• TSX
  • VII

Seven Generations Delivers $1.23 Billion of Funds from Operations in 2017, up 66%

March 15, 2018

Return on capital employed of 10% in 2017

Q4 condensate production of 63,700 bbls/d, up 47%; operating netback of $24.86 per boe

Seven Generations (TSX:VII) achieved record funds from operations of $1.23 billion for 2017 and $404 million in the fourth quarter, up 66 percent and 84 percent respectively from the same periods of the prior year. Cash provided by operating activities also increased by 74 percent to $310 million in the fourth quarter of 2017, compared to the same 2016 period. The company delivered a return on capital employed of 10 percent and a cash return on invested capital of 18 percent in 2017. Condensate production averaged 63,700 bbls/d in the fourth quarter, up 47 percent, compared to the same period in 2016, and averaged 55,700 bbls/d in 2017, up 42 percent, compared to 2016. Total production averaged 197,300 boe/d in the fourth quarter and 175,000 boe/d in 2017.

“We delivered strong financial returns in 2017, demonstrating the profitability of being Canada’s largest producer of high-value condensate, the advantage of having diversified market access, and a low-supply cost business that generates industry-leading returns on capital,” said Marty Proctor, 7G’s President & Chief Executive Officer.


  • Funds from operations of $403.8 million or $1.11 per share, an increase of 84 percent and 85 percent respectively compared to the same periods in 2016.
  • Operating income of $129.3 million or 36 cents per share, an increase of 172 and 177 percent respectively compared to the same periods in 2016.
  • Operating netback of $24.86 per boe, up 11 percent from the fourth quarter of 2016.
  • Liquids production was 115,100 bbls/d, which included 63,700 bbls/d of condensate, up 50 and 47 percent respectively from the fourth quarter of 2016. With natural gas volumes of 493.4 MMcf/d, total production reached a quarterly record of 197,300 boe/d.
  • Proved plus probable reserves increased 10 percent to 1.7 billion boe, as at December 31, 2017, including reserve bookings from 7G’s newly defined Nest 3 area. Proved plus probable finding, development and acquisition costs decreased by 13 percent to $10.13 per boe.
  • Before tax net present value of estimated future net revenue from proved plus probable reserves, discounted at 10 percent (NPV10), increased by 20 percent to $12.0 billion. This increase occurred despite a significant reduction in the year-end 2017 reserve evaluator price deck of 6 percent for oil and 11 percent for natural gas. NPV10, less year-end net debt, increased by about 18 percent to $27.81 per share.
  • Three-year average F&D costs were $8.37 per boe for proved plus probable reserves. This represents a recycle ratio of 2.7x based on the company’s three-year average operating netback.


  Three months ended
December 31,
Year ended
December 31,
  2017 2016 % Change 2017 2016 % Change
Condensate (mbbl/d) 63.7 43.2 47 55.7 39.3 42
NGLs (mbbls/d) 51.4 33.4 54 46.7 30.0 56
Liquids (mbbls/d) 115.1 76.6 50 102.4 69.3 48
Natural gas (MMcf/d) 493.4 334.0 48 435.5 291.0 50
Total Production (mboe/d) 197.3 132.3 49 175.0 117.8 49
Liquids % 58% 58% 58% 59% (2)
Realized prices            
Condensate ($/bbl) 68.10 56.96 20 61.46 50.59 21
Natural gas ($/Mcf) 3.75 4.15 (10) 3.88 3.53 10
NGLs ($/bbl) 24.40 18.23 34 19.98 13.08 53
Total ($/boe) 37.65 33.67 12 34.56 28.92 20
Realized hedging gains ($/boe) 0.38 0.48 (21) 0.25 2.11 (88)
Royalty expense ($/boe) (1.18) (0.98) 20 (0.97) (0.16) nm
Operating expenses ($/boe) (5.69) (4.86) 17 (5.60) (4.22) 33
Transportation, processing and other ($/boe) (6.30) (5.92) 6 (5.81) (5.53) 5
Operating netback ($/boe)(1) 24.86 22.39 11 22.43 21.12 6
G&A per boe ($/boe) (0.65) (1.16) (44) (0.72) (0.92) (22)
Finance expense and other ($/boe) (1.96) (3.18) (38) (2.48) (3.04) (18)
Corporate netback ($/boe)(1) 22.25 18.05 23 19.23 17.16 12
Financial Results (1)            
Revenue ($)(2) 615.1 262.2 136 2,353.5 1,064.1 122
Operating income ($)(1)(5) 129.3 47.6 172 326.3 160.6 103
Per share - diluted ($) 0.36 0.13 177 0.90 0.50 80
Net income (loss) ($)(5) 83.6 (104.9) nm 562.5 (26.2) nm
Per share - diluted ($)(4) 0.23 (0.30) nm 1.54 (0.09) nm
Funds from operations ($)(1)(5) 403.8 219.7 84 1,228.3 740.0 66
Per share - diluted ($) 1.11 0.60 85 3.37 2.32 45
Cash provided by operating activities ($)(5) 310.3 178.7 74 1,154.3 644.6 79
Adjusted EBITDA(1) 434.4 255.3 70 1,373.1 868.6 58
CROIC (%)(1)(6) 17.9 16.4 9 17.9 16.4 9
ROCE (%)(1)(6) 9.8 7.7 27 9.8 7.7 27
Balance sheet            
Capital investments ($)(3) 322.3 283.6 14 1,651.4 978.0 69
Adjusted working capital ($)(1) 109.5 585.9 (81) 109.5 585.9 (81)
Available funding ($)(1) 1,467.4 1,626.7 (10) 1,467.4 1,626.7 (10)
Net debt ($)(1) 1,866.4 1,528.8 22 1,866.4 1,528.8 22
Debt outstanding ($) 1,956.4 2,111.9 (7) 1,956.4 2,111.9 (7)
Weighted average shares - basic(4) 354.7 347.2 2 353.3 299.8 18
Weighted average shares - diluted(4) 363.9 365.0 364.4 318.4 14
(1) Certain comparative figures in the above table have been adjusted to conform to current period presentation. Operating netback, corporate netback, operating income, funds from operations, adjusted EBITDA, CROIC, ROCE, adjusting working capital, available funding and net debt are not defined under IFRS. See “Advisory and Guidance – non-IFRS financial measures” in Management’s Discussion and Analysis dated March 13, 2018, for the years ended December 31, 2017 and 2016, for important information about these measures.
(2) Represents the total of liquids and natural gas sales, net of royalties, gains (losses) on risk management contracts and other income.
(3) Excluding acquisitions and equity investments.
(4) Basic weighted average shares are used to calculate diluted per share amounts when the Company is in a loss position.
(5) For the year ended December 31, 2016, figures include $27.4 million ($20.0 million after tax) of prior-period royalty recoveries.
(6) Calculated based on 12-months trailing financial results as at the reporting dates.



Nest 1 – high intensity completions improve condensate production

Early results from Nest 1 test wells using 7G’s current completions design are encouraging, with a significant increase in condensate production. Initial 30-day condensate production rates for the wells ranged from 775 bbls/d to 1,350 bbls/d, for an average improvement of about 50 percent relative to the company’s Nest 1 type curve. This rate is comparable to 7G’s Nest 2 condensate type curve. The average well cost for the pad was $9.9 million, further demonstrating 7G’s emphasis on cost reductions with improved productivity. A spacing test in Nest 1 is also showing encouraging results with the potential to grow 7G’s core drilling inventory and enhance returns compared to historical well designs in Nest 1.


7G’s realized condensate prices were $68.10 per barrel in the fourth quarter

With increased access to firm liquids transportation in 2017, 7G’s average realized condensate price was $68.10 per barrel, or about 97 percent of the Canadian dollar equivalent WTI benchmark price in the fourth quarter. Condensate and NGL sales generated approximately 72 percent of 7G’s revenues in 2017.

7G’s realized natural gas prices were 76 percent higher than Alberta prices in 2017

7G’s market access strategy continues to provide geographic market diversity and premium pricing in North American natural gas markets located away from the oversupplied Alberta market. 7G’s average realized price for natural gas in 2017 was $3.88 per Mcf compared to Alberta prices that averaged $2.20 per Mcf. About 76 percent of 7G’s natural gas sales go to the U.S. Midwest and the Gulf Coast. About 10 to 15 percent of the company’s natural gas production is expected to be sold into eastern Canada in 2018.

Tapping into the local petrochemical value chain

Beyond diversifying markets through pipelines to price-advantaged locations, 7G secured a new long-term agreement in the fourth quarter to supply propane to Inter Pipeline’s planned propane dehydrogenation and polypropylene Heartland Petrochemical Complex. This sales agreement will enable 7G to diversify its propane sales and capture stronger realized prices within the Alberta petrochemical value chain. The complex is expected to commence production in late 2021.


  Three months ended
December 31,
Three months
September 30,
Year ended
December 31,
Nest Activity 2017 2016 % Change 2017 % Change 2017 2016 % Change
Drilling (1)                
Horizontal wells rig released 20 12 67 15 33 88 50 76
Average measured depth (m) 5,278 5,696 (7) 5,905 (11) 5,742 5,712 1
Average horizontal length (m) 2,128 2,511 (15) 2,756 (23) 2,537 2,589 (2)
Average drilling days per well 29 31 (6) 33 (12) 33 35 (6)
Average drill cost per lateral metre ($)(2) 1,760 1,405 25 1,472 20 1,592 1,575 1
Average well cost ($ millions)(2) 3.6 3.5 3 4.0 (10 3.9 3.9
Completion (1)                
Wells completed 16 21 (24) 25 (36) 88 68 29
Average number of stages per well 39 37 5 45 (13) 41 32 28
Average tonnes pumped per well 5,643 6,481 (13) 6,425 (12) 6,236 5,403 15
Average cost per tonne ($)(2) 1,107 971 14 1,134 (2) 1,190 1,050 13
Average well cost ($ millions)(2) 6.2 6.3 (2) 7.3 (15) 7.3 5.7 28
Total D&C cost per well ($ millions)(2) 9.8 9.8 11.3 (13) 11.2 9.6 17
(1) The drilling and completion counts include only horizontal Montney wells in the Nest. The drilling counts and metrics exclude wells that are re-drilled or abandoned.
(2) Information provided is based on field estimates and are subject to change.



Drilling costs per well down 10 percent compared to third quarter

7G's average drilling cost per well was $3.6 million in the fourth quarter of 2017, down from $4.0 million in the third quarter of 2017. 7G's key drilling metric – dollars per lateral metre drilled – averaged $1,760 in the fourth quarter, up from the previous quarter due to shorter lateral lengths. By employing underbalanced drilling, 7G continued to reduce the average time it takes to drill a well. The company is implementing these efficiencies across its drilling program.

Completion costs per well down 15 percent compared to the third quarter

7G's average completion cost per well was $6.2 million in the fourth quarter of 2017, down from $7.3 million in the third quarter of 2017. Cost improvements have largely been driven by continued improvements in equipment utilization.

The drilling and completion cost per well was $9.8 million in the fourth quarter of 2017, down from $11.3 million in the third quarter of 2017. This was largely attributable to drilling shorter laterals due to land restrictions and optimizing the number of hydraulic fracturing stages and sand tonnage, which varies from quarter to quarter. Seven Generations continues to pursue ways to drive down costs in both drilling and completions to maximize capital efficiencies. The company expects drilling and completions costs to average between $10 million and $10.5 million per well in 2018.

Operating expenses – plans underway for improvement

Fourth quarter operating expenses were $5.69 per boe, up five percent compared to the third quarter of 2017, largely due to higher workover expenses and a lower percentage of recycled water used in completion activity. The company will continue to execute its plan to lower operating costs to a range of $4.50 to $5.00 per boe in 2018 through the expanded use of water disposal wells, water handling infrastructure, water recycling, and an increased focus on managing all operating cost elements.

Active quarter for well activity

With an average of eight drilling rigs running in the fourth quarter, Seven Generations drilled 20 wells, completed 16 wells and brought 23 wells on production. Consistent with its development plan, 7G had 56 wells in various stages of construction between drilling, completion and tie-in at the end of the fourth quarter.

Initial Pembina Kakwa processing plant maintenance

Following unplanned service disruptions at the Pembina Kakwa River processing plant in 2017, Pembina and 7G conducted a preliminary facility assessment that included an independent engineering firm and technical experts from 7G and Pembina. Since late in the fourth quarter, the processing plant has operated at a high reliability rate, however throughput has still been constricted due to a partial blockage in the heat exchanger. 7G has largely been able to mitigate constraints by flowing excess gas to its wholly-owned facilities for processing.

A seven-day planned plant outage in the second quarter is expected to reduce the risk of future obstructions and improve processing rates for the remainder of 2018. The primary work during this outage will be to mitigate the partial blockage in the heat exchanger and accelerate annual turbine maintenance. As well, an ethane extraction compressor has been offline for the first quarter of 2018, which has reduced a portion of natural gas liquids recovery. Repairs for this compressor are also planned in April.

Additional assessments for plant upgrades will take place during the remainder of 2018 and include a detailed reliability and maintenance study and a performance test. Any findings from these tests resulting in additional modifications to improve plant reliability would likely be made in the first half of 2019. 7G’s production guidance factored in a greater proportion of downtime in 2018 than in previous years. Consequently, there is no change to the company’s 2018 production guidance.

New natural gas processing plant construction on time, on budget

Construction of 7G’s new natural gas processing plant at Gold Creek is on time and budget. With a capacity of 250 MMcf/d, this new plant will expand 7G’s processing capacity by about 50 percent to 760 MMcf/d in three plants, complemented by up to 250 MMcf/d of third-party processing, for a total of about 1 billion cubic feet per day of available processing capacity. The new plant, scheduled to start operations in the fourth quarter of 2018, will enable continued organic growth and increase the company’s degree of operational control in processing.


Financial strength

Seven Generations maintained a strong balance sheet with ample liquidity, ending the year with available funding of more than $1.4 billion, net debt of $1.9 billion, and a trailing 12-month debt to funds flow ratio of 1.5x. On an annualized basis, the company’s fourth quarter net debt to funds flow ratio was 1.2x. 7G plans to fund its 2018 capital program through a combination of funds from operations, cash on hand, and draws on its credit facility. Selling 7G’s diverse product mix, which includes large condensate volumes, into a variety of geographically distinct markets that have attractive prices increases ROCE and contributes to lowering the company’s debt ratios.

Debt refinancing reduces annual interest costs by $25 million

In the fourth quarter, 7G completed refinancing transactions repurchasing and redeeming all of its outstanding US$700 million of 8.25% senior unsecured notes due in 2020 and completing an issuance of US$700 million of 5.375% senior unsecured notes due in 2025. The refinancing will result in annual interest savings of about $25 million and extend the maturity of the notes by five years. The improved terms and costs provide 7G with greater financial flexibility, with 7G's currently undrawn $1.4 billion credit facility maturing in 2021 and its earliest senior unsecured note maturity now occurring in 2023.


Managing market risk

Seven Generations uses financial risk management strategies to help reduce the volatility of commodity prices, currency and cash flow. Hedging price targets are established at levels that are expected to provide a threshold rate of return on capital investment based on a combination of benchmark oil and natural gas prices, projected well performance and capital efficiencies. 7G segregates its exposures into three separate risk management portfolios – liquids, natural gas and currency. 7G has typically used collar instruments to protect its liquids revenues. Current 2018 liquids hedging allows for price participation up to a level of approximately C$75 per barrel. To manage the price risk exposure within its diversified natural gas marketing portfolio, 7G employs a combination of location swaps, options and basis hedges in its risk management program. Additionally, a portion of 7G’s net US dollar exposures are hedged to lock in the Canadian dollar equivalent on its US dollar denominated revenue.

The company had the following risk management contracts in place at December 31, 2017:

  Crude Oil
  C$ WTI Collars C$ WTI 3 Way Collars US$ WTI Collars
Period bbl/d C$/bbl bbl/d C$/bbl bbl/d US$/bbl
2018 17,250 $61.20 - $77.32 12,000 $40.83/$56.25/$75.54 2,000 $52.25 - $57.30
2019 16,000 $58.91 - $75.94 7,500 $41.00/$56.33/$75.92 2,000 $52.25 - $57.30
2020 7,000 $57.50 - $71.61 1,500 $40.00/$55.00/$70.98 2,000 $52.25 - $57.30
  Natural Gas Foreign Exchange
  AECO 7A Collars/Swaps C$/US$ Swaps
Period MMbtu/d US$/MMbtu GJ/d C$/GJ US $MM US$/C$
2018 205,000 $2.88 60,000 $2.44 - $2.85 215.1 1.3100
2019 120,000 $2.85 60,000 $2.44 - $2.85 124.8 1.2907
2020 32,500 $2.74 10,000 $2.13 - $2.13 32.5 1.2683



2018 guidance

Consistent with the company’s Investor Day presentation in November 2017, production guidance for 2018 remains on track at 200,000 - 210,000 boe/d. The 2018 capital investment budget remains between $1.675 billion and $1.775 billion. Seven Generations expects production in the first half of 2018 to average 190,000 - 200,000 boe/d, with first quarter production to be the lowest 2018 quarterly level. As discussed during the company’s 2017 Investor Day presentation, a sawtooth production growth profile results from the batch development of multi-well pads, which have longer cycle times. This also results in quarterly variability in condensate-to-gas ratios. The 2018 forecast takes into account this development profile, and has higher production levels in the second half of the year.

There are many economic benefits from this type of development including drilling and completion cost efficiencies, integrated pad water management, pre-built surface facilities that are concurrently installed with development, reduced surface environmental impact, and minimized sub-surface well interactions. 7G believes that batched pad development is a significant contributor to the high return on capital the company is generating.

High-value condensate production drives netbacks, cash flow and returns

Condensate production continues to drive the strong netbacks and the resulting cash flow underpins 7G’s industry-leading returns. The use of high-intensity slickwater completions in 2017 generated higher-than-expected condensate-gas ratios, resulting in higher revenues and returns. Given the market dynamics of strong condensate prices that track US benchmark crude prices, and discounted natural gas prices due to broad oversupply and regional discounting, 7G continues to target liquids production and favours drilling high-impact condensate wells.


Reserves highlights

  • 7G continued to efficiently grow and convert its large resource base into reserves, adding significantly more reserves than it produced, which builds the company’s well location inventory for continued strong production growth. 7G replaced 170 percent of production with proved developed producing (PDP) reserve additions, and 351 percent of production with proved plus probable (2P) reserve additions.
  • 7G’s newly-defined Nest 3 area, located just to the south of its Nest 2 land, has 223.9 MMboe of 2P reserves. These reserve additions support 7G’s view that this region provides a low-cost supply that compares favourably with Nest 2 and Nest 1.
  • 7G’s PDP increased by 27 percent, or 25 percent per share, to 211.1 MMboe. 7G also increased 2P reserves by 10 percent, or 9 percent per share, to 1,695 MMboe. This represents a three-year compound annual growth rate of 84 percent for PDP reserves and 29 percent for 2P reserves.
  • 7G’s PDP F&D costs were $15.22/boe and 2P F&D costs were $10.15/boe. 
  • 7G’s PDP and 2P recycle ratios, based on full year 2017 operating netbacks, were 1.5x and 2.2x, respectively.
  • 7G’s future development capital to trailing funds flow ratio decreased to 10.7x from 17.0x for PDP reserves. This exemplifies the company’s ability to fund its reserve development with expected funds flow.
Finding, Development and Acquisition Costs
  2017 ($/boe) 2017-2015 ($/boe)
  PDP 1P 2P PDP 1P 2P
Finding, Development & Acquisition (FD&A)(1) 15.17 8.61 10.13 19.64 12.70 9.86
Finding & Development (F&D) 15.22 8.64 10.15 14.54 9.86 8.37
  (times) (times)
FD&A Recycle Ratio(2) 1.5 2.6 2.2 1.1 1.8 2.3
F&D Recycle Ratio(2) 1.5 2.6 2.2 1.5 2.3 2.7
Reserve Replacement Ratio(3) 1.7 1.7 3.5 2.1 3.0 4.9
(1) FD&A and F&D costs include the year-over-year change in future development capital to transfer reserves into production.
(2) Recycle Ratio is operating netback divided by F&D or FD&A costs per boe. Operating netback is determined as revenue less royalties, transportation costs, and operating costs.
(3) Reserves Replacement Ratio is total reserve additions (including acquisitions and divestitures) divided by annual production.


Reserves summary and additional detailed information

7G's independent reserves evaluation, effective December 31, 2017, has been completed by McDaniel & Associates Consultants Ltd. (McDaniel).

For additional information regarding the independent reserves evaluation that was conducted by McDaniel as at December 31, 2017, please see the disclosure that is provided under the heading “Statement of Reserves Data” in the company's Annual Information Form, dated March 13, 2018, which is available on the SEDAR website at

    Reserves Summary 2016 – 2017
Category 2 2017


Developed Producing 2,470 1,991 24 211.06 166.11 27
Developed Non-Producing 84 129 (35) 6.37 10.23 (38)
Developed Producing plus Non-Producing


20 217.43 176.34 23
Undeveloped 3,580 3,026 18 652.14 648.77 1
Total Proved 6,133 5,146 19 869.57 825.11 5
Total Probable 5,854 4,850 21 825.35 709.54 16
Total Proved plus Probable 11,988 9,996 20 1,694.92 1,534.65 10
(1) Net present values of future net revenue before income taxes discounted at 10% per year based upon McDaniel’s forecast prices and costs.
(2) Figures may not add due to rounding.


Reserves Reconciliation 2016 – 2017 1
  Gross Proved Gross Probable

Gross Proved plus

  (MMboe) (MMboe) (MMboe)
December 31, 2016 825.11 709.54 1,534.65
Extensions and Improved Recovery 16.51 185.09 201.60
Technical Revisions 98.36 (64.72) 33.64
Acquisitions 0.45 0.79 0.53
Dispositions (0.07) (0.01) (0.08)
Economic Factors (6.91) (4.62) (11.53)
Production (63.88) (63.88)
December 31, 2017 869.57 825.35 1,694.92
(1) Figures may not add due to rounding.



Serving stakeholders

In 2017, Seven Generations continued to demonstrate its commitment to a wide variety of community initiatives that involve collaboration with numerous industry partners, suppliers, service companies, contractors and community members.

"We are privileged to demonstrate our Code of Conduct commitment to serve our stakeholders. Building meaningful relationships and participating through volunteer efforts supports the needs and interests of our partners and our communities," said Cindy Park, 7G’s Director, Community Engagement in Grande Prairie.


Susan Targett, Executive Vice-President, Corporate, retires

“After nearly 10 years of dedicated service, Susan Targett, Executive Vice-President, Corporate, retired from Seven Generations on February 28. Susan was a founder of Seven Generations and made many contributions to the success of the company, creating value and developing strong ties with our stakeholders. Susan was instrumental in assembling 7G’s top tier asset position in the heart of the Montney play. We wish Susan all the best in her future endeavours,” Proctor said.

As a result of her retirement, Susan Targett will no longer be a participant in the automatic securities disposition plan announced on February 12, 2018.

Derek Aylesworth joins Seven Generations as Chief Financial Officer

As previously announced, Derek Aylesworth will join Seven Generations on March 15, 2018 as Chief Financial Officer, responsible for the company’s finance, treasury, accounting, tax and capital markets functions.

Board of Directors update

As part of the Board of Directors’ renewal process, Pat Carlson has decided that he wishes to pursue independent business and philanthropic opportunities. Therefore, he will not be standing for re-election at this year’s annual meeting, May 3, 2018.

Conference Call

7G management will hold a conference call to discuss results and address investor questions today, March 14, 2018 at 9 a.m. MT (11 a.m. ET).

Participant Dial-In Numbers  
Toll Free: (877) 390-7644
International: (647) 252-4486
Conference Call ID: 6879566
Event link:

Encore Dial In: (855) 859-2056 or (404) 537-3406
Replay code: 6879566
Available: March 14 - 21, 2018


Seven Generations Energy

Seven Generations Energy is a low-supply cost, growth-oriented 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.

Non-IFRS Financial Measures

This news release includes certain terms or performance measures commonly used in the oil and natural gas industry that are not defined under IFRS, including “operating netback”, “corporate netback”, “operating income”, “funds from operations”, “adjusted EBITDA”, “cash return on invested capital” or “CROIC”, “return on capital employed” or “ROCE”, “adjusted working capital”, “available funding” and “net debt”. The data presented is intended to provide additional information and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with IFRS. These non-IFRS measures should be read in conjunction with the company’s consolidated financial statements and the accompanying notes. Readers are cautioned that the non-IFRS measures do not have any standardized meaning and should not be used to make comparisons between the company and other companies without also taking into account any differences in the way the calculations were prepared.

For additional information about these measures, please see “Advisories and Guidance – Non-IFRS financial measures” in Management's Discussion and Analysis dated March 13, 2018, for the years ended December 31, 2017 and 2016.


Reader Advisories

Forward-Looking Information Advisory

This news release contains certain forward-looking information and statements that involve various risks, uncertainties and other factors. The use of any of the words “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”, “should”, “believe”, “plans”, and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this news release contains forward-looking information and statements pertaining to the following: expected future production and continued strong production growth; the potential to grow the company’s core drilling inventory and enhance returns compared to historical well designs in certain areas; expectation that 10% to 15% of the company’s natural gas production will be sold into markets in eastern Canada in 2018; planned propane sales to Inter Pipeline’s propane dehydrogenation and polypropylene Heartland Petrochemical Complex, which is expected to commence production in late 2021 and enable 7G to capture stronger realized prices within the Alberta petrochemical value chain; the company’s expectation that drilling and completions costs will average between $10 million to $10.5 million per well in 2018; the expectation that operating costs will be reduced to between $4.50 to $5.00 per boe through the expanded use of water disposal wells, water handling infrastructure, water recycling, and an increased focus on managing operating costs; the planned seven day plant outage at Pembina’s Kakwa River processing plant in the second quarter of 2018, which is expected to reduce the risk of future obstructions and improve processing rates for the remainder of 2018; repairs for an ethane compressor planned in April; the reliability and maintenance study and performance tests that are expected to be conducted in at the Kakwa River processing plant in 2018 and the expectation that any modifications to improve plant reliability would likely be made in the first half of 2019; the planned funding of the company’s 2018 capital program through a combination of funds from operations, cash on hand, and draws on its credit facility; the expectation that the company’s hedging targets will provide threshold rates of return on capital invested, based on a combination of projected well performance and expected capital efficiencies; expected variability in liquid-to-gas ratios resulting from batch development of multi-well pads, which is expected to result in longer cycle times and a saw-tooth production growth profile; expected future supply costs; the interest savings that are expected from the debt refinancing transactions completed in the fourth quarter of 2017; expected processing capacity, including from the processing plant at Gold Creek, and the timing of the completion of the company’s new processing plant at Gold Creek. In addition, information and statements in this news release relating to reserves and the estimated net present value of future cash flows to be generated therefrom 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 the they can be profitably produced in the future.

With respect to forward-looking information contained in this news release, 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 to be utilized; 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; the applicability of 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; 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; 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 company’s Annual Information Form for the year ended December 31, 2017, dated March 13, 2018 (the AIF)which is available on SEDAR at, 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; 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; adoption or modification of climate change legislation by governments; the absence or loss of key employees; uncertainty associated with estimates of oil, NGLs and natural gas reserves and resources and the variance of such estimates from actual future production; dependence upon compressors, gathering lines, pipelines and other facilities, certain of which the company does not control; the ability to satisfy obligations under the company’s firm commitment transportation arrangements; 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; 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 River Project; unforeseen title defects; aboriginal 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; changes in the application, interpretation and enforcement of applicable laws and regulations; restrictions on drilling 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 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 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; sufficiency of internal controls; breach of agreements by counterparties 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 news release 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., as at December 31, 2015, as at December 31, 2016, and as at December 31, 2017. 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. The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. 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 March 7, 2017 for the year ended December 31, 2016, and the annual information form dated March 8, 2016 for the year ended December 31, 2015, which are available on the SEDAR website at

Note Regarding Oil and Gas Metrics

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 is significantly different from the energy equivalency of 6 Mcf: 1 bbl, utilizing a conversion ratio at 6 Mcf: 1 bbl may be misleading as an indication of value.

Finding, development and acquisition 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. Finding and development costs are calculated as the sum of exploration and development costs, plus changes in future development costs (excluding future development capital associated with acquisitions and dispositions), divided by reserve additions (excluding reserves added via acquisitions). Finding and development both including and excluding acquisitions are presented since acquisition and disposition activity can result in reserve replacement metrics that are not indicative of the long-term cost structure that is expected from the company’s assets. Recycle ratios are calculated by dividing operating netback by finding and development or finding, development and acquisition costs. Reserves replacement ratios are calculated as total reserves additions (taking into account acquisitions and divestitures) divided by annual production. Management utilizes these metrics for internal measurement.

Readers are advised that this information may not be comparable to similarly defined metrics presented by other entities and comparisons should not be made between such measures provided by the company and by other companies without also taking into account any differences in the way that the calculations were prepared.

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 non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown.

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.

AECO means the physical storage and trading hub for natural gas on the TransCanada Alberta Transmission System, which is the delivery point for the various benchmark Alberta index prices
AIF Annual Information Form for the year ended December 31, 2017 dated March 13, 2018
bbl barrel
bbls barrels
boe barrels of oil equivalent
CROIC cash return on invested capital
C$ Canadian dollars
d day
D&C drilling and completions
F&D finding and development costs
FD&A finding, development and acquisition costs
G&A general and administrative expenses
GJ gigajoules
IFRS International Financial Reporting Standards
m metres
Mboe thousand barrels of oil equivalent
Mbbls 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

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

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

NGLs natural gas liquids
nm not meaningful information
PDP gross total proved developed producing reserves
Q4 fourth quarter
ROCE return on capital employed
US United States
US$ United States dollars
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.


Investor Relations
Brian Newmarch, Vice President, Capital Markets
Phone: 403-718-0700

Media Relations
Alan Boras, Director, Communications & Stakeholder Relations
Phone: 403-767-0772

Seven Generations Energy Ltd.
Suite 4400, 525 - 8th Avenue SW
Calgary, AB T2P 1G1

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