CALGARY, Feb. 6, 2020 /CNW/ - Yangarra
Resources Ltd. ("Yangarra" or the
"Company") (TSX:YGR) releases operations update and the
results of its 2019 year end oil and gas reserves evaluation.
Operations Update
In 2019 Yangarra achieved several key milestones, including the
construction of a 100% owned gas plant, the doubling of capacity on
one of its existing gas plants, the addition of a new core area and
additional ESG initiatives that will benefit Yangarra shareholders
from 2020 onwards as the Company transitions to free cash flow
generation.
Yangarra originally planned to drill & complete 24 wells in
2019; however, budget was re-directed to infrastructure to
accommodate Chedderville opportunities and as a result elected to
drill & complete 17 wells in 2019.
Despite the limited drilling program, Yangarra's yearly average
production was 12,550 boe/d (33% growth from an average of 9,425
boe/d in 2018) with fourth quarter production expected to average
12,500 boe/d. The average production is lower than guidance due to
the reduced drilling & completions program. The infrastructure
capital spend in the first quarter of 2019 resulted in lower
operating costs and the reduced costs are reflected in the
Company's independent reserves report as prepared by Deloitte LLP
which is effective as of December 31,
2019 (the "2019 Reserve Report").
The Company recognized in late Q4 that industry was rapidly
mobilizing in Alberta, commodity
prices were improving and to ensure crews and equipment were not
lost to competitors, the Board of Directors approved an
acceleration of 2020 capital spending into 2019, resulting in a
2019 budget of $121 million. This
allowed for 3 additional wells to be drilled late in the year and
they were put onstream in January
2020. The Company's revised 2020 budget will be $105 million (originally $120 million), the production guidance range of
14,000-15,000 boe/d remains unchanged.
As highlighted by recent well results, Yangarra plans to focus
the 2020 program primarily on higher IRR wells in the Chedderville
area and will continue to implement the Company's refined
completions strategy that had positive results in late 2019.
Yangarra's land position in Chedderville has increased from 9.5
sections, January 1, 2018 to 62
sections of Cardium land today. The infrastructure build in late
2018 and early 2019 is key to positioning the Company to support
drilling in this area for several years to come.
Updated Corporate Presentation
An updated corporate presentation is available on the Company
website: www.yangarra.ca.
Reserve Report Highlights:
All reserves information contained in this press release is
based on the 2019 Reserve Report. Unless specifically indicated,
all financial and operational information in this press
release is based on estimates and is unaudited and accordingly,
such financial information is subject to change based on the
results of the Company's year-end audit.
Proved Developed Producing ("PDP") Reserves
- 25.5 million boe (9% increase from 2018)
- Net present value before tax discounted at 10% ("NPV10") of
$414 million (5% increase from 2018),
including abandonment capital for all producing and non-producing
wells
- Finding and development costs ("F&D") of $18.10/boe, resulting in a PDP recycle ratio of
1.24 times; 2019 F&D costs were impacted by the significant
facilities spending in the first quarter. This allowed Yangarra to
both reduce its corporate operating costs on its existing plays and
allowed Yangarra to maintain its low-cost structure throughout the
new Chedderville area
- PDP net asset value per fully diluted common share ("NAV per FD
Share") of $2.63
- PDP additions replaced 146% of 2019 production
- PDP reserve additions were impacted by the testing of 15
tons per stage on completions during 2019, upon evaluation Yangarra
discovered the old program of 20 tons per stage provided
significantly better results and those improvements are
reflected in the 1P and 2P bookings
Proved Non-Producing ("PNP") Reserves
- 2.2 million boe
- NPV10 of $40 million
- The majority of the PNP value consists of the three wells that
were drilled before year-end. All these wells are now
producing
- PDP + PNP NAV per FD Share of $3.08
Total Proved reserves ("1P")
- 85.6 million boe (13% increase from 2018)
- NPV10 of $1.1 billion (no change
from 2018)
- The Deloitte price forecast was 10-15% lower in the later years
for all products for the 2019 report versus 2018
- 1P future development costs of $429
million
- F&D costs of $10.74/boe
resulting in a recycle ratio of 2.08 times
- 1P NAV per FD Share of $10.66
- 1P Reserve Life Index ("RLI") based on fourth quarter 2019
production of 18.8 years
- 1P additions replaced 320% of 2019 production
Proved plus probable reserves ("2P")
- 145.6 million boe (15% increase from 2018)
- NPV10 of $1.7 billion (no change
from 2018)
- 2P Future development costs of $650
million
- The Deloitte price forecast was 10-15% lower in the later years
for all products for the 2019 report versus 2018
- Finding and development costs of $6.86/boe resulting in a recycle ratio of 3.26
times
- 2P NAV per FD Share of $17.05
- RLI of 31.9 years
- 2P additions replaced 522% of 2019 production
Oil and Gas Reserves
The following tables summarize certain information contained in
the 2019 Reserve Report. The 2019 Reserve Report encompasses 100%
of Yangarra's oil and gas properties and was prepared in accordance
with definitions, standards and procedures contained in the
Canadian Oil and Gas Evaluation Handbook and National Instrument
51-101 - Standards of Disclosure for Oil and Gas Activities
("NI 51-101") by Deloitte.
Summary of Oil and Gas Reserves
(1)(2)
(Company Share Gross volumes based
on forecast price and costs)
Reserves
Category
|
|
|
|
|
|
|
|
Light
and
Medium
Oil
(Mbbl)
|
Natural
Gas
Liquids
(Mbbl)
|
Natural
Gas
(MMcf)
|
Total
BOE
2019
(Mboe)
|
|
Total
BOE
2018
(Mboe)
|
Proved Developed
Producing
|
5,344
|
5,477
|
88,183
|
25,518
|
|
23,412
|
Proved Developed
Non-Producing
|
620
|
423
|
6,802
|
2,176
|
|
1,917
|
Proved
Undeveloped
|
13,225
|
12,149
|
195,141
|
57,897
|
|
50,178
|
Total
Proved
|
19,189
|
18,049
|
290,126
|
85,592
|
|
75,507
|
Probable
|
12,553
|
13,324
|
205,010
|
60,045
|
|
50,799
|
Total Proved Plus
Probable
|
31,741
|
31,373
|
495,136
|
145,637
|
|
126,305
|
|
Notes to
table:
|
(1)
|
Total values may not
add due to rounding.
|
(2)
|
BOEs are derived by
converting gas to oil equivalent in the ratio of six thousand cubic
feet of gas to one barrel of oil (6 Mcf:1 bbl).
|
Summary of Net Present Values of Future Net Revenue (Before Tax)
(1)(4)
(Based on forecast price and costs)
|
As At December 31,
2019(2)
|
|
As
At December 31,
2018 (3)
|
Reserves
Category
|
0.0% (M$)
|
5.0% (M$)
|
10.0% (M$)
|
15.0% (M$)
|
20.0% (M$)
|
|
10.0% (M$)
|
Proved Developed
Producing
|
660,728
|
507,846
|
413,669
|
351,521
|
307,629
|
|
393,103
|
Proved Developed
Non-
Producing
|
59,131
|
46,963
|
39,514
|
34,480
|
30,834
|
|
47,202
|
Proved
Undeveloped
|
1,243,947
|
878,215
|
659,274
|
516,407
|
417,228
|
|
678,893
|
Total
Proved
|
1,963,806
|
1,433,024
|
1,112,457
|
902,409
|
755,692
|
|
1,119,198
|
Probable
|
1,613,536
|
880,489
|
556,057
|
384,367
|
282,467
|
|
566,699
|
Total Proved Plus
Probable
|
3,577,342
|
2,313,513
|
1,668,514
|
1,286,776
|
1,038,159
|
|
1,685,897
|
|
Notes to
table:
|
|
|
(1)
|
Total values may not
add due to rounding.
|
(2)
|
Forecast pricing used is based on Deloitte
published price forecasts effective December
31, 2019.
|
(3)
|
Forecast pricing used is based on Deloitte
published price forecasts effective December
31, 2018.
|
(4)
|
Cash flows are
reduced for future abandonment costs and estimated capital for
future development associated with the reserves.
|
|
|
Reserve
Definitions:
|
(a)
|
"Proved" reserves are
those reserves that can be estimated with a high degree of
certainty to be recoverable. It is likely that the actual remaining
quantities recovered will exceed the estimated proved
reserves.
|
(b)
|
"Probable" reserves
are those additional reserves that are less certain to be recovered
than proved reserves. It is equally likely that the actual
remaining quantities recovered will be greater or less than the sum
of the estimated proved plus probable reserves.
|
(c)
|
"Developed" reserves
are those reserves that are expected to be recovered from existing
wells and installed facilities or, if facilities have not been
installed, that would involve a low expenditure (e.g. when compared
to the cost of drilling a well) to put the reserves on
production.
|
(d)
|
"Developed Producing"
reserves are those reserves that are expected to be recovered from
completion intervals open at the time of the estimate. These
reserves may be currently producing or, if shut-in, they must have
previously been on production, and the date of resumption of
production must be known with reasonable certainty.
|
(e)
|
"Developed
Non-Producing" reserves are those reserves that either have not
been on production, or have previously been on production, but are
shut in, and the date of resumption of production is
unknown.
|
(f)
|
"Undeveloped"
reserves are those reserves expected to be recovered from known
accumulations where a significant expenditure (for example, when
compared to the cost of drilling a well) is required to render them
capable of production. They must fully meet the requirements of the
reserves classification (proved, probable, possible) to which they
are assigned.
|
Reconciliations of Changes in Reserves
The following table sets out a reconciliation of the changes in
the Corporation's reserves as at December
31, 2019 against such reserves at December 31, 2018 based on forecast prices and
cost assumptions:
|
Light and Medium
Oil
|
Natural Gas
Liquids
|
|
Gross
Proved
|
Gross Probable
|
Gross
Proved Plus
Probable
|
Gross Proved
|
Gross
Probable
|
Gross Proved
Plus
Probable
|
|
(Mstb)
|
(Mstb)
|
(Mstb)
|
(Mstb)
|
(Mstb)
|
(Mstb)
|
Opening
Balance
|
19,562.5
|
13,048.1
|
32,610.7
|
15,577.6
|
10,690.6
|
26,268.2
|
Production
|
-1,448.7
|
-
|
-1,448.7
|
-905.5
|
-
|
-905.5
|
Technical
Revisions
|
-1,552.0
|
-2,234.4
|
-3,786.5
|
1,530.2
|
1,312.5
|
2,842.7
|
Extensions
|
2,633.8
|
1,742.3
|
4,376.1
|
1,805.2
|
1,280.6
|
3,085.8
|
Economic
Factors
|
-9.5
|
-6.3
|
-15.8
|
-11.0
|
-6.2
|
-17.2
|
Closing
Balance
|
19,186.1
|
12,549.7
|
31,735.8
|
17,996.4
|
13,277.5
|
31,273.9
|
Royalty
Interest
|
3.0
|
3.0
|
5.0
|
53.0
|
47.0
|
99.0
|
|
|
|
|
Gas
|
MBOE
|
|
Gross Proved
|
Gross
Probable
|
Gross Proved
Plus
Probable
|
Gross
Proved
|
Gross
Probable
|
Gross Proved
Plus
Probable
|
|
(MMcf)
|
(MMcf)
|
(MMcf)
|
(MBOE)
|
(MBOE)
|
(MBOE)
|
Opening
Balance
|
241,075.3
|
161,356.1
|
402,431.4
|
75,319.3
|
50,631.4
|
125,950.8
|
Production
|
-14,569.0
|
-
|
-14,569.0
|
-4,782.4
|
-
|
-4,782.4
|
Technical
Revisions
|
33,786.4
|
22,632.0
|
56,418.5
|
5,609.2
|
2,850.1
|
8,459.2
|
Extensions
|
29,267.5
|
20,457.2
|
49,724.6
|
9,316.9
|
6,432.5
|
15,749.4
|
Economic
Factors
|
-185.6
|
-102.2
|
-287.8
|
-51.4
|
-29.5
|
-81.0
|
Closing
Balance
|
289,374.6
|
204,343.1
|
493,717.7
|
85,411.6
|
59,884.4
|
145,296.0
|
Royalty
Interest
|
751.0
|
667.0
|
1,419.0
|
180.0
|
161.0
|
341.0
|
Forecast Prices Used in Estimates
The forecast price and market forecasts prepared by Deloitte are
based on information available from numerous government agencies,
industry publication, oil refineries, natural gas marketers, and
industry trends. The prices are Deloitte's best estimate of how the
future will look, based on the many uncertainties that exist in
both the domestic Canadian and international petroleum industries.
Deloitte considers the current monthly trends, the actual and
trends for the year to date, and the prior year actual in
determining the forecast. The crude oil and natural gas forecasts
are based on yearly variable factors weighted to higher percent in
current data and reflecting a higher percent to the prior year
historical. These forecasts are Deloitte's interpretation of
current available information and while they are considered
reasonable, changing market conditions or additional information
may require alteration from the indicated effective date.
Inflation forecasts and exchange rates, an integral part of the
forecast, have also been considered.
|
Price Inflation
Rate
|
Cost Inflation
Rate
|
Cdn to US Exchange
Rate
|
2019
|
1.9%
|
1.9%
|
$0.753
|
2020
|
0.0%
|
0.0%
|
$0.760
|
2021
|
2.0%
|
2.0%
|
$0.760
|
2022
|
2.0%
|
2.0%
|
$0.780
|
2023
|
2.0%
|
2.0%
|
$0.800
|
2024
beyond
|
2.0%
|
2.0%
|
$0.800
|
Oil, NGL, and natural gas base case prices, utilized by Deloitte
in the Deloitte Reserve Report were as follows:
|
Oil
|
Natural
Gas
|
Natural Gas
Liquids
|
Year
|
WTI Cushing (Oklahoma)
|
Edmonton City
Gate 40° API
|
Bow
River 25° API Hardisty
|
Alberta Reference
– Gas Prices
|
Alberta AECO
– Gas Prices
|
Pentanes
+ Condensate Edmonton
|
Butanes Edmonton
|
Propane Edmonton
|
|
($US/bbl)
|
($Cdn/bbl)
|
($Cdn/bbl)
|
($Cdn/mcf)
|
($Cdn/mcf)
|
($Cdn/bbl)
|
($Cdn/bbl)
|
($Cdn/bbl)
|
Forecast
|
|
|
|
|
|
|
|
|
2020
|
$58.00
|
$68.40
|
$53.95
|
$1.85
|
$2.10
|
$66.35
|
$23.95
|
$17.10
|
2021
|
$61.20
|
$73.15
|
$57.75
|
$2.05
|
$2.30
|
$73.15
|
$36.55
|
$25.60
|
2022
|
$65.55
|
$75.00
|
$59.35
|
$2.30
|
$2.55
|
$75.00
|
$48.75
|
$33.75
|
2023
|
$66.85
|
$76.95
|
$61.00
|
$2.55
|
$2.80
|
$76.95
|
$50.05
|
$34.65
|
2024
|
$68.20
|
$78.50
|
$62.25
|
$2.60
|
$2.85
|
$78.50
|
$51.05
|
$35.35
|
2025
|
$69.55
|
$80.05
|
$63.50
|
$2.65
|
$2.95
|
$80.05
|
$52.05
|
$36.05
|
2026
|
$70.95
|
$81.65
|
$64.75
|
$2.70
|
$3.00
|
$81.65
|
$53.10
|
$36.75
|
2027
|
$72.35
|
$83.30
|
$66.05
|
$2.75
|
$3.05
|
$83.30
|
$54.15
|
$37.50
|
2028
|
$73.80
|
$84.95
|
$67.35
|
$2.80
|
$3.10
|
$84.95
|
$55.25
|
$38.25
|
2029
|
$75.30
|
$86.65
|
$68.70
|
$2.85
|
$3.15
|
$86.65
|
$56.35
|
$39.00
|
|
Escalation of 2.0%
Thereafter
|
|
Notes to
table:
|
|
|
-
|
All prices are in
Canadian dollars except WTI and NYMEX which are in U.S.
dollars.
|
-
|
Edmonton City Gate
prices based on light sweet crude posted at major Canadian
refineries (40 Deg. API <0.5% Sulphur).
|
-
|
Natural Gas Liquid
prices are forecasted at Edmonton therefore an additional
transportation cost must be included to plant gate sales
point.
|
-
|
1 Mcf is equivalent
to 1 mmbtu.
|
-
|
Alberta gas prices,
except AECO, include an average cost of service to the plant
gate.
|
Finding and Development Costs
Yangarra's F&D costs for 2019, 2018 and the three-year
average are presented in the tables below. The costs used in the
F&D calculation are the capital costs related to: land
acquisition and retention; drilling; completions; tangible well
site; tie-ins; and facilities, plus the change in estimated future
development costs as per the independent reserve report.
Acquisition costs are net of any proceeds from dispositions of
properties. Due to the timing of capital costs and the subjectivity
in the estimation of future costs, the aggregate of the exploration
and development costs incurred in the most recent financial year
and the change during that year in estimated future development
costs generally will not reflect total finding and development
costs related to reserve additions for that year. The reserves used
in this calculation are Company net reserve additions, including
revisions.
Proved Developed Producing Finding & Development Costs ($
millions)
|
2019
|
2018
|
2017 –
2019
|
Capital
expenditures
|
121.0
|
151.0
|
355.0
|
|
|
|
|
Reserve additions,
net production (Mboe)
|
6,687
|
14,878
|
27,778
|
|
|
|
|
Proved Developed
Producing F&D costs – including future capital
($/boe)
|
18.10
|
10.15
|
12.78
|
|
|
|
|
Proved Recycle
Ratio ($22.35/boe operating netback)
|
1.24
|
2.69
|
|
Proved Finding & Development Costs ($ millions)
|
2019
|
2018
|
2017 -
2019
|
Capital
expenditures
|
121.0
|
151.0
|
355.0
|
Change in future
capital
|
36.5
|
1.9
|
179.2
|
Total capital for
F&D
|
157.5
|
152.9
|
534.2
|
|
|
|
|
Reserve additions,
net production (Mboe)
|
14,665
|
23,072
|
59,241
|
|
|
|
|
Proved F&D costs
– including future capital ($/boe)
|
10.74
|
6.63
|
9.02
|
Proved F&D costs
– excluding future capital ($/boe)
|
8.25
|
6.54
|
5.99
|
|
|
|
|
Proved Recycle
Ratio ($22.35/boe operating netback)
|
|
|
|
Including future
capital
|
2.08
|
4.12
|
|
Excluding future
capital
|
2.71
|
4.17
|
|
Proved plus Probable Finding & Development Costs ($
millions)
|
2019
|
2018
|
2017 -
2019
|
Capital
expenditures
|
121.0
|
151.0
|
355.0
|
Change in future
capital
|
43.1
|
54.2
|
283.6
|
Total capital for
F&D
|
164.1
|
205.2
|
638.6
|
|
|
|
|
Reserve additions,
net production (Mboe)
|
23,912
|
41,847
|
95,108
|
|
|
|
|
Proved plus Probable
F&D costs – including future capital ($/boe)
|
6.86
|
4.90
|
6.71
|
Proved plus Probable
F&D costs – excluding future capital ($/boe)
|
5.06
|
3.61
|
3.73
|
|
|
|
|
Proved plus
Probable Recycle Ratio ($22.35/boe operating
netback)
|
|
|
|
Including future
capital
|
3.26
|
5.57
|
|
Excluding future
capital
|
4.42
|
7.57
|
|
Net Asset Value ("NAV")
As at December 31,
2019
|
PDP
|
PDP +PNP
|
Total
Proved
|
Proved +
Probable
|
|
|
|
|
|
Present Value
Reserves, before tax (discounted at 10%)
|
413.7
|
453.2
|
1,112.5
|
1,668.5
|
Total Net Debt ($
million) (unaudited)
|
(187.0)
|
(187.0)
|
(187.0)
|
(187.0)
|
Proceeds from the
exercise of options (2)
|
1.8
|
1.8
|
1.8
|
1.8
|
Net Asset
Value
|
228.5
|
268.0
|
927.3
|
1,483.3
|
|
|
|
|
|
Fully diluted common
shares outstanding (million)
|
87.0
|
87.0
|
87.0
|
87.0
|
|
|
|
|
|
Net asset value
per share
|
$2.63
|
$3.08
|
$10.66
|
$17.05
|
|
Notes to
table:
|
(1)
|
The preceding table
shows what is customarily referred to as a "produce out" net asset
value calculation under which the current value of Yangarra's
reserves would be produced at the Deloitte forecast future prices
and costs. The value is a snapshot in time as at December 31, 2019
and is based on various assumptions including commodity prices and
foreign exchange rates that vary over time. In this analysis, the
present value of the proved and probable reserves is calculated at
a before tax 10 percent discount rate.
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(2)
|
The calculation of
proceeds from exercise of stock options and the diluted number of
common shares outstanding only include stock options that are
"in-the-money" based on the closing price of YGR of $1.35 as at
December 31, 2019.
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(3)
|
Net debt or adjusted
working capital (deficit), which represent current assets less
current liabilities, excluding current derivative financial
instruments, are used to assess efficiency, liquidity and the
general financial strength of the Company. There is no IFRS measure
that is reasonably comparable to net debt or adjusted working
capital (deficit).
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Year End Disclosure
The financial statements for the year-ended December 31, 2019 are scheduled to be released on
March 5, 2020.
Additional reserve information as required under NI 51-101 will
be included in the Company's Annual Information Form which will be
filed on SEDAR on or before March 31,
2020.
Reader Advisories:
Unaudited Financial Information and Non-IFRS Measures
Certain financial and operating information included in this
press release for the quarter and year ended December 31, 2019, including F&D costs and
netbacks are based on estimated unaudited financial results for the
quarter and year then ended, and are subject to the same
limitations as discussed under Forward Looking Information set out
below. These estimated amounts may change upon the completion of
audited financial statements for the year ended December 31, 2019 and changes could be
material.
Oil and Gas Advisories. Natural gas has been converted to
a barrel of oil equivalent (Boe) using 6,000 cubic feet (6 Mcf) of
natural gas equal to one barrel of oil (6:1), unless otherwise
stated. The Boe conversion ratio of 6 Mcf to 1 Bbl is based on an
energy equivalency conversion method and does not represent a value
equivalency; therefore Boe's may be misleading if used in
isolation. References to natural gas liquids ("NGLs") in this news
release include condensate, propane, butane and ethane and one
barrel of NGLs is considered to be equivalent to one barrel of
crude oil equivalent (Boe). One ("BCF") equals one billion cubic
feet of natural gas. One ("Mmcf") equals one million cubic feet of
natural gas.
All reserve references in this press release are "Company share
gross reserves". Company share gross reserves are the Company's
total working interest reserves (operating or non-operating) before
the deduction of any royalty obligation s but including royalty
interests payable the Company. It should not be assumed that the
present worth of estimated future cash flow presented in the tables
above represents the fair market value of the reserves. There is no
assurance that the forecast prices and costs assumptions will be
attained, and variances could be material. The recovery and reserve
estimates of Yangarra's crude oil, natural gas liquids and natural
gas reserves provided herein are estimates only and there is no
guarantee that the estimated reserves will be recovered. Actual
crude oil, natural gas and natural gas liquids reserves may be
greater than or less than the estimates provided herein.
This press release contains metrics commonly used in the oil and
natural gas industry which have been prepared by management, such
as "recycle ratio", "operating netback", "finding and development
costs", "reserve life index" and "net asset value". These terms do
not have a standardized meaning and may not be comparable to
similar measures presented by other companies and, therefore,
should not be used to make such comparisons.
Management uses these oil and gas metrics for its own
performance measurements and to provide shareholders with measures
to compare Yangarra's operations over time. Readers are cautioned
that the information provided by these metrics, or that can be
derived from metrics presented in this press release, should not be
relied upon for investment or other purposes.
All amounts in this news release are stated in Canadian dollars
unless otherwise specified. Our oil and gas reserves statement for
the year ended December 31, 2019,
which will include complete disclosure of our oil and gas reserves
and other oil and gas information in accordance with NI 51-101,
will be contained within our Annual Information Form which will be
available on our SEDAR profile at www.sedar.com on or before
March 31, 2020. The recovery and
reserve estimates contained herein are estimates only and there is
no guarantee that the estimated reserves will be recovered. In
relation to the disclosure of estimates for individual properties,
such estimates may not reflect the same confidence level as
estimates of reserves and future net revenue for all properties,
due to the effects of aggregation. The Company's belief that it
will establish additional reserves over time with conversion of
probable undeveloped reserves into proved reserves is a
forward-looking statement and is based on certain assumptions and
is subject to certain risks, as discussed below under the heading
"Forward-Looking Information".
Forward Looking Information. This press release contains
forward-looking statements and forward-looking information
(collectively "forward-looking information") within the meaning of
applicable securities laws relating to the Company's plans and
other aspects of our anticipated future operations, management
focus, strategies, financial, operating and production results and
business opportunities. Forward-looking information typically uses
words such as "anticipate", "believe", "continue", "sustain",
"project", "expect", "forecast", "budget", "goal", "guidance",
"plan", "objective", "strategy", "target", "intend" or similar
words suggesting future outcomes, statements that actions, events
or conditions "may", "would", "could" or "will" be taken or occur
in the future, including statements about our strategy, plans,
objectives, priorities and focus, growth plans; our estimations on
future costs; volatility of commodity prices, and currency
fluctuations. Statements relating to "reserves" are also deemed to
be forward-looking statements, as they involve the implied
assessment, based on certain estimates and assumptions, that the
reserves described exist in the quantities predicted or estimated
and that the reserves can be profitably produced in the future.
The forward-looking information is based on certain key
expectations and assumptions made by our management, including
expectations and assumptions concerning prevailing commodity
prices, exchange rates, interest rates, applicable royalty rates
and tax laws; future production rates and estimates of operating
costs; performance of existing and future wells; reserve volumes;
anticipated timing and results of capital expenditures; the success
obtained in drilling new wells; the sufficiency of budgeted capital
expenditures in carrying out planned activities; benefits to
shareholders of our programs and initiatives, the timing, location
and extent of future drilling operations; the expected timing of
release of our audited financials and AIF; the state of the economy
and the exploration and production business; results of operations;
performance; business prospects and opportunities; the availability
and cost of financing, labour and services; the impact of
increasing competition; ability to efficiently integrate assets and
employees acquired through acquisitions, ability to market oil and
natural gas successfully and our ability to access capital.
Although we believe that the expectations and assumptions on
which such forward-looking information is based are reasonable,
undue reliance should not be placed on the forward-looking
information because Yangarra can give no assurance that they will
prove to be correct. Since forward-looking information addresses
future events and conditions, by its very nature they involve
inherent risks and uncertainties. Our actual results, performance
or achievement could differ materially from those expressed in, or
implied by, the forward-looking information and, accordingly, no
assurance can be given that any of the events anticipated by the
forward-looking information will transpire or occur, or if any of
them do so, what benefits that we will derive therefrom. Management
has included the above summary of assumptions and risks related to
forward-looking information provided in this press release in order
to provide security holders with a more complete perspective on our
future operations and such information may not be appropriate for
other purposes.
Readers are cautioned that the foregoing lists of factors are
not exhaustive. Additional information on these and other factors
that could affect our operations or financial results are included
in reports on file with applicable securities regulatory
authorities and may be accessed through the SEDAR website
(www.sedar.com).
These forward-looking statements are made as of the date of this
press release and we disclaim any intent or obligation to update
publicly any forward-looking information, whether as a result of
new information, future events or results or otherwise, other than
as required by applicable securities laws.
All reference to $ (funds) are in Canadian
dollars unless otherwise stated.
Neither the TSX nor its Regulation Service
Provider (as that term is defined in the Policies of the TSX)
accepts responsibility for the adequacy and accuracy of this
release.
SOURCE Yangarra Resources Ltd.