Home / Press Releases / Sundance Energy Australia Limited Reports Second Quarter 2019 Financial and Operational Results

Sundance Energy Australia Limited Reports Second Quarter 2019 Financial and Operational Results

DENVER, Aug. 15, 2019 (GLOBE NEWSWIRE) — Sundance Energy Australia Limited (ASX: SEA) (NASDAQ: SNDE) (“Sundance” or the “Company”), a U.S. onshore oil and gas exploration and production company focused in the Eagle Ford in South Texas, reported its second quarter 2019 financial and operations results today.

Second Quarter 2019 Financial Results Highlights

  • Second quarter net sales volumes were 1,264,686 boe or 13,898 boe per day, at the top end of the Company’s public guidance. This represents an increase of ~79% as compared to the same period for the prior year. Second quarter sales volumes were ~59% oil, ~22% gas and ~19% NGLs.
  • The higher than expected gas to oil ratio (“GOR”) for the quarter was driven by two primary factors.
    • The Dimmit assets, and in specific the two well Red Ranch pad brought online in late first quarter, produced at a ~23% oil cut. Pro Forma for the recently announced Dimmit divestiture expected to close in September 2019, oil would have represented ~62% of total sales volumes.
    • Additionally, the four well Roy Esse pad which was brought online during the quarter produced at the expected oil production rate but overachieved in terms of gas production, further increasing the Company’s second quarter GOR.
  • Total revenue for the quarter increased ~84% to US $52.9 million as compared to the same prior year period.
  • Net Income attributable to owners of the Company for the period was US $3.8 million. Adjusted EBITDAX1 for the period was US $33.7 million, representing a ~64% Adjusted EBITDAX margin and ~230% growth as compared to the same period for the prior year.  Adjusted EBITDAX1 for the quarter was slightly below the Company’s guidance primarily due to the lower oil cut and the impact of realized NGL and gas prices.
  • Average second quarter realized prices excluding the impact of hedging were US $61.93 per barrel of oil, US $2.08 per mcf of gas, and US $13.59 per barrel of NGL. This represents a US $2.17 per barrel premium compared to an average WTI price of US $59.76 per barrel for the quarter. Average second quarter realized price per boe including the impact of hedges was US $41.70.
  • Sundance continued to drive down cash operating costs during the second quarter. Total Cash Operating Costs2 of US $15.01 per boe improved 35% as compared to the same prior year period and a 16% improvement as compared to the Company’s first quarter 2019 Cash Operating Costs, primarily due to lower cash General and Administrative (“G&A”), Lease Operating Expense (“LOE”) and Workover expenses per boe.
    • Most notably, LOE of US $5.43 per boe has decreased ~48% as compared to the same prior year period and ~31% as compared to the first quarter 2019.
    • Cash operating costs for the quarter were below guidance of US $17.95 per boe by US $2.94 per boe, or ~16%.
  • As of 1 August 2019, the Company’s oil hedges covered a total of 4,695,000 barrels through 2023. Hedging covered approximately ~8,000 barrels of oil per day for the remainder of 2019 with a weighted average floor of US $60.32 per barrel. These figures represent ~76% of the remainder of 2019 expected oil sales and exclude hedges which have rolled off during the first seven months of 2019.
  • Second quarter development and production related expenditures totaled US $44.3 million, below the low end of capital expenditure guidance of US $45-50 million.
  • Subsequent to the end of the second quarter, the Company announced that it had entered into a definitive agreement to sell its assets in Dimmit County, TX for a purchase price of USD $29.5 million, subject to customary adjustments at closing. The sale is anticipated to close in September 2019.

_______________________________
1 Adjusted EBITDAX is a Non-IFRS measure, please see reconciliation to net income (loss) attributable to owners of Sundance at the end of this release.

2 Cash Operating Costs is a Non-IFRS measure comprising lease operating expenses, including workover expenses, gathering, processing and transportation expenses, production tax expense and general and administrative expenses, excluding share-based compensation and transaction related expenses.

Second Quarter 2019 Operational Highlights

  • Sundance brought 6.0 gross (6.0 net) wells onto production during the second quarter, including the 4.0 gross (4.0 net) well Roy Esse pad in Live Oak County and the 2.0 gross (2.0 net) well Bracken pad in McMullen County.
  • During the second quarter the Company additionally drilled the 4.0 gross (4.0 net) well HT Chapman pad and the first two wells of the 4.0 gross (4.0 net) well H Harlan Bethune pad in Live Oak County. Year to date the Company’s average spud to rig release time was 11.5 days, an improvement of 33% as compared to 2018 average spud to rig release time of 17.24 days.
  • The Company exited the quarter with 6.0 gross (6.0 net) drilled uncompleted (“DUC”) wells in Live Oak County.
    • The HT Chapman pad was turned to sales on 14 August 2019.
    • Drilling of the final two wells of the H Harlan Bethune pad was finalized and the pad is in the process of being completed as of the date of this report.
  • The Company additionally completed the 4.0 gross (4.0 net) well Georgia Buck pad in Live Oak County but delayed turning those wells to sales and left them temporarily shut in to protect them while an offset operator finalized nearby completion activities.
    • Subsequent to the quarter’s end, the Georgia Buck wells were turned to sales on 24 July 2019 and through the date of this report averaged >1,100 boe/d per well for peak 24-hour rates with approximately an 85% oil cut.
  • As of the date of this report, the Company was in the process of drilling the 2.0 gross (2.0 net) well Justin Tom pad in Atascosa County. The Justin Tom wells are being drilled with a targeted extended lateral length of 12,900 feet.
  • On May 29th, Sundance and its midstream partner completed the previously announced capacity expansion of the CGP-41 gas processing plant through the installation of two additional compressors. This expansion work increased the operating gas processing capacity of the plant to 18 mmcfd, sufficient to handle Sundance’s current production in the CGP-41 area. Subsequent to this expansion, Sundance has begun working with its midstream partner to further expand CGP-41 towards its design capacity to accommodate several years of resource development growth. This second round of expansions is expected to be completed during the fourth quarter. Similar to the initial expansion, any such subsequent expansions would be funded by Sundance’s midstream partner up to US $10 million cumulative capital costs.

Third Quarter and Full Year 2019 Guidance Highlights

  • Sundance believes it has reached its peak drawn debt level at the end of Q2 and will be free cash flow positive in the second half of 2019.
  • During the third quarter, the Company anticipates average sales volumes of 14,000 to 14,500 boe per day driven by 12 new Live Oak wells that will produce an average of approximately 30 days per well during the quarter. Sales volumes guidance for full year 2019 remains unchanged at 14,000 to 15,000 boe per day. The Company anticipates an oil cut during the third quarter of ~60% by sales volume.
  • The Company now intends to bring 22 wells online during full year 2019, with certain of those wells being extended reach laterals. During the third quarter, the Company intends to spud 4 total wells and place 12 wells onto production.
  • Second half capital spending guidance is US $60 to 65 million. Third quarter capital spending represents most of this amount, ranging from US $45 to 60 million pending exact completion timing for the extended reach Justin Toms wells which are the last wells the Company will bring online during 2019.  Full Year Capital cost guidance remains unchanged at US $135 to $155 million.

The table below provides an overview of the Company’s operational activity for year-to-date 20193:

Well Name County Spud
Date
IP
Date
Lateral
Length
Peak
24-Hr IP
30-Day
Avg

(boepd)
30-Day /
1,000′ ft
60-Day
Avg

(boepd)
60-Day /
1,000′ ft
%
Oil
Bracken 22H McMullen 24-Jan-19 2-Apr-19 6,792 1,690 1,053 155 964 142 76 %
Bracken 23H McMullen 22-Jan-19 2-Apr-19 6,630 1,397 856 129 824 124 76 %
Roy Esse  15H Live Oak 1-Dec-18 5-May-19 4,718 1,222 864 183 848 180 72 %
Roy Esse  16H Live Oak 28-Nov-18 5-May-19 4,792 1,371 988 206 912 190 75 %
Roy Esse  17H Live Oak 26-Nov-18 5-May-19 4,657 1,077 785 169 743 160 76 %
Roy Esse  18H Live Oak 24-Nov-18 5-May-19 4,702 1,099 805 171 753 160 73 %
Georgia Buck 01H Live Oak 21-Feb-19 24-Jul-19 3,971 1,200 86 %
Georgia Buck 02H Live Oak 23-Feb-19 24-Jul-19 3,814 1,071 86 %
Georgia Buck 03H Live Oak 25-Feb-19 24-Jul-19 3,792 1,133 84 %
Georgia Buck 10H Live Oak 26-Feb-19 24-Jul-19 3,917 1,105 85 %
HT Chapman 11H Live Oak 16-Apr-19 14-Aug-19 5,287
HT Chapman 12H Live Oak 14-Apr-19 14-Aug-19 5,943
HT Chapman 13H Live Oak 12-Apr-19 14-Aug-19 5,894
HT Chapman 14H Live Oak 10-Apr-19 14-Aug-19 5,763
H Harlan Bethune 15H Live Oak 31-May-19
H Harlan Bethune 16H Live Oak 2-Jun-19
H Harlan Bethune 17H Live Oak 4-Jun-19
H Harlan Bethune 18H Live Oak 6-Jun-19
Justin Tom 08H Atascosa 30-Jul-19
Justin Tom 09H Atascosa 25-Jul-19

_______________________
3 Excludes the Red Ranch 18H & 19H wells in Dimmit County.

The tables below set forth the Company’s hedge position as of 15th August 20194:

 HEDGE POSITION OVERVIEW
Total Oil Derivative Contracts Gas Derivative Contracts
Weighted Average Weighted Average
Year Units (Bbls) Floor Ceiling Units (Mcf) Floor Ceiling
2019 1,229,000 $60.32 $68.19 1,305,000 $2.86 $3.13
2020 2,046,000 $56.92 $60.49 1,536,000 $2.65 $2.70
2021 732,000 $50.37 $59.34 1,200,000 $2.66 $2.66
2022 528,000 $45.68 $60.83 1,080,000 $2.69 $2.69
2023 160,000 $40.00 $63.10 240,000 $2.64 $2.64
Total 4,695,000 $54.95
$62.45
5,361,000 $2.71
$2.79
CRUDE OIL HEDGE POSITION BY BASIS
LLS Derivative Contracts Brent Derivative Contracts WTI Derivative Contracts
Weighted Average Weighted Average Weighted Average
Year Units (Bbls) Floor Ceiling Units (Bbls) Floor Ceiling Units (Bbls) Floor Ceiling
2019 70,000 $52.51 $62.51 359,000 $58.72 $71.06 800,000 $61.72 $67.39
2020 2,046,000 $56.92 $60.49
2021 732,000 $50.37 $59.34
2022 528,000 $45.68 $60.83
2023 160,000 $40.00 $63.10
Total 70,000 $52.51 $62.51 359,000 $58.72 $71.06 4,266,000 $54.67 $61.73

_________________________
4 Excludes realized hedge volumes which rolled off during the first seven months of 2019. WTI pricing includes the impact of WTI-MEH basis hedges.

The following unaudited tables present certain production, per unit metrics and Adjusted EBITDAX that compare results of the corresponding quarterly reporting periods:

Three Months Ended June 30,   Six Months Ended June 30,      
Unaudited 2019   2018   2019   2018   % Change
Net Sales Volumes
Oil (Bbls) 745,130 380,534 1,467,525 745,774 96 % 97 %
Natural gas (Mcf) 1,688,005 1,242,251 2,960,551 2,126,674 36 % 39 %
NGL (Bbls) 238,223 118,506 410,958 198,019 101 % 108 %
Total sales (Boe) 1,264,686 706,081 2,371,909 1,298,239 79 % 83 %
Average Daily Volumes
Average daily sales 13,898 7,759 13,104 7,173 79 % 83 %
Product Price Received
Total price received (per Boe) $41.83 $45.19 $42.43 $45.81 (7 %) (7 %)
Total realized price (per Boe)(1)(2)(3) $41.70 $37.42 $43.94 $37.64 11 % 17 %
Total price received – Oil (per Bbl) $61.93 $68.57 $59.24 $66.73 (10 %) (11 %)
Total price realized – Oil (per Bbl)(1) $61.21 $53.73 $61.18 $52.29 14 % 17 %
Total price received – Natural gas (per Mcf) $2.08 $2.45 $2.29 $2.45 (15 %) (6 %)
Total price realized – Natural gas (per Mcf)(2) $2.20 $2.52 $2.43 $2.50 (13 %) (3 %)
Total price received – NGL (per Bbl) $13.59 $24.00 $16.80 $23.04 (43 %) (27 %)
Total price realized – NGL (per Bbl)(3) $14.33 $24.00 $17.65 $23.04 (40 %) (23 %)
(1) Includes realized losses on oil derivatives of $0.2 million and $2.3 million for the three months ended June 30, 2019 and 2018, respectively, and realized gains of $3.6 million and realized losses of $3.9 million for the six months ended June 30, 2019 and 2018, respectively.  Also includes the impact of a fixed price delivery contract of $8.54/Bbl and $9.09/Bbl for the three and six months ended June 30, 2018, respectively.
(2) Includes realized gains on natural gas derivatives of $0.2 million and $0.1 million for the three months ended June 30, 2019 and 2018, respectively, and realized gains of $0.4 million and $0.1 million for the six months ended June 30, 2019 and 2018, respectively.
(3) Includes realized gains on NGL derivatives of $0.2 million and $0.3 million for the three and six months ended June 30, 2019, respectively.
UNIT COST ANALYSIS Three Months Ended June 30,       Six Months Ended June 30,    
Unaudited 2019     2018   Change   2019   2018   Change
Revenue/Boe (Inclusive of Hedging) $ 41.70 $ 37.42 11 % $ 43.94 $ 37.64 17 %
Lease operating expense/Boe (5.43 ) (10.45 ) (48 %) (6.55 ) (9.88 ) (34 %)
Workover expense/Boe (1.14 ) (1.85 ) (38 %) (1.22 ) (1.94 ) (37 %)
Gathering, processing and transportation /Boe (2.95 ) (1.19 ) 148 % (2.77 ) (0.65 ) 327 %
Production taxes/Boe (2.46 ) (2.67 ) (8 %) (2.63 ) (1.49 ) 77 %
Cash G&A/Boe(1) (3.03 ) (6.84 ) (56 %) (3.19 ) (5.77 ) (45 %)
Net EBITDAX Margin per Boe $ 26.69 $ 14.42 85 % $ 27.58 $ 17.91 54 %
   
Adjusted EBITDAX(2) $ 33,730 $ 10,211 230 % $ 65,435 $ 21,491 204 %
Adjusted EBITDAX Margin (3) 64.0 % 38.7 % 65 % 62.8 % 44.0 % 43 %
(1) Cash G&A represents general and administrative expenses (non transaction-related) incurred less equity-settled share based compensation expense, which totaled $0.1 million and $(0.2) million for the three months ended June 30, 2019 and 2018, respectively, and $0.3 million and $0.2 million for the six months ended June 30, 2019 and 2018, respectively.
(2) See reconciliation of income (loss) attributable to owners of the Company to Adjusted EBITDAX included at end of release.
(3) Adjusted EBITDAX Margin represents Adjusted EBITDAX as a percentage of revenue, inclusive of commodity derivative settlements, during the period.


Condensed Consolidated Financial Statements
The Company’s unaudited condensed consolidated financial statements are included below.

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
Three Months Ended June 30, Six Months Ended June 30,
Unaudited (US$000s) 2019   2018 2019   2018
Revenue $ 52,901 $ 28,729 $ 100,641 $ 52,765
Lease operating, workover and production tax expenses (11,411 ) (10,568 ) (24,668 ) (19,082 )
Gathering, processing and transportation expenses (3,735 ) (840 ) (6,560 ) (840 )
General and administrative expenses (non transaction-related) (3,970 ) (4,644 ) (7,838 ) (7,675 )
Transaction-related expense (487 ) (11,351 ) (1,014 ) (12,377 )
Depreciation and amortisation expense (20,927 ) (15,027 ) (41,265 ) (27,214 )
Impairment expense (5,761 ) (18,936 ) (9,240 ) (21,893 )
Finance costs, net of amounts capitalized (8,366 ) (6,363 ) (16,609 ) (10,346 )
Gain (loss) on commodity hedging, net (1) 10,286 (16,496 ) (23,057 ) (23,180 )
Loss on interest rate derivative financial instruments, net (2) (2,406 ) (434 ) (4,026 ) (434 )
Loss on debt extinguishment (2,428 ) (2,428 )
Other items income (expense), net (3) (229 ) 5,656 (210 ) 6,721
Gain (loss) before income tax    5,895   (52,702 )   (33,846 )   (65,983 )
Income tax benefit (expense) (2,119 ) (5,307 ) 6,201 (7,610 )
Gain (loss) attributable to owners of the Company $    3,776 $    (58,009 ) $    (27,645 ) $    (73,593 )
(1) Included an unrealized gain on commodity hedging of $10.5 million and an unrealized loss of $14.2 million for the three months ended June 30, 2019 and 2018, respectively, and unrealized losses of $26.6 million and $19.3 million for the year ended June 30, 2019 and 2018, respectively.
(2) Included an unrealized loss on interest rate swaps of $2.4 million and $0.4 million for the three months ended June 30, 2019 and 2018, respectively, and unrealized losses of $4.1 million and $0.4 million for the six months ended June 30, 2019 and 2018, respectively.
(3) Included a realized gain on foreign currency derivatives of $5.8 million and $6.8 million for the three and six months ended June 30, 2018, respectively.
CONDENSED CONSOLIDATED BALANCE SHEETS
       
(US$’000s) June 30, 2019   December 31, 2018
  (Unaudited)   (Audited)
Cash $ 977 $ 1,581
Trade and other receivables 16,623 23,633
Derivative assets – current 4,123 24,315
Other current assets 3,907 3,546
Assets held for sale(1) 23,746 24,284
Total current assets 49,376 77,359
Oil and gas properties 755,118 712,870
Derivative assets – non current 2,033 8,003
Lease right-of-use assets 12,592
Other assets 3,481 3,847
Total assets $    822,600   $    802,079
Current liabilities $ 64,108 $ 70,919
Derivative liabilities – current 2,218 436
Lease liabilities – current 6,942
Liabilities held for sale(1) 1,245 1,125
Total current liabilities 74,513 72,480
Credit facilities, net of financing fees 341,922 300,440
Derivative liabilities – non current 5,288 2,578
Lease liabilities – non current 5,693
Other non current liabilities 29,160 33,206
Total liabilities $    456,576   $    408,704
Net assets $    366,024   $    393,375
Equity $    366,024   $    393,375
(1) The Company’s Dimmit County Eagle Ford assets (and related liabilities) were classified as held for sale as of June 30, 2019 and December 31, 2018.  In July 2019, the Company entered into a definitive agreement to sell its Dimmit County assets for a purchase price of $29.5 million, subject to customary adjustments at closing.  The sale is expected to close by the end of the third quarter.
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS  
 
Six Months Ended June 30,
Unaudited (US$000s) 2019   2018
Operating
Receipts from sales $ 102,867 $ 49,620
Payments for operating and administrative expenses (42,145 ) (41,204 )
Settlements of restoration provision (116 ) (29 )
Receipts (payments) for commodity derivative settlements, net 6,638 (3,667 )
Other, net (2,301 )
Net cash provided by operating activities  $ 67,244 $ 2,419
Investing
Payments for development expenditures (92,252 ) (40,717 )
Payments for exploration expenditures (564 ) (1,927 )
Payment for Eagle Ford acquisition, net (220,132 )
Sale of non current assets 50
Other (121 ) (79 )
Net cash used in investing activities $ (92,887 ) $ (262,855 )
Financing
Interest paid, net of capitalized portion (14,732 ) (12,436 )
Deferred financing costs capitalized (232 ) (16,724 )
Proceeds from borrowings 40,000 250,000
Repayments of borrowings (including production prepayment) (210,194 )
Proceeds from the issuance of shares 253,517
Payments for the costs of capital raisings (10,260 )
Receipts from settlements of foreign currency derivatives 6,849
Other 2
Net cash provided by financing activities $ 25,038 $ 260,752
Total Net Cash Provided (Used) $    (605 )   $    316
Cash beginning of year $    1,581   $    5,761
FX effect 1 180
Cash at end of period $    977   $    6,257


Conference Call
The Company will host a conference call for investors on Thursday 15th August, 2019 at 4 p.m. MDT (Friday, 16th August, 2019 at 8 a.m. AEST).

Interested investors can listen to the call via webcast at https://edge.media-server.com/m6/p/4tsj3ygb. The webcast will also be available for replay on the Company’s website.

Additional Information
We define “Adjusted EBITDAX”, a non-IFRS measure, as earnings before interest expense, income taxes, depreciation, depletion and amortization, property impairments, gain/(loss) on sale of non-current assets, exploration expense, share based compensation and income, gains and losses on commodity hedging, net of settlements of commodity hedging and items that the Company believes affect the comparability of operating results such as items whose timing and/or amount cannot be reasonably estimated or items that are non-recurring. Management uses Adjusted EBITDAX to facilitate comparisons of its performance between periods and to the performance of its peers.  This non-IFRS financial measure should not be considered as a substitute for, nor superior to, measures of financial performance prepared in accordance with IFRS.

Below is a reconciliation from the net income (loss) attributable to owners of the Company to Adjusted EBITDAX:

IFRS Income (Loss) Attributable to Owners of Sundance Reconciliation to Adjusted EBITDAX
 Three Months Ended June 30,   Six Months Ended June 30, 
Unaudited (US$000s)  2019   2018   2019   2018 
Income (loss) attributable to owners of the Company $ 3,776 $ (58,009 ) $ (27,645 ) $ (73,593 )
Income tax expense (benefit) 2,119 5,307 (6,201 ) 7,610
Finance costs, net of amounts capitalized 8,366 6,363 16,609 10,346
Loss on debt extinguishment 2,428 2,428
(Gain) loss on derivative financial instruments, net (10,286 ) 16,496 23,057 23,180
Settlement of commodity derivatives financial instruments (168 ) (2,311 ) 3,583 (3,894 )
Loss on interest rate derivative financial instruments, net 2,406 434 4,026 434
Depreciation and amortization 20,927 15,027 41,265 27,214
Impairment expense 5,761 18,936 9,240 21,893
Noncash share-based compensation 142 (184 ) 277 186
Transaction-related costs included in general and administrative expenses and other 487 11,351 1,014 12,377
Gain on foreign currency derivatives (5,766 ) (6,838 )
Other (income) expense, net 200 139 210 148
Adjusted EBITDAX $    33,730 $    10,211 $    65,435 $    21,491

The Company reports under International Financial Reporting Standards (IFRS).  All amounts are reported in US dollars unless otherwise noted.

The Company’s full Unaudited Activities Report as filed with the Australian Securities Exchange (ASX) and Securities and Exchange Commission on Form 6-K for the Quarter Ended June 30, 2019 can be found at www.sundanceenergy.net.

The Company’s 2018 Annual Report as filed with the ASX and Form 20-F as filed with the SEC can be found at www.sundanceenergy.net.

About Sundance Energy Australia Limited

Sundance Energy Australia Limited (“Sundance” or the “Company”) is an Australian-based, independent energy exploration company, with a wholly owned US subsidiary, Sundance Energy Inc., located in Denver, Colorado, USA. The Company is focused on the acquisition and development of large, repeatable oil and natural gas resource plays in North America. Current activities are focused in the Eagle Ford.  A comprehensive overview of the Company can be found on Sundance’s website at www.sundanceenergy.net.

Summary Information

The following disclaimer applies to this document and any information contained in it. The information in this release is of general background and does not purport to be complete. It should be read in conjunction with Sundance’s periodic and continuous disclosure announcements lodged with ASX Limited that are available at www.asx.com.au and Sundance’s filings with the Securities and Exchange Commission available at www.sec.gov

Forward Looking Statements

This release may contain forward-looking statements. These statements relate to the Company’s expectations, beliefs, intentions or strategies regarding the future. These statements can be identified by the use of words like “anticipate”, “believe”, “intend”, “estimate”, “expect”, “may”, “plan”, “project”, “will”, “should”, “seek” and similar words or expressions containing same.

These forward-looking statements reflect the Company’s views and assumptions with respect to future events as of the date of this release and are subject to a variety of unpredictable risks, uncertainties, and other unknowns. Actual and future results and trends could differ materially from those set forth in such statements due to various factors, many of which are beyond our ability to control or predict. These include, but are not limited to, risks or uncertainties associated with the discovery and development of oil and natural gas reserves, cash flows and liquidity, business and financial strategy, budget, projections and operating results, oil and natural gas prices, amount, nature and timing of capital expenditures, including future development costs, availability and terms of capital and general economic and business conditions. Given these uncertainties, no one should place undue reliance on any forward looking statements attributable to Sundance, or any of its affiliates or persons acting on its behalf.  Although every effort has been made to ensure this release sets forth a fair and accurate view, we do not undertake any obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

For more information, please contact:

United States:
John Roberts
VP Finance & Investor Relations
Tel: +1 (720) 638-2400
Eric McCrady
CEO and Managing Director
Tel: +1 (303) 543-5703
Australia:
Mike Hannell
Chairman
Tel: + 61 8 8274 2128 or
+ 61 418 834 957

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