Free cash flow of $120 million in the fourth quarter and $158 million for 2019 reflect improving capital efficiencies and reduced operating costs; Nest 2 inventory expansion replenishes top-tier inventory life
Seven Generations Energy Ltd. (TSX: VII):
FOURTH QUARTER 2019 HIGHLIGHTS
- Net income per diluted share was $0.24 in the fourth quarter, and $1.36 for the full year, an increase of 12% over 2018 on a full year basis.
- Fourth quarter and full year 2019 funds flow was $353 million and $1.39 billion, respectively, with capital investments of $233 million for the fourth quarter and $1.23 billion for the full year. Free cash flow was $120 million in the fourth quarter and $158 million for full year 2019.
- Sales volumes were 208,100 boe/d (36% condensate, 22% other NGLs, 42% natural gas) in the fourth quarter of 2019, and average sales volumes were 203,000 boe/d (37% condensate, 22% other NGLs, 41% natural gas) for the full year in 2019, consistent with 2019 guidance.
- Operating expenses averaged $4.43 per boe in the fourth quarter and $4.79 per boe for the full year 2019, below the full year guidance range of $5.00 to $5.25 per boe, representing a 13% improvement year over year.
- During 2019, the company repurchased 22.1 million shares at a volume weighted average price of $7.61 per share, representing 6.3% of shares outstanding at the beginning of the year. The company has repurchased 31.8 million shares, equivalent to 8.8% of its share count since the commencement of the company’s first normal course issuer bid (“NCIB”) effective November 5, 2018.
- 7G continues to be a sustainability leader. The company recently received an A- rating from CDP for its environmental disclosure and performance. As previously announced, the company has also entered into a responsible natural gas supply agreement with Québec’s main natural gas distributor, Énergir s.e.c. (“Énergir”), after achieving Equitable Origins’ EO100™ Standard for Responsible Energy Development certification.
2019 RESERVES AND RESOURCE HIGHLIGHTS
- McDaniel & Associates Consultants Ltd. (“McDaniel”), the company’s independent qualified reserves evaluator, has estimated 7G’s gross total proved (“1P”) reserves of 842 million boe with an NPV10 of $6.7 billion and gross proved plus probable (“2P”) reserves of 1.6 billion boe with an NPV10 of $12.6 billion, as at December 31, 2019.
- Capital efficiency gains drove a $940 million reduction to total undiscounted 2P future development costs, as assessed by McDaniel at December 31, 2019, compared to the prior year. Proved developed producing (“PDP”) reserve finding, development and acquisition (“FD&A”) costs, including changes to future development capital, of $13.06 per boe drove a recycle ratio of 1.6x for the year, based upon operating netback, before the effects of hedging and marketing income. 1P reserve and 2P reserve recycle ratios were 2.6x and 2.4x, respectively.
- The Company’s delineation efforts in 2019 successfully expanded the known boundary of high-deliverability, condensate-rich locations in the western portion of Nest 2, which was previously considered part of the Wapiti region at year end 2018. This has converted approximately 100 upper/middle Montney reserve and resource locations from a Wapiti to a Nest 2 type well for year end 2019.
7G’s results in the fourth quarter and full year 2019 reflect the company’s 2019 strategic objectives of increasing per share value, expanding free cash flow potential and achieving significant inventory delineation, with differentiated ESG performance.
|
OPERATIONAL AND FINANCIAL HIGHLIGHTS
|
|
|
|
|
|
($ millions, except boe
and per share amounts)
|
Three months ended
December 31
|
Three months ended
September 30
|
Year ended
December 31
|
|
2019
|
2018
|
% Change
|
2019
|
% Change
|
2019
|
2018
|
% Change
|
|
Financial Results
|
|
|
|
|
|
|
|
|
|
Funds flow ($)(1)
|
353.2
|
|
336.2
|
|
5
|
|
340.5
|
|
4
|
|
1,387.8
|
|
1,672.2
|
|
(17
|
)
|
|
Per share - diluted ($)
|
1.05
|
|
0.93
|
|
13
|
|
0.98
|
|
7
|
|
3.98
|
|
4.60
|
|
(13
|
)
|
|
Free cash flow ($)(1)
|
120.3
|
|
73.9
|
|
63
|
|
55.9
|
|
115
|
|
158.3
|
|
(93.5
|
)
|
nm
|
|
|
Net income ($)
|
82.6
|
|
245.4
|
|
(66
|
)
|
85.1
|
|
(3
|
)
|
473.8
|
|
439.9
|
|
8
|
|
|
Per share - diluted ($)
|
0.24
|
|
0.68
|
|
(65
|
)
|
0.25
|
|
(4
|
)
|
1.36
|
|
1.21
|
|
12
|
|
|
Adjusted net income ($)(1)
|
89.7
|
|
66.3
|
|
35
|
|
78.5
|
|
14
|
|
349.0
|
|
573.6
|
|
(39
|
)
|
|
Per share - diluted ($)
|
0.27
|
|
0.18
|
|
50
|
|
0.23
|
|
17
|
|
1.00
|
|
1.58
|
|
(37
|
)
|
|
Revenue ($)(2)
|
669.6
|
|
1,146.8
|
|
(42
|
)
|
718.0
|
|
(7
|
)
|
2,729.4
|
|
3,169.9
|
|
(14
|
)
|
|
CROIC (%)(1)
|
14.0%
|
|
19.1%
|
|
(27
|
)
|
14.1%
|
|
(1
|
)
|
14.0%
|
|
19.1%
|
|
(27
|
)
|
|
ROCE (%)(1)
|
9.0%
|
|
14.1%
|
|
(36
|
)
|
8.6%
|
|
5
|
|
9.0%
|
|
14.1%
|
|
(36
|
)
|
|
Sales volumes(3)
|
|
|
|
|
|
|
|
|
|
Condensate (mbbl/d)
|
75.0
|
|
81.8
|
|
(8
|
)
|
75.5
|
|
(1
|
)
|
74.8
|
|
76.4
|
|
(2
|
)
|
|
Natural gas (MMcf/d)
|
523.1
|
|
515.4
|
|
1
|
|
515.3
|
|
2
|
|
503.0
|
|
490.5
|
|
3
|
|
|
Other NGLs (mbbl/d)
|
45.9
|
|
47.4
|
|
(3
|
)
|
43.2
|
|
6
|
|
44.4
|
|
44.4
|
|
—
|
|
|
Total sales volumes (mboe/d)(4)
|
208.1
|
|
215.1
|
|
(3
|
)
|
204.6
|
|
2
|
|
203.0
|
|
202.6
|
|
—
|
|
|
Liquids %
|
58%
|
|
60%
|
|
(3
|
)
|
58%
|
|
—
|
|
59%
|
|
60%
|
|
(2
|
)
|
|
Realized prices
|
|
|
|
|
|
|
|
|
|
Condensate ($/bbl)
|
66.39
|
|
53.57
|
|
24
|
|
65.59
|
|
1
|
|
66.76
|
|
71.63
|
|
(7
|
)
|
|
Natural gas ($/Mcf)
|
3.25
|
|
4.77
|
|
(32
|
)
|
2.85
|
|
14
|
|
3.41
|
|
3.98
|
|
(14
|
)
|
|
Other NGLs ($/bbl)
|
10.75
|
|
8.44
|
|
27
|
|
2.74
|
|
nm
|
|
6.34
|
|
12.21
|
|
(48
|
)
|
|
Total ($/boe)(4)
|
34.48
|
|
33.66
|
|
2
|
|
31.97
|
|
8
|
|
34.44
|
|
39.33
|
|
(12
|
)
|
|
Royalty expense ($/boe)
|
(2.62
|
)
|
(0.99
|
)
|
165
|
|
(1.99
|
)
|
32
|
|
(2.28
|
)
|
(1.34
|
)
|
70
|
|
|
Operating expenses ($/boe)
|
(4.43
|
)
|
(5.25
|
)
|
(16
|
)
|
(4.81
|
)
|
(8
|
)
|
(4.79
|
)
|
(5.52
|
)
|
(13
|
)
|
|
Transportation, processing and other ($/boe)
|
(7.01
|
)
|
(7.07
|
)
|
(1
|
)
|
(6.46
|
)
|
9
|
|
(6.69
|
)
|
(6.65
|
)
|
1
|
|
|
Operating netback before the following ($/boe)(1)(4)
|
20.42
|
|
20.35
|
|
—
|
|
18.71
|
|
9
|
|
20.68
|
|
25.82
|
|
(20
|
)
|
|
Realized hedging gains (losses) ($/boe)
|
0.55
|
|
(1.58
|
)
|
nm
|
|
1.63
|
|
(66
|
)
|
0.48
|
|
(1.33
|
)
|
nm
|
|
|
Marketing income ($/boe)(1)
|
0.18
|
|
0.20
|
|
(10
|
)
|
0.19
|
|
(5
|
)
|
0.30
|
|
0.39
|
|
(23
|
)
|
|
Operating netback ($/boe)(1)
|
21.15
|
|
18.97
|
|
11
|
|
20.53
|
|
3
|
|
21.46
|
|
24.88
|
|
(14
|
)
|
|
Funds flow ($/boe)(1)
|
18.45
|
|
16.99
|
|
9
|
|
18.09
|
|
2
|
|
18.73
|
|
22.61
|
|
(17
|
)
|
|
Balance sheet
|
|
|
|
|
|
|
|
|
|
Capital investments ($)
|
232.9
|
|
262.3
|
|
(11
|
)
|
284.6
|
|
(18
|
)
|
1,229.5
|
|
1,765.7
|
|
(30
|
)
|
|
Available funding ($)(1)
|
1,351.0
|
|
1,345.9
|
|
—
|
|
1,277.2
|
|
6
|
|
1,351.0
|
|
1,345.9
|
|
—
|
|
|
Senior notes ($)
|
2,030.2
|
|
2,129.8
|
|
(5
|
)
|
2,069.3
|
|
(2
|
)
|
2,030.2
|
|
2,129.8
|
|
(5
|
)
|
|
Net debt ($)(1)
|
2,099.3
|
|
2,206.8
|
|
(5
|
)
|
2,213.7
|
|
(5
|
)
|
2,099.3
|
|
2,206.8
|
|
(5
|
)
|
|
Repurchase of common shares ($)
|
50.2
|
|
104.2
|
|
(52
|
)
|
73.8
|
|
(32
|
)
|
168.1
|
|
104.2
|
|
61
|
|
|
Common shares outstanding
|
334.7
|
|
352.6
|
|
(5
|
)
|
340.5
|
|
(2
|
)
|
334.7
|
|
352.6
|
|
(5
|
)
|
|
Weighted average shares outstanding - basic
|
336.5
|
|
359.2
|
|
(6
|
)
|
345.9
|
|
(3
|
)
|
346.8
|
|
358.6
|
|
(3
|
)
|
|
Weighted average shares outstanding - diluted
|
337.9
|
|
362.3
|
|
(7
|
)
|
347.0
|
|
(3
|
)
|
348.5
|
|
363.9
|
|
(4
|
)
|
|
(1)
|
|
Refer to the Reader Advisory at the end of this news release and the Advisories and Guidance section of the company’s Management’s Discussion and Analysis for the years ended December 31, 2019 and 2018 for additional information regarding the Company's non-GAAP and additional GAAP measures. Certain comparative figures have been adjusted to conform to current period presentation.
|
|
(2)
|
|
Represents the total of liquids and natural gas sales, net of royalties, gains (losses) on risk management contracts and other income.
|
|
(3)
|
|
See "Note Regarding Product Types" in the Reader Advisory at the end of this news release and the Advisories and Guidance section of the
company’s Management’s Discussion and Analysis for the years ended December 31, 2019 and 2018.
|
|
(4)
|
|
Excludes the purchase and sale of condensate and natural gas in respect of the Company's transportation commitment utilization and marketing activities.
|
|
|
Three months ended
December 31
|
Three months ended
September 30
|
Year ended
December 31
|
|
Nest Activity
|
2019
|
2018
|
% Change
|
2019
|
% Change
|
2019
|
2018
|
% Change
|
|
Drilling(1)
|
|
|
|
|
|
|
|
|
|
Horizontal wells rig released
|
20
|
|
19
|
|
5
|
|
20
|
|
-
|
|
78
|
|
91
|
|
(14
|
)
|
|
Average measured depth (m)
|
5,782
|
|
6,010
|
|
(4
|
)
|
5,979
|
|
(3
|
)
|
5,966
|
|
5,735
|
|
4
|
|
|
Average horizontal length (m)
|
2,579
|
|
2,776
|
|
(7
|
)
|
2,785
|
|
(7
|
)
|
2,729
|
|
2,551
|
|
7
|
|
|
Average drilling days per well
|
26
|
|
28
|
|
(7
|
)
|
25
|
|
4
|
|
28
|
|
27
|
|
4
|
|
|
Average drill cost per metre ($)(2)
|
526
|
|
560
|
|
(6
|
)
|
502
|
|
5
|
|
545
|
|
607
|
|
(10
|
)
|
|
Average well cost ($ millions)(2)
|
3.1
|
|
3.4
|
|
(9
|
)
|
3.0
|
|
3
|
|
3.3
|
|
3.5
|
|
(6
|
)
|
|
Completion(1)
|
|
|
|
|
|
|
|
|
|
Wells completed
|
10
|
|
13
|
|
(23
|
)
|
30
|
|
(67
|
)
|
79
|
|
89
|
|
(11
|
)
|
|
Average tonnes pumped per metre
|
1.7
|
|
1.9
|
|
(11
|
)
|
2.1
|
|
(19
|
)
|
2.0
|
|
2.3
|
|
(13
|
)
|
|
Average cost per tonne ($)(2)
|
1,070
|
|
1,282
|
|
(17
|
)
|
917
|
|
17
|
|
1,073
|
|
1,228
|
|
(13
|
)
|
|
Average cost per lateral metre ($)(2)
|
1,850
|
|
2,350
|
|
(21
|
)
|
1,953
|
|
(5
|
)
|
2,131
|
|
2,718
|
|
(22
|
)
|
|
Average well cost ($ millions)(2)
|
4.8
|
|
5.7
|
|
(16
|
)
|
5.4
|
|
(11
|
)
|
5.7
|
|
6.6
|
|
(14
|
)
|
|
Total D&C cost per well ($ millions)(2)(3)
|
7.9
|
|
9.1
|
|
(13
|
)
|
8.4
|
|
(6
|
)
|
9.0
|
|
10.1
|
|
(11
|
)
|
|
Wells brought on production
|
26
|
|
8
|
|
nm
|
|
15
|
|
73
|
|
83
|
|
91
|
|
(9
|
)
|
|
(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. Drilling counts are based on rig release date and on production counts are based on the first production date after the wells are tied in to permanent facilities.
|
|
(2)
|
|
Information provided is based on field estimates and is subject to change.
|
|
(3)
|
|
The number of horizontal wells rig-released do not correspond to the number of wells completions in the table above. Accordingly, the total average D&C costs per well may differ from the actual D&C costs for any individual well.
|
OPERATIONS UPDATE
Drilling and completion costs for full year 2019 averaged $9 million per well, an 11% reduction relative to the $10.1 million achieved in 2018. Drilling and completion costs in the fourth quarter averaged $7.9 million per well, representing a 12% reduction relative to the 2019 average. While shorter lateral lengths during the fourth quarter contributed to a portion of the reduced costs, the results also included wells with enhanced completions designs. This design includes an increased number of per-stage fracture initiation points, which the company believes will lead to similar effective fracture initiations, but with lower per-well costs. The company has also benefitted from ongoing supply chain management optimization.
Operating expenses for the fourth quarter were $4.43 per boe, while full year operating expenses were $4.79 per boe, both meaningfully below the 2019 guidance range of $5.00 to $5.25 per boe. These results are a function of the company’s previous water handling investments, a strengthening culture of cost mindfulness and continuous improvement throughout the organization. 2020 operating cost guidance remains in a range of $4.75 to $5.25 per boe, due to slightly reduced sales volumes expected in the first half of the year and the previously announced Karr facility turnaround and upgrade.
RESOURCE UPDATE
Moderating Sustaining Capital Requirements
As 7G evolves from a high-growth model to a value-focused, free cash flow generating business, the company has moderated its corporate production decline rates, reducing the amount of capital investment required to sustain production at current levels by approximately 10% year over year, consistent with prior 2020 budget disclosures. With the maturing of its asset base, the company anticipates a continued reduction in its production decline rates and sustaining capital requirements that will make meaningful contributions to its free cash flow profile and optionality.
Nest 2 Upper/Middle Montney Inventory
Due to the company’s 2019 delineation program, 7G now has data to support transferring 100 upper/middle Montney locations to its Nest 2 region, which were previously categorized with a Wapiti type well assumption. The conversion of 100 locations from Wapiti to Nest 2 (booked in either reserves or contingent resources at year end 2019) exceeds the pace of development in the Nest, which saw 78 locations rig released. McDaniel has evaluated the new Nest 2 locations and expects them to be sweet, high condensate rate locations analogous to other undeveloped locations in the western region of Nest 2. The region also remains prospective for lower Montney locations to be validated with future delineation efforts.
Nest 3 Update
The company’s development efforts continued in the Nest 3 region during the fourth quarter. The table below shows results from the 8-well Nest 3 pad discussed in the company’s third quarter news release, and the second Nest 3 pad, consisting of 8 wells, brought onstream in October. This second pad saw periods of intermittent rate curtailment to manage pressures across the broader Nest infrastructure, but is now flowing at unrestricted rates. Despite flow restrictions, these latest wells have trended in-line with expectations on total productivity, and more than 20% ahead of expectations on condensate deliverability.
The most productive location within 7G’s 2019 Nest 3 program is the lower Montney location which has outperformed upper/middle Montney locations and was brought onstream with the lowest well cost among the locations drilled on these two pads. The company anticipates additional follow-up stacked development of the lower Montney at Nest 3 throughout the 2020 capital program.
|
|
|
Sales Volumes(1)
|
|
|
Average D&C
Cost
|
IP120
(boe/d)
|
Condensate
(bbl/d)
|
Other NGLs
(bbl/d)
|
Natural Gas
(mcf/d)
|
|
|
|
|
|
|
|
|
First 8-Well Pad
|
$8.8 MM
|
2,289
|
673
|
558
|
6,346
|
|
Second 8-Well Pad
|
$8.7 MM
|
1,964
|
473
|
515
|
5,855
|
|
Lower Montney Location
|
$8.5 MM
|
2,253
|
693
|
539
|
6,127
|
|
|
|
|
|
|
|
| 1) See “Note Regarding Early Production” in the Reader Advisory in this news release. |
2019 YEAR-END RESERVES
The following table summarizes 7G’s reserves, based upon reports prepared by McDaniel, as at December 31, 2018 and December 31, 2019 (the “McDaniel Reports”), using the forecast price and cost assumptions in effect at the applicable effective reserve evaluation dates.
|
|
Year ended
December 31
|
|
|
2019(1)
|
|
2018(1)
|
|
|
Reserve Category
|
MMboe
|
$MM(2)
|
MMboe
|
$MM(2)
|
|
Gross PDP reserves
|
261
|
|
|
$
|
2,899
|
|
242
|
|
|
$
|
2,824
|
|
|
Gross 1P reserves
|
842
|
|
|
$
|
6,730
|
|
856
|
|
|
$
|
6,518
|
|
|
Gross 2P reserves
|
1,604
|
|
|
$
|
12,602
|
|
1,644
|
|
|
$
|
12,282
|
|
|
(1)
|
|
Refer to the Reader Advisory in this news release and the Annual Information Form dated February 26, 2020 (for the year ended December 31,
2019) and dated February 27, 2019 (for the year ended December 31, 2018), which are available on SEDAR for additional information regarding
the Company's reserves and the estimated net present value of future net revenue associated with such reserves, evaluated by McDaniel.
|
|
(2)
|
|
Estimated pre-tax net present value of discounted cash flows from reserves using a 10% discount rate.
|
|
2019 ($/boe)(3)
|
|
|
PDP
|
1P
|
2P
|
|
FD&A Cost(1)
|
13.06
|
7.95
|
8.62
|
|
FD&A Recycle Ratio(2)
|
1.6x
|
2.6x
|
2.4x
|
|
1)
|
|
FD&A costs include the year over year change in future development capital to convert reserves into production.
|
|
2)
|
|
Recycle Ratio is operating netback prior to hedging and marketing income, divided by FD&A costs per boe. See “Non-GAAP Financial Measures” in the Reader Advisory in this news release for additional information.
|
|
3)
|
|
See “Note Regarding Oil and Gas Metrics” in the Reader Advisory in this news release for additional information.
|
Relative to year end 2018, based on the reports prepared by McDaniel, total undiscounted future development capital costs expected to be required to develop the company’s 2P reserves were reduced by $940 million, or approximately $2.80 per share, due to improved capital efficiencies throughout the Nest. These improvements in future development capital costs, along with the successful 2019 development program, resulted in a recycle ratio of 1.6x on a PDP reserves basis, 2.6x on a 1P reserves basis and 2.4x on a 2P reserves basis, based on operating netbacks before the effect of hedging and marketing income.
Based on total produced volumes for full year 2019, the company’s reserve life index was 11.4 years on a 1P basis and 21.6 years on a 2P basis.
Total PDP reserve volumes increased by 8% as the company has been successful at converting undeveloped reserves, while seeing reductions in overall corporate decline rates, consistent with prior expectations. Based on the McDaniel Reports, 1P NGL reserves decreased by 0.7% and 2P NGL reserves increased by 0.8% at year end 2019, compared to the prior year; however, condensate and pentanes plus, which combined represented 59% of the 1P NGL reserves and 63% of the 2P NGL reserves, evaluated at December 31, 2019, increased by 2.2% and 6.9% relative to the prior year.
Relative to 2018, the pre-tax NPV of 1P reserves and 2P reserves, using a 10% discount rate, increased by $212 million and $320 million, respectively, despite reductions to reserve evaluator price decks. These improvements have been driven by the combination of favorable changes in product mix and improvements to capital efficiency.
NORMAL COURSE ISSUER BID
During 2019, the company repurchased 22.1 million shares at a volume weighted average price of $7.61 per share, representing 6.3% of shares outstanding at the beginning of the year. The company has repurchased 31.8 million shares, equivalent to 8.8% of its share count since the commencement of the company’s first NCIB effective November 5, 2018. The company continues to view the allocation of free cash flow towards a share buy-back program as a competitive investment opportunity. The company plans to allocate free cash flow generated during 2020 towards its share buy-back program and net debt reduction.
ESG UPDATE
A commitment to differentiated stakeholder service and responsible development is key to 7G’s strategy. With a prudent risk-management mindset of “what gets measured, gets managed”, the company is pleased to report several key successes in advancing its sustainability profile:
- 7G’s responsible energy development practices and commitment to stakeholder service have been recognized through Equitable Origins’ EO100™ certification, following a comprehensive, independent, assurance process that verified 7G’s ESG performance through site-level assessments. As a result of the certification, 7G has successfully commercialized its sustainability profile through an agreement to supply responsibly produced natural gas to Québec’s main natural gas distributor, Énergir. Globally, this is the first transaction executed under the EO100™ framework, which establishes a new standard in terms of responsible development and transparency across the value chain and, ultimately, recognizes 7G’s commitment to continuous improvement of its sustainable development practices.
- In January, the company received an A- ranking from CDP, positioning 7G as the top-ranked energy producer in Canada for its emissions measurement, management and disclosure. The company aims to maintain its top-decile emissions and disclosure profile in future years.
- Also in January, 7G was included as one of 325 companies globally in the 2020 Bloomberg Gender-Equality Index (“GEI”). Through disclosure of gender-related metrics using the GEI framework, the firms included in the 2020 index have provided a comprehensive look at their investment in workplace gender equality and the communities in which they operate. 7G was included in this year’s index for scoring at or above a global threshold established by Bloomberg to reflect a high level of disclosure and overall performance across the framework’s five pillars.
These initiatives, and a broader discussion of 7G’s ESG practices, will be discussed in 7G’s sustainability report to be released in March 2020. The report will highlight 7G’s commitment to differentiated stakeholder service, responsible energy development and stakeholder engagement, including simplified reporting and statistical data for decision making by investors and rating agencies.
MIDSTREAM UPDATE
Subsequent to year end, 7G concluded its review of multiple proposals to monetize some or all of the company’s midstream investments. The company has decided that, at this time, it is in its best interest to retain full ownership of these assets and that maintaining its low cost structure, enhanced flexibility, operatorship and reserve processing capacity, will continue to drive strategic benefits.
2020 OUTLOOK
The company’s 2020 capital budget and guidance are unchanged from previously disclosed metrics, including $1.0 billion of production and supporting infrastructure capital primarily to sustain annual production levels at 200,000 to 205,000 boe/d and a further $100 million for value enhancement projects and delineation. At the midpoint of guidance, full year production is anticipated to average 202,500 boe/d.
Consistent with prior guidance, the company anticipates production volumes in the first half of the year to be lower than the second half, primarily as offset wells are routinely shut-in during adjacent completion operations. The resumption of production from these wells, and volumes from newly completed wells, are anticipated to bring production to the 205,000 to 215,000 boe/d range for the second half of the year.
Condensate volumes in 2020 are approximately 55% hedged with WTI contracts within a range of US$52/bbl to US$57/bbl, while natural gas is approximately 39% hedged at a level of US$2.65/MMBtu.
|
|
2020 Capital Budget & Guidance
|
|
Production & Supporting Infrastructure
|
$1.0 billion
|
|
Value Enhancement Projects and Delineation
|
$0.1 billion
|
|
Total Capital Investment
|
$1.1 billion
|
|
|
|
Average Production(1)
|
200 - 205 Mboe/d
|
|
H1 Production(1)
|
190 - 200 Mboe/d
|
|
H2 Production(1)
|
205 - 215 Mboe/d
|
|
|
|
Development Wells On-Stream (#)
|
75 - 80
|
|
Percent Liquids(1)
|
56 - 60%
|
|
Percent Condensate(1)
|
34 - 38%
|
|
Royalty Rate at US$50 WTI
|
5 - 7%
|
|
Royalty Rate at US$60 WTI
|
7 - 9%
|
|
Operating Expenses ($/boe)
|
$4.75 - $5.25
|
|
Transportation ($/boe)
|
$6.75 - $7.25
|
|
G&A ($/boe)
|
$0.85 - $0.95
|
|
Interest ($/boe)
|
$1.80 - $1.90
|
|
1)
|
|
See “Note Regarding Product Types” and “Forward-Looking Information Advisory” in the Reader Advisory in this news release.
|
CONFERENCE CALL
7G management will hold a conference call to discuss results and address investor questions today, February 27, 2020, at 9 a.m. MST (11 a.m. EST).
Seven Generations Energy
Seven Generations 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-GAAP 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 “adjusted net income”, “marketing income”, “marketing income per boe”, “operating netback”, “operating netback before realized hedging gains and marketing income” (and words to like effect), “funds flow per boe”, “free cash flow”, “return on capital invested” (or “ROCE”), “cash return on invested capital” (or “CRIOC”) 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. Such non-GAAP measures should be read in conjunction with the company’s consolidated financial statements for the years ended December 31, 2019 and 2018 and the accompanying notes. Readers are cautioned that the non-GAAP 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-GAAP financial measures” in Management’s Discussion and Analysis February 26, 2020, for the years ended December 31, 2019 and 2018.
“Operating netback before realized hedging gains (loss) and marketing income” is calculated on a per boe basis and is determined by deducting royalties, operating, transportation, processing and other expenses from oil and natural gas sales, before taking into account marketing income and excluding realized hedging gains or losses. For the year ended December 31, 2019, operating netback before realized hedging gains and marketing income was calculated by subtracting royalties of $2.28, operating expenses of $4.79 and transportation, processing and other costs of $6.69, from revenues per boe of $34.44. Operating netback before realized hedging gains and marketing income is utilized by Seven Generations and others to assess the profitability of the Company's liquids and natural gas assets at the field level and to compare results to prior periods by isolating for the impact of changes in production volumes.
"Net debt" has been included in Note 15 - Capital Management in the company’s consolidated financial statements for the years ended December 31, 2019 and 2018and "funds flow" has been presented in the consolidated cash flow statement. Accordingly, these performance measures are additional GAAP measures and are not considered non-GAAP measures. Readers are cautioned that these additional GAAP measures do not have any standardized meaning and should not be used to make comparisons between Seven Generations and other companies without also taking into account any differences in the methods by which the calculations are prepared. For additional information about these measures, please see “Advisories and Guidance – Additional GAAP measures” in Management’s Discussion and Analysis February 26, 2020, for the years ended December 31, 2019 and 2018.
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 document contains forward-looking information and statements pertaining to the following: estimated future development costs; the expectation that the area recently added to Nest 2 will have sweet, high condensate rate production and will be analogous to other undeveloped locations (in terms of productivity) in the western region of Nest 2; the possibility of adding lower Montney locations in the western region of Nest 2 through further delineation activities; the strategic objectives of increasing per share value, expanding the company’s free cash flow potential and achieving significant inventory delineation, differentiated ESG performance; expectation that an increased number of per-stage facture initiation points will lead to similar fracture initiations at lower cost; the planned Karr facility turnaround and upgrade; the company’s evolution from a high growth model to a value-focused, free cash flow generating business; expectation that there will be continued reductions to production decline rates and sustaining capital requirements, which will make meaningful contributions to the company’s free cash flow profile and optionality; follow-up stacked development of the lower Montney in Nest 3 that is planned as part of the 2020 capital program; plans to allocate free cash flow generated in 2020 to the company’s share buy-back program and net debt reduction; the continued improvement of the company’s sustainable development practices; the goal of maintaining a top-decile emissions and disclosure profile; the planned release of the company’s annual sustainability report in March of 2020; details and forecasts related to the 2020 budget, including those described under the heading “2020 Outlook”, including: expected production and supporting infrastructure capital investments, expected capital investments in value enhancing projects and delineation, total capital investments in 2020, average daily production for the first half, second half and full-year in 2020, the number of development wells to be brought on-stream, liquids and condensate yields, royalty rates, operating expenses, drilling and completions costs, transportation expenses, G&A expenses and interest expenses. In addition to the foregoing, information and statements in this news release relating to reserves and resources and the net present value of future net revenue from reserves are 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 they can be profitably produced and/or sold based upon certain forecast prices and costs, as evaluated by the Company’s qualified independent reserves evaluator.
With respect to forward-looking information contained in this document, 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; new 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.
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 annual information form dated February 26, 2020 for the year ended December 31, 2019 (the “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; the ability to find, develop or acquire additional reserves and the availability of the capital or financing necessary to do so on satisfactory terms; 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; actions by governmental authorities, including changes in government regulation, royalties and taxation; political changes; potential legislative and regulatory changes; the rescission, or amendment to the conditions, of groundwater licenses of the Company; management of the Company’s growth; 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 adoption or modification of climate change legislation by governments; potential impacts of climate change on the Company’s operations; 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 and processing arrangements; the export and sale of natural gas to the United States; the 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 possibility that the Company’s drilling activities may encounter sour gas; execution risks associated with the Company’s business plan; failure to acquire or develop replacement reserves; the concentration of the Company’s assets in the Kakwa area; unforeseen title defects; Indigenous claims; 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; horizontal drilling and completion technique risks and failure of drilling results to meet expectations for reserves or production; limited intellectual property protection for operating practices and dependence on employees and contractors; 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; failure to realize the anticipated benefits of acquisitions or dispositions; failure of properties acquired now or in the future to produce as projected and inability to determine reserve and resource potential, identify liabilities associated with acquired properties or obtain protection from sellers against such liabilities; government regulations; changes in the application, interpretation and enforcement of applicable laws and regulations; environmental, health and safety requirements; restrictions on development intended to protect certain species of wildlife; potential conflicts of interests; actual results differing materially from management estimates and assumptions; seasonality of the Company’s activities and the Canadian oil and gas industry; 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; lower oil, NGLs and natural gas prices and higher costs; failure of seismic data used by the Company to accurately identify the presence of oil and natural gas; risks relating to commodity price hedging instruments; terrorist attacks or armed conflict; cyber security risks, loss of information and computer systems; inability to dispose of non-strategic assets on attractive terms; the potential for security deposits to be required under provincial liability management programs; reassessment by taxing and royalty 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; variation in future calculations of non-IFRS measures; breach of and potential enforceability issues in contracts; impact of expansion into new activities on risk exposure; inability of the Company to respond quickly to competitive pressures; and 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.
Independent Reserves Evaluation
Estimates of the company’s reserves and the net present value of future net revenue attributable to the company’s reserves contained in this news release are based upon the reports prepared McDaniel & Associates Consultants Ltd. (“McDaniel”), as at December 31, 2018 and as at December 31, 2019. The estimates of reserves contained herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided in this news release and the differences may be material. Estimates of net present value of future net revenue attributable to the company’s reserves do not represent the fair market value of the company’s reserves and there is uncertainty that the net present value of future net revenue will be realized. There is no assurance that the forecast price and cost assumptions applied by McDaniel in evaluating Seven Generations’ reserves will be attained and variances could be material. For important additional information regarding the independent reserves evaluations that were conducted by McDaniel, please refer to the AIF, as well as the annual information form dated February 27, 2019 for the year ended December 31, 2018, which are available on the SEDAR website at www.sedar.com.
Note Regarding Oil and Gas Metrics
This news release includes certain metrics, including barrels of oil equivalent (“boe”), finding and development (“F&D) costs, finding, development and acquisition (“FD&A”) costs, PDP FD&A Cost, FD&A recycle ratios, 1P recycle ratio, 2P recycle ratio, PDP recycle ratio, 1P reserve life index and 2P reserve life index, 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.
F&D costs have been calculated by the company as the sum of exploration and development capital, plus changes in future development costs for the given year, divided by total reserve additions for that year. This metric is utilized by the company to monitor reserve addition efficiencies over time.
1P F&D costs have been calculated by the company as the sum of exploration and development capital, plus changes in 1P future development costs for the given year, divided by total 1P reserve additions for that year. This metric is utilized by the company to monitor reserve addition efficiencies over time.
2P F&D costs have been calculated by the company as the sum of exploration and development capital, plus changes in 2P future development costs for the given year, divided by total 2P reserve additions for that year. This metric is utilized by the company to monitor reserve addition efficiencies over time.
FD&A costs have been calculated by the company as the sum of exploration and development capital, plus acquisition capital, plus changes in future development costs for the given year, divided by total reserve additions for that year. This metric is utilized by the company to monitor reserve addition efficiencies over time.
F&D recycle ratios have been calculated by the company as operating netback before hedging and marketing gains (losses) divided by F&D costs on a boe basis. This metric is utilized by the company to monitor reserve addition efficiencies relative to the netbacks achieved from such reserve additions.
FD&A recycle ratios have been calculated by the company as operating netback before hedging and marketing gains divided by FD&A costs on a boe basis. This metric is utilized by the company to monitor reserve addition efficiencies, inclusive of acquisition costs, relative to the netbacks achieved from such reserve additions.
PDP reserve capital is defined as total capital investments during the year plus any changes in future development capital.
PDP reserves additions is defined as the sum of all extensions/improved recoveries, technical revisions and economic factors for the year.
PDP FD&A cost has been calculated by dividing the PDP Reserve Capital by the PDP Reserves Additions.
PDP recycle ratios have been calculated by taking the operating netback prior to gains from hedging and marketing and dividing by the PDP F&D.
1P recycle ratios have been calculated by taking the operating netback prior to gains from hedging and marketing and dividing by the 1P F&D costs.
2P recycle ratios have been calculated by taking the operating netback prior to gains from hedging and marketing and dividing by the 2P F&D costs.
1P reserve life index has been calculated by dividing the total 1P reserve volumes by 2019 full year average production.
2P reserve life index has been calculated by dividing the total 2P reserve volumes by 2019 full year average production.
For important additional information regarding the independent reserves evaluations that were conducted by McDaniel, please refer to the AIF, as well as the annual information form dated February 27, 2019 for the year ended December 31, 2018, which are available on the SEDAR website at www.sedar.com.
Note Regarding Product Types
This news release includes references to total average daily production, condensate production, other NGL production, natural gas production, liquids production and CGRs. Other NGLs refers to all natural gas liquids, except for condensate, which is reported separately. Natural gas refers to conventional natural gas and shale gas combined. Liquids refers to condensate and other NGLs combined. CGR refers to the ratio of condensate production compared to natural gas production. The following table is intended to provide supplemental information about the product type composition for each of the production figures that are provided in this news release:
|
|
Condensate
(mbbl/d)
|
Other NGLs
(mbbl/d)
|
Shale gas
(MMcf/d)
|
Conventional
natural gas
(MMcf/d)
|
Total
(mboe/d)
|
|
Three months ended
|
|
|
|
|
|
|
September 30, 2018
|
87.3
|
|
47.3
|
|
479.8
|
|
31.5
|
|
219.8
|
|
December 31, 2018
|
81.8
|
|
47.4
|
|
480.9
|
|
34.5
|
|
215.1
|
|
September 30, 2019
|
75.5
|
|
43.2
|
|
480.5
|
|
34.8
|
|
204.6
|
|
December 31, 2019
|
75.0
|
|
45.9
|
|
492.4
|
|
30.7
|
|
208.1
|
|
Year ended
|
|
|
|
|
|
|
December 31, 2018
|
76.4
|
|
44.4
|
|
454.0
|
|
36.5
|
|
202.6
|
|
December 31, 2019
|
74.8
|
|
44.4
|
|
469.1
|
|
33.9
|
|
203.0
|
This news release also makes reference to Company's forecasted total average daily production of 200 - 205 mboe/d for 2020. Seven Generations expects that approximately 34% - 38% of that production will be comprised of condensate, 37% - 41% will be comprised of shale gas, 22% will be comprised of other NGLs and 3% will be comprised of conventional natural gas.
Note Regarding Early Production
The initial and/or early production rates described in this news release are not necessarily indicative of longer-term performance or ultimate recovery.
Note Regarding Drilling Locations
There is no certainty that the company will drill any of its identified drilling opportunities or drilling locations and there is no certainty that such locations will result in additional reserves or production. The drilling locations on which the company will actually drill wells, including the number and timing thereof, will be dependent upon a number of factors, which may include the availability of funding, regulatory approvals, oil and natural gas prices and costs, actual drilling results and the additional reservoir information that is obtained.
Oil and Gas Definitions
Certain terms that are used in this news release that are not otherwise defined herein are provided below:
developed producing reserves are those gross 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.
developed reserves are those gross 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 (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.
gross means (i) in relation to the Company’s interest in production or reserves, its “company gross reserves”, which are the Company’s working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of the Company; and (ii) in relation to wells, the total number of wells in which the Company has an interest.
probable reserves are those additional gross 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 gross 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. Reserves are classified according to the degree of certainty associated with the estimates.
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) to which they are assigned.
|
Abbreviations
|
|
|
|
|
AIF
|
|
annual information form dated February 26, 2020 for the year ended December 31, 2019
|
|
bbl
|
|
barrel
|
|
bbls
|
|
barrels
|
|
boe
|
|
barrels of oil equivalent
|
|
CDP
|
|
CDP Worldwide (formerly, the Carbon Disclosure Project)
|
|
CGR
|
|
condensate gas ratio
|
|
CROIC
|
|
cash return on invested capital
|
|
C$
|
|
Canadian dollars
|
|
d
|
|
day
|
|
D&C
|
|
drilling and completions
|
|
ESG
|
|
environment, social and governance factors
|
|
F&D
|
|
finding and development costs
|
|
FD&A
|
|
finding, development and acquisition costs
|
|
G&A
|
|
general and administrative expenses
|
|
GAAP
|
|
generally accepted accounting practices
|
|
IFRS
|
|
International Financial Reporting Standards
|
|
IP120
|
|
initial production over the first 120 days
|
|
m
|
|
metres
|
|
Mboe
|
|
thousand barrels of oil equivalent
|
|
Mbbl
|
|
thousands of barrels
|
|
mcf
|
|
thousand cubic feet
|
|
MM
|
|
millions
|
|
MMbbls
|
|
millions of barrels
|
|
MMboe
|
|
millions of barrels of oil equivalent
|
|
MMbtu
|
|
million British thermal units
|
|
MMcf
|
|
million cubic feet
|
|
Nest
|
|
the Nest 1, Nest 2 and Nest 3 areas combined
|
|
Nest 1
|
|
the “Nest 1” area that is shown in the map that is provided under the heading “Description of Business – Development Areas” in the AIF, which is available on the SEDAR website at www.sedar.com
|
|
Nest 2
|
|
the “Nest 2” area that is shown in the map that is provided under the heading “Description of Business – Development Areas” in the AIF, which is available on the SEDAR website at www.sedar.com
|
|
Nest 3
|
|
the “Nest 3” area that is shown in the map that is provided under the heading “Description of Business – Development Areas” in the AIF, which is available on the SEDAR website at www.sedar.com
|
|
NGLs
|
|
natural gas liquids
|
|
nm
|
|
not meaningful information
|
|
NPV10
|
|
forecast before tax net present value of future net revenue using a discount rate of 10%
|
|
PDP
|
|
gross total proved developed producing reserves
|
|
ROCE
|
|
return on capital employed
|
|
TSX
|
|
Toronto Stock Exchange |
|
US
|
|
United States
|
|
US$
|
|
United States dollars
|
|
Wapiti
|
|
means the “Wapiti” area that is shown in the map that is provided under the heading “Description of Business Development Areas” in the AIF, which is available on the SEDAR website at www.sedar.com.
|
|
WTI
|
|
West Texas Intermediate
|
|
1P
|
|
gross total proved reserves
|
|
2P
|
|
gross total proved plus probable reserves
|
|
$MM
|
|
millions of dollars
|
Seven Generations Energy Ltd. is also referred to as Seven Generations, Seven Generations Energy, 7G, we, our, the company or the Company.
View source version on businesswire.com: https://www.businesswire.com/news/home/20200227005304/en/
Copyright Business Wire 2020