CALGARY, April 15, 2014 /CNW/ - Sterling Resources Ltd. (TSXV: SLG)
("Sterling" or the "Company"), an international oil and gas company
with exploration and development assets in the United Kingdom, Romania,
France and the Netherlands, is pleased to announce operating and
financial results for the year ended December 31, 2013. Sterling
changed the presentation currency of its financial reporting from
Canadian dollars (which remains the functional currency of the Company)
to US dollars effective December 31, 2013 and accordingly, unless
otherwise noted, all figures contained in this release are denominated
in US dollars. The change in presentation currency has been made to
reflect better the Company's business activities and improve
comparability with the Company's peers in the oil and gas industry.
The net loss for the year ended December 31, 2013 was $31.2 million
($0.11 per common share) compared to a net loss of $49.7 million ($0.22
per common share) for the year ended December 31, 2012. The decrease in
the net loss is largely attributable to non-recurring refinancing and
strategic review costs partially offset by increased revenues, foreign
exchange gains and the 2012 relinquishment of the Sheryl licence in the
UKNS. Highlights for the year ended December 31, 2013 include the
The Company's first material production commenced at the Breagh gas
field in the UKNS during October 2013 generating revenue of $3.5
million by year-end 2013. Natural gas is sold on a spot basis pursuant
to a gas trading agreement with Vitol signed in 2011, whereby Sterling
nominates volumes on a day ahead or month ahead basis and achieves a
price very close to the UK reference spot price at the National
Balancing Point. Sterling is paid the month following production. A
small amount of condensate is also produced at Breagh (approximately 3
barrels of liquids per million standard cubic feet of production) and
is sold to a third party at a price linked to NW European spot prices
for naphthenic products.
A third party Gemini Oil & Gas Fund II, L.P. ("Gemini") was paid
$465,000 pursuant to a loan agreement originally executed in 2007
related to the funding of appraisal wells on the Breagh field. Gemini
is entitled to interest and principal repayments representing a portion
of gas and condensate production revenue from Breagh and the portion
varies as certain thresholds of cumulative payment are reached.
Pre-licence and other exploration costs during 2013 were $8.4 million, a
significant decrease from the 2012 level of $31.5 million, due to lower
activity levels during 2013 and the relinquishment of Sheryl (UK block
21/23a) during 2012 which resulted in a charge of $12.8 million. Of
the $8.4 million total, $3.6 million ($20.1 million in 2012) was
attributable to licences in the UK, $2.0 million ($7.8 million in 2012)
attributable to Romania, and $2.8 million ($3.6 million in 2012) was
attributable to the Netherlands and other international ventures. In
addition to the charge related to Sheryl, the 2012 pre-licence number
was higher due to seismic costs on the UK 42/13b, 42/17 and 42/18
(Lochran) blocks, the Muridava block in Romania, and the E3/F1 block in
the Netherlands which were acquired and expensed in the period.
For the year ended December 31, 2013 the Company recorded a foreign
exchange gain of $9.8 million due to the weakening of the US dollar (in
which $225 million senior secured bond of the Company's UK subsidiary
is denominated (the "Bond")) against the UK pound (which is the
functional currency for the UK), partially offset by bank balances held
in US dollars. This gain offset losses incurred in the first half of
2013 which arose mainly (1) on the repayment of the UK pound
denominated £105 million senior secured bank credit facility (the
"Credit Facility") from the US dollar denominated Bond as a result of
the UK pound strengthening against the Canadian dollar and (2) a
foreign exchange loss of $0.6 million during the first quarter of 2013
which arose on the US dollar denominated short-term loan as a result of
the Canadian dollar weakening relative to the US dollar.
Net employee expense during 2013 totaled $7.3 million increasing
marginally by $151,000 over the 2012 level. Of this total, $6.5 million
was wages and salaries with the remaining $0.8 million related to
non-cash compensation. The non-cash component was down from the $3.3
million level in 2012 as certain options were fully amortized and no
new options were issued.
General and administrative expenses for the year ended December 31, 2013
after recoveries totaled $3.0 million, increasing by $159,000 over the
2012 level. During 2013 a number of cost saving initiatives were
launched including the relocation of the offices in both London and
Aberdeen to smaller facilities.
Costs related to refinancing and strategic review activities during 2013
totaled $12.9 million of which $7.6 million related to bank and
professional consultants, $1.5 million to severance payments and $3.8
million of transaction costs related to the Credit Facility.
Financing costs during 2013 totaled $9.6 million primarily attributable
to borrowing costs on the Bond issue occurred from the date production
at Breagh commenced in October 2013. The remainder of financing costs
include accretion of the discount on decommissioning obligations and
have increased due to greater decommissioning obligations on the Breagh
development. During the first quarter of 2013, $1.9 million of
financing costs were incurred in relation to the $12 million bridging
The Company has not yet recognized a deferred tax asset generated as a
result of non-capital and other tax losses, due to the uncertainty of
future taxable profits against which such losses can be offset. In the
UK, tax losses are estimated to amount to $616 million for ring fence
corporation tax losses and $580 million for supplementary charge
corporation tax. The net value of UK tax losses (including future ring
fence expenditure supplement available to claim on these losses) is
estimated by management to be approximately $220 million. Tax losses
and allowances in Canada include tax pools of approximately $61 million
and non-capital losses of approximately $43 million, and $17 million of
tax deductible expenses and losses are available to shield future
taxable income in the Netherlands.
Cash and cash equivalents were $34.7 million at December 31, 2013
compared to $9.5 million at year-end 2012. Restricted cash of $7.8
million at December 31, 2013 ($22.0 million as at December 31, 2012)
was cash held in blocked accounts, specifically $2.8 million related to
expenditures at Breagh and $5.0 million towards the second Bond
interest payable on April 30, 2014.
Net working capital was $2.2 million as at December 31, 2013,
significantly higher than the level at year end 2012 mainly due to the
refinancing, the wind-down of the drilling campaign in Romania and
funds received from the share issue partly offset by the continuing
development expenditure at Breagh. The current portion of long-term
debt at year-end 2012 of $138.3 million was refinanced during the
second quarter of 2013.
Capital expenditures during 2014 are anticipated to reach $86 million,
of which approximately $31 million is related to UK Breagh Phase 1
field development; $16 million related to other UK exploration and
appraisal; $24 million for exploration and appraisal in Romania, the
Netherland and France; and $4 million for pre-development costs at
Breagh Phase 2 and at Ana and Doina offshore Romania. The expected cost
of exploration and appraisal work in Romania, the Netherland and France
has decreased significantly compared to earlier guidance principally
due to the deferral of the Luceafarul-1 well into 2015.
An updated corporate presentation is available for viewing on the
Sterling Resources website.
"The past year has been a transitional one as the Company finally
achieved production at Breagh and went through a significant change in
leadership," noted Jake Ulrich Sterling`s CEO. "Our focus is now upon
optimizing production levels at Breagh and reducing our working
interest levels in the Black Sea, in order to advance development
towards achieving Romanian production," added Mr. Ulrich.
Operational Summary for 2013
Breagh field development
Following first gas and a few weeks of intermittent operation as the
Teesside Gas Processing Plant ("TGPP") was started up, production at
Breagh was suspended in November 2013 to resolve mechanical issues at
TGPP associated with pipeline pigging operations used to clear the
field pipeline of liquids. These mechanical issues were resolved after
seven weeks by changing the pipeline junction at the TGPP inlet and
making improvements to operational management of pigging operations.
Production recommenced in late December and has continued until April
10, 2014 on which date a further production shutdown commenced to
remove fouling within the slug catchers and to replace level control
instrumentation with the intention of improving processing uptime at
TGPP. This shutdown is expected to be completed in early May 2014.
The majority of the drilling operations have been completed for the
planned Phase 1 of the development. Wells A01-A06 have been drilled,
completed, tested and on production since late December 2013. Since
then, sales production during the first quarter of 2014 has averaged 75
million standard cubic feet per day ("MMscf/d") for the whole field or
22 MMscf/d net to Sterling. The Ensco 70 jack-up drilling rig will
return to the field at the end of April at which time we plan to
complete well A07 using hydraulic fracture stimulation (fracking), and
then to drill and complete well A08. We are also planning further
development drilling of wells A09 and A10 from the Breagh Alpha
platform late in 2015 early in 2016, following a new 3D seismic
acquisition over the field which will be acquired during the summer of
The expected average sales gas production for 2014 is 90-95 MMscf/d for
the whole field (27-28 MMscf/d net to Sterling), below the previous
guidance of 106-112 MMscf/d for the whole field provided in a news
release on February 19, 2014 equivalent to a reduction of approximately
This change reflects production performance over the first quarter of
2014 to reflect lower than planned production efficiency (well
time-on-stream and plant uptime), lower production expectations for
wells A07 and A08, and changes to forecasted performance data to match
actual sales production (system pressures, gas shrinkage and stabilized
performance of wells A01 - A06). The sales gas rate production rate at
the end of 2014 is now forecast to be 117 MMscf/d for the whole field
(35 MMscf/d net to Sterling), only marginally lower than the 118
MMscf/d announced on February 19, 2014.
Despite the lower initial production rates, reserves for the whole field
at the end of 2013 at the proved plus probable level (Phases 1 and 2)
have only decreased by 1 percent from the end of 2012 (after adjusting
for a small amount of production in 2013) and for Phase 1 are
effectively unchanged. The issue therefore is how to extract the
reserves more effectively and we are looking to enhance production
rates through fracking wells and by drilling additional wells in both
phases of development.
The large areal extent of the Breagh field of approximately 80 square
kilometres means that further offshore facilities will be required to
completely develop the field, most likely a second platform on the
eastern side of the field. The size of the platform and well type and
degree of stimulation are all key factors to a successful development
of this area of the field during the second phase, all of which are
currently being studied. The results of the hydraulic fracture
treatment on well A07 will be particularly important in the evaluation
of the Phase 2 development. Because of the time required for these
studies, it is possible that development approval may slip into 2015.
Initial production from Breagh Phase 2 is now expected during the third
quarter of 2017.
Cladhan field development
The Cladhan development in Block 210/29a is proceeding satisfactorily,
slightly behind schedule but within budget, with first production
expected around the end of the first quarter of 2015. Development
drilling is expected to recommence later in April 2014; installation of
the subsea pipelines and tie-back to the host Tern platform is expected
to begin over the summer of 2014 and final modifications to the Tern
platform are anticipated to be completed over the period from the third
quarter of 2014 into the second quarter of 2015 (finishing with the
second compressor train, which is not needed for first production).
Initial field production from Cladhan is expected at the end of the
first quarter 2015 to be 17,000 bbls/d (approximately 2,300 bbls/d net
to Sterling at a 13.8 percent interest level)
As a result of two separate agreements with TAQA Bratani regarding
Cladhan in 2012 and 2013, Sterling reduced its equity interest but is
now fully carried through to first oil. Part of the carry costs are
repayable out of production revenue and after pay-out occurs, expected
during the third quarter of 2015. Sterling will hold a 13.8 percent
interest in the Cladhan field.
Exploration activities in 2013 focused on the acquisition and processing
of seismic surveys over the Lochran prospect near to the Breagh field
and the re-processing of a number of existing seismic datasets, which
included the Niadar prospect in the Southern North Sea. The Niadar
prospect is situated close to infrastructure, which may provide a
relatively quick turnaround from exploration (if successful) to
production. Following a planned farm-down this year, the prospect is
expected to be drilled in 2015.
Preparatory planning work, including acquisition of a site survey, was
completed in 2013 for drilling the exploration well to test the
Beverley oil prospect in the Central North Sea. Sterling's costs for
drilling are fully carried, with expectations to drill in the latter
half of 2014, following transfer of operatorship of this licence to
Shell (UK) Ltd. later this month.
In December 2013, Sterling was awarded its choice of blocks applied for
in the 27th Offshore Licensing Round. The Company gained a 100 percent interest in
several more blocks close to the Breagh field containing the Ossian and
Darach prospects. Our current plan is to farm-down and seek a carry
for the firm well commitment, which is planned to test both prospects.
We are also applying for additional prospective acreage in the 28th
Licensing Round, which is due to close later this month with awards
possibly by the end of 2014.
Between December 2013 and February 2014, Sterling as operator completed
3D seismic surveys amounting to 1,350 square kilometres over key areas
of the Luceafarul, Midia and Pelican offshore blocks. This was
completed several months earlier than expected by using two vessels
rather than one. The earlier completion of the 3D seismic program means
that the planned sell-down process to reduce the Company's equity
interests in its Black Sea blocks can commence at the end of the summer
2014 with interpreted results available for all of Sterling's main
fields and prospects, providing important information for potential new
partners. Sterling intends to reduce its equity interests in the Midia
Shallow and Pelican blocks (currently 65 percent), in the Luceafarul
block (currently 50 percent) and in the Muridava block (currently 40
percent) to approximately half of the current levels by introducing a
new partner. It is the intention to sign binding documentation, if the
process is successful, around the end of 2014 with completion expected
in the first quarter of 2015.
The development of the Ana and Doina fields in the Midia block continues
to be evaluated by Sterling, but the timing of first production is now
expected to occur during 2019. This will allow for optimization of the
development to reflect the recent 3D seismic acquired and to
incorporate any exploration or appraisal success in Midia and nearby
blocks over the next two years, which should add value by leading to a
larger regional development.
An exploration well spudded in our remaining Black Sea block, Muridava
(Sterling 40 percent) on April 11, 2014 and is expected to take two
months to complete. The Muridava-1 well is on the same geological trend
as the existing Olimpiyskaya and Eugenia gas discoveries and has
targets in three formations. An exploration well on the Luceafarul
block is planned in early 2015.
Licence extensions for the Midia Shallow and Pelican blocks have
recently been agreed with the National Agency for Mineral Resources.
Three extension options to the exploration period currently ending in
May 2014 are available, with extensions to May 2015, May 2018 and May
2020. Commitments are projected to be satisfied in 2014 for the first
extension period and for each of the second and third extension periods
the commitments comprise two wells (in aggregate, over the two blocks).
During January 2014 the sale of Sterling's 65 percent interest in a
portion of the Midia Block in the Romanian Black Sea (the "Sale
Portion") to ExxonMobil Exploration and Production Romania and OMV
Petrom S.A., was completed. Net of Romanian tax, the Company received
proceeds of approximately $25 million. In the event of future
exploration success on the Sale Portion, Sterling will be entitled to
further proceeds of $29.25 million upon a commercial discovery being
made and an additional $19.5 million upon first production from the
Sale Portion. The Midia block has now been split into two parts with
the Shallow Waters Contract Area ("Midia Shallow") being retained by
Sterling at its current equity interest of 65 percent. The Midia
Shallow block includes the Ana and Doina discoveries, the Ioana
prospect and several other prospects. Sterling retains no interest in
the smaller, carved-out portion of the deep water Midia block.
A 3D seismic survey is planned over the oil discoveries and prospects in
the Jurassic and Early Cretaceous horizons in blocks F17a and F18
(Sterling 35 percent) in the second half of 2014. This will improve
reservoir understanding and assist in evaluating development options.
With the commitment to complete 3D seismic in place, a further
multi-year extension has been requested from the Dutch authorities. The
oil discovery by Wintershall Noord Zee BV with well F17-10 in late 2012
(which it estimated at the time as being at least 30 million barrels)
in the shallower, Late Cretaceous horizon has, in the view of Sterling
and partner Energie Beheer Nederland BV, increased the likelihood of a
regional oil development hub. Sterling estimates that first production
could be achieved at the earliest by 2019.
Financial Review and Outlook
We were successful in refinancing the Company in 2013 through a series
of challenging funding transactions. In January, we completed a
shareholder loan of $12 million from Vitol; in March, we closed an
equity raise of $63.25 million (before expenses), enabling repayment of
the Vitol loan); in early April, we agreed a transaction with TAQA to
provide development funding for Cladhan; and finally later in April we
closed the $225 million senior secured ""Bond, allowing repayment of
the Credit Facility (of which $134 million had been drawn).
We ended the year with $42.5 million of cash (including restricted cash)
which was increased in February 2014 by the receipt of after-tax
proceeds of approximately $24.9 million from the sale of a subdivided
portion of our Midia block offshore Romania. However, the Company's
expected 2014 operating cash flow has been impacted by a combination of
lower than expected Breagh production for 2014 and lower UK spot gas
prices. As noted above, 2014 production is now expected to be 15
percent down on earlier guidance while the average forward curve UK gas
spot price for 2014 has decreased by around 15 percent from the
beginning of January to early April (adjusting for actuals for the
Sterling should have available funding to satisfy a requirement under
the Bond to have a minimum of $10 million unrestricted cash in the UK
subsidiary up to around the end of the third quarter of 2014 at a flat
gas price of 55 pence per therm ($9.10 per thousand cubic feet) for the
remainder of the year, in line with recent current forward curve gas
prices. The extent of the cash shortfall will be determined by many
factors including production rate, gas price, Breagh capital
expenditures and the phasing and cost of exploration activities. To
address this potential cash shortfall, we are considering a number of
relatively small financing alternatives most likely involving debt
Reserves and Resources Summary
Sterling is pleased to announce the filing of its annual reserves
disclosure pursuant to National Instrument 51-101 ("NI 51-101") and an
update of the Company's Contingent and Prospective Resources, both as
at December 31, 2013.
The Company has decreased its Proved and Proved plus Probable Reserves
by 1.0 and 3.0 million barrels of oil equivalent ("MMboe")
respectively. This is due largely to the farm-outs and reduced working
interest for the Cladhan field.
The Company has decreased the P50 Contingent Resources by 7.0 MMboe. a
decrease of 8 percent over year-end 2012. The decrease is due to a
combination of several licence relinquishments and further evaluations
of the Nia prospect on 49/18b and of the deeper Zone 3 sands within the
The Company has decreased Best Estimate Prospective Resources by 50.2
MMboe equivalent, a decrease of 9 percent over year-end 2012. This
increase is mainly due to further subsurface evaluations of the
Company's Romanian properties, mainly in the Muridava block, which was
offset by further additions in the UK with awards within the 27th licensing round (Ossian and Darach prospects).
The Company has relinquished the Romanian onshore licence and
consequently now has no unconventional gas Resources.
Reserves and Resources Summary (Based on Forecast Prices and Costs)(1)
Company Share Gross(2) and Net Oil
and Gas Reserves
as at December 31, 2013
Summary of Net Present Value of Future Net
Revenue Before Income Tax(7)
as at December 31, 2013
Company Total (8,13)
Unrisked Contingent Resources (9)(11)
as at December 31, 2013
Unrisked Prospective Resources (10)(12)
as at December 31, 2013
Estimates of Reserves and Future Net Revenue have been made assuming the
development of each property in respect of which the estimate is made
will occur, without regard to the likely availability to the Company of
funding required for that development.
Numbers may not correspond precisely with those set forth in the
Company's annual disclosure in Form 51-101F1 due to the effects of
Gross before royalties.
Possible reserves are those additional reserves that are less certain to
be recovered than probable reserves. There is a 10 percent probability
that the quantities actually recovered will equal or exceed the sum of
proved plus probable plus possible reserves. In this instance the gross
values are the same as the net values because the royalty is zero.
MMboes may be misleading, particularly if used in isolation. A BOE
conversion ratio of 6 Mcf : 1 bbl is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead.
Breagh reserves are predominantly gas.
Discounted at 10 percent per annum.
Company Reserves totals are arithmetic aggregations of multiple
estimates, which statistical principles indicate may be misleading as
to volumes that may actually be recovered. Readers should give
particular attention to the estimates of individual classes of Reserves
and appreciate the differing probabilities of recovery associated with
each class. For Proved (1P) Reserves the totals have a higher than 90
percent probability of being produced on an unrisked basis. For Proved
plus Probable plus Possible (3P) Reserves, the totals have a lower than
10 percent probability of being produced on an unrisked basis.
Contingent Resources are those quantities of petroleum estimated as of a
given date to be potentially recoverable from known accumulations using
established technology or technology under development, but which are
not currently considered to be commercially recoverable due to one or
more contingencies. The contingencies that result in the categorization
as Contingent Resources of the Corporation's resources are either
technical, requiring further appraisal work (Breagh, Cladhan and
Crosgan), or commercial, requiring final definition of gas markets and
development plans (Ana and Doina). The Resources volumes shown
represent probabilistic totals of several entities within each licence
or block area, and have not been risked for Chance of Development.
There is no certainty that it will be commercially viable to produce
any portion of the Contingent Resources.
Prospective Resources are those quantities of petroleum estimated as of
a given date to be potentially recoverable from undiscovered
accumulations by application of future development projects. There is
no certainty that any portion of the Prospective Resources will be
discovered or, if discovered, that it will be commercially viable to
produce any portion of the Resources. The volumes shown represent
statistical aggregations of several unrisked entities within each
licence or block area, and assume that all prospects are successful.
The probability of all prospects being successful is extremely small.
These Prospective Resources are in areas of the field or geological
horizons in which the presence of hydrocarbons require confirmation by
Company Resources totals shown by Resource category are statistical
aggregates of unrisked Resources at a company level. For Contingent
Resources the statistical aggregates assume no dependencies between
discoveries and for Prospective Resources these statistical totals
assume no dependencies between prospects.
The P(50) or 2C is considered to be the best estimate of the quantity
that will actually be recovered. If probabilistic methods are used
there is at least a 50 percent probability P(50) that the quantities
actually recovered will equal or exceed the estimate. Similarly, the 1C
or P(90) and 3C or P(10) represent the low and high estimates
The estimates of Reserves and Resources for individual properties may
not reflect the same confidence level as estimates of Reserves and
Resources for all properties, due to the effects of aggregation.
The Company's hydrocarbon reserves and resources were independently
evaluated by RPS effective December 31, 2013 in accordance with the
Canadian Oil and Gas Evaluation Handbook ("COGEH") reserves definitions
and evaluation practices and procedures, as specified by NI 51-101.
There is no certainty that it will be commercially viable to produce
any portion of the Reserves. The evaluation uses the RPS forecast
prices and costs as at December 31, 2013. Complete details regarding
Sterling's reserves and resources for the year ended December 31, 2013
and in a format specified by NI 51-101 can be found on SEDAR at www.sedar.com or on the Company's website www.sterling-resources.com
Sterling Resources is a Canadian-listed international oil and gas
company headquartered in Calgary, Alberta with assets in the United
Kingdom, Romania, France and the Netherlands. The common shares are
listed and posted for trading on the Toronto Stock Exchange Venture
(TSX-V) exchange under the symbol "SLG".
Neither the TSX-V nor its Regulation Services Provider (as that term is
defined in the policies of the TSX-V) accepts responsibility for the
adequacy or accuracy of this release.
Filer Profile No. 00002072
All statements included in this news release that address activities,
events or developments that Sterling expects, believes or anticipates
will or may occur in the future are forward-looking statements. In
addition, statements relating to expected production, reserves or
resources are deemed to be forward-looking statements as they involve
the implied assessment, based on certain estimates and assumptions that
the reserves and resources described can be profitably produced in the
These forward-looking statements involve numerous assumptions made by
Sterling based on its experience, perception of historical trends,
current conditions, expected future developments and other factors it
believes are appropriate in the circumstances. In addition, these
statements involve substantial known and unknown risks and
uncertainties that contribute to the possibility that the predictions,
forecasts, projections and other-forward looking statements will prove
inaccurate, certain of which are beyond Sterling's control, including:
the impact of general economic conditions in the areas in which
Sterling operates, civil unrest, industry conditions, changes in laws
and regulations including the adoption of new environmental laws and
regulations and changes in how they are interpreted and enforced,
increased competition, the lack of availability of qualified personnel
or management, fluctuations in commodity prices, foreign exchange or
interest rates, stock market volatility and obtaining required
approvals of regulatory authorities. In addition there are risks and
uncertainties associated with oil and gas operations. Readers should
also carefully consider the matters discussed under the heading "Risk
Factors" in the Company's Annual Information Form.
Undue reliance should not be placed on these forward-looking statements,
as there can be no assurance that the plans, intentions or expectations
upon which they are based will occur. Sterling's actual results,
performance or achievements could differ materially from those
expressed in, or implied by, these forward-looking statements. These
statements speak only as of the date of the news release. Sterling does
not intend and does not assume any obligation to update these
forward-looking statements except as required by law.
Financial outlook information contained in this news release about
prospective results of operations, financial position or cash flows is
based on assumptions about future events, including economic conditions
and proposed courses of action, based on management's assessment of the
relevant information currently available. Readers are cautioned that
such financial outlook information contained in this news release
should not be used for purposes other than for which it is disclosed
SOURCE: Sterling Resources Ltd.
For further information:
visit www.sterling-resources.com or contact:
Jacob Ulrich, Chief Executive Officer, Mobile: 44-7584-416684, email@example.com
David Blewden, Chief Financial Officer, Phone: 44-20-3008-8488, Mobile: 44-7771-740804, firstname.lastname@example.org
George Kesteven, Manager, Corporate and Investor Relations, Phone: (403) 215-9265, Mobile: (403) 519-3912, email@example.com