Strong liquids production, improving regional condensate pricing and
reduced operating costs contribute to expected free cash flow generation
in 2019
FIRST QUARTER 2019 HIGHLIGHTS
-
7G’s market access initiatives, coupled with a stronger condensate
price environment and improved operating costs, led to adjusted funds
flow of $339 million or $0.95 per share and yielded an operating
netback of $21.99 per boe, 16 percent higher than the fourth quarter
of 2018.
-
The company’s trailing 12-month return on capital employed was 11.9
percent. Cash return on invested capital was 17.7 percent.
-
Investments in water handling helped reduce operating expenses to
$4.93 per boe, 11 percent below the company’s full year 2018 average
of $5.52 per boe. 7G’s investments in water management and
conservation are reducing costs, carbon emissions and traffic by
taking approximately 50 water hauling trucks off the road each day.
-
Sales volumes averaged 197,400 boe/d, with liquids representing 59
percent of 7G’s total production. Condensate sales of 72,700 bbl/d
increased by 8 percent compared to the same period in 2018.
-
7G now has the capacity to sell approximately 90 percent of its
natural gas into premium markets in the US Midwest, Eastern Canada and
the US Gulf Coast. The company’s realized natural gas price was
$4.32/Mcf in the first quarter, an approximate 70 percent premium to
AECO pricing. 7G continues to advance its market access initiatives,
recently adding 55 MMcf/d of pipeline capacity from Chicago directly
to the US Gulf Coast, taking that total capacity to 155 MMcf/d.
-
Realizing the benefit of its delineation capital investments, 7G has
an additional lower Montney result with initial 30-day flow rates
averaging approximately 1,250 boe/d (63 percent condensate). The
company is currently tying-in its first full triple-stack pad, with
flow rates expected later this summer.
-
7G has the lowest carbon intensity per unit among its Canadian peers
at 0.0136 tonnes of CO2e per boe, as reported by CDP, a
global environmental disclosure protocol. 7G is committed to
responsible energy development that serves stakeholders through
leading governance, social and environmental performance within the
North American energy industry.
Key Nest 3 infrastructure development in progress, outlook for
increasing free cash flow
7G had an active first quarter that included the build-out of its Nest 3
connector pipeline. This 2019 pipeline investment underpins the Nest 3
development plan and enables the tie-in of Nest 3 resource into the
company’s larger gathering and processing infrastructure network. Nest 3
infrastructure development is expected to continue in the second
quarter, before aligning toward a more resource development focused
second half of the year. Once the connector is complete, 7G expects
future infrastructure capital, as a percent of total cash flow, to fall
relative to historical levels.
Capital discipline and returns to shareholders remain top priorities
As 7G transitions from one of the fastest drill-bit growth companies in
Canadian history to a sustainable, free cash flow growth entity, capital
discipline remains paramount. Strong liquids production, improving local
condensate pricing and reduced operating costs are expected to generate
free cash flow in excess of 7G’s $1.25 billion 2019 capital budget. 7G
plans to apply free cash flow to a combination of share repurchases
pursuant to the previously announced normal course issuer bid (NCIB) and
net debt reduction.
OPERATIONAL AND FINANCIAL HIGHLIGHTS
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
March 31,
|
|
|
Three months ended
December 31,
|
|
($ millions, except boe
and per share amounts)
|
|
|
2019
|
|
|
2018
|
|
|
% Change
|
|
|
2018
|
|
|
% Change
|
|
Sales volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensate (mbbl/d)
|
|
|
72.7
|
|
|
|
67.3
|
|
|
8
|
|
|
|
81.8
|
|
|
(11
|
)
|
|
NGLs (mbbl/d)
|
|
|
44.1
|
|
|
|
41.5
|
|
|
6
|
|
|
|
47.4
|
|
|
(7
|
)
|
|
Liquids (mbbl/d)
|
|
|
116.8
|
|
|
|
108.8
|
|
|
7
|
|
|
|
129.2
|
|
|
(10
|
)
|
|
Natural gas (MMcf/d)
|
|
|
483.6
|
|
|
|
473.3
|
|
|
2
|
|
|
|
515.4
|
|
|
(6
|
)
|
|
Total sales volumes (mboe/d)(1)
|
|
|
197.4
|
|
|
|
187.7
|
|
|
5
|
|
|
|
215.1
|
|
|
(8
|
)
|
|
Liquids %
|
|
|
59%
|
|
|
|
58%
|
|
|
|
2
|
|
|
|
60%
|
|
|
|
(2
|
)
|
|
Realized prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensate ($/bbl)
|
|
|
63.00
|
|
|
|
73.39
|
|
|
|
(14
|
)
|
|
|
53.57
|
|
|
|
18
|
|
|
Natural gas ($/Mcf)
|
|
|
4.32
|
|
|
|
3.54
|
|
|
|
22
|
|
|
|
4.77
|
|
|
|
(9
|
)
|
|
NGLs ($/bbl)
|
|
|
7.46
|
|
|
|
13.33
|
|
|
|
(44
|
)
|
|
|
8.44
|
|
|
|
(12
|
)
|
|
Total ($/boe)(1)
|
|
|
35.44
|
|
|
|
38.19
|
|
|
|
(7
|
)
|
|
|
33.66
|
|
|
|
5
|
|
|
Royalty expense ($/boe)
|
|
|
(2.30
|
)
|
|
|
(1.12
|
)
|
|
|
105
|
|
|
|
(0.99
|
)
|
|
|
132
|
|
|
Operating expenses ($/boe)
|
|
|
(4.93
|
)
|
|
|
(5.73
|
)
|
|
|
(14
|
)
|
|
|
(5.25
|
)
|
|
|
(6
|
)
|
|
Transportation, processing and other ($/boe)
|
|
|
(6.65
|
)
|
|
|
(6.24
|
)
|
|
|
7
|
|
|
|
(7.07
|
)
|
|
|
(6
|
)
|
|
Operating netback before the following ($/boe)(1)(2)
|
|
|
21.56
|
|
|
|
25.10
|
|
|
|
(14
|
)
|
|
|
20.35
|
|
|
|
6
|
|
|
Realized hedging gains (losses) ($/boe)
|
|
|
(0.34
|
)
|
|
|
(0.78
|
)
|
|
|
(56
|
)
|
|
|
(1.58
|
)
|
|
|
(78
|
)
|
|
Marketing income ($/boe)(2)
|
|
|
0.77
|
|
|
|
0.62
|
|
|
|
24
|
|
|
|
0.20
|
|
|
|
285
|
|
|
Operating netback ($/boe)(2)
|
|
|
21.99
|
|
|
|
24.94
|
|
|
|
(12
|
)
|
|
|
18.97
|
|
|
|
16
|
|
|
Adjusted funds flow ($/boe)(2)(4)
|
|
|
19.05
|
|
|
|
22.54
|
|
|
|
(15
|
)
|
|
|
17.06
|
|
|
|
12
|
|
|
Financial Results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue ($)(3)
|
|
|
546.3
|
|
|
|
648.5
|
|
|
|
(16
|
)
|
|
|
1,146.8
|
|
|
|
(52
|
)
|
|
Net income ($)
|
|
|
10.8
|
|
|
|
22.7
|
|
|
|
(52
|
)
|
|
|
245.4
|
|
|
|
(96
|
)
|
|
Per share - diluted ($)
|
|
|
0.03
|
|
|
|
0.06
|
|
|
|
(50
|
)
|
|
|
0.68
|
|
|
|
(96
|
)
|
|
Operating income ($)(2)
|
|
|
84.0
|
|
|
|
129.4
|
|
|
|
(35
|
)
|
|
|
66.3
|
|
|
|
27
|
|
|
Per share - diluted ($)
|
|
|
0.24
|
|
|
|
0.36
|
|
|
|
(33
|
)
|
|
|
0.18
|
|
|
|
33
|
|
|
Cash provided by operating activities ($)
|
|
|
259.3
|
|
|
|
424.1
|
|
|
|
(39
|
)
|
|
|
410.1
|
|
|
|
(37
|
)
|
|
Per share - diluted ($)
|
|
|
0.73
|
|
|
|
1.17
|
|
|
|
(38
|
)
|
|
|
1.13
|
|
|
|
(35
|
)
|
|
Adjusted funds flow ($)(4)
|
|
|
338.5
|
|
|
|
380.8
|
|
|
|
(11
|
)
|
|
|
337.4
|
|
|
|
—
|
|
|
Per share - diluted ($)
|
|
|
0.95
|
|
|
|
1.05
|
|
|
|
(10
|
)
|
|
|
0.93
|
|
|
|
2
|
|
|
CROIC (%)(2)
|
|
|
17.7%
|
|
|
|
18.1%
|
|
|
|
(2
|
)
|
|
|
19.1%
|
|
|
|
(7
|
)
|
|
ROCE (%)(2)
|
|
|
11.9%
|
|
|
|
10.4%
|
|
|
|
14
|
|
|
|
12.9%
|
|
|
|
(8
|
)
|
|
Balance sheet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital investments ($)
|
|
|
400.9
|
|
|
|
582.6
|
|
|
|
(31
|
)
|
|
|
262.3
|
|
|
|
53
|
|
|
Available funding ($)(2)
|
|
|
1,280.9
|
|
|
|
1,312.6
|
|
|
|
(2
|
)
|
|
|
1,345.9
|
|
|
|
(5
|
)
|
|
Net debt ($)(4)
|
|
|
2,229.9
|
|
|
|
2,118.2
|
|
|
|
5
|
|
|
|
2,206.8
|
|
|
|
1
|
|
|
Weighted average shares - basic
|
|
|
353.0
|
|
|
|
354.9
|
|
|
|
(1
|
)
|
|
|
359.2
|
|
|
|
(2
|
)
|
|
Weighted average shares - diluted
|
|
|
355.6
|
|
|
|
363.5
|
|
|
|
(2
|
)
|
|
|
362.3
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Excludes the purchase and resale of condensate and natural gas in
respect of the Company's transportation commitment utilization and
marketing activities.
(2) See “Non-IFRS Financial Measures” under
Reader Advisory. Certain comparative figures have been adjusted to
conform to current period presentation.
(3) Represents the total of
liquids and natural gas sales, net of royalties, gains (losses) on risk
management contracts and other income.
(4) Refer to Note 13 of the
Q1 2019 condensed interim consolidated financial statements for further
details.
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
March 31,
|
|
|
Three months ended
December 31,
|
|
Nest Activity
|
|
|
2019
|
|
|
2018
|
|
|
% Change
|
|
|
2018
|
|
|
% Change
|
|
Drilling(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Horizontal wells rig released
|
|
|
18
|
|
|
|
27
|
|
|
|
(33
|
)
|
|
|
19
|
|
|
|
(5
|
)
|
|
Average measured depth (m)
|
|
|
5,911
|
|
|
|
5,621
|
|
|
|
5
|
|
|
|
6,010
|
|
|
|
(2
|
)
|
|
Average horizontal length (m)
|
|
|
2,598
|
|
|
|
2,459
|
|
|
|
6
|
|
|
|
2,776
|
|
|
|
(6
|
)
|
|
Average drilling days per well
|
|
|
30
|
|
|
|
28
|
|
|
|
7
|
|
|
|
28
|
|
|
|
7
|
|
|
Average drill cost per metre ($)(2)
|
|
|
|
614
|
|
|
|
|
642
|
|
|
|
(4
|
)
|
|
|
|
560
|
|
|
|
10
|
|
|
Average well cost ($ millions)(2)
|
|
|
|
3.6
|
|
|
|
|
3.6
|
|
|
|
—
|
|
|
|
|
3.4
|
|
|
|
6
|
|
|
Completion(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wells completed
|
|
|
19
|
|
|
|
20
|
|
|
|
(5
|
)
|
|
|
13
|
|
|
|
46
|
|
|
Average number of stages per well
|
|
|
55
|
|
|
|
39
|
|
|
|
41
|
|
|
|
46
|
|
|
|
20
|
|
|
Average tonnes pumped per metre
|
|
|
1.9
|
|
|
|
2.4
|
|
|
|
(21
|
)
|
|
|
1.9
|
|
|
|
—
|
|
|
Average tonnes pumped per well
|
|
|
4,750
|
|
|
|
5,923
|
|
|
|
(20
|
)
|
|
|
4,417
|
|
|
|
8
|
|
|
Average cost per tonne(2)
|
|
|
|
1,215
|
|
|
|
|
1,218
|
|
|
|
—
|
|
|
|
|
1,282
|
|
|
|
(5
|
)
|
|
Average well cost ($ millions)(2)
|
|
|
|
5.8
|
|
|
|
|
7.2
|
|
|
|
(19
|
)
|
|
|
|
5.7
|
|
|
|
2
|
|
|
Total D&C cost per well ($ millions)(2)
|
|
|
|
9.4
|
|
|
|
|
10.8
|
|
|
|
(13
|
)
|
|
|
|
9.1
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) The drilling and completion counts include only horizontal Montney
wells in the Nest. The drilling counts and metrics exclude wells that
are re-drilled or abandoned.
(2) Information provided is based on
field estimates and is subject to change.
OPERATIONS AND RESOURCE DEVELOPMENT
Cost structure
Operating costs in the first quarter improved to $4.93 per boe,
benefitting from investments in water handling infrastructure. At this
time, 7G is not updating its previously disclosed 2019 operating expense
budget of $5.00 to $5.50 per boe, and will continue to progress its
water management initiatives, including increased recycling of produced
water.
Lower Montney resource delineation update
7G’s second partial triple-stack pad, located in the western edge of
Nest 2, came on stream slightly ahead of schedule and on budget. It
targeted a single well in the lower Montney, below simultaneous
completions of the upper and middle Montney. The lower Montney location
delivered initial rates during the first 30 days of production of
approximately 1,250 boe/d (63 percent condensate), while the middle and
upper locations performed as expected. The pad is located approximately
a township west of the company’s first partial triple-stack that was
announced last year and enhances 7G’s understanding of the lower Montney
resource across a broader areal extent. With continued lower Montney
success, the company could materially expand its highly economic
drilling inventory, while improving full cycle returns as surface costs
are allocated across a larger well count.
Full triple-stack pad and advanced completions design
The company’s first full triple-stack pad, located in the north-western
portion of Nest 2, has proceeded according to plan and budget, with
three wells in each of the upper, middle and lower Montney completed in
the first quarter and in the process of being tied-in. This triple-stack
pad will help further delineate the lower Montney potential and evaluate
the effectiveness of co-completions across all three Montney benches. In
addition, 7G has deployed fibre-optic monitoring, micro-seismic, and
image logging to improve understanding of the subsurface fracture
network and to enhance future completion designs. 7G plans to use its
expanding dataset to help analyze and advance the economic benefits of
increasing intra-stage clusters that could materially improve the
company’s capital efficiencies.
Nest 1 update
7G’s previously announced Nest 1 perimeter test continues to flow at
rates and pressures exceeding expectations. Initial rates during the
first 60 days of production averaged 1,898 boe/d (72 percent condensate)
while flowing at restricted rates during most of the second month. This
prolific result, located 12 kilometres east of the company’s existing
Nest 1 development, provides important initial production data that will
help guide development planning of the company’s inventory of 480 Nest 1
locations.
MARKET ACCESS INITIATIVES
During the first quarter, 7G acquired an additional 55 MMcf/d of market
access from the US Midwest to the Gulf Coast. When combined with 7G’s
existing 100 MMcf/d of direct Henry Hub sales, the company can
potentially sell nearly one third of its Montney natural gas production
directly into the global LNG market. This pipeline capacity provides
price diversification and differentiated egress optionality for the
company’s natural gas production. 7G remains committed to expanding its
market access options to enhance price realizations across its entire
production suite.
NORMAL COURSE ISSUER BID UPDATE
With benchmark WTI prices exceeding the assumptions used in the
company’s 2019 budget, 7G has entered into incremental oil hedges
subsequent to the first quarter to establish floor pricing on 5,000
bbl/d of its production above US$65/bbl for the balance of 2019. With
hedged cash flows exceeding budgeted WTI pricing, and a commitment to
execute the original $1.25 billion capital program, 7G intends to
allocate excess free cash flow to a combination of its NCIB and net debt
reduction.
GENERATIONS – 7G’S STAKEHOLDER AND SUSTAINABILITY REPORT
7G has published on its website the fourth annual edition of
Generations, its stakeholder and sustainability report. Generations 2019
highlights 7G’s commitment to differentiated stakeholder service,
responsible energy development and stakeholder engagement. Generations
2019 expands 7G’s reporting of quantitative and qualitative
environmental, social and governance performance. Generations is
available at:
https://www.7genergy.com/responsibility/generations-stakeholder-and-sustainability-report
OUTLOOK
2019 guidance remains unchanged. The company has provided additional
details regarding expected royalty rates to reflect the current
commodity price environment. During the second quarter of 2019, brief
outages are planned for turnaround work at third party processing
facilities and natural gas pipeline systems. The previously provided
outlook reflects these maintenance-related events.
|
|
|
|
|
|
|
Production
|
|
|
|
|
|
Condensate (%)
|
|
|
|
36 - 38
|
|
Total liquids (%)
|
|
|
|
58 - 60
|
|
Natural gas (%)
|
|
|
|
40 - 42
|
|
|
|
|
|
|
|
Total production (Mboe/d)
|
|
|
|
200 - 205
|
|
H1 2019 (Mboe/d)
|
|
|
|
195 - 200
|
|
H2 2019 (Mboe/d)
|
|
|
|
205 - 210
|
|
|
|
|
|
|
|
Expenses
|
|
|
|
|
|
Royalties at US$50 WTI (%)
|
|
|
|
5 - 7
|
|
Royalties at US$60 WTI (%)
|
|
|
|
7 - 9
|
|
Operating ($/boe)
|
|
|
|
5.00 - 5.50
|
|
Transportation ($/boe)
|
|
|
|
6.75 - 7.25
|
|
G&A ($/boe)
|
|
|
|
0.80 - 0.90
|
|
Interest ($/boe)
|
|
|
|
1.80 - 1.90
|
|
|
|
|
|
|
|
Capital investment ($mm)
|
|
|
|
1,250
|
|
Drilling and completions (%)
|
|
|
|
55 - 60
|
|
Pipelines and infrastructure (%)
|
|
|
|
30 - 35
|
|
Delineation (%)
|
|
|
|
10 - 15
|
|
Wells on-stream
|
|
|
|
65 - 70
|
|
|
|
|
|
|
BOARD OF DIRECTORS UPDATE
As previously announced, 7G’s board of directors renewal process is
currently underway with Mark Monroe taking on the chair role as of
January 1, 2019 and Ronnie Irani joining 7G’s board of directors as of
February 27, 2019. Founding chair Kent Jespersen did not stand for
re-election at the company’s annual general meeting that took place on
Wednesday, May 1, 2019. Additionally, directors Kevin Brown, Kaush
Rakhit and Jeff van Steenbergen did not stand for re-election. Seven
Generations thanks these directors for their guidance and contributions
to the conception, evolution and foundational success of the company.
Additionally, 7G’s board of directors has appointed Leontine Atkins as a
board member effective May 2, 2019. Atkins was previously a board member
of KPMG Canada’s National Board of Directors until early 2019, having
sat on the National Acquisitions and Admissions and Succession
committees. She served as a Partner at KPMG Canada from 2006 until early
2019 and was previously a Partner at KPMG Netherlands until she moved to
Canada in 2006. Atkins has 30 years of experience in the global oil and
gas industry, with a focus on corporate strategy in each of the
upstream, midstream and downstream sectors of the energy value chain.
Atkins currently serves as a director of Points International, a leading
global loyalty ecommerce platform, the board of Calgary Economic
Development as the chair of the audit committee and on the board of
Heritage Park Museum where she also is a member of the audit committee.
She was also the vice chair and past chair of the audit/investment
committee of the Glenbow Museum board. Atkins holds a Bachelor of
Business Administration in Finance from Acadia University and a Master
of Business Administration from Dalhousie University. She has also
obtained her CPA, CA designation as well as the ICD.D designation from
the Institute of Corporate Directors.
CONFERENCE CALL
7G management will hold a conference call to discuss results and address
investor questions today, May 3, 2019, at 9 a.m. MT (11 a.m. ET).
Participant Dial-In Numbers
Seven Generations Energy
Seven Generations Energy is a low-supply cost energy producer dedicated
to stakeholder service, responsible development and generating strong
returns from its liquids-rich Kakwa River Project in northwest Alberta.
7G’s corporate office is in Calgary, its operations headquarters is in
Grande Prairie and its shares trade on the TSX under the symbol VII.
Further information on Seven Generations is available on the
company’s website: www.7genergy.com.
Reader Advisory
Non-IFRS Financial Measures
This news release includes certain terms or performance measures
commonly used in the oil and natural gas industry that are not defined
under International Financial Reporting Standards (IFRS), including
“return on capital invested” (ROCE), “cash return on invested capital”
(CRIOC), “operating income”, “operating netback”, “adjusted funds flow
per boe”, “marketing income” and “available funding”. The data presented
is intended to provide additional information and should not be
considered in isolation or as a substitute for measures of performance
prepared in accordance with IFRS. These non-IFRS measures should be read
in conjunction with the company’s consolidated financial statements for
the years ended December 31, 2018 and 2017 and the accompanying notes.
Readers are cautioned that the non-IFRS measures do not have any
standardized meaning and should not be used to make comparisons between
the company and other companies without also taking into account any
differences in the way the calculations were prepared.
For additional information about these measures, please see “Advisories
and Guidance – Non-IFRS financial measures” in Management’s Discussion
and Analysis dated May 2, 2019, for the three months ended March 31,
2019 and 2018.
Net debt and adjusted funds flow have been included in Note 13 in the
company’s condensed interim consolidated financial statements for the
three months ended March 31, 2019 and 2018 in order to provide users
with a better understanding of these key metrics used by the company to
manage its capital and liquidity and assess performance. Accordingly,
the net debt and adjusted funds flow performance measures are considered
to be measures presented in accordance with IFRS. Please refer to Seven
Generations’ condensed interim consolidated financial statements for the
three months ended March 31, 2019 and 2018 and consolidated financial
statements for the years ended December 31, 2018 and 2017 for further
details.
Forward-Looking Information Advisory
This news release contains certain forward-looking information and
statements that involve various risks, uncertainties and other factors.
The use of any of the words “anticipate”, “continue”, “estimate”,
“expect”, “may”, “will”, “should”, “believe”, “plans”, and similar
expressions are intended to identify forward-looking information or
statements. In particular, but without limiting the foregoing, this news
release contains forward-looking information and statements pertaining
to the following: expected free cash flow generation in 2019;
anticipated transportation and processing capacity and market access;
commitment to responsible energy development with leading governance,
social and environmental performance; planned transition to a
sustainable free cash flow growth entity; plans to allocate cash flow in
excess of the 2019 capital budget to a combination of share repurchases
and debt reduction; the timing of the production from the company’s
first full triple-stack pad; the potential to materially expand the
company’s highly economic drilling inventory and full cycle returns with
lower Montney success; expected reductions in future infrastructure
capital as a percent of total cash flow; continued progress on water
management initiatives, including increased recycling of produced water;
cost reductions; planned delineation of the lower Montney and further
evaluation of the effectiveness of co-completions across all three
Montney benches; further enhancement of the company’s completion
designs; plans to use the company’s expanding dataset to analyze and
advance the potential economic benefits of increasing intra-stage
clusters applied during hydraulic fracturing, which has the potential to
materially improve the company’s capital efficiencies; the expected
drilling inventory in the company’s Nest 1 area; development plans;
planned outages; and the guidance provided under the heading “Outlook”.
With respect to forward-looking information contained herein,
assumptions have been made regarding, among other things: future oil,
NGLs and natural gas prices being consistent with current commodity
price forecasts after factoring in quality adjustments at the company’s
points of sale; the company’s continued ability to obtain qualified
staff and equipment in a timely and cost-efficient manner; drilling and
completion techniques; infrastructure and facility design concepts that
have been successfully applied by the company elsewhere in its Kakwa
River Project may be successfully applied to other properties within the
Kakwa River Project; the consistency of the regulatory regime and
framework governing royalties, taxes and environmental matters in the
jurisdictions in which the company conducts its business and any other
jurisdictions in which the company may conduct its business in the
future; the company’s ability to market production of oil, NGLs and
natural gas successfully to customers; the company’s future production
levels and amount of future capital investment will be consistent with
the company’s current development plans and budget; technologies for
recovery and production of the company’s reserves and resources may
improve capital and operational efficiencies in the future; the
recoverability of the company’s reserves and resources; sustained future
capital investment by the company; future cash flows from production;
taxes and royalties will remain consistent with the company’s calculated
rates; the future sources of funding for the company’s capital program;
the company’s future debt levels; geological and engineering estimates
in respect of the company’s reserves and resources; the geography of the
areas in which the company is conducting exploration and development
activities, and the access, economic, regulatory and physical
limitations to which the company may be subject from time to time; the
impact of competition on the company; and the company’s ability to
obtain financing on acceptable terms.
Operating cost assumptions reflect recent actual cost trends with
adjustments to address planned activity levels. Royalty rate assumptions
were calculated using a price range of US$50-US$60/bbl WTI, net of
credits and projected C* for new wells to be drilled in 2019. Royalty
rate assumptions are net of expected gas cost allowance from investments
in gas plants and gathering infrastructure. G&A cost assumptions reflect
recent actuals and expectations for a larger staff count and information
technology investments in 2019.
Actual results could differ materially from those anticipated in the
forward-looking information that is contained herein as a result of the
risks and risk factors that are set forth in the company’s annual
information form dated February 27, 2019 for the year ended December 31,
2018 (AIF), which is available on SEDAR, including, but not limited to:
volatility in market prices and demand for oil, NGLs and natural gas and
hedging activities related thereto; general economic, business and
industry conditions; variance of the company’s actual capital costs,
operating costs and economic returns from those anticipated; risks
related to the exploration, development and production of oil and
natural gas reserves and resources; negative public perception of oil
sands development, oil and natural gas development and transportation,
hydraulic fracturing and fossil fuels; political risk; the rescission,
or amendment to the conditions, of groundwater licenses of the company;
the ability to successfully identify and make attractive acquisitions,
joint ventures or investments, or successfully integrate future
acquisitions or businesses; the availability, cost or shortage of rigs,
equipment, raw materials, supplies or qualified personnel; the potential
impact of climate change on the company’s operations; the absence or
loss of key employees; uncertainty associated with estimates of oil,
NGLs and natural gas reserves and resources and the variance of such
estimates from actual future production; dependence upon compressors,
gathering lines, pipelines and other facilities, certain of which the
company does not control; the ability to satisfy obligations under the
company’s firm commitment transportation arrangements; uncertainties
related to the company’s identified drilling locations; the high-risk
nature of successfully stimulating well productivity and drilling for
and producing oil, NGLs and natural gas; operating hazards and uninsured
risks; the risks of fires, floods and natural disasters, which could
become more frequent or of a greater magnitude as a result of climate
change; the concentration of the company’s assets in the Kakwa River
Project; unforeseen title defects; claims by indigenous peoples; failure
to accurately estimate abandonment and reclamation costs; development
and exploratory drilling efforts and well operations may not be
profitable or achieve the targeted return; third-party claims regarding
the company’s right to use technology and equipment; expiry of certain
leases for the undeveloped leasehold acreage in the near future;
government regulations; changes in the application, interpretation and
enforcement of applicable laws and regulations; actual results differing
materially from management estimates and assumptions; alternatives to
and changing demand for petroleum products; extensive competition in the
company’s industry; changes in the company’s credit ratings; third party
credit risk; dependence upon a limited number of customers; terrorist
attacks or armed conflict; cyber security risks, loss of information and
computer systems; the potential for security deposits to be required
under provincial liability management programs; reassessment by taxing
or regulatory authorities of the company’s prior transactions and
filings; variations in foreign exchange rates and interest rates; risks
associated with counterparties in risk management activities related to
commodity prices and foreign exchange rates; sufficiency of insurance
policies; potential for litigation; breach of agreements by
counterparties and potential enforceability issues in contracts; impact
of expansion into new activities on risk exposure; the risks related to
the common shares that are publicly traded and the company’s senior
notes and other indebtedness.
Any financial outlook and future-oriented financial information
contained in this document regarding prospective financial performance,
financial position or cash flows is based on assumptions about future
events, including economic conditions and proposed courses of action
based on management’s assessment of the relevant information that is
currently available. Projected operational information contains
forward-looking information and is based on a number of material
assumptions and factors, as are set out above. These projections may
also be considered to contain future oriented financial information or a
financial outlook. The actual results of the company’s operations for
any period will likely vary from the amounts set forth in these
projections and such variations may be material. Actual results will
vary from projected results. Readers are cautioned that any such
financial outlook and future-oriented financial information contained
herein should not be used for purposes other than those for which it is
disclosed herein. The forward-looking information and statements
contained in this document speak only as of the date hereof and the
company does not assume any obligation to publicly update or revise them
to reflect new events or circumstances, except as may be required
pursuant to applicable laws.
Notes Regarding Industry Metrics and Early Production
This presentation includes certain metrics, including barrels of oil
equivalent (boe), carbon intensity and free cash flow, which do not have
standardized meanings or standard methods of calculation and therefore
such measures may not be comparable to similar measures used by other
companies and should not be used to make comparisons. Such metrics have
been included herein to provide readers with additional information to
evaluate the company’s performance; however, such measures are not
reliable indicators of the future performance of the company and future
performance may not compare to the performance in previous periods.
Seven Generations has adopted the standard of 6 Mcf:1 bbl when
converting natural gas to boes. Condensate and other NGLs are converted
to boes at a ratio of 1 bbl:1 bbl. Boes may be misleading, particularly
if used in isolation. A boe conversion ratio of 6 Mcf: 1 bbl is based
roughly on an energy equivalency conversion method primarily applicable
at the burner tip and does not represent a value equivalency at the
Company’s sales point. Given the value ratio based on the current price
of oil as compared to natural gas and NGLs is significantly different
from the energy equivalency of 6 Mcf: 1 bbl and 1 bbl: 1 bbl,
respectively, utilizing a conversion ratio at 6 Mcf: 1 bbl for natural
gas and 1 bbl: 1 bbl for NGLs, may be misleading as an indication of
value.
The carbon intensity estimates for 7G that are provided herein were
calculated by the company with the assistance of third parties. For the
2018 reporting year, based on 2017 performance, 7G’s carbon intensity of
0.0136 tonnes of CO2e per boe was ranked by CDP as the lowest compared
to six peer companies. 7G quantified and reported its GHG emissions
using what is referred to as the “operational control” approach. 7G’s
deemed organizational boundary included its corporate offices and all
natural gas extraction and processing facilities (including well pads).
7G elected to report its Scope 1 and 2 GHG emissions and not to report
its Scope 3 GHG emissions. For the purposes of 7G’s GHG emissions
reporting:
-
Scope 1 emissions were defined as direct emissions from GHG sources
that 7G owned or controlled (including, but not limited to, emissions
from stationary equipment, mobile combustion, and process emissions
and fugitive emissions);
-
Scope 2 emissions were defined as indirect GHG emissions that resulted
from 7G’s consumption of energy in the form of purchased electricity;
and
-
Scope 3 emissions were defined as 7G’s indirect emissions other than
those covered in Scope 2, including from all sources not owned or
controlled by 7G, but which occurred as a result of 7G’s activities.
Notably, 7G’s drilling and completion activities in the relevant periods
were conducted by third parties and, consequently, those activities were
deemed to be Scope 3.
7G retained Brightspot Climate Inc. to support the quantification of its
2018 GHG emissions. Emissions for all facilities were quantified in
accordance with the methodologies specified in Alberta’s Carbon
Competitiveness Incentive Regulation (CCIR) and Specified Gas Reporting
Regulation (SGRR), and Environment and Climate Change Canada’s
Greenhouse Gas Emissions Reporting Program, as applicable. Measured
quantities, such as fuel volume, fuel carbon content, flare volumes,
venting volumes, fugitive volumes, and electricity consumption were
used, where metered data was available. Emission factors from published
government sources were applied to the calculations. A third party
verification was conducted by Millennium EMS Solutions. This
verification was completed in accordance with the ISO 14064:3 standard
and the requirements of CCIR.
References to “free cash flow” are referring to any adjusted funds flow
that is in excess of total capital expenditures during a particular
period of time.
The lower Montney well production that is described in this news release
is from a well drilled in the Nest 2 area. The results have been
obtained during a 30 day initial flow period (includes completions
flowback and flow through permanent facilities). The average gas
production rate observed to date is 2,732 Mcf/d and the average
condensate production rate observed to date is 782 bbl/d. Cumulative gas
production has been 82 MMcf, cumulative condensate production has been
23,445 bbls and cumulative produced water has been 45,536 bbls. Gas,
condensate, and water rates ramped up over a period of 10 days. Gas
maintained a plateau rate of about 3,300 Mcf/d while condensate
gradually declined as expected. Tubing pressure reached a maximum of
17,000 KPa (2,460 psi) after 5 days of flow and gradually decreased to
about 10,000 KPa (1,450 psi), consistent with a relatively high
liquid/gas ratio of about 840 bbl/MMcf. No pressure transient analysis
or well-test interpretation has been carried out to date.
The Nest 1 perimeter well that is described in this news release was
drilled in the middle interval of the Montney formation in the company’s
Nest 1 area. The results have been obtained during a 60 day initial flow
period (includes completions flowback and flow through permanent
facilities). The average gas production rate observed to date is 3,136
Mcf/d and the average condensate production rate observed to date is
1,375 bbl/d. Cumulative gas production has been 188 MMcf, cumulative
condensate production has been 82,505 bbls and cumulative produced water
has been 59,082 bbls. Gas, condensate, and water rates ramped up over a
period of 12 days. Gas maintained a plateau rate of about 4,100 Mcf/d)
while condensate gradually declined as expected. Tubing pressure reached
a maximum of 9,300 KPa (1,350 psi) after 5 days of flow and gradually
decreased to about 3,500 KPa (510 psi), consistent with a relatively
high liquid/gas ratio of about 750 bbl/MMcf. No pressure transient
analysis or well-test interpretation has been carried out to date.
Readers are cautioned that the flow test results are not necessarily
indicative of long-term performance or ultimate recovery.
Independent Reserves and Resources Evaluation and Drilling
Locations
Estimates of the company’s reserves and contingent resources, as at
December 31, 2018, are based upon the reports prepared by McDaniel &
Associates Consultants Ltd. (McDaniel), dated February 27, 2019 (the
McDaniel Reports). Estimates of reserves and contingent resources are
estimates only and there is no guarantee that the estimated reserves or
contingent resources will be recovered. Actual reserves and contingent
resources may be greater than or less than the estimates provided and
the differences may be material. There is no assurance that the forecast
price and cost assumptions applied by McDaniel in evaluating Seven
Generations’ reserves and contingent resources will be attained and
variances could be material. There is uncertainty that it will be
commercially viable to produce any portion of the contingent resources.
For important additional information regarding the independent reserves
and resources evaluations conducted by McDaniel, please refer to the
AIF, which is available on SEDAR.
For the purposes of estimating potential drilling locations or drilling
opportunities in the Nest 1 area, the company has assumed well spacing
of 12 wells per section and a lateral well lengths of 2,310 metres based
upon industry practice and internal review. The anticipated well spacing
and lateral well length is expected to change over time as technology
and the company’s understanding of the reservoir changes. Of the 480
potential drilling locations or drilling opportunities estimated to be
contained within the company’s Nest 1 area, as at December 31, 2018, 64%
were attributed proved plus probable reserves and 36% were attributed
best estimate contingent resources in the McDaniel Reports. There is no
certainty that the company will drill all of the identified drilling
opportunities or drilling locations and there is no certainty that such
locations will result in additional reserves, resources or production.
The drilling locations on which the company will actually drill wells,
including the number and timing thereof will be dependent upon the
availability of funding, 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 estimated undeveloped drilling locations have been de-risked by
wells drilled in relative close proximity to such locations, some of the
locations are further away from existing wells and management has less
information about the characteristics of the reservoir in such locations
and there is more uncertainty regarding such locations.
Certain oil and gas terms
Terms used in this news release that are not otherwise defined herein
are provided below:
best estimate is a classification of estimated resources
described in the COGE Handbook, which is considered to be the best
estimate of the quantity that will actually be recovered. It is equally
likely that the actual quantities recovered will be greater or less than
the best estimate. Resources in the best estimate case are considered to
have a 50% probability that the actual quantities recovered will equal
or exceed the estimate.
contingent resources are those quantities of petroleum estimated,
as of a given date, to be potentially recoverable from known
accumulations using established technology or technology under
development, but which are not currently considered to be commercially
recoverable due to one or more contingencies. Contingencies are
conditions that must be satisfied for a portion of contingent resources
to be classified as reserves that are: (a) specific to the project being
evaluated; and (b) expected to be resolved within a reasonable
timeframe. Contingencies may include factors such as economic,
environmental, social, political factors and regulatory matters, lack of
markets or a prolonged timetable for development. It is also appropriate
to classify as contingent resources the estimated discovered recoverable
quantities associated with a project in the early evaluation stage.
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.
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.
reserves are estimated remaining quantities of oil and natural
gas and related substances anticipated to be recoverable from known
accumulations, as of a given date, based on: (i) analysis of drilling,
geological, geophysical and engineering data; (ii) the use of
established technology; and (iii) specified economic conditions, which
are generally accepted as being reasonable, and shall be disclosed.
Reserves are classified according to the degree of certainty associated
with the estimates.
|
|
|
Other Definitions/Abbreviations
|
|
AECO
|
|
|
|
physical storage and trading hub for natural gas on the TransCanada
Alberta transmission system
|
|
bbl or bbls
|
|
|
|
barrel or barrels
|
|
boe
|
|
|
|
barrels of oil equivalent
|
|
CO2e
|
|
|
|
carbon dioxide equivalent
|
|
COGE Handbook
|
|
|
|
the Canadian Oil and Gas Evaluation Handbook maintained by the
Society of Petroleum Evaluation Engineers (Calgary Chapter), as
amended from time to time.
|
|
CROIC
|
|
|
|
cash return on invested capital
|
|
C*
|
|
|
|
the drilling and completion cost allowance under Alberta’s
Modernized Royalty Framework
|
|
d
|
|
|
|
day
|
|
D&C
|
|
|
|
drilling and completions
|
|
G&A
|
|
|
|
general and administrative expenses
|
|
H1
|
|
|
|
first half of the year
|
|
H2
|
|
|
|
second half of the year
|
|
IFRS
|
|
|
|
International Financial Reporting Standards
|
|
KPa
|
|
|
|
kilopascals
|
|
LNG
|
|
|
|
liquefied natural gas
|
|
m
|
|
|
|
metres
|
|
MM
|
|
|
|
millions
|
|
mboe
|
|
|
|
thousand barrels of oil equivalent
|
|
mbbl
|
|
|
|
thousands of barrels
|
|
Mcf
|
|
|
|
thousand cubic feet
|
|
MMcf
|
|
|
|
million cubic feet
|
|
Nest
|
|
|
|
the Nest 1, Nest 2 and Nest 3 areas combined
|
|
Nest 1
|
|
|
|
the “Nest 1” area shown in the map provided in the AIF
|
|
Nest 2
|
|
|
|
the “Nest 2” area shown in the map provided in the AIF
|
|
Nest 3
|
|
|
|
the “Nest 3” area shown in the map provided in the AIF
|
|
NGL or NGLs
|
|
|
|
natural gas liquids
|
|
nm
|
|
|
|
not meaningful information
|
|
psi
|
|
|
|
pounds per square inch
|
|
ROCE
|
|
|
|
return on capital employed
|
|
SEDAR
|
|
|
|
the System for Electronic Document Analysis and Retrieval
maintained by the Canadian Securities Administrators available at
www.sedar.com.
|
|
TSX
|
|
|
|
Toronto Stock Exchange
|
|
US
|
|
|
|
United States
|
|
US$
|
|
|
|
United States dollars
|
|
WTI
|
|
|
|
West Texas Intermediate
|
|
|
|
|
|
|
Seven Generations Energy Ltd. is also referred to as Seven
Generations, Seven Generations Energy, 7G, we, our, the
Company and the company.
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