Return on capital employed of 10.4%
CALGARY, Alberta, May 03, 2018 (GLOBE NEWSWIRE) -- Seven Generations (TSX:VII) delivered funds from operations of $381 million or $1.05 per share in the first quarter, generating a trailing 12-month return on capital employed of 10.4 percent and a cash return on invested capital of 18.1 percent. Condensate production averaged 67,285 barrels per day (bbls/d), up 30 percent from the first quarter of 2017. Total production increased 23 percent to 187,686 barrels of oil equivalent (boe/d), with liquids making up 58 percent of that total.
FIRST QUARTER HIGHLIGHTS
“The strength we are seeing in global oil prices, coupled with our access to premium-priced North American natural gas markets, is helping to drive our strong returns. First quarter condensate production is higher than expected, generating better than expected funds from operations. We’ve completed processing plant maintenance to improve reliability and we made significant progress on projects aimed at lowering costs in the second half of the year,” said Marty Proctor, 7G’s President & Chief Executive Officer.
“We are focused on developing our highest-value products as efficiently as possible to optimize funds from operations and returns,” Proctor said.
OPERATIONAL AND FINANCIAL HIGHLIGHTS
|Three months ended
|Three months ended
|($ millions, except boe and per share amounts)||2018||2017||% Change||2017||% Change|
|Natural gas (MMcf/d)||473.3||384.5||23||493.4||(4)|
|Total Production (mboe/d)||187.7||153.1||23||197.3||(5)|
|Natural gas ($/Mcf)||4.11||4.36||(6)||3.75||10|
|Realized hedging gains (losses) ($/boe)||(0.78)||(0.52)||50||0.38||nm|
|Royalty expense ($/boe)||(1.12)||(1.22)||(8)||(1.18)||(5)|
|Operating expenses ($/boe)||(5.73)||(4.99)||15||(5.69)||1|
|Transportation, processing and other ($/boe)||(7.06)||(5.22)||35||(6.30)||12|
|Operating netback ($/boe)(1)(3)(4)||24.94||23.57||6||24.86||0|
|G&A per boe ($/boe)||(0.65||(0.79)||(18)||(0.65||—|
|Finance expense and other ($/boe)||(1.75)||(3.03)||(42)||(1.96)||(11)|
|Corporate netback ($/boe)(1)||22.54||19.75||14||22.25||1|
|Operating income ($)(1)||129.4||74.8||73||128.6||1|
|Per share - diluted ($)||0.36||0.21||71||0.35||3|
|Net income ($)||22.7||215.6||(89)||83.1||(73)|
|Per share - diluted ($)||0.06||0.59||(90)||0.23||(74)|
|Funds from operations ($)(1)||380.8||272.1||40||403.8||(6)|
|Per share - diluted ($)||1.05||0.75||40||1.11||(5)|
|Cash provided by operating activities ($)||424.1||335.7||26||310.3||37|
|Capital investments ($)||582.6||362.3||61||322.3||81|
|Adjusted working capital ($)(1)||(87.4)||500.5||(117)||109.5||nm|
|Available funding ($)(1)||1,312.6||1,540.9||(15)||1,467.4||(11)|
|Net debt ($)(1)||2,118.2||1,594.1||33||1,866.4||13|
|Debt outstanding ($)||2,011.1||2,092.1||(4)||1,956.4||3|
|Weighted average shares - basic||354.9||350.6||1||354.7||—|
|Weighted average shares - diluted||363.5||363.1||—||363.9||—|
MARKET ACCESS ADVANTAGE
7G’s first quarter condensate price was $73.40 per barrel
7G’s average realized condensate price was $73.40 per barrel in the first quarter, up 15 percent compared to the same period one year ago and equated to 93 percent of the Canadian dollar equivalent WTI benchmark price. Condensate production comprised 36 percent of total volumes and generated 66 percent of corporate revenues in the first quarter. 7G expects attractive condensate pricing to continue given projected long-term supply and demand imbalances in Alberta.
Natural gas price averages $4.11 per Mcf in first quarter
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 was $4.11 per thousand cubic feet (Mcf) in the first quarter, nearly double Alberta prices that averaged $2.08 per Mcf. 7G sells about 70 percent of its natural gas in the United States, the majority of which is sold in Chicago.
Establishing longer-term market access to U.S. Gulf Coast
7G has lengthened the term of its natural gas shipping agreement on the Natural Gas Pipeline Company of America (NGPL) system to the US Gulf Coast. Under the agreement, 7G has extended its 100 MMcf/d of NGPL capacity until 2028, further diversifying its natural gas marketing portfolio.
Encouraging preliminary well results along western Nest 2 boundary and Wapiti areas
Early results from two Montney wells drilled along the boundary between 7G’s Nest 2 and Wapiti lands are encouraging. The two 40-stage wells have been on production for about 30 days, each delivering about 836 bbls/d of condensate and 7.1 MMcf/d of natural gas, while facility constrained. Additional delineation wells are planned along this boundary area in 2019.
During the first quarter, 7G tied in a five-well pad in its Nest 1 area with 90-day production rates from each well averaging 831 bbls/d of condensate and 1.17 MMcf/d of natural gas. While these wells are producing more condensate and generating better economics than the company’s Nest 1 type curve, they are delivering lower boes than originally projected due to lower initial natural gas and NGL rates. The company is completing a 12-well pad in Nest 1, offsetting a 2017 pad drilled in the transition zone between Nest 2 and Nest 1, and expects to have preliminary results in the second half of 2018.
The company drilled two follow-up Montney delineation wells in Nest 3 in the first quarter and expects to have preliminary well results in the second quarter. The Nest 3 well drilled and completed in 2017 continues to have superior performance, with cumulative production of more than 3 Bcf of natural gas and 120,000 bbls of condensate, while still constrained by surface facilities. 7G plans to ramp-up production from its Nest 3 area in 2019 once larger pipeline infrastructure is built to handle the higher natural gas volumes that are expected in that area.
Improved processing plant reliability
During April, 7G’s third-party natural gas processing plant underwent planned maintenance to mitigate a partial blockage in the heat exchanger to restore the plant’s designed processing capacity of 200 MMcf/d. The seven-day maintenance was completed as planned and the facility is now capable of processing at its design capacity. Also, as reported in 7G’s 2017 fourth quarter report, the plant’s ethane extraction compressor was offline during the first quarter, which curtailed ethane recovery by about 2,500 bbls/d, but had minimal impact on revenue. After repairs were made, the plant operator resumed normal operations of this deep cut ethane extraction unit on April 30, 2018. The facility downtime year-to-date is within 7G’s budget expectations.
Construction of 7G’s third wholly-owned natural gas processing facility at Gold Creek and the associated pipeline activity remain on schedule and on budget. The plant will have 250 MMcf/d of natural gas processing capacity. 7G expects to bring these new facilities online during the fourth quarter of 2018.
DRILLING AND COMPLETIONS
|Three months ended
|Three months ended
|Nest Activity||2018||2017||% Change||2017||% Change|
|Horizontal wells rig released||27||23||17||20||35|
|Average measured depth (m)||5,621||5,875||(4)||5,278||6|
|Average horizontal length (m)||2,459||2,649||(7)||2,128||16|
|Average drilling days per well||28||34||(18||29||(3)|
|Average drill cost per lateral metre ($)(2)||1,500||1,441||4||1,760||(15)|
|Average well cost ($ millions)(2)||3.6||3.8||(5)||3.6||—|
|Average number of stages per well||39||39||—||39||—|
|Average tonnes pumped per well||5,927||6,520||(9)||5,643||5|
|Average cost per tonne(2)||1,187||1,155||3||1,107||7|
|Average well cost ($ millions)(2)||7.0||7.5||(7)||6.2||13|
|Total D&C cost per well ($ millions)(2)||10.6||11.3||(6)||9.8||8|
Active quarter for drilling and completions
Drilling and completions capital investment of $320 million funded the drilling of 27 wells and the completion of 20 wells. Seventeen wells were brought on production with the majority of the tie‑ins occurring in the latter half of the first quarter. The company had an inventory of 66 wells at various stages of construction between drilling, completion and tie-in, and 347 producing horizontal Montney wells within the Kakwa River Project at the end of the first quarter.
Completion costs per well down seven percent
7G's average completion cost per well was $7 million in the first quarter of 2018, down from $7.5 million in the first quarter of 2017, reflecting fewer tonnes of proppant per well, while the cost per tonne of proppant was up 3 percent.
The total drilling and completion cost per well was $10.6 million in the first quarter of 2018, on budget, and down from $11.3 million in the first quarter of 2017. Seven Generations continues to pursue ways to drive down costs in both drilling and completions to maximize capital efficiencies.
Operating expenses were $5.73 per boe in the first quarter, relatively flat compared to the fourth quarter of 2017. Water transportation and disposal costs stemming from greater production and increased water handling from slickwater completions are the largest component of operating costs.
Developing water infrastructure to lower water costs
Early results from 7G’s second water disposal well are encouraging and will help drive operating cost improvements in the second half of the year. A third disposal well has been drilled that shows reservoir characteristics similar to the second well.
Commodity and currency price hedging is a core component of 7G’s financial strategy. The company uses a combination of swaps and options-based derivatives to lock in threshold returns on capital investments, to help reduce the impact of price volatility on funds from operations and bring greater certainty to funding its capital investment program. 7G has used collars to hedge a portion of its liquids sales, which provide downside protection and allow for upside participation to a certain point. For the balance of 2018 at a 1.265 C$/US$ exchange rate, an average of approximately 33,700 boe per day of liquids are hedged with US$ equivalent floors of US$47.37 and ceilings of US$60.20, or the Canadian dollar equivalent of $76.16 per boe of condensate at the ceiling of those collars.
Seven Generations maintained a strong balance sheet with ample liquidity, including available funding of more than $1.3 billion, net debt of $2.1 billion, and a trailing 12-month debt to funds flow ratio of 1.6x. 7G plans to fund its 2018 capital program through a combination of funds from operations, cash on hand, and, if necessary, draws on its credit facility.
Changes in presentation of operating results
Recent changes in International Financial Reporting Standards and a reclassification of condensate volumes impact the presentation of transportation, processing and other costs and condensate production volumes. For details on these changes, refer to the “Operating Results” section of Management’s Discussion and Analysis for three months ended March 31, 2017 and 2018, posted on 7G’s website: 7genergy.com.
“As we continue to study and refine our understanding of our land base, we have begun to observe some variances in the reservoir characteristics of the Montney formation across our Nest areas. Recent wells with higher-intensity completions designs outside of our core Nest 2 development area are producing at higher condensate production rates and higher condensate-gas-ratios (CGRs) than we anticipated in the 2018 budget. In new parts of Nest 2, we are encountering high variability in our natural gas production volumes by pad, with consistent condensate production across pads. Having gained more information from recent pads, we now expect overall condensate production rates to be ahead of our original expectations, with lower concurrent natural gas and NGL rates,” Proctor said.
The cumulative effect of recent well results is an increase in higher-value condensate production rates and a net reduction in expected total boe production. The updated commodity split and liquids yields, and revised funds from operations guidance, are presented below.
|Production proportion update*|
|2018 original forecast||Revised 2018 outlook|
|Total Liquids||55 – 60%||58 – 60%|
|Condensate||30 – 32%||35 – 36%|
|NGLs||25 – 28%||23 – 24%|
|Natural gas||40 – 45%||40 – 42%|
|Condensate (bbl/MMcf)||125||145 – 155|
|NGL (bbl/MMcf)||95||85 - 90|
|Funds from operations @ US$60/bbl WTI ($MM)||1,550 – 1,625||1,600 – 1,675|
* Original forecast and revised outlook reflect the reclassification of condensate and NGLs. For additional information, refer to the “Operating Results” section of Management’s Discussion and Analysis for three months ended March 31, 2017 and 2018, posted on 7G’s website: 7genergy.com.
Based on recent updates and 7G’s continually progressing technical analysis of the resource, the company currently projects overall production trending towards the lower end of 2018 boe production guidance of 200,000 – 210,000 boe/d, while production of condensate is likely to exceed expectations. 7G expects 2018 funds from operations to be approximately $1.635 billion, assuming a WTI oil price of US$60 per bbl. 7G plans 2018 capital investments of between $1.675 billion to $1.775 billion, consistent with its original guidance.
David Holt, Chief Operating Officer
Seven Generations is pleased to welcome David Holt as its new Chief Operating Officer starting May 14, 2018. David will lead 7G’s drilling, completions, facilities, production optimization, construction, health, safety and environment teams. David is a petroleum engineer with more than 25 years of progressive technical, operational and leadership experience at well-respected major exploration and production companies. In his recent position as vice president of production, David was responsible for west and central Alberta development areas including the Peace River Arch, Deep Basin, Foothills and a significant Montney formation development program.
Chris Law, Executive Vice President, Strategy Management, and Glen Nevokshonoff, Chief Operating Officer, have resigned from Seven Generations to pursue other interests.
“Chris and Glen joined Seven Generations in October 2008. Chris played a key role in devising the strategy and financing the growth that helped 7G develop from an idea to the company we are today. Glen has been instrumental in leading the development of the Kakwa River Project from modest production to one of Canada’s largest producers. We wish Chris and Glen well in their future endeavours,” Proctor said.
Annual meeting of shareholders today
7G is holding its annual meeting of shareholders today, Thursday, May 3, 2018, at 2 p.m. in Macleod Hall A at the Telus Convention Centre, located at 120 - 9th Avenue S.E., Calgary.
Science Expo today
Seven Generations will host a Science Expo at 3 p.m. today following its annual meeting at the Telus Convention Centre. The Science Expo will feature a variety of booths showcasing operational, technical, strategic, environmental and community initiatives.
Generations 2018 stakeholder report published today
Generations 2018 is Seven Generations’ third annual stakeholder report. The publication contains stakeholder-focused stories and details a number of the connections that 7G has established in Grande Prairie, across the Peace Region and in Calgary. Please see www.7genergy.com for the report.
7G management will hold a conference call to discuss results and address investor questions today, May 3, 2018 at 9 a.m. MT (11 a.m. ET).
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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.
Further information on Seven Generations is available on the company’s website: www.7genergy.com, or by contacting:
Marty Proctor, President & CEO
Derek Aylesworth, Chief Financial Officer
Brian Newmarch, Vice President, Capital Markets
Alan Boras, Director, Communications & Stakeholder Relations
Seven Generations Energy Ltd.
Suite 4400, 525 - 8th Avenue SW
Calgary, AB T2P 1G1
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 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 May 2, 2018, for the three months ended March 31, 2018 and 2017.
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: planned capital investments and allocation of capital; the Company’s focus on maximizing returns from its capital investments; anticipated costs, cost savings and cost improvements; the future outlooks described under the heading “Outlook”, including anticipated production, product yields, liquid to gas ratios and funds from operations; wells expected to be drilled, including planned delineation wells; expected timing of first production results from new wells to be drilled; expectation that attractive condensate pricing will continue given projected long-term supply and demand imbalances in Alberta; the pursuit of opportunities to lower drilling and completion costs to maximize capital efficiencies; the development of water disposal infrastructure and cost savings expected to result therefrom; the expected processing capacity of the new natural gas processing plant that is being constructed at Gold Creek; the timing of completion of the construction of that facility and the associated pipeline; and the Company’s anticipated sources of funding.
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 www.sedar.com, 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.
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.
Note Regarding Initial Production Results
Readers are cautioned that the preliminary well results and early-stage initial production results referenced in this news release are not indicative of longer-term performance or ultimate recovery.
|AIF||Annual Information Form for the year ended December 31, 2017 dated March 13, 2018|
|Bcf||billion cubic feet|
|boe||barrels of oil equivalent|
|CROIC||cash return on invested capital|
|D&C||drilling and completions|
|G&A||general and administrative expenses|
|IFRS||International Financial Reporting Standards|
|Mboe||thousand barrels of oil equivalent|
|Mbbls||thousands of barrels|
|mcf||thousand cubic feet|
|MMcf||million cubic feet|
|Nest||the Nest 1, Nest 2 and Nest 3 areas combined|
|Nest 1||the “Nest 1” area that is shown in the map that is provided under the heading “Description of Business – Development Areas” in the AIF, which is available on the SEDAR website at www.sedar.com|
|Nest 2||the “Nest 2” area that is shown in the map that is provided under the heading “Description of Business – Development Areas” in the AIF, which is available on the SEDAR website at www.sedar.com|
|Nest 3||the “Nest 3” area that is shown in the map that is provided under the heading “Description of Business – Development Areas” in the AIF, which is available on the SEDAR website at www.sedar.com|
|NGLs||natural gas liquids|
|nm||not meaningful information|
|ROCE||return on capital employed|
|TSX||Toronto Stock Exchange|
|US$||United States dollars|
|WTI||West Texas Intermediate|
|$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.Return to News Release Listing