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Seven Generations Energy Releases Third Quarter 2020 Results and 2021 Guidance

November 09, 2020

Execution drives increase to midpoint of 2020 production guidance, 2021 budget targets stable production and free cash flow

CALGARY, Alberta--(BUSINESS WIRE)-- Seven Generations Energy Ltd. (TSX: VII)

THIRD QUARTER 2020 HIGHLIGHTS

  • The company successfully completed its planned three-week turnaround and upgrade at the Karr plant and condensate stabilizer on-time and on-budget, while mitigating the impact to production volumes. Third quarter sales volumes were 168.9 Mboe/d (43% natural gas, 34% condensate, 23% other NGLs). October average field production estimates are in excess of 185 Mboe/d.
  • 7G has increased the lower end of its full-year 2020 production guidance to average 180-185 Mboe/d, compared to its prior guidance of 175-185 Mboe/d. Planned capital investments for 2020 are unchanged at $650 million. Additionally, the upper end of full-year 2020 operating cost guidance has been reduced from $4.50-$5.00/boe to $4.50-$4.75/boe.
  • The company restarted drilling and completion activity early in the third quarter and generated a modest amount of free cash flow despite the capital and volume impacts of the Karr turnaround. For both the fourth quarter and full-year 2020, 7G expects to generate free cash flow given the remaining capital investment, production volumes and hedging profile. 7G’s strategy of free cash flow generation continues despite the multitude of challenges faced in 2020. The company currently has 80% of net condensate volumes hedged in the fourth quarter and 55% hedged in the first quarter of 2021 at an average WTI price of US$44.60/bbl.
  • Third quarter drilling and completions costs averaged $6.5 million dollars per well, an 11% improvement relative to the per-well costs achieved in the first half of 2020. Drilling costs per meter and completion costs per tonne of proppant pumped improved by 5% and 30% respectively compared to the first half of 2020.
  • 7G continues to execute its symbiotic ESG-driven market access strategy. Supported by its Equitable Origin EO100™ certification and its low upstream emissions intensity profile, 7G entered into a supply agreement with Vermont Gas Systems, Inc. (VGS). VGS is an integrated energy services company that will distribute 7G’s responsibly developed natural gas to its consumer base and in return pay 7G a premium that the company will direct towards the 7G Sustainability Fund.
  • The company also entered a combined renewable energy certificate (REC) natural gas supply transaction, that sees a portion of 7G’s Alberta-based natural gas sales receive a REC as part of the sales price in the fourth quarter. This transaction is expected to reduce 7G’s 2020 scope 2 emissions profile to net zero and ties with 7G’s continuing emissions reduction efforts.

2021 BUDGET

  • 2021 production is expected to average 180-185 Mboe/d on capital investments of $650 million. Year-over-year improvements to cash costs and operating efficiencies, combined with moderating corporate decline rates are expected to contribute to 7G’s growing free cash flow profile in 2021 at current strip prices.
  • 7G’s 2021 WTI breakeven price is expected to be $35/bbl at current Henry Hub strip pricing of approximately US$2.75/MMbtu. In a $45/bbl WTI and $3/MMbtu Henry Hub price environment, 7G forecasts its 2021 capital investment plan to represent approximately 75% of forecasted funds flow.

OPERATIONAL AND FINANCIAL HIGHLIGHTS

$ millions, except per share and unit of production amounts

Three months
ended
September 30,

 

Three months
ended
June 30,

 

Nine months
ended
September 30,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

          %      

%

          %
 

2020

 

2019

 

Change

 

2020

 

Change

 

2020

 

2019

 

Change

Financial Results

 

 

 

 

 

   

 

 

 

 

 

 

 

 

 

 

Funds flow ($)(1)

166.3

 

 

340.5

 

 

(51

)

 

138.8

 

 

20

 

 

580.1

 

1,034.6

 

 

(44

)

Per share - diluted ($)(1)

0.50

 

 

0.98

 

 

(49

)

 

0.42

 

 

19

 

 

1.74

 

2.94

 

 

(41

)

Free cash flow ($)(1)

1.0

 

 

55.9

 

 

(98

)

 

69.4

 

 

(99

)

 

79.6

 

38.0

 

 

109

 

Net income (loss) ($)

(66.8

)

 

85.1

 

 

nm

   

(116.9

)

 

(43

)

 

(1,192.9)

 

391.2

 

 

nm

 

Per share - diluted ($)

(0.20

)

 

0.25

 

 

nm

   

(0.35

)

 

(43

)

 

(3.58)

 

1.11

 

 

nm

 

Adjusted net income (loss) ($)(1)

(24.2

)

 

78.5

 

 

nm

   

(43.1

)

 

(44

)

 

(33.3)

 

259.8

 

 

nm

 

Per share - diluted ($)(1)

(0.07

)

 

0.23

 

 

nm

   

(0.13

)

 

(46

)

 

(0.10)

 

0.74

 

 

nm

 

Revenue ($)(2)

469.6

 

 

718.0

 

 

(35

)

 

306.0

 

 

53

 

 

1,765.0

 

2,059.8

 

 

(14

)

CROIC (%)(1)

9.0

 

 

14.1

 

 

(36

)

 

10.7

 

 

(16

)

 

9.0

 

14.1

 

 

(36

)

ROCE (%)(1)

3.5

 

 

8.6

 

 

(59

)

 

5.6

 

 

(38

)

 

3.5

 

8.6

 

 

(59

)

Sales volumes(3)(4)

 

 

 

 

 

   

 

 

 

 

 

 

 

 

 

 

Condensate (mbbl/d)

57.6

 

 

75.5

 

 

(24

)

 

64.3

 

 

(10

)

 

63.6

 

74.7

 

 

(15

)

Natural gas (MMcf/d)

434.6

 

 

515.3

 

 

(16

)

 

467.9

 

 

(7

)

 

463.7

 

496.3

 

 

(7

)

Other NGLs (mbbl/d)

38.8

 

 

43.2

 

 

(10

)

 

40.9

 

 

(5

)

 

40.9

 

43.9

 

 

(7

)

Total sales volumes (mboe/d)

168.9

 

 

204.6

 

 

(17

)

 

183.2

 

 

(8

)

 

181.8

 

201.3

 

 

(10

)

Liquids %

57

 

 

58

 

 

(2

)

 

57

 

 

 

 

57

 

59

 

 

(3

)

Realized prices(4)

 

 

 

 

 

   

 

 

 

 

 

 

 

 

 

 

Condensate ($/bbl)

47.40

 

 

65.59

 

 

(28

)

 

26.59

 

 

78

 

 

43.82

 

66.91

 

 

(35

)

Natural gas ($/Mcf)

2.61

 

 

2.85

 

 

(8

)

 

2.49

 

 

5

 

 

2.59

 

3.47

 

 

(25

)

Other NGLs ($/bbl)

14.60

 

 

2.74

 

 

nm

   

12.01

 

 

22

 

 

11.73

 

4.79

 

 

145

 

Total ($/boe)

26.24

 

 

31.97

 

 

(18

)

 

18.38

 

 

43

 

 

24.57

 

34.42

 

 

(29

)

Royalty expense ($/boe)

(1.76

)

 

(1.99

)

 

(12

)

 

(0.97

)

 

81

 

 

(1.68)

 

(2.16

)

 

(22

)

Operating expenses ($/boe)

(5.30

)

 

(4.81

)

 

10

 

 

(4.16

)

 

27

 

 

(4.65)

 

(4.91

)

 

(5

)

Transportation, processing and other ($/boe)

(7.86

)

 

(6.46

)

 

22

 

 

(7.53

)

 

4

 

 

(7.46)

 

(6.58

)

 

13

 

Operating netback before the following ($/boe)(1)(4)

11.32

 

 

18.71

 

 

(39

)

 

5.72

 

 

98

 

 

10.78

 

20.77

 

 

(48

)

Realized hedging gains ($/boe)

2.76

 

 

1.63

 

 

69

 

 

6.44

 

 

(57

)

 

4.27

 

0.46

 

 

nm

 

Marketing income (loss) ($/boe)(1)

(0.64

)

 

0.19

   

nm

   

(0.80

)

 

(20

)

 

(0.63)

 

0.34

 

 

nm

 

Operating netback ($/boe)(1)

13.44

 

 

20.53

 

 

(35

)

 

11.36

 

 

18

 

 

14.42

 

21.57

 

 

(33

)

Funds flow ($/boe)(1)

10.70

 

 

18.09

 

 

(41

)

 

8.33

 

 

28

 

 

11.65

 

18.83

 

 

(38

)

Balance sheet

 

 

 

 

 

   

 

 

 

 

 

 

 

 

 

 

Capital investments ($)

165.3

 

 

284.6

 

 

(42

)

 

69.4

 

 

138

 

 

500.5

 

996.6

 

 

(50

)

Available funding ($)(1)

1,113.1

 

 

1,277.2

 

 

(13

)

 

1,110.7

 

 

 

 

1,113.1

 

1,277.2

 

 

(13

)

Net debt ($)(1)

2,178.8

 

 

2,213.7

 

 

(2

)

 

2,224.9

 

 

(2

)

 

2,178.8

 

2,213.7

 

 

(2

)

Purchase of common shares ($)

 

 

73.8

 

 

(100

)

 

 

 

 

 

15.6

 

117.9

 

 

(87

)

Common shares outstanding (mm)

333.3

 

 

340.5

 

 

(2

)

 

333.2

 

 

 

 

333.3

 

340.5

 

 

(2

)

Weighted average shares outstanding - basic (mm)

333.3

 

 

345.9

 

 

(4

)

 

333.1

 

 

 

 

333.3

 

350.2

 

 

(5

)

Weighted average shares outstanding - diluted (mm)

334.0

 

 

347.0

 

 

(4

)

 

333.8

 

 

 

 

333.9

 

352.0

 

 

(5

)

 (1)    Refer to the Reader Advisory section at the end of this news release for additional information regarding the company's GAAP and non-GAAP measures.
(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 section at the end of this news release.
(4)    Excludes realized hedging gains and losses, as well as the purchase and sale of condensate and natural gas in respect to the company's transportation commitment utilization and marketing activities.

 

 

 

Three months ended
September 30,

 

Nine months ended
September 30,

Nest Activity

 

2020

 

2019

 

% Change

 

2020

 

2019

 

% Change

Drilling(1)

 

 

 

 

 

 

 

 

 

 

 

 

Horizontal wells rig released

 

9

 

20

 

(55

)

 

35

 

57

 

(39

)

Average measured depth (m)

 

6,416

 

5,979

 

7

 

 

6,121

 

6,037

 

1

 

Average horizontal length (m)

 

3,098

 

2,785

 

11

 

 

2,890

 

2,785

 

4

 

Average drilling days per well

 

31

 

25

 

24

 

 

29

 

28

 

4

 

Average drill cost per metre ($)(2)

 

487

 

502

 

(3

)

 

506

 

551

 

(8

)

Average well cost ($ millions)(2)

 

3.1

 

3.0

 

3

 

 

3.1

 

3.3

 

(6

)

Completion(1)

 

 

 

 

 

 

 

 

 

 

 

 

Wells completed

 

19

 

30

 

(37

)

 

46

 

67

 

(31

)

Average tonnes pumped per metre

 

2.0

 

2.1

 

(5

)

 

1.9

 

2.0

 

(5

)

Average cost per tonne ($)(2)

 

646

 

917

 

(30

)

 

797

 

1,058

 

(25

)

Average cost per lateral metre ($)(2)

 

1,269

 

1,884

 

(33

)

 

1,543

 

2,080

 

(26

)

Average well cost ($ millions)(2)

 

3.4

 

5.4

 

(37

)

 

3.9

 

5.8

 

(33

)

Total D&C cost per well ($ millions)(2)(3)

 

6.5

 

8.4

 

(23

)

 

7.0

 

9.1

 

(23

)

Wells brought on production

 

23

 

15

 

53

 

 

49

 

57

 

(14

)

 (1)    The metrics include all horizontal Montney wells that are tied in for production. Excluded from the metrics are vertical wells re-drilled, abandoned wells, water disposal wells, as well as any delineated and expiring wells not tied in for production. 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 completed 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 AND RESOURCE DEVELOPMENT

Seven Generations resumed field activity in early July 2020 and concluded the quarter with the successful planned turnaround of the Karr plant and upgrade of the Karr condensate stabilizer. The project was completed on-time and on-budget with a smooth post-turnaround start-up that led to average October production in excess of 185 Mboe/d. Importantly, efforts to mitigate the volume impact were successful, although there was a temporary condensate pricing and per unit cost impact.

During a three-week period in September, more than 400 contractors and staff were on site at peak times to complete the maintenance and upgrade work. Work teams adhered to strict small-cohorts, physical distancing measures and rigorous logistics plans to minimize health risks which ensured the project was completed safely during the COVID-19 pandemic. Coincident with the turnaround, the company also invested approximately $20 million to upgrade and enhance the reliability of the stabilizer’s boiler system which is expected to drive improvements to average condensate price realizations, while reducing operating costs and improving safety.

Drilling and completion costs in the quarter averaged $6.5 million per well. The company has continued to achieve record reductions in costs without sacrificing well productivity via a combination of improved drilling performance, advanced completion designs and execution efficiencies, and vendor collaboration. Notable structural cost improvements since the fall of 2019 include continued efficiency improvements to on-the-ground operational logistics, using limited entry plug-and-perf completion design with wider stage spacing, increased perforation clusters and optimized sand and water intensity.

Two additional lower Montney wells were also brought on stream in the Nest 3 region during the quarter. Early stage rates are encouraging relative to other wells in Nest 3, with IP60 sales rates of approximately 2.075 Mboe/d (685 bbl/d condensate, 480 bbl/d other NGLs, 5.5 MMcf/d natural gas) and 1.8 Mboe/d (573 bbl/d condensate, 425 bbl/d other NGLs, 4.8 MMcf/d of natural gas), respectively. Continued lower Montney success underscores 7G’s inventory along with half-cycle economics via the use of existing infrastructure.

2020 OUTLOOK AND 2021 BUDGET

Following the successful turnaround and continued strong execution, the company has increased the lower-end of its full-year 2020 production guidance to now average 180-185 Mboe/d, compared to the prior guidance of 175-185 Mboe/d.

Seven Generations has also released its 2021 budget, with total capital investments expected to total $650 million and production to average 180-185 Mboe/d. 2021 investments are expected to maintain a flat year-over-year production profile that is predicated on maximizing the company’s free cash flow generating capacity. Building on the durable cost efficiencies captured in 2020, the company anticipates ongoing improvements to its cost structure in 2021. The 2021 budget assumes similar well costs on a per metre and per tonne basis to those achieved in late 2020. Due to marginally longer average well lengths in the 2021 program, the company anticipates per well drill and complete costs to average $6.9 million, a 5% improvement relative to 2020 budget assumptions.

Free cash flow generated in the future will initially be prioritized for net debt reduction. The company has reduced its target leverage metric, net debt to adjusted EBITDA to 1.5x from the previous 2.0x target.

The 2021 capital program requires fewer wells brought on-stream than 2020 to maintain production given the company’s flattening decline profile. The company forecasts carrying an in-process inventory of 10-15 additional wells at year-end 2021 that create the option to respond to improved commodity prices in the year or to further reduce 2022 sustaining capital requirements in a “lower for longer” energy price environment.

With the continued moderation of decline rates, improvement in cost structure and expected optimization of natural gas revenues net of transportation costs in late 2022, Seven Generations expects to expand its free cash flow profile independent of commodity prices. 7G believes that returning capital to shareholders is an important component of total shareholder returns and will continue to evaluate the optimal allocation of free cash flow over time.

 

 

2021 Budget(1)

 

2020 Budget(1)

Total Capital Investment

 

$650 million

 

$650 million

   

 

 

 

Average Production(2)

 

180 - 185 Mboe/d

 

180 - 185 Mboe/d

   

 

 

 

Development Wells Drilled (#)

 

65 - 70

 

50 - 60

Development Wells On-Stream (#)

 

50 - 60

 

65 - 70

Percent Natural Gas(2)

 

42 - 44%

 

42 - 44%

Percent Condensate(2)

 

32 - 36%

 

32 - 36%

Percent Other NGLs(2)

 

22 - 24%

 

22 - 24%

Royalty Rate(3)

 

5 - 7%

 

4 - 6%

Operating Expenses ($/boe)

 

$4.50 - $4.75

 

$4.50 - $4.75

Transportation ($/boe)

 

$7.50 - $7.75

 

$7.50 - $8.25

G&A ($/boe)

 

$0.80 - $0.90

 

$0.85 - $0.95

Interest ($/boe)

 

$1.80 - $2.00

 

$1.80 - $2.00

 (1)    See “Forward-Looking Information Advisory” in the Reader Advisory in this news release.
(2)    See “Note Regarding Product Types” in the Reader Advisory in this news release.
(3)    2021 royalty guidance based on US$40 WTI and US$3.00 Henry Hub pricing.

 

RISK MANAGEMENT

Seven Generations continues to execute its consistent hedging program that is designed to manage commodity price risk, support returns on invested capital, and ensure a minimum level of cash flow despite fluctuating commodity prices. Details of the company’s liquids and natural gas hedges at the end of the third quarter are shown below:

   

Q4 2020

 

2021

 

2022

WTI Hedges - bbl/d(1)

 

49,500

 

17,000

 

5,750

Floor Price - US$/bbl

 

$45.22

 

$45.70

 

$43.32

Natural Gas Hedges - MMbtu/d(2)

 

192,793

 

226,250

 

145,000

Floor Price - US$/MMbtu

 

$2.58

 

$2.55

 

$2.52

 (1)    Combined USD and CAD WTI instruments. 7G also has the following sold puts in place within its hedging portfolio: 4,000 bbl/d for Q4 at US$40 and 1,750 bbl/d for 2021 at US$40.
(2)    Combined Henry Hub, Chicago Citygate and AECO fixed price instruments.
(3)    Complete details of 7G’s hedging program including FX hedges are available in the company’s Q3 November 2020 corporate presentation and MD&A.

 

ESG UPDATE

Seven Generations continues to advance its symbiotic ESG-driven market diversification strategy with the announcement of a new responsible natural gas supply agreement with Vermont Gas Systems, Inc. (VGS). VGS is an integrated energy services company providing clean, affordable and reliable thermal energy services to more than 53,000 customers in northwest Vermont. 7G continues to pursue additional arrangements with other counterparties interested in securing responsibly produced, low-carbon intensity natural gas, supported by its Equitable Origin EO100™ certification. The company’s commitment to delivering responsibly developed natural gas to consumer markets is an evolution of its market access strategy that is enabled by its diverse, continent-wide natural gas transportation portfolio. The premium received will be directed toward the 7G Sustainability Fund, a fund created to further reduce 7G’s environmental footprint and broaden Indigenous partnerships.

7G has also entered into an Alberta-based natural gas supply arrangement that sees the company receive a REC in addition to standard index based AECO pricing for a portion of its natural gas sales. As a result of this transaction, 7G expects a net zero 2020 Scope 2 emission profile.

CONFERENCE CALL

7G management will hold a conference call to discuss its third quarter results and address investor questions today, November 9, 2020, at 9 a.m. MDT (11 a.m. EDT).

Participant Dial-In Numbers

Dial in – toll-free:

 

1-888-664-6392

Dial in – toll:

 

416-764-8659

Webcast link:

 

https://produceredition.webcasts.com/starthere.jsp?ei=1383306&tp_key=dc0f8a7ad3

Replay dial in toll-free:

 

1-888-390-0541

Replay dial in toll:

 

416-764-8677

Conference ID:

 

023519 #

Available until:

 

November 16, 2020

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 is available on the company’s website: www.7genergy.com.

READER ADVISORY

Non-GAAP Measures

This news release includes certain terms or performance measures commonly used in the oil and natural gas industry that are not defined under IFRS, including “adjusted net income”, “adjusted net income per diluted share”, “marketing income”, “operating netback”, “funds flow per diluted share”, “funds flow per boe”, “free cash flow”, “return on capital employed” (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 and the company’s condensed interim consolidated financial statements for the three and nine months ended September 30, 2020 and 2019 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 measures” in Management’s Discussion and Analysis dated November 6, 2020 for the three and nine months ended September 30, 2020 and 2019.

GAAP Measures

Certain performance measures included in this news release which are utilized by the company and others to assess performance have also been included in the company’s financial statements as they are considered to be relevant to a reader’s understanding of the company's business, performance results and financial condition. Specifically, the company’s “net debt” and “adjusted EBITDA” measures have been included in Note 15 - Capital Management in the consolidated financial statements for the years ended December 31, 2019 and 2018, and in Note 12 of the condensed interim consolidated financial statements for the three and nine months ended September 30, 2020 and 2019. The company has also presented a “funds flow” subtotal in the consolidated cash flow statements in the financial statements. Accordingly, these performance metrics are considered GAAP measures within this news release but would otherwise have been considered to be non-GAAP measures absent their inclusion in the financial statements.

Readers are cautioned that these performance measures do not have any standardized meanings 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 were prepared.

For additional information about these measures, please see “Advisories and Guidance – GAAP measures” in Management’s Discussion and Analysis dated November 6, 2020 for the three and nine months ended September 30, 2020 and 2019.

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: expected production and production guidance; expected capital investments and capital budgets; expected breakeven commodity prices; the number of wells expected to be drilled and brought on-stream; expected royalty rates; expected operating costs, transportation costs, G&A costs, and interest expense; expected free cash flow; the premium pricing expected from sales to VGS and plans to direct such amounts to 7G’s Sustainability Fund; the company’s expected 2020 scope 2 net zero emissions profile; continued emissions reductions efforts; the expectation that year-over-year improvements to cash costs and operating efficiencies, combined with moderating corporate production decline rates will contribute to growing free cash flow in 2021 at current strip prices; the enhanced reliability of the boiler system at the Karr condensate stabilization facility, which is expected to drive improvements to average condensate price realizations and reduce operating costs and improve safety; the expectation that the company’s 2021 investments will maintain a flat year-over-year production profile with allocations that are intended to maximize the company’s free cash flow generating capacity; anticipated improvements to per well drill and complete costs; plans to prioritize the allocation of free cash flow to net debt reduction; targeted net debt to adjusted EBITDA; the expectation that fewer wells will be required in 2021 to maintain production given the company’s flattening corporate production decline profile; plans to carry an in-process inventory of 10-15 additional wells at year-end 2021 to create an option to respond to improved commodity prices or further reduce 2022 sustaining capital requirements (i.e. capital expenditures required to maintain production from existing facilities at current levels); expected drilling inventory; the optimization of natural gas revenues net of transportation costs in late 2022; and the ability to expand the company’s free cash flow profile independent of commodity prices.

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 which may affect the company; 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; the accuracy of the forecasts provided under “2020 Outlook and 2021 Budget”; forecasted costs and expenses; 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 sources of funding for the company’s capital investment 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; the access, economic, regulatory and physical limitations which the company may be affected by 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 AIF and in Management’s Discussion and Analysis for the three and six months ended June 30, 2020 and 2019, which are 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; global or national health concerns, including the outbreak of pandemic or contagious diseases, such as the current novel coronavirus outbreak; recent and ongoing declines in general economic, business or industry conditions and weakness and volatility in the market conditions for the oil and gas industry; civil unrest, pandemics and other disruptions and dislocations; 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; potential impacts of climate change on the Company’s operations; 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 water 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; 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 2D and 3D 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, armed conflict or sabotage; 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-GAAP/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 news release 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.

The 2021 break-even commodity price and funds flow forecasts that are contained herein were approved by Management as at the date of this news release. These outlooks convey the commodity price levels that are expected to be required in order for the company to fund its budgeted level of capital investment with funds flow, and also the funds flow generating potential of the business, based upon those commodity price assumptions. The forecasts are based upon a US$3.00/MMbtu Henry Hub price, 0.76 USD/CAD exchange rate, and a -US$3 Edmonton benchmark condensate differential to WTI, and the other assumptions that are described under the heading “2020 Outlook and 2021 Budget”.

Note Regarding Oil and Gas Metrics and Initial Production

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 initial production rates described in this presentation are not necessarily indicative of longer-term performance or ultimate recovery.

Note Regarding Product Types

This news release includes references to total average daily production, condensate production, other NGL production, natural gas production and liquids production. 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. 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, 2019

 

75.5

 

 

43.2

 

 

480.5

 

 

34.8

 

 

204.6

 

June 30, 2020

 

64.3

 

 

40.9

 

 

441.0

 

 

26.9

 

 

183.2

 

September 30, 2020

 

57.6

 

 

38.8

 

 

413.7

 

 

20.9

 

 

168.9

 

Nine months ended

 

 

 

 

 

 

 

 

 

 

September 30, 2019

 

74.7

 

 

43.9

 

 

461.3

 

 

35.0

 

 

201.3

 

September 30, 2020

 

63.6

 

 

40.9

 

 

438.6

 

 

25.1

 

 

181.8

 

This news release also makes reference to Company's forecasted total average daily production of 180 - 185 mboe/d for 2020. Seven Generations expects that approximately 32% - 36% of that production will be comprised of condensate, 39% - 41% will be comprised of shale gas, 22% - 24% will be comprised of other NGLs and 3% will be comprised of conventional natural gas.

 

 

 

Abbreviations

 

 

     

AECO

physical storage and trading hub for natural gas on the TransCanada Alberta transmission system which is the delivery point for various benchmark Alberta index prices

 

AIF

annual information form dated February 26, 2020 for the year ended December 31, 2019

 

bbl or bbls

barrels

 

boe

barrels of oil equivalent

 

CAD or C$

Canadian dollars

 

CROIC

cash return on invested capital

 

D

day

 

D&C

drilling and completions

 

EBITDA

earnings before interest, taxes, depreciation and amortization

 

ESG

environment, social and governance factors

 

FX

foreign exchange

 

G&A

general and administrative expenses

 

GAAP

generally accepted accounting practices

 

IFRS

International Financial Reporting Standards

 

IP60

initial production over the first 60 producing days

 

m

metres

 

mboe

thousand barrels of oil equivalent

 

mbbl

thousands of barrels

 

mcf

thousand cubic feet

 

MD&A

Management’s Discussion and Analysis dated November 6, 2020, for the three and nine months ended September 30, 2020 and 2019

 

mm

millions

 

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

 

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

 

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

 

NGL

natural gas liquids

 

nm

not meaningful information

 

ROCE

return on capital employed

 

SEDAR

System for Electronic Document Analysis and Retrieval

 

TSX

Toronto Stock Exchange

 

USD or 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 or the Company.

Investor & Analyst Inquiries
Brian Newmarch
Vice President, Capital Markets & Stakeholder Engagement
Phone: 403-718-0700
Email: bnewmarch@7genergy.com

Ryan Galloway
Director, Investor Relations
Phone: 403-718-0709
Email: ryan.galloway@7genergy.com

Media Inquiries
Taryn Bolder
Manager, Communications
Phone: 403-718-0715
Email: taryn.bolder@7genergy.com

Source: Seven Generations Energy Ltd.

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