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Seven Generations Energy Ltd. class A common shares

Exchange: TSX Exchange | May 22, 2019, 11:41 AM EDT

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Seven Generations delivers $1.67 billion of adjusted funds flow, or $4.60 per share, up 36 percent in 2018

CALGARY, Alberta

Proved plus probable reserves valued at $12.3 billion by independent reserve evaluator as of December 31, 2018


  • 2018 adjusted funds flow of $1.67 billion or $4.60 per share, representing a per share increase of 36 percent compared to 2017.
  • 2018 net income of $440 million, $1.21 per share. Operating income of $574 million, $1.58 per share, up 76 percent versus 2017. As of December 31, 2018, 7G’s trailing 12-month return on capital employed was 12.9 percent and its cash return on invested capital was 19.1 percent.
  • 2018 sales volumes were 16 percent higher than 2017, averaging 202,600 boe/d, with liquids representing 60 percent of 7G’s total production. Condensate sales of 76,400 bbls/d increased by 25 percent in 2018. Fourth quarter condensate sales were 81,800 bbls/d, total liquids sales were 129,200 bbls/d, and total sales were 215,100 boe/d.
  • 7G’s market access initiatives drove fourth quarter natural gas realizations to $4.77 per Mcf due to the company’s marketing arrangements in the US Midwest, Gulf Coast and Eastern Canada.
  • 2018 capital investments were $1.77 billion. Drilling and completion costs per-well were reduced by 10 percent year-over-year.
  • 7G completed its natural gas processing facility at Gold Creek on time and under budget. The facility successfully tested its 250 MMcf/d design capacity during December.
  • Year-end gross proved plus probable (2P) reserves of 1.64 billion boe were valued at $12.3 billion as at December 31, 2018, on a before-tax net present value basis, at a 10 percent discount rate, by McDaniel & Associates Consultants Limited (McDaniel), the company’s independent qualified reserves evaluator. At 2018 production levels, this represents a 22-year reserve life index.

Surpassing the 200,000 boe per day milestone

“Our hard-working team delivered excellent technical, operating and financial performance in 2018, achieving a significant milestone – annual average production that exceeded 200,000 boe/d. Capital investments of $1.77 billion remained within our capital guidance range as we grew daily production by 16 percent to 202,600 boe/d and enhanced the value of our assets through disciplined scientific analysis and successful delineation drilling,” said Marty Proctor, 7G’s President & Chief Executive Officer.

Enhancing asset value with disciplined self-funded investment in 2019

“Assuming a WTI oil price of US$50 per bbl and a Henry Hub natural gas price of US$3.00 per Mcf in 2019, we plan a self-funded capital program of $1.25 billion, about $500 million less than the 2018 program. This 2019 capital plan maintains annual average production above 200,000 boe/d while continuing to enhance the value of our asset base through further delineation of the lower Montney and development of the Nest 3 and Nest 1 areas of our Kakwa River Project. Our strategy in this commodity price environment includes lower growth that mitigates production decline rates and preserves our top-tier drilling inventory, disciplined execution to improve operating and capital cost efficiencies, infrastructure investments to lower operating costs and expand margins, plus delineation drilling to increase our inventory and maximize lower Montney value,” Proctor said.




Three months ended
December 31,


Three months ended
September 30,


Year ended
December 31,

($ millions, except boe
and per share amounts)
  2018   2017   % Change   2018   % Change   2018   2017   % Change
Sales volumes          
Condensate (mbbl/d)(1) 81.8 70.0 17 87.3 (6) 76.4 61.3 25
NGLs (mbbl/d)(1)   47.4     45.1   5   47.3     44.4     41.1   8
Liquids (mbbl/d) 129.2 115.1 12 134.6 (4) 120.8 102.4 18
Natural gas (MMcf/d)   515.4     493.4   4   511.3   1   490.5     435.5   13
Total sales volumes (mboe/d)(2) 215.1 197.3 9 219.8 (2) 202.6 175.0 16
Liquids %   60%     58%     3   61%     (2)   60%     58%     3
Realized prices
Condensate ($/bbl)(1) 53.57 67.95 (21) 79.26 (32) 71.63 61.28 17
Natural gas ($/Mcf) 4.77 3.53 35 3.65 31 3.98 3.84 4
NGLs ($/bbl)(1)   8.44     18.30     (54)   14.02     (40)   12.21     14.56     (16)
Total ($/boe)(2) 33.66 37.13 (9) 42.99 (22) 39.33 34.45 14
Royalty expense ($/boe) (0.99 ) (1.18 ) (16) (2.20 ) (55) (1.34 ) (0.97 ) 38
Operating expenses ($/boe) (5.25 ) (5.69 ) (8) (5.22 ) 1 (5.52 ) (5.60 ) (1)
Transportation, processing and other ($/boe)   (7.07 )   (6.43 )   10   (6.14 )   15   (6.65 )   (6.09 )   9
Operating netback before the following(2)(3) 20.35 23.83 (15) 29.43 (31) 25.82 21.79 18
Realized hedging gains (losses) ($/boe) (1.58 ) 0.38 nm (1.79 ) (12) (1.33 ) 0.25 nm
Marketing income ($/boe)(3)   0.20     0.65     (69)   0.28     (29)   0.39     0.39    
Operating netback ($/boe)(3) 18.97 24.86 (24) 27.92 (32) 24.88 22.43 11
Adjusted funds flow ($/boe)(3)(5)   17.06     22.25     (23)   25.81     (34)   22.65     19.23     18
Financial Results
Revenue ($)(4) 1,146.8 615.1 86 809.0 42 3,169.9 2,454.6 29
Net income ($) 245.4 83.1 195 196.4 25 439.9 562.5 (22)
Per share - diluted ($) 0.68 0.23 196 0.53 28 1.21 1.54 (21)
Operating income ($)(3) 66.3 129.2 (49) 208.3 (68) 573.6 326.3 76
Per share - diluted ($) 0.18 0.36 (50) 0.57 (68) 1.58 0.90 76
Cash provided by operating activities ($) 410.1 310.3 32 536.9 (24) 1,796.3 1,154.3 56
Per share - diluted ($) 1.13 0.85 33 1.47 (23) 4.94 3.17 56
Adjusted funds flow ($)(5) 337.4 403.8 (16) 522.0 (35) 1,674.2 1,228.3 36
Per share - diluted ($) 0.93 1.11 (16) 1.43 (35) 4.60 3.37 36
CROIC (%)(3) 19.1% 17.9% 7 20.5% (7) 19.1% 17.9% 7
ROCE (%)(3)   12.9%     9.8%     32   15.6%     (17)   12.9%     9.8%     32
Balance sheet
Capital investments ($) 262.3 322.3 (19) 358.2 (27) 1,765.7 1,651.4 7
Available funding ($)(3) 1,345.9 1,467.4 (8) 1,379.4 (2) 1,345.9 1,467.4 (8)
Net debt ($)(5) 2,202.8 1,866.4 18 2,059.5 7 2,202.8 1,866.4 18
Weighted average shares - basic 359.2 354.7 1 361.9 (1) 358.6 353.3 2
Weighted average shares - diluted   362.3     363.9       365.7     (1)   363.9     364.4    
(1)   Beginning in 2018, Seven Generations began presenting C5+ (pentanes plus) in the NGL mix as a condensate volume (previously reported as an NGL volume). 2017 liquids and natural gas sales have been adjusted to conform to this current period presentation.
(2) Excludes the purchase and resale of condensate and natural gas in respect of the company's transportation commitment utilization and marketing activities.
(3) See “Non-IFRS Financial Measures” under Reader Advisory. Certain comparative figures have been adjusted to conform to current period presentation.
(4) Represents the total of liquids and natural gas sales, net of royalties, gains (losses) on risk management contracts and other income.
(5) Refer to Note 17 of the audited consolidated financial statements of the company for the years ended December 31, 2018 and 2017.

Three months ended
December 31,


Three months ended
September 30,


Year ended
December 31,

Nest Activity   2018   2017   % Change   2018   % Change   2018   2017   % Change
Horizontal wells rig released 19 20 (5 ) 21 (10 ) 91 88 3
Average measured depth (m) 6,010 5,278 14 5,691 6 5,735 5,742
Average horizontal length (m) 2,776 2,128 30 2,557 9 2,551 2,537 1
Average drilling days per well 28 29 (3 ) 28 27 33 (18 )
Average drill cost per lateral metre ($)(2) $ 1,236 $ 1,760 (30 ) $ 1,373 (10 ) $ 1,389 $ 1,592 (13 )
Average well cost ($ millions)(2)   $ 3.4     $ 3.6     (6 )   $ 3.5     (3 )   $ 3.5     $ 3.9     (10 )
Wells completed 13 16 (19 ) 28 (54 ) 89 88 1
Average number of stages per well 46 39 18 58 (21 ) 48 41 17
Average tonnes pumped per metre 1.9 2.2 (14 ) 2.0 (5 ) 2.3 2.4 (4 )
Average tonnes pumped per well 4,417 5,643 (22 ) 5,206 (15 ) 5,402 6,236 (13 )
Average cost per tonne(2) $ 1,282 $ 1,107 16 $ 1,240 3 $ 1,228 $ 1,190 3
Average well cost ($ millions)(2)   $ 5.7     $ 6.2     (8 )   $ 6.5     (12 )   $ 6.6     $ 7.3     (10 )
Total D&C cost per well ($ millions)(2)   $ 9.1     $ 9.8     (7 )   $ 10.0     (9 )   $ 10.1     $ 11.2     (10 )
(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.


With the temporary weakness in fourth quarter Canadian condensate pricing, 7G elected to defer until January the start-up of seven Nest 2 upper/middle Montney wells that were previously drilled, completed, equipped and tied-in. This was an economic decision driven by visibility toward improved condensate differentials in the beginning of 2019. 7G has seen a significant strengthening in the Canadian condensate market with the local discount to WTI currently averaging approximately US$3.25 per bbl.

Average well drilling and completion costs in 2018 were 10 percent lower than the previous year with reductions roughly equal in both drilling and completions. Drilling activity benefitted from an 18 percent reduction in drilling days versus 2017, on wells of a similar depth and lateral length. 7G continues to evolve its completions design, which has shifted towards a higher stage count and a lower per-stage proppant intensity in order to efficiently develop and recover its resource at reduced costs. The company is encouraged with the results from its evolving completions designs and will continue to innovate and progress its resource understanding to enhance corporate returns.

7G’s third owned and operated processing plant, located in the Gold Creek area, was brought on stream in November of 2018. It was successfully tested at full capacity during December. This 250 MMcf/d interconnected plant provides heightened operating flexibility to mitigate both planned and unplanned downtime and is built to accommodate a cost-effective expansion to 500 MMcf/d. The plant’s connectivity to the NGTL and Alliance pipeline systems also provides opportunities to optimize the pricing of 7G’s natural gas and NGL revenue stream between the Alberta market and Aux Sable facilities in the US Midwest. The Gold Creek plant was designed, engineered and constructed to achieve the company’s lowest emissions intensity with a carbon dioxide emission intensity about 10 percent lower than 7G’s other plants.

7G continues to evaluate infrastructure partnership opportunities and is encouraged by the level of interest. The company is evaluating proposals aimed at enhancing the value of its infrastructure assets.


The following table summarizes 7G’s reserves at December 31, 2018 and 2017 as estimated by the company’s independent qualified reserves evaluator using the forecast price and cost assumptions in effect at the applicable reserves evaluation date.




Year ended
December 31,

        2018   2017
Reserve Category(1) MMboe $MM(2)   MMboe $MM(2)
Gross proved developed producing (PDP) 242   2,824 211   2,470
Gross proved reserves (1P) 856 6,518 870 6,133
Gross proved plus probable reserves (2P) 1,644 12,282 1,695 11,988
Gross best estimate risked (2C) contingent resources       1,323     2,942     1,291     2,579
(1)   For important additional information regarding the independent reserves and resources evaluations conducted by McDaniel, please see “Reader Advisory” and the Annual Information Form dated February 27, 2019 for the year ended December 31, 2018 that is available on SEDAR.
(2) Estimated pre-tax net present value of discounted cash flows from reserves using a 10% discount rate.

7G is committed to increasing the long-term value of its resource within one of the most economic plays in Western Canada. As discussed in 2018, the company saw increased condensate volumes and reduced natural gas volumes in its production stream. This dynamic drove a 2.5 percent increase in the pre-tax net present value of the company’s 2P reserves, despite a year-over-year reduction in reserve evaluator price forecasts and wider local price differentials. The company’s increase in condensate reserves were offset by a reduction in natural gas volumes on a boe basis. Based on 2018 production levels of 202,600 boe/d, 7G’s 1.64 billion boe 2P reserves represent more than 22 years of reserve life.

Total PDP reserve volumes increased 14.7 percent year-over-year, replacing 142 percent of 2018 production. These gains were consistent with a successful 2018 development program. Per-boe future development capital continues to fall on a 1P and 2P basis, and is consistent with the company’s 5-year trend as the company completes initial investments in its natural gas processing build-out.

The company’s 2C contingent resources increased by 2.5 percent to 1,323 MMboe representing a pre-tax net present value of $2.9 billion, an increase of 14 percent. Approximately 98 percent of the 2C contingent resources attributed to the company’s properties by McDaniel, as at December 31, 2018, are in the Montney formation and have been classified in the “development pending” project maturity subclass. 7G also includes more than 170 lower Montney locations within the 2C contingent resource estimate. Development plans for these locations are expected to be established once the 2019 lower Montney delineation program is complete.


Nest 1 Perimeter

7G recently concluded completion operations on the first well of 2019’s Nest 1 perimeter delineation program. The company is encouraged by initial results that have exceeded expectations, with initial wellhead rates of approximately 2,200 boe/d (75% condensate) over the first 30 days. The company will use the delineation results to design gathering systems and artificial lift for full-scale Nest 1 development anticipated to begin in 2020.

Lower Montney

The company completed drilling of its comprehensive triple-stack test in January, consisting of three wells in the upper Montney, three wells in the middle Montney, and three wells in the lower Montney. Completion operations commenced in February. Following tie-in and sufficient flow data, management anticipates providing an update on initial rates in the second half of 2019. Upon successful lower Montney results, future development has the potential to benefit from improved cost efficiencies and the use of existing surface infrastructure.


During 2018, the company retired 9.67 million shares at an average cost of $10.72 per share plus transaction costs, reducing its outstanding shares at the beginning of 2019 to 352.6 million, a 2.7 percent reduction of 7G’s outstanding shares. 7G continues to evaluate further allocation of excess cash to the NCIB, reduction of debt and other investment opportunities in its portfolio, subject to commodity prices generating additional adjusted funds flow in excess of its budgeted capital requirements.


7G’s 2019 guidance remains unchanged, as below:

Condensate (%) 36 - 38
Total liquids (%) 58 - 60
Natural gas (%) 40 - 42
Total production (Mboe/d) 200 - 205
H1 2019 (Mboe/d) 195 - 200
H2 2019 (Mboe/d) 205 - 210
Royalties (%) 5 - 7
Operating ($/boe) 5.00 - 5.50
Transportation ($/boe) 6.75 - 7.25
G&A ($/boe) 0.80 - 0.90
Interest ($/boe) 1.80 - 1.90
Capital investment ($mm) 1,250
Drilling and completions (%) 55 - 60
Pipelines and infrastructure (%) 30 - 35
Delineation (%) 10 - 15
Wells on-stream 65 - 70


7G is pleased to announce that Ronnie Irani, an executive and director with more than 39 years of experience in the oil and gas industry, has joined the 7G Board effective February 27, 2019. Irani is founder and Chief Executive Officer of RKI Energy Resources, LLC, a private company headquartered in Oklahoma City. He also serves as a director of Enable Midstream Partners, LP, a NYSE-listed company.

Irani was founder, President and Chief Executive Officer of RKI Exploration and Production until the company sold its assets for US$3.5 billion in 2015. He was Senior Vice President and General Manager with Dominion Resources, a Fortune 200 company, until 2005 and previously held senior executive positions at Louis Dreyfus Natural Gas Corp. and Woods Petroleum Corporation, both NYSE-listed companies. Irani has served on several private and public boards, including Quest Resource Corporation and Seventy Seven Energy Inc. He has made significant contributions to broader industry and community initiatives having served as a director of the Greater Oklahoma City Chamber of Commerce, the Integrated Petroleum Environmental Consortium, the US Department of Energy Industry Oil Review Panel, and as a founding board member and past Chair of the Oklahoma Energy Explorers.

Irani holds a Bachelor of Science in Chemistry from Bombay University, India, a Bachelor’s and a Master’s degree in Petroleum Engineering from the University of Oklahoma, and an MBA from Oklahoma City University.


7G management will hold a conference call to discuss results and address investor questions today, February 28, 2019, at 9 a.m. MT (11 a.m. ET).

Participant Dial-In Numbers

Dial in - toll free: (866) 521-4909
Dial in - toll: (647) 427-2311
Webcast link:


Replay dial in toll-free: (800) 585-8367
Replay dial in toll: (416) 621-4642
Audience passcode: 9578078
Available to: March 14, 2019

Seven Generations Energy

Seven Generations Energy is a low-supply cost energy producer dedicated to stakeholder service, responsible development and generating strong returns from its liquids-rich Kakwa River Project in northwest Alberta. 7G’s corporate office is in Calgary, its operations headquarters is in Grande Prairie and its shares trade on the TSX under the symbol VII.

Further information on Seven Generations is available on the company’s website: www.7genergy.com.

Reader Advisory

Non-IFRS Financial Measures

This news release includes certain terms or performance measures commonly used in the oil and natural gas industry that are not defined under International Financial Reporting Standards (IFRS), including “return on capital invested” (ROCE), “cash return on invested capital” (CRIOC), “operating income”, “operating netback”, “adjusted funds flow per boe”, “marketing income”, “adjusted working capital” and “available funding”. The data presented is intended to provide additional information and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with IFRS. These non-IFRS measures should be read in conjunction with the company’s consolidated financial statements for the years ended December 31, 2018 and 2017 and the accompanying notes. Readers are cautioned that the non-IFRS measures do not have any standardized meaning and should not be used to make comparisons between the company and other companies without also taking into account any differences in the way the calculations were prepared.

For additional information about these measures, please see “Advisories and Guidance – Non-IFRS financial measures” in Management’s Discussion and Analysis dated February 27, 2019, for the years ended December 31, 2018 and 2017.

Net debt and adjusted funds flow have been included in Note 17 in the company’s consolidated financial statements for the years ended December 31, 2018 and 2017 in order to provide users with a better understanding of these key metrics used by the company to manage its capital and liquidity and assess performance. Accordingly, the net debt and adjusted funds flow performance measures are considered to be measures presented in accordance with IFRS. Please refer to Seven Generations’ consolidated financial statements for the years ended December 31, 2018 and 2017 for further details.

Forward-Looking Information Advisory

This news release contains certain forward-looking information and statements that involve various risks, uncertainties and other factors. The use of any of the words “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”, “should”, “believe”, “plans”, and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this news release contains forward-looking information and statements pertaining to the following: the timing of bringing new wells online; expected improvements in condensate differentials in 2019; expected processing capacity; the ability to expand the processing capacity of the Gold Creek plant in a cost-effective manner; continued innovation and improved understanding of the company’s assets will lead to enhanced corporate returns; value enhancement expected from further delineation drilling; the expectation that the new Gold Creek gas processing plant will provide heightened operating flexibility to mitigate both planned and unplanned downtime and opportunities to optimize 7G’s natural gas and NGL revenue stream between the Alberta market and Aux Sable facilities in the US Midwest; the expectation that development plans for the company’s planned lower Montney locations will be established once the company’s lower Montney delineation program has been completed; expectation that future lower Montney development may benefit from improved cost efficiencies and the use of existing surface infrastructure; planned timing for the release of results from the first well drilled as part of the company’s Nest 1 perimeter delineation program; expectation that the Nest 1 perimeter delineation results will be used to optimize plans for gathering systems and artificial lift design for a full-scale Nest 1 development program anticipated to begin in 2020; expected reserve life; expectation that initial rates from lower Montney wells will be provided in the second half of 2019; the objectives of the midstream process that is currently underway and the timing of the conclusion of that process; the guidance provided under the heading “Outlook” including expected production, expenses, capital investment and allocation of capital; the company’s expected development horizon; further value enhancement expected through scientific analysis and delineation drilling; expectation that the 2019 capital program will be funded by the company’s expected cash flow; expectation that lower growth will mitigate production declines and preserve top-tier drilling inventory; expectation that disciplined execution will improve operating and capital cost efficiencies; expectation that planned infrastructure investments will lower operating coasts and expand profit margins. In addition to the foregoing, information and statements in this news release relating to reserves and contingent resources are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and contingent resources described exist in the quantities predicted or estimated, and that they can be profitably produced in the future.

With respect to forward-looking information contained herein, assumptions have been made regarding, among other things: future oil, NGLs and natural gas prices being consistent with current commodity price forecasts after factoring in quality adjustments at the company’s points of sale; the company’s continued ability to obtain qualified staff and equipment in a timely and cost-efficient manner; drilling and completion techniques; infrastructure and facility design concepts that have been successfully applied by the company elsewhere in its Kakwa River Project may be successfully applied to other properties within the Kakwa River Project; the consistency of the regulatory regime and framework governing royalties, taxes and environmental matters in the jurisdictions in which the company conducts its business and any other jurisdictions in which the company may conduct its business in the future; the company’s ability to market production of oil, NGLs and natural gas successfully to customers; the company’s future production levels and amount of future capital investment will be consistent with the company’s current development plans and budget; 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.

Operating cost assumptions reflect recent actual cost trends with adjustments to address planned activity levels. Royalty rate assumptions were calculated using a price range of US$50-US$65/bbl WTI, net of credits and projected C* for new wells to be drilled in 2019. Royalty rate assumptions are net of expected gas cost allowance from investments in gas plants and gathering infrastructure. G&A cost assumptions reflect recent actuals and expectations for a larger staff count and information technology investments in 2019.

Actual results could differ materially from those anticipated in the forward-looking information that is contained herein as a result of the risks and risk factors that are set forth in the company’s annual information form dated February 27, 2019 for the year ended December 31, 2018 (AIF), which is available on SEDAR, including, but not limited to: volatility in market prices and demand for oil, NGLs and natural gas and hedging activities related thereto; general economic, business and industry conditions; variance of the company’s actual capital costs, operating costs and economic returns from those anticipated; 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 risk; 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 and the potential impact of climate change on the company's operations; the absence or loss of key employees; uncertainty associated with estimates of oil, NGLs and natural gas reserves and resources and the variance of such estimates from actual future production; dependence upon compressors, gathering lines, pipelines and other facilities, certain of which the company does not control; the ability to satisfy obligations under the company’s firm commitment transportation arrangements; 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 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; 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 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; 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 document regarding prospective financial performance, financial position or cash flows is based on assumptions about future events, including economic conditions and proposed courses of action based on management’s assessment of the relevant information that is currently available. Projected operational information contains forward-looking information and is based on a number of material assumptions and factors, as are set out above. These projections may also be considered to contain future oriented financial information or a financial outlook. The actual results of the Company’s operations for any period will likely vary from the amounts set forth in these projections and such variations may be material. Actual results will vary from projected results. Readers are cautioned that any such financial outlook and future-oriented financial information contained herein should not be used for purposes other than those for which it is disclosed herein. The forward-looking information and statements contained in this document speak only as of the date hereof and the company does not assume any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws.

Notes Regarding Oil and Gas Metrics and Early Production

This presentation includes certain metrics, including barrels of oil equivalent (boe) and reserve life, 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.

Reserve life has been calculated by dividing the 2P reserves stated herein by 2018 production. Management has used this measure to determine how long booked reserves would last at 2018 production levels, if no further reserves were added.

The Nest 1 perimeter well that is described in this news release was drilled in the middle interval of the Montney formation in the company’s Nest 1 area. The results have been obtained during a 27 day initial production test. The average gas production rate observed to date is 3,343 Mcf/d and the average condensate production rate observed to date is 1,641 bbl/d. Cumulative gas production has been 90.6 MMcf, cumulative condensate production has been 44,470 bbls and cumulative produced water has been 38,033 bbls. Gas, condensate, and water rates ramped up over a period of 10 days. Gas maintained a plateau rate of about 4,200 Mcf/d) while condensate gradually declined as expected. Tubing pressure reached a maximum of 9,300 KPa (1,350 psi) after 6 days of flow and gradually decreased to about 5,750 KPa (834 psi), consistent with a relatively high liquid/gas ratio of about 700 bbl/MMcf. No pressure transient analysis or well-test interpretation has been carried out to date. Readers are cautioned that the flow test results are not necessarily indicative of long-term performance or ultimate recovery.

Independent Reserves and Resources Evaluation

Estimates of the company’s reserves and contingent resources and the net present value of future net revenue attributable to the company’s reserves and contingent resources, as at December 31, 2018, are based upon the reports prepared by McDaniel, dated February 27, 2019. The estimates of reserves and contingent resources provided in this news release are estimates only and there is no guarantee that the estimated reserves or contingent resources will be recovered. Actual reserves and contingent resources may be greater than or less than the estimates provided in this in this document, and the differences may be material. Estimates of net present value of future net revenue attributable to the company’s reserves and contingent resources do not represent the fair market value of the company’s reserves and contingent resources 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 and contingent resources will be attained and variances could be material. Contingent resources in the “development pending” project maturity subclass have been assigned by McDaniel, as at December 31, 2018, in the upper, middle and lower intervals of the Montney formation in certain parts of the Nest 1, Nest 2, Nest 3, Rich Gas and Wapiti areas within the Kakwa River Project. The COGE Handbook indicates that it is appropriate to categorize contingent resources in the development pending project maturity subclass where resolution of the final conditions for development are being actively pursued and there is a high chance of development. Approximately 98% of the contingent resources attributed to the Company’s properties by McDaniel, as at December 31, 2018, have been classified as “development pending” and the balance of the contingent resources have been classified as “development unclarified”. Contingent resources in the “development unclarified” project maturity subclass have been assigned by McDaniel, as at December 31, 2018, in the Wilrich formation within the Cretaceous stack across the Project area. The COGE Handbook indicates that it is appropriate to categorize contingent resources in the “development unclarified” project maturity subclass when the evaluation is incomplete and there is ongoing activity to resolve any risks or uncertainties. There is uncertainty that it will be commercially viable to produce any portion of the contingent resources. For important additional information regarding the independent reserves and resources evaluations that were conducted by McDaniel, please refer to the AIF, which is available on SEDAR.

Certain oil and gas terms

Terms used in this news release that are not otherwise defined herein are provided below:

best estimate is a classification of estimated resources described in the COGE Handbook, which is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual quantities recovered will be greater or less than the best estimate. Resources in the best estimate case are considered to have a 50% probability that the actual quantities recovered will equal or exceed the estimate.

contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies are conditions that must be satisfied for a portion of contingent resources to be classified as reserves that are: (a) specific to the project being evaluated; and (b) expected to be resolved within a reasonable timeframe. Contingencies may include factors such as economic, environmental, social, political factors and regulatory matters, lack of markets or a prolonged timetable for development. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage.

developed producing reserves are those 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 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, in relation to reserves, means the applicable working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests.

probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on: (i) analysis of drilling, geological, geophysical and engineering data; (ii) the use of established technology; and (iii) specified economic conditions, which are generally accepted as being reasonable, and shall be disclosed. Reserves are classified according to the degree of certainty associated with the estimates.


Other Definitions/Abbreviations


  gross proved reserves


gross proved plus probable reserves


gross best estimate contingent resource


the Alliance Pipeline System






barrels of oil equivalent

COGE Handbook

the Canadian Oil and Gas Evaluation Handbook maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter), as amended from time to time.


the sediment deposition between the Jurassic and Tertiary periods. It includes development opportunities in formations such as the Cadomin, Gething, Bluesky, Wilrich, Falher, Cadotte, Dunvegan and Cardium


cash return on invested capital


the drilling and completion cost allowance under Alberta’s Modernized Royalty Framework




drilling and completions


general and administrative expenses


first half of the year


second half of the year


International Financial Reporting Standards








million barrels of oil equivalent


thousand barrels of oil equivalent


thousands of barrels


thousand cubic feet


million cubic feet


the Nest 1, Nest 2 and Nest 3 areas combined

Nest 1

the “Nest 1” area shown in the map provided in the AIF

Nest 2

the “Nest 2” area shown in the map provided in the AIF

Nest 3

the “Nest 3” area shown in the map provided in the AIF


natural gas liquids


not meaningful information


New York Stock Exchange


Nova Gas Transmission Ltd. System


gross proved developed producing reserves


pounds per square inch

Rich Gas

the “Rich Gas” area shown in the map provided in the AIF


return on capital employed


the System for Electronic Document Analysis and Retrieval maintained by the Canadian Securities Administrators available at www.sedar.com.


Toronto Stock Exchange


the “Wapiti” area shown in the map provided in the AIF


West Texas Intermediate

Seven Generations Energy Ltd. is also referred to as Seven Generations, Seven Generations Energy, 7G, we, our, the Company and the company.

Investor Relations
Brian Newmarch, Vice President, Capital Markets
Phone: 403-718-0700
Email: bnewmarch@7genergy.com

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

Media Relations
Alan Boras, Director, Communications & Stakeholder Relations
Phone: 403-767-0772
Email: aboras@7genergy.com

Seven Generations Energy Ltd.
Suite 4400, 525 - 8th Avenue SW
Calgary, AB T2P 1G1
Website: 7genergy.com

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