CALGARY, Nov. 7, 2018 /CNW/ - Yangarra Resources
Ltd. ("Yangarra" or the "Company") (TSX:YGR)
announces its financial and operating results for the three and
nine months ended September 30,
2018.
Yangarra continues to delineate its core, bioturbated Cardium
acreage and is currently drilling bioturbated wells #54 and #55
with 30 (26.7 net) wells drilled to date in 2018. Current
production is approximately 12,500 boe/d and the Company expects to
drill another 6 (5 net) wells and tie-in 4 to 5 additional wells
before year-end.
Third Quarter Highlights
- Average production of 10,323 boe/d (61% liquids) during the
quarter, an increase of 36% from the second quarter of 2018 and a
71% increase from the same period in 2017.
- Oil and gas sales were $45
million, an increase of 156% from the same period in 2017.
- Funds flow from operations of $29.5
million ($0.35 per share -
basic), an increase of 128% from the same period in 2017.
- Adjusted EBITDA (which excludes changes in derivative financial
instruments) was $29.4 million
($0.35 per share - basic).
- Net income of $12.9 million
($0.15 per share - basic) or
$18.3 million net income before
tax.
- Operating costs were $6.35/boe
(including $1.07/boe of
transportation costs).
- Field netbacks were $36.79 per
boe.
- Operating netbacks, which include the impact of commodity
contracts, were $33.15 per boe.
- Operating margins were 70% and cash flow margins were
66%.
- G&A costs of $0.61/boe.
- Royalties were 9% of oil and gas revenue.
- Total capital expenditures were $48
million.
- Net debt (which excludes current derivative financial
instruments) was $135.7 million.
- Net Debt to annualized third quarter funds flow from operations
was 1.2 : 1.
- Corporate LMR is 10.67 with decommissioning liabilities of
$11.8 million (discounted).
Operations Update
Yangarra drilled and completed a five well pad during the
quarter that generated cost savings of over $400k per well when compared to single well pads
which provide a template for costs as the Company transitions to
pad drilling.
Yangarra has undertaken an extensive infrastructure upgrade to
four key gas processing facilities that includes 79 km of pipeline
and installation of an additional 10,000 Horse Power (HP) of
compression which will increase capacity to 90 mmcf/d.
Essentially all Yangarra's gas will be processed through
Company owned infrastructure once the project is complete in Q1
2019 (75% complete now).
The Company truck division has grown to 11 units with several
more on order. Increased regulatory burden in Alberta has resulted in the loss of small
& mid-size trucking firms in Central
Alberta which has given rise to significant increases in
trucking rates. The Company internal rate for trucking is
approximately 35% lower than commercial rates.
In addition, the Company has a full complement of company
staffed crew trucks, pressure trucks and mechanical services which
provide significant savings to operating costs.
The Company power requirements are internally generated by lease
fuel fired generators or primary drivers which provide significant
cost savings over grid supplied power.
Budget Update
The Board of Directors approved an increase in the capital
budget from $120 million to
$140 million for 2018. This
revised budget includes $120 million
for drilling 36 (31.7 net wells) and $20
million of infrastructure and land acquisition. The
Company has run two rigs for the entire year, with a shorter than
usual spring break-up period.
Financial Summary
|
|
|
|
|
|
|
|
2018
|
2017
|
|
Nine months
ended
|
|
Q3
|
Q2
|
Q3
|
|
2018
|
2017
|
Statements of
Comprehensive Income
|
|
|
|
|
|
|
Petroleum &
natural gas sales
|
$
|
45,131,784
|
$
|
29,922,471
|
$
|
17,663,925
|
|
$
|
104,803,971
|
$
|
52,740,708
|
|
|
|
|
|
|
|
Net income (before
tax)
|
$
|
18,301,586
|
$
|
2,604,506
|
$
|
5,511,977
|
|
$
|
28,952,803
|
$
|
20,747,441
|
|
|
|
|
|
|
|
Net income
|
$
|
12,946,733
|
$
|
1,646,498
|
$
|
3,975,606
|
|
$
|
20,251,290
|
$
|
14,803,369
|
Net income per share
- basic
|
$
|
0.15
|
$
|
0.02
|
$
|
0.05
|
|
$
|
0.24
|
$
|
0.18
|
Net income per share
- diluted
|
$
|
0.15
|
$
|
0.02
|
$
|
0.05
|
|
$
|
0.23
|
$
|
0.18
|
|
|
|
|
|
|
|
Statements of Cash
Flow
|
|
|
|
|
|
|
Funds flow from
operations
|
$
|
29,524,289
|
$
|
17,004,713
|
$
|
12,948,149
|
|
$
|
65,166,952
|
$
|
35,339,023
|
Funds flow from
operations per share - basic
|
$
|
0.35
|
$
|
0.20
|
$
|
0.16
|
|
$
|
0.77
|
$
|
0.44
|
Funds flow from
operations per share - diluted
|
$
|
0.34
|
$
|
0.19
|
$
|
0.15
|
|
$
|
0.75
|
$
|
0.42
|
Cash from operating
activities
|
$
|
26,538,939
|
$
|
16,288,319
|
$
|
13,381,396
|
|
$
|
57,816,186
|
$
|
31,233,002
|
|
|
|
|
|
|
|
Statements of
Financial Position
|
|
|
|
|
|
|
Property and
equipment
|
$
|
426,744,949
|
$
|
387,733,694
|
$
|
315,064,829
|
|
$
|
426,744,949
|
$
|
315,064,829
|
Total
assets
|
$
|
479,396,785
|
$
|
430,520,160
|
$
|
342,983,774
|
|
$
|
479,396,785
|
$
|
342,983,774
|
Working capital
deficit
|
$
|
23,528,470
|
$
|
18,600,280
|
$
|
79,069,633
|
|
$
|
23,528,470
|
$
|
79,069,633
|
Net Debt (which
excludes current derivative financial instruments)
|
$
|
135,712,402
|
$
|
115,118,849
|
$
|
80,449,394
|
|
$
|
135,712,402
|
$
|
80,449,394
|
Non-Current
Liabilities, excluding bank debt
|
$
|
58,467,174
|
$
|
51,546,663
|
$
|
40,523,942
|
|
$
|
58,467,174
|
$
|
40,523,942
|
Shareholders
equity
|
$
|
239,945,953
|
$
|
224,991,440
|
$
|
202,437,802
|
|
$
|
239,945,953
|
$
|
202,437,802
|
|
|
|
|
|
|
|
Weighted average
number of shares - basic
|
85,330,893
|
85,019,808
|
81,033,965
|
|
84,421,121
|
80,523,866
|
Weighted average
number of shares - diluted
|
87,613,710
|
87,782,665
|
84,772,793
|
|
86,783,199
|
83,692,914
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Company Netbacks ($/boe)
|
|
|
|
|
|
|
|
2018
|
2017
|
|
Nine months
ended
|
|
Q3
|
Q2
|
Q3
|
|
2018
|
2017
|
|
|
|
|
|
|
|
Sales
price
|
$
|
47.52
|
$
|
43.43
|
$
|
31.87
|
|
$
|
45.29
|
$
|
35.71
|
Royalty
expense
|
(4.38)
|
(3.90)
|
(2.43)
|
|
(4.17)
|
(2.75)
|
Production
costs
|
(5.28)
|
(6.40)
|
(5.41)
|
|
(5.94)
|
(6.84)
|
Transportation
costs
|
(1.07)
|
(1.31)
|
(1.45)
|
|
(1.31)
|
(1.06)
|
Field operating
netback
|
36.79
|
31.82
|
22.58
|
|
33.87
|
25.06
|
Realized gain (loss)
on commodity contract settlement
|
(3.65)
|
(5.18)
|
2.95
|
|
(3.70)
|
1.49
|
Operating
netback
|
33.15
|
26.64
|
25.53
|
|
30.17
|
26.55
|
G&A
|
(0.61)
|
(0.56)
|
(0.74)
|
|
(0.58)
|
(0.74)
|
Finance
expenses
|
(1.30)
|
(1.39)
|
(0.71)
|
|
(1.32)
|
(1.39)
|
Funds flow
netback
|
31.24
|
24.69
|
24.07
|
|
28.26
|
24.42
|
Depletion and
depreciation
|
(10.09)
|
(10.00)
|
(10.95)
|
|
(10.06)
|
(10.83)
|
Asset
Impairment
|
(0.85)
|
-
|
-
|
|
(0.35)
|
-
|
Accretion
|
(0.06)
|
(0.08)
|
(0.08)
|
|
(0.07)
|
(0.09)
|
Stock-based
compensation
|
(1.59)
|
(1.95)
|
(0.71)
|
|
(1.59)
|
(0.74)
|
Unrealized gain (loss)
on financial instruments
|
0.62
|
(8.87)
|
(2.39)
|
|
(3.69)
|
1.29
|
Deferred income
tax
|
(5.64)
|
(1.39)
|
(2.77)
|
|
(3.76)
|
(4.02)
|
Net Income
netback
|
$
|
13.63
|
$
|
2.39
|
$
|
7.17
|
|
$
|
8.75
|
$
|
10.02
|
|
|
|
|
|
|
|
Business Environment
|
|
|
|
|
|
|
|
2018
|
2017
|
|
Nine months
ended
|
|
Q3
|
Q2
|
Q3
|
|
2018
|
2017
|
Realized Pricing
(Including realized commodity contracts)
|
|
|
|
|
|
|
Oil ($/bbl)
|
$
|
74.84
|
$
|
71.34
|
$
|
60.41
|
|
$
|
72.02
|
$
|
62.66
|
NGL ($/bbl)
|
$
|
40.05
|
$
|
31.71
|
$
|
37.52
|
|
$
|
37.23
|
$
|
32.51
|
Gas ($/mcf)
|
$
|
1.38
|
$
|
1.16
|
$
|
1.88
|
|
$
|
1.56
|
$
|
2.62
|
|
|
|
|
|
|
|
Realized Pricing
(Excluding commodity contracts)
|
|
|
|
|
|
|
Oil ($/bbl)
|
$
|
82.54
|
$
|
80.03
|
$
|
56.51
|
|
$
|
78.79
|
$
|
60.85
|
NGL ($/bbl)
|
$
|
41.76
|
$
|
40.38
|
$
|
33.39
|
|
$
|
42.23
|
$
|
30.58
|
Gas ($/mcf)
|
$
|
1.30
|
$
|
1.16
|
$
|
1.60
|
|
$
|
1.53
|
$
|
2.45
|
|
|
|
|
|
|
|
Oil Price
Benchmarks
|
|
|
|
|
|
|
West Texas
Intermediate ("WTI") (US$/bbl)
|
$
|
69.50
|
$
|
67.88
|
$
|
48.20
|
|
$
|
66.75
|
$
|
49.45
|
Edmonton Par
(C$/bbl)
|
$
|
81.92
|
$
|
80.54
|
$
|
57.05
|
|
$
|
78.19
|
$
|
61.20
|
Edmonton Par to WTI
differential (US$/bbl)
|
$
|
(6.83)
|
$
|
(5.46)
|
$
|
(2.56)
|
|
$
|
(6.00)
|
$
|
(2.61)
|
|
|
|
|
|
|
|
Natural Gas Price
Benchmarks
|
|
|
|
|
|
|
AECO gas
(Cdn$/mcf)
|
$
|
1.19
|
$
|
1.03
|
$
|
1.45
|
|
$
|
1.48
|
$
|
2.30
|
|
|
|
|
|
|
|
Foreign
Exchange
|
|
|
|
|
|
|
U.S./Canadian Dollar
Exchange
|
0.77
|
0.78
|
0.80
|
|
0.78
|
0.77
|
|
|
|
|
|
|
|
Operations Summary
Net petroleum and natural gas
production, pricing and revenue are summarized below:
|
|
|
|
|
|
|
|
2018
|
2017
|
|
Nine months
ended
|
|
Q3
|
Q2
|
Q3
|
|
2018
|
2017
|
|
|
|
|
|
|
|
Daily production
volumes
|
|
|
|
|
|
|
Natural gas
(mcf/d)
|
24,378
|
18,336
|
16,142
|
|
20,439
|
14,260
|
Oil (bbl/d)
|
4,853
|
3,162
|
2,380
|
|
3,789
|
2,165
|
NGL's
(bbl/d)
|
1,406
|
1,353
|
955
|
|
1,282
|
866
|
Combined
(boe/d 6:1)
|
10,323
|
7,570
|
6,025
|
|
8,477
|
5,408
|
|
|
|
|
|
|
|
Revenue
|
|
|
|
|
|
|
Petroleum &
natural gas sales - Gross
|
$
|
45,131,784
|
$
|
29,922,471
|
$
|
17,663,925
|
|
$
|
104,803,971
|
$
|
52,740,708
|
Realized gain (loss)
on commodity contract settlement
|
(3,462,012)
|
(3,569,273)
|
1,632,783
|
|
(8,553,310)
|
2,196,435
|
Total
sales
|
41,669,772
|
26,353,198
|
19,296,708
|
|
96,250,661
|
54,937,143
|
Royalty
expense
|
(4,156,841)
|
(2,684,294)
|
(1,344,746)
|
|
(9,642,356)
|
(4,063,292)
|
Total Revenue - Net
of royalties
|
$
|
37,512,931
|
$
|
23,668,904
|
$
|
17,951,962
|
|
$
|
86,608,305
|
$
|
50,873,851
|
|
|
|
|
|
|
|
Working Capital Summary
The following table summarizes
the change in working capital during the nine months ended
September 30, 2018 and the year ended
December 31, 2017:
|
|
|
|
2018
|
2017
|
Net Debt - beginning
of period
|
$
|
(93,533,252)
|
$
|
(65,005,805)
|
|
|
|
Funds flow from
operations
|
65,166,951
|
52,902,650
|
Additions to
property and equipment
|
(105,803,666)
|
(83,472,094)
|
Decommissioning
costs incurred
|
-
|
(95,433)
|
Additions to
E&E Assets
|
(8,082,910)
|
-
|
Issuance of
shares
|
6,758,792
|
2,179,593
|
Other
|
(218,317)
|
(42,163)
|
Net Debt - end
of period
|
$
|
(135,712,402)
|
$
|
(93,533,252)
|
|
|
|
Credit facility
limit
|
$
|
150,000,000
|
$
|
120,000,000
|
Subsequent to September 30, 2018
the maximum amount available under the syndicated credit facility
was increased to $175 million.
Capital Spending
Capital spending is summarized as
follows:
|
|
|
|
|
|
|
|
2018
|
2017
|
|
Nine months
ended
|
Cash
additions
|
Q3
|
Q2
|
Q3
|
|
2018
|
2017
|
|
|
|
|
|
|
|
Land, acquisitions
and lease rentals
|
$
|
79,477
|
$
|
92,348
|
$
|
3,503,852
|
|
$
|
228,967
|
$
|
6,001,336
|
Drilling and
completion
|
38,264,772
|
19,519,585
|
14,939,137
|
|
84,555,869
|
39,289,999
|
Geological and
geophysical
|
163,002
|
199,680
|
134,283
|
|
501,773
|
562,085
|
Equipment
|
9,892,565
|
6,112,877
|
2,248,622
|
|
20,346,403
|
6,541,666
|
Other asset
additions
|
81,528
|
85,687
|
84,631
|
|
170,654
|
299,967
|
|
$
|
48,481,344
|
$
|
26,010,177
|
$
|
20,910,525
|
|
$
|
105,803,666
|
$
|
52,695,053
|
|
|
|
|
|
|
|
Exploration &
evaluation assets
|
$
|
1,562,879
|
$
|
1,471,820
|
$
|
-
|
|
$
|
8,082,910
|
$
|
-
|
Quarter End Disclosure
The Company's financial statements, notes to the financial
statements and management's discussion and analysis for the year
ended December 31, 2017 and three and
nine months ended September 30, 2018
have been filed on SEDAR (www.sedar.com) and are available on the
Company's website (www.yangarra.ca).
Forward looking information
Certain information regarding Yangarra set forth in this news
release, management's assessment of future plans, operations
and operational results may constitute forward-looking statements
under applicable securities law and necessarily involve risks
associated with oil and gas exploration, production, marketing and
transportation such as loss of market, volatility of prices,
currency fluctuations, imprecision of reserves estimates,
environmental risks, competition from other producers and ability
to access sufficient capital from internal and external
sources. As a consequence, actual results may differ
materially from those anticipated in the forward-looking
statements. Certain of these risks are set out in more detail
in Yangarra's current Annual Information Form, which is available
on Yangarra's SEDAR profile at www.sedar.com.
Forward-looking statements are based on estimates and
opinions of management of Yangarra at the time the statements are
presented. Yangarra may, as considered necessary in the
circumstances, update or revise such forward-looking statements,
whether as a result of new information, future events or otherwise,
but Yangarra undertakes no obligation to update or revise any
forward-looking statements, except as required by applicable
securities laws.
Barrels of Oil Equivalent
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.
Non-GAAP Financial Measures
This press
release contains references to measures used in the oil and natural
gas industry such as "funds flow from operations", "operating
netback", "adjusted working capital deficit", and "net debt".
These measures do not have standardized meanings prescribed by
generally accepted accounting principles ("GAAP") and,
therefore should not be considered in isolation. These
reported amounts and their underlying calculations are not
necessarily comparable or calculated in an identical manner to a
similarly titled measure of other companies where similar
terminology is used. Where these measures are used they
should be given careful consideration by the reader. These
measures have been described and presented in this press release in
order to provide shareholders and potential investors with
additional information regarding the Company's liquidity and its
ability to generate funds to finance its operations.
Funds flow from operations should not be considered an
alternative to, or more meaningful than, cash provided by
operating, investing and financing activities or net income as
determined in accordance with GAAP, as an indicator of Yangarra's
performance or liquidity. Funds flow from operations is used
by Yangarra to evaluate operating results and Yangarra's ability to
generate cash flow to fund capital expenditures and repay
indebtedness. Funds flow from operations denotes cash flow
from operating activities as it appears on the Company's Statement
of Cash Flows before decommissioning expenditures and changes in
non-cash operating working capital. Funds flow from operations is
also derived from net income (loss) plus non-cash items including
deferred income tax expense, depletion and depreciation expense,
impairment expense, stock-based compensation expense, accretion
expense, unrealized gains or losses on financial instruments and
gains or losses on asset divestitures. Funds from operations
netback is calculated on a per boe basis and funds from operations
per share is calculated as funds from operations divided by the
weighted average number of basic and diluted common shares
outstanding. Operating netback denotes petroleum and natural
gas revenue and realized gains or losses on financial instruments
less royalty expenses, operating expenses and transportation and
marketing expenses calculated on a per boe basis. Adjusted
working capital deficit includes current assets less current
liabilities excluding the current portion of the amount drawn on
the credit facilities, the current portion of the fair value of
financial instruments and the deferred premium on financial
instruments. Yangarra uses net debt as a measure to assess
its financial position. Net debt includes current assets less
current liabilities excluding the current portion of the fair value
of financial instruments and the deferred premium on financial
instruments, plus the long-term financial obligation.
Readers should also note that adjusted earnings before
interest, taxes, depletion & depreciation, amortization
("Adjusted EBITDA") is a non-GAAP financial measures and do
not have any standardized meaning under GAAP and is therefore
unlikely to be comparable to similar measures presented by other
companies. Yangarra believes that Adjusted EBITDA is a useful
supplemental measure, which provide an indication of the results
generated by the Yangarra's primary business activities prior to
consideration of how those activities are financed, amortized or
taxed. Readers are cautioned, however, that Adjusted EBITDA should
not be construed as an alternative to comprehensive income (loss)
determined in accordance with GAAP as an indicator of Yangarra's
financial performance.
Any references in this press release to initial and/or final
raw test or production rates and/or "flush" production rates are
useful in confirming the presence of hydrocarbons, however, such
rates are not determinative of the rates at which such wells will
commence production and decline thereafter. These test results are
not necessarily indicative of long-term performance or ultimate
reserve recovery. While encouraging, readers are cautioned not to
place reliance on such rates in calculating the aggregate
production.
This press release discloses unbooked drilling locations.
Unbooked locations are internal estimates based on the
Corporation's prospective acreage and an assumption as to the
number of wells that can be drilled per section based on industry
practice and internal review. Unbooked locations do not have
attributed reserves or resources. Unbooked locations have been
identified by management as an estimation of our multi-year
drilling activities based on evaluation of applicable geologic,
seismic, engineering, production and reserves information. There is
no certainty that the Corporation will drill all unbooked drilling
locations and if drilled there is no certainty that such locations
will result in additional oil and gas reserves, resources or
production. The drilling locations on which we actually drill wells
will ultimately depend upon the availability of capital, regulatory
approvals, seasonal restrictions, oil and natural gas prices,
costs, actual drilling results, additional reservoir information
that is obtained and other factors. While certain of the unbooked
drilling locations have been derisked by drilling existing wells in
relative close proximity to such unbooked drilling locations, other
unbooked drilling locations are farther away from existing wells
where management has less information about the characteristics of
the reservoir and therefore there is more uncertainty whether wells
will be drilled in such locations and if drilled there is more
uncertainty that such wells will result in additional oil and gas
reserves, resources or production.
All reference to $ (funds) are in Canadian dollars.
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.