capital expenditure for the last four quarters Q4 2016 to Q1 2016 has amounted to US$16.9 million compared to US$38.4
million from Q4 2015 to Q3 2014. The 2015 workover and drilling program commenced in Q3 2015 with some preliminary
expenditure in Q2 2015 and was completed at the end of the second quarter 2016 with the demobilization of the rig.
ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis 31
The level of Industrial sales volumes increased in the four quarters ending Q4 2016 to an average of 1,146 MMcf (2015:
1,042 MMcf). Industrial sales volume for the four quarters ending Q4 2016 increased by 10% to 4,587 MMcf (12.5 MMcfd)
compared to 4,166 MMcf (11.4 MMcfd) in 2015. The increased volumes are primarily the result of fewer days of unscheduled
maintenance work by cement, textile and edible oil companies and consumption by new customers connected during the
first half of 2016.
The level of Power sales volumes decreased by 11% in the in the four quarters ending Q4 2016 to an average of 2,926 MMcf
(2015: 3,286 MMcf). Power sector sales volumes for the four quarters ending Q4 2016 decreased by 11% to 11,704 MMcf
(32.0 MMcfd) compared to 13,145 MMcf (36.0 MMcfd) in 2015. The decline is mainly the consequence of the decision by
TANESCO not to renew a contract with an emergency power plant, unscheduled maintenance at the Songo Ubungo Power
generation facility and the increased competition from gas suppliers within Tanzania.
SELECTED FINANCIAL INFORMATION
Selected annual financial information derived from the audited consolidated financial statements for the years ended
December 31, 2016, 2015 and 2014 is set out below:
Figures in US$’000 except per share amount
Revenue
Net cash flows from operating activities
Cash flow from operations (1)
Net income (loss)
Total assets
Earnings (loss) in US$ per share:
Basic and diluted
(1) See Non-GAAP measures
2016
64,659
19,968
31,855
2,164
226,532
2015
54,088
7,018
26,454
1,533
189,683
2014
56,607
29,757
32,412
(38,301)
198,492
0.06
0.04
(1.10)
Revenue increased by 20% to US$64.7 million in 2016 from US$54.1 million in 2015. The increase is primarily a consequence
of the Company being entitled to 85% of the net revenue in 2016 compared to 74% in 2015 following the increased costs
pools after the completion of the Offshore Development Program in 2016. The increase in revenue occurred even though
sales volumes were 10% lower in 2016 than 2015 and the weighted average price decreased 5% from US$4.49/mcf to
US$4.73/mcf. As a result, TPDC share of revenue decreased from US$17.3 million in 2015 to US$9.8 million in 2016.
The increased share of revenue contributed to the 20% increase in the cash flow from operations to US$31.9 million (2015:
US$26.5 million) and the 185% increase in net cash flow from operating activities to US$20 million (2015: US$7.0 million).
management's discussion & analysis 32
BUSINESS RISKS
Financing
The ability of the Company to meet its financing obligations or to arrange financing in the future will 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. The Company has been impacted by
TANESCO’s inability to pay for current deliveries and pay down arrears.
Prior to 2016 the Company had reached an understanding with TANESCO that it would continue to supply gas if TANESCO
remained reasonably current with payments for gas deliveries. As a result of TANESCO’s inability to fully pay all amounts
invoiced by the Company for the past few years, management of the Company has modified its approach to revenue
recognition as it relates to TANESCO only. Commencing on October 1, 2016 the Company will record 80% of the amounts
invoiced to TANESCO for revenue recognition purposes. The 80% amount was determined by comparison of TANESCO’s
historical payment history to the amounts invoiced by the Company over the past three years. Management believes this
approach provides the best estimate of TANESCO’s ability to pay and remain reasonably current and as well reflects the
economic reality of the situation. This results in a reduction in revenue recognized from the effective date.
The percentage used to recognize TANESCO revenue will be reviewed on at least a semi-annual basis, more frequently
if circumstances require and if there is a significant difference between the amount of revenue recorded and amounts
received, the percentage used to record revenue as well as any existing receivable or deferred revenue balance will be
revised accordingly.
At December 31, 2016 TANESCO owed the Company US80.1 million, excluding interest, (of which arrears were US$74.4
million) compared to US$69.8 million (including arrears of US$61.9 million) as at December 31, 2015. Current TANESCO
receivables as at December 31, 2016 amounted to US$5.7 million (2015 US$7.8 million). Since the year-end, TANESCO has
paid the Company US$12.9 million in 2017, and as at the date of this report the total TANESCO receivable is US$74.8 million
(of which US$74.4 million has been provided for). The amounts owed do not include interest billed to TANESCO or debtors
not meeting the revenue recognition criteria with respect to assurance of collectability.
As at December 31, 2016 Songas owed the Company US$23.3 million (2015: US$19.0 million), whilst the Company owed
Songas US$2.3 million (2015: US$2.6 million); there is no contractual right to offset these amounts. Amounts due to Songas
primarily relate to pipeline tariff charges of US$ 1.9 million (2015: US$1.1 million), whereas the amounts due to the Company
are mainly for capital expenditures of US$14.4 million (2015: US$11.2 million), sales of gas of US$2.2 million (2015: US$2.2
million) and for the operation of the gas plant of US$6.6 million (2015: US$5.6 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 December 31, 2016 the net amount owed by Songas to the Company was US$21.0 million (2015: US$16.4 million).
Although significant progress has been made in settling outstanding balances, a doubtful debt provision of US$9.8 million
(2015: 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 be pursued through the mechanisms
provided in the agreements with Songas.
ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis 33
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.
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 in the third quarter of 2015. 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.
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.
management's discussion & analysis 34
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 116 out of 176 on the 2016 Transparency International Corruption
Index. At the end of 2014 there was a significant corruption scandal in Tanzania’s energy sector involving a number of
senior government officials, including senior officials from MEM. Having assessed the Company’s exposure to corruption in
Tanzania, it was concluded that the risk of the Company and/ or its subsidiaries violating applicable laws prohibiting corrupt
activities are mitigated or unlikely given the Company’s controls relating to such risks and their effective operation. There
can be no assurance, however that corruption may indirectly affect or otherwise impair the Company’s ability to operate in
Tanzania and effectively pursue its business plan in that country.
The 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 monetization of the Company’s reserves through additional gas sales. The Government of Tanzania has completed
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 Company is currently negotiating 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
Although 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 realize 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 in 2013 and no new agreement is currently in place.
Without the Re-Rating Agreement Songas, the owner of the gas processing plant, may require the plant to be operated at
70 MMcfd (the capacity originally agreed to), which would result in a material reduction in the Company’s sales volumes of
Additional Gas.
ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis 35
The Petroleum Act, 2015
In the third quarter of 2015 the Tanzania Parliament passed the Petroleum Act, 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 PURA. The mid and downstream petroleum as well as gas activities
are proposed to be regulated by the current authority, EWURA.
The Act also confers upon on 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 and related impact on the Company.
On October 7, 2016, the Government of Tanzania issued the Petroleum (Natural Gas Pricing) Regulation made under
Sections 165 and 258 (I) of the Act. Article 260 (3) preserves the Company’s pre-existing right with TPDC to market and sell
Additional Gas together or independently on terms and conditions (including prices) negotiated with third party Natural Gas
customers. The impact of the Natural Gas Pricing Regulation, if any, cannot be determined at this time.
Amended and Restated Gas Agreement
The 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 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, 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 organizations 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.
management's discussion & analysis 36
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,
Songas and TPDC which includes the NNGIP. 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.
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 recognizes 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 recognized 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. Until the
Company is connected to the NNGIP, it has no redundant capacity in the production facilities or pipeline. A loss or material
reduction in production capabilities will have a material adverse effect on the total production and funds flow from operating
activities of the Company. The Company has an interest in the Elsa licence in Italy however changes in Italian environmental
legislation in late 2015 have resulted in the development of the Elsa Italian licence being postponed indefinitely.
ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis 37
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.
The Company’s petroleum and natural gas operations are subject to extensive governmental legislation and regulation and
increased public awareness concerning environmental protection.
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.
In accordance with the terms of the PSA, no provision has been recognized 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.
management's discussion & analysis 38
Uncertainties in Estimating Reserves and Future Net Cash Flows
There are numerous uncertainties inherent in estimating quantities of proved and probable reserves and cash flows to be
derived therefrom, including many factors beyond the control of the Company. The reserve and cash flow information
contained herein represents estimates only. The reserves and estimated future net cash flow from the Company’s properties
have been independently evaluated by McDaniel & Associates Consultants Ltd. These evaluations include a number of
assumptions relating to factors such as initial production rates, production decline rates, ultimate recovery of reserves,
timing and amount of capital expenditures, marketability of production, crude oil price differentials to benchmarks, future
prices of oil and natural gas, operating costs, transportation costs, cost recovery provisions and royalties, TPDC “back-in”
methodology and other government levies that may be imposed over the producing life of the reserves. These assumptions
were based on price forecasts in use at the date of the relevant evaluations were prepared and many of these assumptions
are subject to change and are beyond the control of the Company. Actual production and cash flows derived therefrom will
vary from these evaluations, and such variations could be material.
Title to Properties
Although title reviews have been done and will continue to be done according to industry standards prior to the purchase
of most oil and natural gas producing properties or the commencement of drilling wells, such reviews do not guarantee or
certify that an unforeseen defect in the chain of title will not arise to defeat the claim of the Company which could result in
a reduction of the revenue received by the Company.
Acquisition Risks
The Company intends to acquire natural gas infrastructure and possibly additional oil and gas properties. Although the
Company performs a review of the acquired properties that it believes is consistent with industry practices, such reviews are
inherently incomplete. It generally is not feasible to review in depth every individual property involved in each acquisition.
Ordinarily, the Company will focus its due diligence efforts on the higher valued properties and will sample the remainder.
However, even an in depth review of all properties and records may not necessarily reveal existing or potential problems,
nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities.
Inspections may not be performed on every well, and structural or environmental problems, such as ground water
contamination, are not necessarily observable even when an inspection is undertaken. The Company may be required to
assume pre-closing liabilities, including environmental liabilities, and may acquire interests in properties on an “as is” basis.
There can be no assurance that the Company’s acquisitions will be successful.
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. | 2016 ANNUAL REPORTManagement’s Discussion & Analysis 39
CRITICAL ACCOUNTING ESTIMATES AND JUDGEMENTS
The following are the critical judgements, apart from those involving estimations (see below), that management has made
in the process of applying the Company’s accounting policies and that have the most significant effect on the accounts
recognized in these consolidated financial statements.
Critical judgements in applying accounting policies:
A. 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.
B. 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. As a result of TANESCO’s inability to fully pay all
amounts invoiced by the Company for the past few years, management of the Company has modified its approach to
revenue recognition as it relates to TANESCO only. Commencing on October 1, 2016 the Company will record 80% of
the amounts invoiced to TANESCO for revenue recognition purposes. The 80% amount was determined by comparison
of TANESCO’s historical payment history to the amounts invoiced by the Company over the past three years. This results
in a reduction in revenue recognized from the effective date.
The percentage used to recognize TANESCO revenue will be reviewed on at least a semi-annual basis, more frequently
if circumstances require and if there is a significant difference between the amount of revenue recorded and amounts
received, the percentage used to record revenue as well as any existing receivable or deferred revenue balance will be
revised accordingly.
C. Taxes
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.
Deferred tax assets (if any) are recognized only to the extent it is considered probable that those assets will be recoverable.
This involves an assessment of when those deferred tax assets are likely to reverse and a judgment as to whether or not
there will be sufficient taxable profits available to offset the tax assets when they do reverse. This requires assumptions
regarding future profitability and is therefore inherently uncertain. To the extent assumptions regarding future profitability
change, there can be an increase or decrease in the amounts recognized in respect of deferred tax assets as well as the
amounts recognized in profit or loss in the period in which the change occurs.
management's discussion & analysis
40
Key sources of estimation of uncertainty
D. 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 evaluated by 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 December 31, 2016 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.
E. 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.
F. 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.
G. 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. | 2016 ANNUAL REPORTORCA EXPLORATION GROUP INC.Management’s Discussion & Analysis
2016
FINANCIAL
STATEMENTS
& NOTES
ORCA EXPLORATION GROUP INC. 42
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 authorized, 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
April 12, 2017
Blaine E. Karst
Chief Financial Officer
April 12, 2017
ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORT
Independent Auditors’ Report
43
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, 2016 and December 31, 2015, the consolidated statements
of comprehensive income, 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 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, 2016 and December 31, 2015 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
April 12, 2017
Calgary, Canada
financial statements 44
Consolidated Statements of Comprehensive Income
ORCA EXPLORATION GROUP INC.
US$’000
Revenue
Production and distribution
Net production revenue
Operating expenses
General and administrative
Depletion
Operating income
Finance income
Finance expense
Income before tax
Income tax – current
Income tax – deferred
Net income
Foreign currency translation (loss) gain from foreign operations
Comprehensive income
Net income per share (US$)
Basic and diluted
See accompanying notes to the consolidated financial statements.
Note
6, 7
9
9
10
10
YEARS ENDED DECEMBER 31
2016
2015
64,659
(4,033)
60,626
(16,337)
(9,191)
35,098
383
(19,937)
15,544
(9,719)
(3,661)
2,164
(295)
1,869
54,088
(3,751)
50,337
(13,608)
(11,855)
24,874
43
(13,988)
10,929
(7,691)
(1,705)
1,533
144
1,677
17
0.06
0.04
ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORT Consolidated Statements of Financial Position
45
ORCA EXPLORATION GROUP INC.
US$’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
Additional Profits Tax
Total Liabilities
Equity
Capital stock
Contributed surplus
Accumulated other comprehensive loss
Accumulated loss
Total equity and liabilities
AS AT DECEMBER 31
Note
2016
2015
12
10
12
13
14
10
15
11
80,895
27,638
5,402
651
53,797
25,391
4,519
1,118
114,586
84,825
525
584
111,421
104,274
111,946
104,858
226,532
189,683
39,707
2,890
42,597
12,973
58,399
32,540
103,912
146,509
49,531
2,773
52,304
9,312
18,599
31,314
59,225
111,529
16
85,488
85,488
6,347
(381)
(11,431)
80,023
6,347
(86)
(13,595)
78,154
226,532
189,683
See accompanying notes to the consolidated financial statements.
Nature of Operations (Note 1); Contractual obligations and committed capital investment (Note 19); Contingencies
(Note 20). The consolidated financial statements were approved by the Board of Directors on April 12, 2017.
Director
Director
financial statements
46
Consolidated Statements of Cash Flows
ORCA EXPLORATION GROUP INC
US$’000
Operating activities
Net Income
Adjustment for:
Depletion and depreciation
Provision for doubtful accounts
Stock-based compensation (recovery)
Deferred income taxes
Additional Profits Tax
Unrealized gain on foreign exchange
Interest expense
Change in non-cash working capital
Net cash flow from operating activities
Investing activities
Property, plant and equipment expenditures
Change in working capital related to investing activities
Net cash used in investing activities
Financing activities
Interest paid
Increase in long-term loan
Normal course issuer bid repurchases
Net cash flow from financing activities
Increase (decrease) in cash
Cash and cash equivalents at the beginning of the year
Effect of change in foreign exchange on cash for the year
Cash and cash equivalents at the end of the year
See accompanying notes to the consolidated financial statements.
YEARS ENDED DECEMBER 31
Note
2016
2015
2,164
1,533
13
9
16
10
11
9
13
9
15
16
9,777
14,245
1,604
3,661
1,226
(822)
5,668
(17,555)
19,968
(16,924)
(10,685)
(27,609)
(5,668)
39,800
–
34,132
26,491
53,797
607
80,895
12,555
9,908
(244)
1,705
2,355
(1,358)
117
(10,553)
7,018
(38,411)
8,461
(29,950)
(117)
18,599
(158)
18,324
(4,608)
57,659
746
53,797
ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORT
Consolidated Statements of Changes
in Shareholders’ Equity
47
ORCA EXPLORATION GROUP INC.
US$’000
Note
Capital stock
Contributed
surplus
Cumulative
translation
adjustment
Accumulated
loss
Total
16
Balance as at January 1, 2016
85,488
6,347
(86)
(13,595)
78,154
Foreign currency translation
adjustment on foreign operations
Net income
–
–
–
–
Balance as at December 31, 2016
85,488
6,347
(295)
–
(381)
–
2,164
(295)
2,164
(11,431)
80,023
US$’000
Note
Balance as at January 1, 2015
Normal course issuer bid exercise
Foreign currency translation
adjustment on foreign operations
Net income
Capital stock
Contributed
surplus
Cumulative
translation
adjustment
Accumulated
loss
Total
16
85,637
(149)
–
–
6,356
(9)
–
–
(230)
–
144
–
(86)
(15,128)
76,635
–
–
1,533
(158)
144
1,533
(13,595)
78,154
Balance as at December 31, 2015
85,488
6,347
See accompanying notes to the consolidated financial statements.
financial statements 48
General Information
Orca Exploration Group Inc. was incorporated on April 28, 2004 under the laws of the British Virgin Islands with
registered offices located at PO Box 146, Road Town, Tortola, British Virgin Islands, VG110 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 December 31, 2016 comprise
accounts of the Company and all its wholly owned subsidiaries (collectively, the “Company” or “Orca Exploration”)
and were authorized for issue in accordance with a resolution of the directors on April 12, 2017.
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 (“Gas Agreement”) 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.
ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTNotes to the Consolidated Financial Statements 49
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$”).
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”).
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
PanAfrican Energy Tanzania Limited
Orca Exploration UK Services Limited
British Virgin Islands
British Virgin Islands
British Virgin Islands
Mauritius
Jersey
United Kingdom
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 unrealized gains or losses arising from inter-company transactions,
are eliminated in preparing the consolidated financial statements.
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
Foreign currency differences are recognized in comprehensive income and accumulated in the translation
reserve. The assets and liabilities of these companies are translated into the functional currency at the period-end
exchange rate. The income and expenses of the companies are translated into the functional currency at the
average exchange rate for the period. Translation gains and losses are included in other comprehensive income.
notes 50
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.
Exploration and evaluation assets, property plant and equipment
i)
Exploration and evaluation assets
Exploration and evaluation costs are capitalized as intangible assets. Intangible assets include 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 techno-
logically 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 capitalized. The cost associated with tangible natural gas assets are amortized
on a field by field unit of production method based on commercial proven reserves. The calculation of the unit
of production amortization takes into account the estimated future development cost associated with proven
reserves.
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 recognized for the CGU in prior years. A reversal of an impairment loss is recognized
in earnings.
ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTNotes to the Consolidated Financial Statements
51
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.
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 recognized 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, and the estimate of the level of forfeiture. .
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
income 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.
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.
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 recognizes 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.
notes 52
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.
Prior to 2016 the Company had reached an understanding with TANESCO that it would continue to supply gas if
TANESCO remained reasonably current with payments for gas deliveries. As a result of TANESCO’s inability to fully
pay all amounts invoiced by the Company for the past few years, management of the Company has modified its
approach to revenue recognition as it relates to TANESCO only. Commencing on October 1, 2016 the Company
will record 80% of the amounts invoiced to TANESCO for revenue recognition purposes. The 80% amount was
determined by comparison of TANESCO’s historical payment history to the amounts invoiced by the Company over
the past three years. Management believes this approach provides the best estimate of TANESCO’s ability to pay and
remain reasonably current and as well reflects the economic reality of the situation. This results in a reduction in
revenue recognized from the effective date (see Notes 4 and 7).
For cash received in excess of the revenue recorded from TANESCO in any given period, the additional amounts
received will be recorded as deferred revenue. In periods when cash received is less than revenue recorded, the
deferred revenue will be reduced accordingly. If the deferred revenue amount is reduced to nil, the difference will be
recorded as accounts receivable.
The percentage used to recognize TANESCO revenue will be reviewed on at least a semi-annual basis, more
frequently if circumstances require and if there is a significant difference between the amount of revenue recorded
and amounts received, the percentage used to record revenue as well as any existing receivable or deferred revenue
balance will be revised accordingly.
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 program.
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.
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 realization or settlement of carrying amounts of assets and liabilities using tax rates substantively
enacted at the balance sheet date. A deferred tax asset is recognized only to the extent that it is probable that future
taxable profits will be available, against which the asset can be utilized. Deferred tax assets are reduced to the extent
that it is no longer probable that the related tax benefits will be realized.
ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTNotes to the Consolidated Financial Statements 53
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
Computer equipment
Vehicles
Fixtures and fittings
Over remaining life of the lease
3 years
3 years
3 years
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.
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%.
notes 54
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.
New accounting standards and interpretations
At the date of these financial statements the standards and interpretations listed below were issued but not yet
effective. The adoption of these standards may result in future changes to existing accounting policies and disclosures.
The Company is currently evaluating the impact that these standards will have on results of operations and financial
position.
In May 2014, the IASB issued IFRS 15 "Revenue from Contracts with Customers," which replaces IAS 18 "Revenue," IAS
11 "Construction Contracts," and related interpretations. The standard is required to be adopted either retrospectively
or using a modified transition approach for fiscal years beginning on or after January 1, 2018, with earlier adoption
permitted. The Company has commenced the process of identifying and reviewing sales contracts with customers
to determine the extent of the impact, if any, that this standard will have on the consolidated financial statements.
In July 2014, the IASB finalized the remaining elements of IFRS 9 – Financial Instruments, which includes new
requirements for the classification and measurement of financial assets, amends the impairment model and outlines
a new general hedge accounting standard. The mandatory effective date of IFRS 9 is for annual periods on or
after January 1, 2018 and must be applied retrospectively with some exemptions. Early adoption is permitted. The
Company is evaluating the impact of this standard on the consolidated financial statements and does not anticipate
material changes to the valuation of its financial assets.
In January 2016, the IASB issued IFRS 16 Leases, which replaces IAS 17 Leases. For lessees applying IFRS 16, a single
recognition and measurement model for leases would apply, with required recognition of assets and liabilities for
most leases. The standard will come into effect for annual periods beginning on or after January 1, 2019, with earlier
adoption permitted if the entity is also applying IFRS 15 Revenue from Contracts with Customers. The Company
is currently identifying contracts that will be identified as leases and evaluating the impact of the standard on the
consolidated financial statements.
There are no other standards and interpretations in issue but not yet adopted that are expected to have a material
effect on the reported earnings or net assets of the Company.
ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTNotes to the Consolidated Financial Statements 55
4
USE OF ESTIMATES AND JUDGEMENTS
The following are the critical judgements, apart from those involving estimations (see below), that management has
made in the process of applying the Company’s accounting policies and that have the most significant effect on the
accounts recognized in these consolidated financial statements.
Critical judgements in applying accounting policies:
A. 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
reserves. The unit-of-production method takes into account estimates of capital expenditures incurred to date
along with future development capital required to develop the proved reserves.
B. 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.
Prior to 2016 the Company had reached an understanding with TANESCO that it would continue to supply gas
if TANESCO remained reasonably current with payments for gas deliveries. As a result of TANESCO’s inability
to fully pay all amounts invoiced by the Company for the past few years, management of the Company has
modified its approach to revenue recognition as it relates to TANESCO only. Commencing on October 1, 2016
the Company will record 80% of the amounts invoiced to TANESCO for revenue recognition purposes. The
80% amount was determined by comparison of TANESCO’s historical payment history to the amounts invoiced
by the Company over the past three years. Management believes this approach provides the best estimate
of TANESCO’s ability to pay and remain reasonably current and as well reflects the economic reality of the
situation. This results in a reduction in revenue recognized from the effective date (see Notes 7 and 12).
C. Taxes
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.
Deferred tax assets (if any) are recognized only to the extent it is considered probable that those assets will be
recoverable. This involves an assessment of when those deferred tax assets are likely to reverse and a judgment
as to whether or not there will be sufficient taxable profits available to offset the tax assets when they do
reverse. This requires assumptions regarding future profitability and is therefore inherently uncertain. To the
extent assumptions regarding future profitability change, there can be an increase or decrease in the amounts
recognized in respect of deferred tax assets as well as the amounts recognized in profit or loss in the period in
which the change occurs.
notes 56
Key sources of estimation of uncertainty
D. 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 evaluated by 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 December 31, 2016 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 date of the consolidated financial statements, TPDC
has made no such election.
Reserves are integral to the amount of depletion and impairment test.
E.
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.
F. 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 field revenue less processing and pipeline tariffs (“field 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.
G. 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. | 2016 ANNUAL REPORTNotes to the Consolidated Financial Statements 57
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 recognized 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 unrestricted, 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.
Capital stock, equity financing and any associated stock based compensation are denominated in Canadian
dollars. The operational revenue and the majority of capital expenditures 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 decrease in
working capital (defined as current assets less current liabilities) of US$0.7 million to US$71.3 million and an
increase in the income before tax to US$16.2 million. The sensitivity includes only outstanding foreign currency
denominated monetary items and adjusts their translation at period end for a 10% change in the foreign currency
rates. A 10% sensitivity rate is used when reporting foreign currency risk internally to key management personnel
and represents management’s assessment of the reasonable possible change in foreign exchange rates.
The following balances are denominated in foreign currency (stated in US dollars at period end exchange rates):
Balances as at December 31, 2016
US$’000
Cash
Trade and other receivables
Trade and other payables
Canadian
dollars
Tanzanian
shillings
Euros
Other
0.1
–
(3.3)
(3.2)
7.6
8.1
(4.4)
11.3
1.1
0.7
(0.1)
1.7
0.4
0.8
(1.0)
0.2
Total
9.2
9.6
(8.8)
10.0
B. Commodity price risk
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.
notes 58
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 at December 31, 2016 and 2015, other than the provisions against the long-term TANESCO
receivable, the provision for gas plant operations charges and capital expenditure receivables from Songas and
the provision of US$ 0.4 million for two industrial customers, 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 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 53% of the Company’s gross field revenue during 2016 and
US$3.8 million of the short and long-term receivables prior to provision at year-end.
TANESCO continues to have difficulties paying invoices in full. As a result, management has placed a provision
for doubtful accounts against arrears due from TANESCO in the amount of US$74.4 million as at December 31,
2016 (2015: US$61.9 million). Based on a review of the TANESCO payment history in October 2016, Management
revised its estimate for collectability of revenue for sales to TANESCO (see Notes 7 and 12).
Sales to the Industrial sector 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$39.7 million of financial liabilities with regards to trade and other payables of which US$38.8
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 14). As at year-end the Company had a current tax liability of US$2.9 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; in accordance with the terms of the PSA TPDC is entitled to the payment of its
share of Profit Gas, on a quarterly basis in relation to the cash receipts during the quarter. 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.
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
optimization 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$21
million in Cost Gas revenue. In response to a Notice of Dispute delivered by the Company in March 2014, TPDC
retracted the allegation and no further action has been taken by Parliament or the Government against the
Company related to the allegations. Accordingly, the Company continues to rely upon its rights under the existing
PSA and has initiated notices of dispute to resolve any remaining issues. The Company has put in place an advisory
committee of experienced individuals with significant experience working with the Tanzanian government to
mitigate the risks of doing business in Tanzania.
ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTNotes to the Consolidated Financial Statements 59
6
SEGMENT INFORMATION
The Company has one reportable industry segment which is international exploration, development and production
of petroleum and natural gas. The Company currently has producing and exploration assets in Tanzania and had
exploration and appraisal interests in Italy.
US$’000
External revenue
Segment income (loss)
Non-cash charge (1)
Depletion & depreciation
Capital additions
Total assets
Total liabilities
2016
2015
Italy
Tanzania
Total
Italy
Tanzania
Total
–
(100)
–
–
–
1,477
102
64,659
2,264
64,659
2,164
(14,245)
(14,245)
9,777
16,924
9,777
16,924
–
(167)
–
–
–
54,088
54,088
1,700
(9,908)
12,555
38,411
1,533
(9,908)
12,555
38,411
225,055
226,532
1,621
188,062
189,683
146,407
146,509
131
111,398
111,529
(1)
Non-cash charge represent amounts provided for doubtful accounts receivable from TANESCO and indirect taxes expensed
directly to the statement of comprehensive income.
notes
60
7
REVENUE
US$’000
Industrial sector
Power sector
Gross field revenue
Processing and transportation tariff
Field net revenue
TPDC share of revenue
Company operating revenue
Additional Profits Tax charge
Current income tax adjustment
Revenue
YEARS ENDED DECEMBER 31
2016
2015
35,626
39,751
75,377
(10,057)
65,320
(9,798)
55,522
(1,226)
10,363
64,659
33,164
46,721
79,885
(12,282)
67,603
(17,349)
50,254
(2,355)
6,189
54,088
The Company’s reported revenues for the year amounted to US$64.7 million after adjusting the Company’s operating
revenue of US$55.5 million by:
i)
Adding US$10.4 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%; and,
ii)
Subtracting US$1.2 million for deferred Additional Profits Tax charged in the year. This tax is considered a royalty
and is presented as a reduction in revenue.
Prior to 2016 the Company had reached an understanding with TANESCO that it would continue to supply gas if
TANESCO remained reasonably current with payments for gas deliveries. As a result of TANESCO’s inability to fully
pay all amounts invoiced by the Company for the past few years, management of the Company has modified its
approach to revenue recognition as it relates to TANESCO only. Commencing on October 1, 2016 the Company
will record 80% of the amounts invoiced to TANESCO for revenue recognition purposes. The 80% amount was
determined by comparison of TANESCO’s historical payment history to the amounts invoiced by the Company over
the past three years. Management believes this approach provides the best estimate of TANESCO’s ability to pay and
remain reasonably current and as well reflects the economic reality of the situation. This results in a reduction in
revenue recognized from the effective date
For cash received in excess of the revenue recorded from TANESCO in any given period, the additional amounts
received will be recorded as deferred revenue. In periods when cash received is less than revenue recorded, the
deferred revenue will be reduced accordingly. If the deferred revenue amount is reduced to nil, the difference will be
recorded as accounts receivable.
The percentage used to recognize TANESCO revenue will be reviewed on at least a semi-annual basis, more
frequently if circumstances require and if there is a significant difference between the amount of revenue recorded
and amounts received, the percentage used to record revenue as well as any existing receivable or deferred revenue
balance will be revised accordingly.
As a result of recording revenue based on the expected collectability from the effective date, there is the following
impact on the 2016 results:
1) US$1.6 million decrease in revenue,
2) US$1.3 million decrease in long-term receivables, allowance for doubtful accounts,
3) US$0.6 million decrease in current accounts receivable,
4) US$0.3 million decrease in net income and current liabilities.
ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTNotes to the Consolidated Financial Statements 8
PERSONNEL EXPENSES
Personnel costs are as follows:
US$’000
Wages and salaries
Social security costs
Other statutory costs
Stock based compensation
61
YEARS ENDED DECEMBER 31
2016
2015
10,589
629
284
11,502
2,591
14,093
9,037
876
207
10,120
(244)
9,876
Stock based compensation is recorded under general and administrative expenses in the statement of comprehensive
income. The balance of personnel expenses for 2016 of US$11.5 million (2015: US$10.1 million) is recorded in
distribution and production expenses and general administrative expenses at US$2.6 million (2015: US$1.9 million)
and US$8.9 million (2015: US$8.0 million) respectively. Personnel expenses include Company employees who
operate the plant on behalf of Songas, these expenses are recharged to Songas.
9
NET FINANCE EXPENSE
US$’000
Finance income
Interest expense
Net foreign exchange loss
Financing fee
Indirect tax
Provision for doubtful accounts
Finance expense
Net finance expense
YEARS ENDED DECEMBER 31
2016
383
(5,668)
(24)
–
(1,392)
(12,853)
(19,937)
(19,554)
2015
43
(117)
(2,677)
(16)
–
(11,178)
(13,988)
(13,945)
The total amount of interest paid in 2016 was US$5.7 million (2015: US$0.1 million). During 2016 the Company invoiced
TANESCO US$4.2 million of interest for late payments (2015: US$2.4 million). 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 recognized in earnings when collected.
The US$1.4 million is in relation to indirect taxation associated with trade receivables not recognized in the financial
statements due to IFRS revenue recognition criteria with respect to assurance of collectability. The provision for
doubtful accounts includes US$12.4 million for overdue TANESCO receivables (2015: US$9.9 million), US$ nil relates
to Songas receivables (2015: US$1.3 million) and US$0.4 million relates to Industrial customers (2015: US$0.1 million).
notes 62
10
INCOME TAXES
The tax charge is as follows:
US$’000
Current tax
Deferred tax expense
YEARS ENDED DECEMBER 31
2016
9,719
3,661
13,380
2015
7,691
1,705
9,396
Tax of US$1.2 million was paid during the year in relation to the settlement of the prior year’s tax liability (2015: US$3.0
million). In addition, provisional tax payments totaling US$8.3 million were made in respect of the current year (2015:
US$6.9 million). These are presented as a reduction in tax payable on the statement of financial position.
Tax rate reconciliation
US$’000
Income 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
Stock-based compensation (recovery)
TANESCO interest not recognized as interest income (Note 9)
Unrecognized tax asset
Other permanent differences
YEARS ENDED DECEMBER 31
2016
15,544
4,663
1,343
48
777
1,062
5,445
42
13,380
2015
10,929
3,279
1,552
199
(73)
714
2,930
795
9,396
As at December 31, 2016, the provision for doubtful debt from TANESCO has resulted in a US$23.1 million unrecognized
deferred tax asset (2015: US$17.6 million). If this amount was ultimately not recovered, the Company would also be
entitled to a US$13.9 million recovery of Value Added Tax.
A deferred tax asset of US$2.2 million in respect of Longastrino Italy exploration and evaluation costs has not been
recognized because it is not probable that there will be future profits against which this can be utilized (2015: US$2.2
million).
ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTNotes to the Consolidated Financial Statements
63
The deferred income tax liability includes the following temporary differences:
US$’000
AS AT DECEMBER 31
2016
2015
Differences between tax base and carrying value of property, plant and equipment
(21,563)
(18,185)
Tax recoverable from TPDC
Provision for doubtful debt
Deferred Additional Profits Tax
Unrealized exchange losses/other provisions
(4,142)
3,110
9,787
(165)
(12,973)
(3,442)
2,987
9,394
(66)
(9,312)
Tax recoverable
The Company has a tax recoverable balance of US$5.4 million (2015: US$4.5 million). This arises from the revenue
sharing mechanism within the PSA, which entitles the Company to recover from TPDC, by way of a deduction
from TPDC’s Profit Gas share an amount equal to the actual income taxes payable by the Company. The recovery,
by deduction from TPDC’s share of revenue, is dependent upon payment of income taxes relating to prior period
adjustment factors as they are assessed.
US$’000
Tax recoverable
11
ADDITIONAL PROFITS TAX
AS AT DECEMBER 31
2016
5,402
2015
4,519
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 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 18.8% (2015: 20.2%) has been applied to Profit Gas of US$6.5 million
(2015: US$11.6 million). Accordingly, US$1.2 million has been netted off revenue for the year ended December 31,
2016 (2015: US$2.4 million).
notes 64
12
TRADE AND OTHER RECEIVABLES
Current receivables
US$’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 DECEMBER 31
2016
2015
5,749
2,218
7,463
7,831
2,178
6,894
15,430
16,903
6,601
14,458
1,516
(10,367)
12,208
27,638
5,631
11,209
1,604
(9,956)
8,488
25,391
AS AT DECEMBER 31, 2016
>90
–
–
780
780
Total
5,749
2,218
7,463
15,430
AS AT DECEMBER 31, 2015
>90
–
–
821
821
Total
7,831
2,178
6,894
16,903
Current
>30 <60
>60 <90
2,570
1,190
2,769
6,529
2,559
1,028
3,679
7,266
620
–
235
855
Current
>30 <60
>60 <90
3,972
1,082
3,317
8,371
3,859
1,096
1,859
6,814
–
–
897
897
ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTNotes to the Consolidated Financial Statements 65
TANESCO
At December 31, 2016 TANESCO owed the Company US$80.1 million excluding interest (including arrears of
US$74.4 million) compared to US$69.8 million (including arrears of US$61.9 million) as at December 31, 2015. Current
TANESCO receivables as at December 31, 2016 amounted to US$5.7 million (2015 US$7.8 million). Since the year-end,
TANESCO has paid the Company US$12.9 million, and as at the date of this report the total TANESCO receivable is
US$74.8 million (of which US$74.4 million has been provided for). The amounts owed do not include interest billed
to TANESCO or debtors not meeting the revenue recognition criteria with respect to assurance of collectability (see
Note 7).
To September 30, 2016 the Company classified US$12.4 million as a long-term receivable and placed a full provision
against this amount. The total provision was US$74.4 million (2015: US$ 61.9 million) at December 31, 2016.
Long-term receivables
US$’000
TANESCO receivable
Provision for doubtful accounts
Net TANESCO receivable
VAT bond
Lease deposit
Long-term receivables
AS AT DECEMBER 31
2016
2015
74,361
61,922
(74,361)
(61,922)
–
318
207
525
–
332
252
584
Songas
As at December 31, 2016 Songas owed the Company US$23.3 million (2015: US$19.0 million), whilst the Company
owed Songas US$2.3 million (2015: US$2.6 million); there is no contractual right to offset these amounts. Amounts
due to Songas primarily relate to pipeline tariff charges of US$ 1.9 million (2015: US$1.1 million), whereas the amounts
due to the Company are mainly for capital expenditures of US$14.4 million (2015: US$11.2 million), sales of gas of
US$2.2 million (2015: US$2.2 million) and for the operation of the gas plant of US$6.6 million (2015: US$5.6 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 December 31, 2016 the net amount owed by Songas to the Company was US$21.0 million (2015: US$16.4
million). Although significant progress has been made in settling outstanding balances, a doubtful debt provision
of US$9.8 million (2015: US$9.8 million) is necessary recognizing the possible settlement of the remaining overdue
operatorship charges and the Songas share of the well workover costs. Any significant amounts not agreed will likely
be pursued through the mechanisms provided in the agreements with Songas. All amounts due to and from Songas
have been summarized in the table below:
Pipeline tariff – payable
Gas sales – receivable
Gas plant operation receivable
Workover program
Other payable
Net balances
January
1, 2016
Year to date
transactions
Gross
balance
December
31, 2016
Post
year-end
payments
and receipts
Outstanding
as at the date
of this report
(1,071)
2,178
5,631
11,209
(1,546)
16,401
(822)
40
970
3,249
1,168
4,605
(1,893)
2,218
6,601
14,458
(378)
21,006
1,893
(2,218)
(1,465)
–
–
–
–
5,136
14,458
(378)
(1,736)
19,270
notes 66
13
PROPERTY, PLANT AND EQUIPMENT
US$’000
Costs
Oil & natural
gas interests
Leasehold
improvements
Computer
equipment
Vehicles
Fixtures &
fittings
Total
As at January 1, 2016
Additions
As at December 31, 2016
178,808
16,816
195,624
Accumulated depletion and depreciation
As at January 1, 2016
Depletion and depreciation
As at December 31, 2016
Net book values
75,389
9,191
84,580
As at December 31, 2016
111,044
699
–
699
345
281
626
73
1,341
25
1,366
1,168
136
1,304
62
297
83
380
168
81
249
131
1,125
182,270
–
16,924
1,125
199,194
926
88
1,014
77,996
9,777
87,773
111
111,421
US$’000
Costs
Oil & natural
gas interests
Leasehold
improvements
Computer
equipment
Vehicles
Fixtures &
fittings
Total
As at January 1, 2015
Additions
As at December 31, 2015
140,653
38,155
178,808
Accumulated depletion and depreciation
As at January 1, 2015
Depletion and depreciation
As at December 31, 2015
63,534
11,855
75,389
Net book values
699
–
699
170
175
345
1,233
108
1,341
955
213
1,168
149
148
297
120
48
168
1,125
143,859
–
38,411
1,125
182,270
662
264
926
65,441
12,555
77,996
As at December 31, 2015
103,419
354
173
129
199
104,274
In determining the depletion charge, it is estimated that future development costs of US$84.0 million (2015: US$103.8
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 completion of the SS-12 development well 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 licence. During the year the Company recorded depreciation
of US$0.6 million (2015: US$0.7 million) in general and administrative expenses.
ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTNotes to the Consolidated Financial Statements 14
TRADE AND OTHER PAYABLES
US$’000
Songas
Other trade payables
Trade payables
TPDC share of Profit Gas
Deferred income
Accrued liabilities
15
LONG-TERM LOAN
67
AS AT DECEMBER 31
2016
1,893
3,245
5,138
28,319
–
6,250
39,707
2015
1,071
11,234
12,305
28,208
667
8,351
49,531
On October 29, 2015, the Company’s subsidiary, PanAfrican Energy Tanzania Limited (“PAET”), entered into a loan
agreement (“Loan”) with the International Finance Corporation (“IFC”), a member of the World Bank Group, for US$60
million.
The term of the Loan is ten years, with no 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$30 million. The guarantee
may only be called upon by IFC at maturity in 2025 and, subject to IFC approval and receipt of all required regulatory
approvals, the Company may issue shares in fulfillment of all or part of the guarantee obligation in 2025.
Base interest on the Loan is payable quarterly at 10% per annum on a ‘pay-if-you-can-basis’ using a formula to
calculate the net cash available for such payments as at any given interest payment date. To date, all interest incurred
has been paid. In addition, an annual variable participatory interest equating to 7% of the net cash flow from operating
activities of PAET net of net cash flow used in investing activities in respect of any given year. Such participatory
interest will continue until October 15, 2026 regardless whether the Loan is repaid prior to its contractual maturity
date. No provision was made for the year ended December 31, 2016 as the current cash flow from operating activities
less cash flow used in investing activities for 2016 is a negative amount. Dividends and distributions from PAET to
the Company are restricted at any time that any amounts of unpaid interest, principal or participating interest are
outstanding.
US$’000
Total IFC facility
Loan drawdown
Financing costs
AS AT DECEMBER 31
2016
2015
60,000
60,000
(1,601)
58,399
60,000
20,000
(1,401)
18,599
notes 68
16
CAPITAL STOCK
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.
Changes in the capital stock of the Company were as follows:
2016
2015
Authorised
(000)
Issued
(000)
Amount
(US$’000)
Authorised
(000)
Issued
(000)
Amount
(US$’000)
50,000
1,751
983
50,000
1,751
983
Number of shares
Class A
As at January 1 and
December 31
Class B
As at January 1
100,000
33,106
84,505
100,000
33,164
84,654
Normal course issuer
bid repurchases
–
–
–
–
(58)
(149)
As at December 31
100,000
33,106
84,505
100,000
33,106
84,505
First preference
As at December 31
100,000
–
–
100,000
–
–
Total Class A, Class B
and first preference
250,000
34,857
85,488
250,000
34,857
85,488
All issued capital stock is fully paid.
Stock Options
Number of options
Outstanding as at January 1
Forfeited
Outstanding as at December 31
2016
2015
Options
Exercise Price
Options
(000)
CDN$
–
–
–
–
–
–
(000)
400
(400)
–
Exercise
Price
CDN$
3.18
3.18
–
ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTNotes to the Consolidated Financial Statements 69
Stock Appreciation Rights (“SARs”)
2016
2015
SARs
(000)
Exercise Price
(CDN$)
SARs
(000)
Exercise Price
(CDN$)
Outstanding as at January 1
3,100
2.12 to 3.25
2,910
2.12 to 4.20
Exercised
Exercised
Exercised
Forfeited
Expired
Granted
(260)
2.12 to 2.30
(265)
2.32 to 2.70
(55)
3.02 to 3.25
(90)
–
–
2.30
–
–
–
–
–
–
–
–
(300)
4.20
490
3.02 to 3.25
Outstanding as at December 31
2,430
2.12 to 3.25
3,100
2.12 to 3.25
The number outstanding, the weighted average remaining life and weighted average exercise prices of SARs at
December 31, 2016 were as follows:
Exercise price
(CDN$)
2.12 to 2.30
2.32 to 2.70
3.02 to 3.25
2.12 to 3.25
Number
outstanding
(000)
Weighted average
remaining contractual life
(years)
Number
exercisable
(000)
Weighted average
exercise price
(CDN$)
1,730
265
435
2,430
1.94
0.83
3.77
2.15
752
265
85
1,102
2.27
2.48
3.05
2.43
Restricted Stock Units (“RSUs”)
Outstanding as at January 1
Granted
Exercised
Outstanding as at December 31
2016
2015
RSUs
(000)
–
386
(147)
239
Grant/
exercise price
(CDN$)
–
–
3.90
–
RSUs
(000)
645
–
(645)
–
Grant/
exercise price
(CDN$)
–
–
–
–
(i) A total of 386,420 RSUs were granted during the year. The RSUs vested on the date of grant and have an exercise price of
CDN$.001 and have a five-year term.
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 0.5%, stock volatility of 33.5 to 50.7%; 0% dividend yield; 5% forfeiture; a closing stock price of CDN$3.86
per share.
US$’000
SARs
RSUs
AS AT DECEMBER 31
2016
2,495
682
3,177
2015
1,572
–
1,572
As at December 31, 2016, a total accrued liability of US$3.2 million (2015: US$1.6 million) has been recognized in
relation to SARs and RSUs which is included in other payables. The Company recognized an expense for the year of
US$2.6 million (2015: credit US$0.2 million) in general and administrative expenses.
notes 70
17
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
AS AT DECEMBER 31
2016
2015
34,857
34,857
34,887
34,887
The calculation of basic earnings per share is based on a net income for the year of US$2.2 million (2015: US$1.5
million) and a weighted average number of Class A and Class B shares outstanding during the period of 34,856,432
(2015: 34,887,100).
18
RELATED PARTY TRANSACTIONS
One of the non-executive Directors is council to a law firm that provides legal advice to the Company and its
subsidiaries. For the year ended December 31, 2016 US$0.2 million (2015: US$0.6 million) was incurred from this firm
for services provided.
The former Chief Financial Officer provided services to the Company through a consulting agreement with a personal
services company until his resignation on November 2, 2015. For the period from January 1, 2015 to November 2,
2015, US$0.4 million was incurred from this firm for services provided.
As at December 31, 2016 the Company has a total of US$0.1 million (2015: US$0.4 million) recorded in trade and
other payables in relation to the related parties.
ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTNotes to the Consolidated Financial Statements 71
19
CONTRACTUAL OBLIGATIONS
& COMMITTED CAPITAL INVESTMENTS
Protected Gas
Under the terms of the 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 (161.2
Bcf as at December 31, 2016). 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.
Terms of the Gas Agreement were modified by the Amended and Restated Gas Agreement (“ARGA”) which was initialed
by all parties but remains unsigned. 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. Although the ARGA remains unsigned, the
parties have continued to conduct 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, TPDC and Songas (the “Re-Rating Agreement”)
which evidenced an increase to the gas processing capacity of the Songas facilities 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 paid additional compensation of US$0.30/
mcf for sales between 70 MMcfd and 90 MMcfd and US$0.40/mcf for volumes above 90 MMcfd by issuing credit
notes to TANESCO. This was in addition to the tariff of US$0.59/mcf payable to Songas as set by the energy regulator,
EWURA. In May 2016 the Company notified TANESCO and Songas that the additional compensation would no
longer be paid effective June 2016. This additional compensation was always intended to be temporary in nature
until such time as Songas applied to EWURA to obtain approval of a new tariff for the processing of volumes over 70
MMcfd. The PGSA provides for passing on to TANESCO any tariff to be charged to the Company.
The parties are seeking to resolve the status of the re-rating agreement. The processing capacity at the Songas
facilities remain unaltered and are fully utilized by the company. Without a new agreement, there are no assurances
that Songas will continue to allow the gas plant to operate above 70 MMcfd.
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.
notes
72
Portfolio Gas Supply Agreement ("PGSA")
On June 17, 2011, a long term PGSA was signed (to June 2023) 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 July 1, 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 November 1, 2015 and expires on October 31,
2019 at an annual rent of US$0.4 million. The agreement in Winchester expires on September 25, 2022 and is at an
annual rental of US$0.1 million per annum. The costs of these leases are recognized in the general and administrative
expenses.
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 has
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 licence, 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 would 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.
ORCA EXPLORATION GROUP INC. | 2016 ANNUAL REPORTNotes to the Consolidated Financial Statements 73
20
CONTINGENCIES
Downstream unbundling
The Petroleum Act, 2015 (the “Act”) was passed into Law by Presidential decree on August 4, 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 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 and the Company is uncertain regarding the potential impact on its business in Tanzania.
On October 7, 2016, the Government of Tanzania issued the Petroleum (Natural Gas Pricing) Regulation made under
Sections 165 and 258 (I) of the Petroleum Act 2015. Article 260 (3) of the Act preserves the Company’s pre-existing
right with TPDC to market and sell Additional Gas together or independently on terms and conditions (including
prices) negotiated with third party Natural Gas customers. The impact of the Natural Gas Pricing Regulation, if any,
cannot be determined at this time.
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 December 31, 2016, 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$1.0 million from the Cost Pool. In 2015 and 2016 there were no further developments. Under the dispute
mechanism outlined in the PSA, TPDC are to appoint an independent specialist to assist the parties in reaching
agreement on costs that are still subject to dispute, as at the time of writing this report no such specialist has been
appointed. If the matter is not resolved to the Company’s satisfaction, the Company intends to proceed to arbitration
via the International Centre for Settlement of Investment Disputes (“ICSID”) pursuant to the terms of the PSA.
Taxation
Area
PAYE
Tax dispute
Period
Reason for dispute
2008-10 Pay-As-You-Earn (“PAYE”) on grossed-up amounts in
staff salaries which are contractually stated as net.
WHT
2005-10 WHT on services performed outside of
Tanzania by non-resident persons.
Disputed amounts US$ million
Principal
Interest
Total
0.3
1.1
–
0.3 (1)
0.7
1.8 (2)
Income Tax 2008-15 Deductibility of capital expenditures and expenses
16.8
10.1
26.9 (3)
(2009 and 2012), additional income tax (2008,
2010, 2011 and 2012), tax on repatriated income
(2012), foreign exchange rate application (2013
and 2015) and underestimation of tax due (2014).
VAT
2008-10 Output VAT on imported services
2.7
2.9
5.6 (4)
and SSI Operatorship services.
20.9
13.7
34.6
notes 74
(1) In 2015 PAET appealed the Tax Revenue Appeals Board (“TRAB”) ruling that PAET is liable to pay PAYE on grossed-up amounts
in staff salaries. TRAB waived interest assessed thereon. PAET is awaiting ruling of the Tax Revenue Appeals Tribunal (“TRAT”);
(2) (a) 2005-2009 (US$1.7 million): In 2016 TRA filed an application for review of the Court of Appeal decision in favour of PAET
and later filed another application for leave to amend its earlier application. At the Court of Appeal hearing subsequent
to year-end, TRA withdrew their second application for review. The Court has set April 27, 2017 for hearing of the first
application;
(b) 2010 (US$0.1 million): TRAB is awaiting a ruling from the review by 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): In 2015 TRAB ruled against PAET with respect to the deductibility of capital expenditures and other
expenses. PAET appealed to TRAT and is awaiting a hearing date to be scheduled;
(b) 2008 and 2011 (US$2.1 million): In 2015 PAET filed objections against TRA assessments with respect to the deductibility
of capital expenditures and other expenses as well as underestimation of interest and is awaiting a response. Subsequent
to year-end, TRA rejected PAET’s objections for 2011 and undertook to issue a final assessment for the year. PAET intends
to appeal the assessment. The 2008 assessment was issued late and is time-barred;
(c) 2010 (US$2.6 million): PAET filed an appeal with TRAB against TRA assessment with respect to the deductibility of capital
expenditures and other expenses as well as underestimation of interest and penalty amounts. PAET is awaiting a hearing
date to be scheduled;
(d) 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;
(e) 2012 (US$16.3 million): During the year TRA issued two assessments with respect to understated revenue, deductibility
of capital expenditures and expenses, and tax on repatriated income. PAET filed an appeal with TRAB against the TRA
decision to deny PAET a waiver required for its objection to be admitted and is awaiting a hearing date to be scheduled;
(f)
2014 (US$3.5 million): During the year TRA issued an assessment with respect to underestimation of tax due based on
the provisional quarterly payments made by PAET, delayed filings of returns and late payments. PAET filed objections to
the assessments and is awaiting a response;
(g) 2015 (US$0.4 million): During the year TRA issued a self-assessment. PAET filed an objection to the assessment with
respect to foreign exchange rate application and is awaiting a response;
(4) During the year TRA responded to PAET’s objection filed in 2014 and issued an assessment in respect of output VAT on
imported services and SSI Operatorship services. PAET filed an appeal with TRAB against TRA assessment and is awaiting a
hearing date to be scheduled.
(5) On March 29, 2017, management received a tax audit findings report from TRA for the years 2012-14. The report requests
the Company to elaborate on the corporation tax, repatriated income, VAT and withholding tax. Management is preparing its
response and expects to submit it to TRA before the deadline of April 19, 2017.
Management, with the advice from its legal counsels, has reviewed the Company’s position on the above objections and
appeals and has concluded that no provision is required with regard to the above matters.
21
DIRECTORS AND OFFICERS COMPENSATION
US$’000
Directors
Directors
Officers
Officers
Year
Base
Bonus
2016
2015
2016
2015
1,277
1,100
900
1,469
–
500
280
345
Stock based
compensation
expense
1,744
1,676
348
43
Total
3,021
3,276
1,528
1,857
The table above provides information on compensation relating to the Company’s officers and directors. Three officers
and four non-executive directors comprised the key management personnel during the year ended December 31,
2016 (2015: five officers and three 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. | 2016 ANNUAL REPORTNotes to the Consolidated Financial Statements
Corporate Information
Board of Directors
W. David Lyons
Chairman and
Chief Executive Officer
David W. Ross
Non-Executive
Director
75
c
o
r
p
o
r
a
t
e
i
n
f
o
r
m
a
t
i
o
n
William H. Smith
Non-Executive
Director
Calgary, Alberta
Canada
E. Alan Knowles
Non-Executive
Director
Calgary, Alberta
Canada
Glenn D. Gradeen
Non-Executive
Director
Calgary, Alberta
Canada
Calgary, Alberta
Canada
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
Blaine Karst
Chief Financial Officer
Calgary, Alberta
Canada
David K. Roberts
Vice President of Operations
Kansas City, Missouri
United States of America
Registered Office
Investor Relations
Orca Exploration
Group Inc.
P.O. Box 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.