NOT FOR DISTRIBUTION TO UNITED STATES NEWS WIRE SERVICES OR DISSEMINATION IN
UNITED STATES
Iona Energy Inc. ("Iona" or the "Company") (TSX VENTURE:INA) announces its
financial results for the three and twelve months ended December 31, 2013 and
the Company's independently evaluated reserves as of the same date.
FINANCIAL & OPERATING HIGHLIGHTS
(in United States dollars (tabular amounts in thousands) except as otherwise noted)
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Three months ended Twelve months ended December
December 31, 31,
2013 2012 Change 2013 2012 Change
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Financial
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Crude oil and
natural gas
revenues $ 33,797 - - $ 65,508 - -
Cost of sales (9,462) - - (18,620) - -
Depletion,
Depreciation &
Amortization (16,206) (34,768)
Gross Profit 8,129 - - 12,120 - -
Gross Profit
before DD&A 24,335 - - 46,888 - -
Income (loss)
Before Tax (39,006) (4,427) (781%) (65,461) (10,581) (519%)
Income (loss)
After Tax 31,553 (4,427) 813% 29,466 (10,581) 378%
Per share -
basic ($) 0.09 (0.01) 0.08 (0.04)
Per share -
diluted ($) 0.09 (0.01) 0.08 (0.04)
Funds Flow(1)(2) 28,225 (4,601) 713% 31,324 (4,553) 788%
Per share -
basic ($) 0.08 (0.01) 0.09 (0.02)
Per share -
diluted ($) 0.08 (0.01) 0.09 (0.02)
Adjusted
EBITDA(1)(2) 27,936 (4,601) 707% 46,956 (10,737) 538%
Per share -
basic ($) 0.08 (0.01) 0.13 (0.04)
Per share -
diluted ($) 0.08 (0.01) 0.13 (0.04)
As at December 31
2013 2012
Cash and cash equivalents $ 19,808 $ 15,579
Restricted cash 85,114 9,808
Working capital surplus(1) 79,075 (34,897)
Secured bonds $ 262,450 $ -
Common shares, end of period 366,831 324,905
Fully diluted, end of period(1) 369,225 351,985
Weighted average common shares - basic 360,849 273,611
Weighted average common shares-fully diluted 363,078 273,611
Three months ended Twelve months ended
December 31, December 31,
2013 2012 Change 2013 2012 Change
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Operational
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Crude oil and natural gas
production (boepd)(3)(4)
Crude oil 2,320 - - 1,694 - -
Natural Gas 765 - - 736 - -
Total 3,085 - - 2,430 - -
Realized sales prices
Crude oil ($/boe) 112.15 - - 108.35 - -
Natural Gas ($/mmcf)(5) 12.88 - - 10.07 - -
Average ($/boe) 103.84 - - 97.63 - -
Operating costs(1)(6)
($/boe) $ 24.94 - - $ 27.75 - -
Netback(1) ($/boe) $ 78.90 $ 69.88
(1) Non-GAAP measure - see "non-IFRS Measures" section within MD&A.
(2) See reconciliation on page 5.
(3) Adjusted for start of production of Huntington on April 12, 2013.
(4) Based on 15.75% (excludes 1.8% royalty) working interest of volumes
from Huntington.
(5) Q3 2013 revenue accrual had been understated by $916,000; this amount
has been included in the Company's Q4 2013 revenue. Realized sales
prices have been normalized. Revenue numbers for Q3 2013 have not been
restated.
(6) Q3 2013 operating costs had been understated by $2.1 million; this
amount has been included in the Company's Q4 2013 operating costs.
Realized operating costs have been normalized. Operating costs for Q3
2013 have not been restated.
FINANCIAL
-- The Company recorded record quarterly revenue of $33.8 million (Q4 2012
- $Nil) and $65.5 million (2012 - Nil) respectively for the three and
twelve months ended December 31, 2013. There was no revenue generated
from operations in 2012 as Huntington commenced production on April 12,
2013, while all revenues from Trent & Tyne ("T&T") accrued into a
restricted cash account between the economic date of the T&T acquisition
and the completion of the 44/18-T6 ("T6") well in January 2013.
-- Revenues of $33.8 million for the three months ended December 31, 2013
consisted of $24.5 million (Q4 2012 - $Nil) from oil production, $6.1
million (Q4 2012 - $Nil) from gas production and $3.1 million (Q4 2012 -
$Nil) from the Company's royalty interest at Huntington.
-- Revenues of $65.5 million for the twelve months ended December 31, 2013
consisted of $46.3 million (2012 - $Nil) from oil production, $14.4
million (2012 - $Nil) from gas production, $332,000 (2012 - $Nil) from
condensate and $4.5 million (2012 - $Nil) from the Company's royalty
interest in the Huntington field.
-- The average realized oil price for the three and twelve month period
ended December 31, 2013 was $112.15 per barrel and $108.35 per barrel
respectively, and the average realized gas price for the three and
twelve month period ended December 31, 2013 was $12.88 per mcf and
$10.07 per mcf.
-- 4th quarter netbacks of $78.9/boe and netbacks for the year ended
December 31, 2013 of $69.9/boe.
-- Record funds flow from operations of $28.2 million for the three months
ended December 31, 2013 (Q4 2012 - $(4,601) million) and $31.3 million
for the twelve month period ended December 31, 2013 (2012 - $(4,553)
million).
-- Having produced approximately 690,000 boe net in 2013, the Company's
reserves remained robust, with Gaffney, Cline & Associates Ltd. ("GCA")
assigning 34 MMboe 2P reserves to Iona as at December 31, 2013 (34.3
MMboe at December 31, 2012), in part due to additional reserves of
650,000 boe being attributed to the Huntington field.
-- On February 21, 2013, Iona closed a bought-deal private placement of
common shares for an aggregate amount of CAD$23 million. Pursuant to the
private placement the Company issued 41,818,603 common shares at $0.55
per share. Concurrently, Iona Energy Company (UK) plc ("Iona UK") signed
a Senior Secured Borrowing Base Facility for up to $250 million with a
group of three banks led by Bank of America Merrill Lynch, Lloyds TSB
Bank plc, and BNP Paribas. Further, Iona UK completed a $60 million
structured energy derivative transaction with Britannic Trading Ltd., a
subsidiary of BP Oil International Limited, in addition to entering into
a Marketing and Offtake Agreement with BP Oil International Limited.
-- On September 27, 2013, Iona UK issued $275 million senior secured bonds
(the "Bonds"). Proceeds from the Bond were used to repay the Company's
Senior Secured Borrowing Base Facility in full and to offset 3.1 million
call options through a mirrored call structure, with the balance of the
proceeds being allocated towards funding the delivery of the Orlando and
Kells projects to first oil.
-- The Company has corporate tax pools of approximately $321 million and
does not expect to pay UK taxes until 2017 or later.
-- The Company's current production is not subject to any crown or third
party royalties on any revenues, now or in the foreseeable future.
RESERVES
-- Company reserves assessed by Gaffney, Cline & Associates Ltd. at the end
of 2013(2) :
-- Net 1P Reserves of 18.9 million barrels of oil equivalent ("mmboe")
(2012: 18.8 mmboe(3))
-- Net 2P Reserves(1) of 34.0 mmboe (2012: 34.3 mmboe(3))
-- Net 3P Reserves of 43.8 mmboe (2012: 44.2 mmboe(3))
-- Net 2P Reserves Pre-Tax Net Present Value (assuming a discount rate
of 10%) of $1,280 million (2012: $1,256 million(3))
(1) 2P Reserves comprises 84% oil and 16% natural gas.
(2) Reserves are from the December 31, 2013 Gaffney Cline & Associates Ltd.
reserve report produced for the Company in April, 2014.
(3) Reserves are from the December 31, 2012, Gaffney Cline & Associates
Ltd. reserve report produced for the Company in June, 2013.
KEY PROJECT HIGHLIGHTS
Huntington
-- On February 22nd, 2013, Iona, through Iona UK, acquired Carrizo UK
Huntington Limited which included a 15% working interest in License
P1114 of UK North Sea Block 22/14b containing the near-producing
Huntington Forties oil field development ("Huntington"), the Jurassic
Fulmar discovery ("Maxwell"), the undrilled potential extension of the
Jurassic Fulmar ("Lobe 2"), and two Triassic Skagerrak structures, one
of which includes a drilled discovery. Additionally, the acquisition
included royalties equivalent to 2.55% of gross oil and gas production
from License P1114 payable by the Huntington joint venture partners, and
Carrizo UK's ring-fenced tax losses totaling $125 million.
-- Also as part of the Huntington acquisition, Iona UK acquired a 100%
interest in Block 22/14d located in the Central North Sea, immediately
to the south of Huntington, containing an undrilled extension of the
Jurassic Fulmar ("Lobe 3"), and a discovered and tested extension of the
Triassic Skagerrak. Iona plans to remap both the Jurassic targets and
Triassic discoveries in the near-term, and future appraisal could see
these as candidates for development through the existing infrastructure
at the producing Huntington field.
-- The Huntington field commenced oil production on April 12, 2013, with
gross production initially limited to 7,300 boepd, prior to first gas
export in June which allowed oil production levels to be increased.
-- In early September, Huntington production was curtailed by restrictions
on gas export due to problems in the Central Area Transmission System
("CATS") gas export pipeline. These restrictions continued from
September through November and, following a period of inclement weather
in December, Huntington returned to plateau production levels and was
producing at peak rates above 34,700 boepd (6,100 boepd net to Iona) at
year-end.
-- Net production from the Huntington field to Iona during the period from
first oil (April 12, 2013) until December 31, 2013 was 2,149 boepd (Q4
2013 - 2,947 boepd), including the 2.55% royalty, and the Huntington
reservoir and FPSO continued to perform well with Q4 2013 system
availability of 94%.
-- On March 1, 2014, the Voyageur FPSO passed its Performance & Reliability
Test and as of March 31st 2014, the field had produced 5.1 million
barrels of oil equivalent, with Iona's net share of production totaling
0.9 million barrels of oil equivalent. Iona's Q1 2014 average production
at Huntington increased 34% over Q4 2013, from 2,974 boepd to 3,959
boepd, as operational and weather-related downtime at the field
continued to improve. Further, cargo schedule optimization has increased
oil liftings, taking advantage of good weather windows as and when
available.
-- On April 12, 2014, Huntington production was suspended as work commenced
to replace a number of straub couplings that are part of the inert gas
system on the floating production, storage and offloading ("FPSO")
facility. On April 24, 2014, the Operator, E.ON E&P UK Ltd, informed the
partners that the replacement work had been completed ahead of schedule
and that production restart had commenced. However, on April 26th the
Huntington partnership was advised that due to an unplanned shutdown
issue involving the CATS riser system, all fields producing through the
system would be shut in until May 1, 2014. The joint venture partnership
is at present analyzing optimization measures to debottleneck the
Voyageur FPSO's current production capacity of 34,500 boe/d by an
additional 10%. The results of the analysis should be complete by Q3
2014.
Huntington Jurassic Fulmar ("Maxwell")
-- Relating to the deeper Maxwell discovery which lies beneath the
producing Huntington Forties field, a subsequent phase of development is
under evaluation by the Huntington joint venture partners to submit an
FDP, to conduct engineering work in 2015, and to set a first oil target
in 2016. Further appraisal and development of the Fulmar horizon may
follow depending on the geoscience evaluation of the overall extent of
this reservoir to include Iona's 100% owned Block 22/14d.
Trent & Tyne
-- The net production from the Trent & Tyne fields to Iona during the year
was 2.96 MMcf/d.
-- The net average daily production rate from Trent & Tyne to Iona during
the three and twelve months ended December 31, 2013 was 2.1 MMcf/d and
3.0 MMcf/d respectively, which was severely reduced as a result of
remedial works at the onshore reception terminal in addition to
restricted production from the T6 well due to the intermittent
performance of the fresh water maker at Tyne and further exacerbated by
the past winter's exceptionally stormy weather, which restricted manned
interventions to effect repairs.
-- The Tyne 44/18-T6 ("T6") well was completed in January 2013 as a
production well and flow tested at an average rate of 25 MMcf/d with a
peak rate of 28 MMcf/d. Until late 2013, T6 production was consistently
above 25 MMcf/d and exceeding expectations. Late in 2013 the T6 well
began experiencing technical difficulties, and production dropped from
28 MMcf/d to 12 MMcf/d. The well was taken offline to analyze the
problem.
-- In the operating envelope of the Tyne field, and in particular the T6
well, salt deposition in the wellbore tubulars is a significant risk to
production. As super-saline formation water enters the wellbore tubulars
it experiences a drop in both temperature and pressure. This causes salt
to drop out of solution and deposit in the well. It is a well-known
issue in the gas fields of the UK Southern Gas Basin and elsewhere with
highly saline formation waters. Standard industry practice is to install
a water washing system to the wells. Fresh water is pumped down the
wells and this washes salt deposits to surface. A water maker takes sea
water and, by reverse osmosis, generates fresh water for the water
washing system. Salt build-up is sufficiently quick to preclude
producing wells such as T6 without continual water washing. It is
routine procedure to suspend production while the water maker is out of
commission. Operational improvements to enhance the performance and
reliability of the Tyne water maker are being implemented and should be
rectified during the second half of 2014.
Orlando
-- On February 21, 2013, Iona UK completed the acquisition of its partners'
interests, MPX North Sea Limited (30%) and Sorgenia E&P (UK) Ltd (35%),
in the Orlando oil field in exchange for approximately $48.25 million
and the obligation to make future payments out of production totaling
$29 million.
-- The development plan for Orlando comprises the re-entering of the
suspended 3/3b-13z well, drilling a 3,000 foot horizontal producer, and
completion with dual electric submersible pumps. Additionally, a subsea
pipeline, power supply and control umbilical are expected to be laid
between the well-head and the Ninian Central Platform ("NCP")
approximately 10 km to the south west of the Orlando field. Engineering
modifications are expected to be completed at NCP allowing tie-in and
first production shortly after completing the development well.
-- It was originally contemplated that each of these items would be
completed by 2015, enabling first oil from Orlando in the second half of
the year. Subsequent to December 31, 2013, the Company has determined
that some of these items will not be completed during 2014 and 2015, and
Iona now aims to achieve first oil from Orlando as early as possible in
2016.
-- The manufacture of line pipe and Xmas trees is substantially complete.
The copper cores for the umbilical are also complete and delivered to
the umbilical assembly plant. Manufacture of the control system is
ongoing and contractual arrangements for the balance of the project
supply chain are in the process of being finalized. Additionally, piping
tie-ins to the NCP have now been completed.
-- On April 16, 2013 the Department of Energy and Climate Change ("DECC")
advised the Orlando joint venture partners that it had approved the
Orlando Field Development Plan submitted by the partners.
Kells
-- Kells is currently slated for development through NCP following tie-in
of Orlando to the same facility. The Kells development plan comprises
two subsea production wells, an oil pipeline, a control umbilical, and
some pipework modifications at NCP. An FDP has been submitted and
project activity will be phased through 2015 and 2016, with first oil
expected in the second half of 2016. A subsequent water injection
project is planned to unlock additional reserves. This 2017 project will
involve the laying of water injection and gas lift lines, and the
conversion of the second well to water injection service.
Orlando & Kells (Sale of 25% working interest)
-- On February 21, 2013, Iona UK completed its sale of a 25% working
interest in its UK North Sea Orlando and Kells fields to Volantis
Exploration for total gross proceeds of $34 million and pro-rata share
of future staged payment obligations totaling $8.5 million. Iona
acquired its 100% operated working interest in the Orlando and Kells
fields for USD 5.35/boe. This accretive partial disposition saw the
company recognize a sale price of USD 7.03/boe.
Ronan & Oran
-- Since acquiring these oil discoveries in the 27th licencing round, Iona
has commenced reprocessing 270 km2 of 3D seismic data over the region,
and has conducted more detailed subsurface mapping of Ronan & Oran that
suggests the area of the discoveries may be greater than previously
thought. The three discovery wells all encountered oil 'down to' the
base of the reservoir without encountering oil-water contacts.
Subsurface mapping has shown the potential to add significant resources
through appraisal drilling which exist below known oil levels, and that
a potential oil-water contact 150 ft deeper could be mapped out to the
spill point lying to the northeast. A preliminary appraisal location has
been selected to penetrate and test the extension of this oil column
deeper into the basin to determine the extent of these resources.
-- The reprocessed 3D data should be received in July, after which a final
subsurface appraisal location will be confirmed. Iona is currently
contemplating the appraisal drilling in early 2015, and has initiated
the permitting, site survey, and procurement of a semi-submersible rig
to pursue this opportunity.
Highlights Subsequent to the Year End
Subsequent to the year-end the Company, through its wholly owned UK subsidiary,
Iona UK Developments Co Limited, entered into a Sale and Purchase Agreement
("SPA") with Perenco UK Limited ("Perenco"), to purchase Perenco's remaining 80%
working interest, rights, and obligations in the Trent & Tyne fields (including
the Trent East Discovery Area).
Upon satisfaction of certain conditions as set out in the SPA, the Company shall
pay to Perenco a sum of $20,000,000, adjusted pursuant to any adjustments as per
the SPA, and assume all decommissioning liabilities in relation to the licenses
being purchased. Payment shall be made no later than six (6) calendar months
after the date of the SPA or on such later date as agreed in writing.
Subsequent to the year-end the Company appointed Mr. Richard Ames as Iona's
Executive Vice President. Mr. Ames is currently a Director of Iona. Mr. Alan
Curran will remain as Chief Operating Officer until his departure in June 2014
and Mr. Graham Heath continues his roles as Interim Chief Financial Officer and
VP Corporate Development until a permanent replacement is found for the role of
CFO. Mr. Ames has 32 years of broad range experience in the oil and gas industry
with senior executive roles in full cycle oil and gas exploration and
production, information technology and oil and gas services.
CHANGE IN PRESENTATION CURRENCY
This press release is presented in United States dollars ("US dollars"). In
2013, the Company changed its presentation currency from the Canadian dollars
("CAD") to the US dollar. The change in presentation currency is to better
reflect the Company's business activities and to improve investors' ability to
compare the Company's financial results with other publicly traded businesses in
the oil and gas industry. In making this change to the US dollar presentation
currency, the Company followed the guidance in IAS 21 The Effects of Changes in
Foreign Exchange Rates and have applied the change retrospectively as if the new
presentation currency had always been the Company's presentation currency. In
accordance with IAS 21, the financial statements for all years and periods
presented have been translated to the new US dollar presentation currency. For
the 2012 comparative balances, assets and liabilities have been translated into
the presentation currency (US dollars) at the rate of exchange prevailing at the
reporting date. Items impacting income (loss) or comprehensive income (loss)
were translated at the average exchange rates for the reporting period, or at
the exchange rates prevailing at the date of transactions.
NON-GAAP FINANCIAL MEASURES
Throughout this press release, the Company uses the terms "funds flow", "funds
flow per share - basic". "funds flow per share - diluted", "Adjusted EBITDA",
"Adjusted EBITDA per share - basic", "Adjusted EBITDA per share - diluted",
"working capital" and "operating netback". These terms do not have any
standardized meaning as prescribed by IFRS and, therefore, may not be comparable
with the calculation of similar measures presented by other issuers. Management
uses working capital and operating netback measures. Working capital is
calculated as current assets less current liabilities, and is used to evaluate
the Corporation's financial leverage. Operating netback is a benchmark common in
the oil and gas industry and is calculated as total petroleum and natural gas
sales, less production and transportation expenses, calculated on a per barrel
equivalent ("boe") basis of sales volumes using a conversion. Operating netback
is an important measure in evaluating operational performance as it demonstrates
field level profitability relative to current commodity prices. Working capital
and operating netback as presented do not have any standardized meaning
prescribed by IFRS and therefore may not be comparable with the calculation of
similar measures for other entities.
Funds flow is calculated based on cash flow from operating activities before
changes in non-cash working capital. Adjusted EBITDA is calculated as net income
before finance costs, derivative gains and losses, taxes, depletion,
depreciation and amortization. Funds flow or Adjusted EBITDA per share - basic
and funds flow or Adjusted EBITDA per share - diluted are calculated as funds
flow or Adjusted EBITDA divided by the number of weighted average basic and
diluted shares outstanding, respectively. Management utilizes funds flow and
Adjusted EBITDA as key measures to assess the ability of the Company to finance
dividends, operating activities, capital expenditures and debt repayments. Funds
flow and Adjusted EBITDA as presented are not intended to represent cash flow
from operating activities, net earnings or other measures of financial
performance calculated in accordance with IFRS.
Notes:
The Company's petroleum and natural gas reserves (the "reserves") were
independently evaluated by Gaffney, Cline & Associates Ltd ("GCA") in accordance
with the Canadian Oil and Gas Evaluation Handbook ("COGEH") reserves definitions
and evaluation practices and procedures as specified by National Instrument 51-
101 ("NI 51-101"). The evaluation uses GCA's forecast prices and costs at
December 31, 2013. The Company's Form 51-101F1 Statement of reserves data for
the year ended December 31, 2013 ("Statement of Reserves Data"), which includes
the disclosure and reports relating to reserves data and other oil and gas
information along with the Form 51-101F2 Report on Reserves Data by GCA and Form
51-101F3 Report of Management and Directors on Reserves Data and Other
Information will be available for review at www.sedar.com.
Further details on the above are provided in the Consolidated Financial
Statements and Management's Discussion and Analysis for the year and quarter
ended December 31, 2013, which have been filed with securities regulatory
authorities in Canada. These documents are available on the System for
Electronic Document Analysis and Retrieval (SEDAR) at www.sedar.com and on the
Company's website: www.ionaenergy.com.
Iona is an oil and natural gas acquisition, appraisal, and development
corporation active through its 100% wholly owned United Kingdom subsidiary, Iona
Energy Company (UK) Ltd. in the United Kingdom's Continental Shelf ("UKCS").
Forward-looking statements
Some of the statements in this announcement are forward-looking, including
statements regarding Iona's plans for the development of its properties,
statements regarding acquisitions, estimated production levels, anticipated
effects of the UK small field allowance, and estimates of the net present value
of future net revenue of proved and probable reserves from Iona's properties.
Forward-looking statements include statements regarding the intent, belief and
current expectations of Iona Energy Inc. or its officers with respect to various
matters, including assumptions regarding Huntington production rates. When used
in this announcement, the words "expects," "believes," "anticipate," "plans,"
"may," "will," "should", "scheduled", "targeted", "estimated" and similar
expressions, and the negatives thereof, whether used in connection with
estimated production levels and future activity or otherwise, are intended to
identify forward-looking statements. Such statements are not promises or
guarantees, and are subject to risks and uncertainties that could cause actual
outcome to differ materially from those suggested by any such statements,
including without limitation, the risk that Iona's development plans change as a
result of new information or events or the risk that proposed transactions are
not completed. These forward-looking statements speak only as of the date of
this announcement. Iona Energy Inc. expressly disclaims any obligation or
undertaking to release publicly any updates or revisions to any forward-looking
statement contained herein to reflect any change in its expectations with regard
thereto or any change in events, conditions or circumstances on which any
forward-looking statement is based except as required by applicable securities
laws.
Note: "Boe" means barrel of oil equivalent on the basis of 6 mcf of natural gas
to 1 bbl of oil. Boes 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.
It should not be assumed that the present worth of estimated future net revenue
represents the fair market value of the reserves disclosed in this press
release. The reserve and related revenue estimates set forth in this press
release are estimates only and the actual reserves and realized revenue may be
greater or less than those calculated. The estimates of reserves and future net
revenue for individual properties may not reflect the same confidence level as
estimates of reserves and future net revenue for all properties, due to the
effects of aggregation. As used in this press release, "possible reserves" are
those additional reserves that are less certain to be recovered than probable
reserves. There is a 10% probability that the quantities actually recovered will
equal or exceed the sum of proved plus probable plus possible reserves.
Additionally, this press release uses certain abbreviations as follows:
Oil and Natural Gas Liquids Natural Gas
--------------------------------- ----------------------------------------
bbls barrels mcf thousand cubic feet
Mbbls thousand barrels mcf/d thousand cubic feet per day
MMbbls million barrels MMcf millions of cubic feet
bbls/d barrels per day MMcf/d millions of cubic feet per day
bopd barrels of oil per day Bcf billion cubic feet
NGLs natural gas liquids
Neither the TSX Venture Exchange Inc. nor its Regulation Services Provider (as
that term is defined in policies of the TSX Venture Exchange) accepts
responsibility for the adequacy or accuracy of this release.
FOR FURTHER INFORMATION PLEASE CONTACT:
Iona Energy Inc.
Neill A. Carson
Chief Executive Officer
+011 (44) 7919 057989
Iona Energy Inc.
Graham Heath
Interim Chief Financial Officer
+1 (403) 605-6726
info@ionaenergy.com
Dave Ricciardi
Investor Relations
+1 (403) 978 4894
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