CALGARY, Alberta--(BUSINESS WIRE)-- FIRST QUARTER 2019 HIGHLIGHTS
- 7G’s market access initiatives, coupled with a stronger condensate price environment and improved operating costs, led to adjusted funds flow of $339 million or $0.95 per share and yielded an operating netback of $21.99 per boe, 16 percent higher than the fourth quarter of 2018.
- The company’s trailing 12-month return on capital employed was 11.9 percent. Cash return on invested capital was 17.7 percent.
- Investments in water handling helped reduce operating expenses to $4.93 per boe, 11 percent below the company’s full year 2018 average of $5.52 per boe. 7G’s investments in water management and conservation are reducing costs, carbon emissions and traffic by taking approximately 50 water hauling trucks off the road each day.
- Sales volumes averaged 197,400 boe/d, with liquids representing 59 percent of 7G’s total production. Condensate sales of 72,700 bbl/d increased by 8 percent compared to the same period in 2018.
- 7G now has the capacity to sell approximately 90 percent of its natural gas into premium markets in the US Midwest, Eastern Canada and the US Gulf Coast. The company’s realized natural gas price was $4.32/Mcf in the first quarter, an approximate 70 percent premium to AECO pricing. 7G continues to advance its market access initiatives, recently adding 55 MMcf/d of pipeline capacity from Chicago directly to the US Gulf Coast, taking that total capacity to 155 MMcf/d.
- Realizing the benefit of its delineation capital investments, 7G has an additional lower Montney result with initial 30-day flow rates averaging approximately 1,250 boe/d (63 percent condensate). The company is currently tying-in its first full triple-stack pad, with flow rates expected later this summer.
- 7G has the lowest carbon intensity per unit among its Canadian peers at 0.0136 tonnes of CO2e per boe, as reported by CDP, a global environmental disclosure protocol. 7G is committed to responsible energy development that serves stakeholders through leading governance, social and environmental performance within the North American energy industry.
Key Nest 3 infrastructure development in progress, outlook for increasing free cash flow
7G had an active first quarter that included the build-out of its Nest 3 connector pipeline. This 2019 pipeline investment underpins the Nest 3 development plan and enables the tie-in of Nest 3 resource into the company’s larger gathering and processing infrastructure network. Nest 3 infrastructure development is expected to continue in the second quarter, before aligning toward a more resource development focused second half of the year. Once the connector is complete, 7G expects future infrastructure capital, as a percent of total cash flow, to fall relative to historical levels.
Capital discipline and returns to shareholders remain top priorities
As 7G transitions from one of the fastest drill-bit growth companies in Canadian history to a sustainable, free cash flow growth entity, capital discipline remains paramount. Strong liquids production, improving local condensate pricing and reduced operating costs are expected to generate free cash flow in excess of 7G’s $1.25 billion 2019 capital budget. 7G plans to apply free cash flow to a combination of share repurchases pursuant to the previously announced normal course issuer bid (NCIB) and net debt reduction.
OPERATIONAL AND FINANCIAL HIGHLIGHTS
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($ millions, except boe
|2019||2018||% Change||2018||% Change|
|Natural gas (MMcf/d)||483.6||473.3||2||515.4||(6||)|
|Total sales volumes (mboe/d)(1)||197.4||187.7||5||215.1||(8||)|
|Natural gas ($/Mcf)||4.32||3.54||22||4.77||(9||)|
|Royalty expense ($/boe)||(2.30||)||(1.12||)||105||(0.99||)||132|
|Operating expenses ($/boe)||(4.93||)||(5.73||)||(14||)||(5.25||)||(6||)|
|Transportation, processing and other ($/boe)||(6.65||)||(6.24||)||7||(7.07||)||(6||)|
|Operating netback before the following ($/boe)(1)(2)||21.56||25.10||(14||)||20.35||6|
|Realized hedging gains (losses) ($/boe)||(0.34||)||(0.78||)||(56||)||(1.58||)||(78||)|
|Marketing income ($/boe)(2)||0.77||0.62||24||0.20||285|
|Operating netback ($/boe)(2)||21.99||24.94||(12||)||18.97||16|
|Adjusted funds flow ($/boe)(2)(4)||19.05||22.54||(15||)||17.06||12|
|Net income ($)||10.8||22.7||(52||)||245.4||(96||)|
|Per share - diluted ($)||0.03||0.06||(50||)||0.68||(96||)|
|Operating income ($)(2)||84.0||129.4||(35||)||66.3||27|
|Per share - diluted ($)||0.24||0.36||(33||)||0.18||33|
|Cash provided by operating activities ($)||259.3||424.1||(39||)||410.1||(37||)|
|Per share - diluted ($)||0.73||1.17||(38||)||1.13||(35||)|
|Adjusted funds flow ($)(4)||338.5||380.8||(11||)||337.4||—|
|Per share - diluted ($)||0.95||1.05||(10||)||0.93||2|
|Capital investments ($)||400.9||582.6||(31||)||262.3||53|
|Available funding ($)(2)||1,280.9||1,312.6||(2||)||1,345.9||(5||)|
|Net debt ($)(4)||2,229.9||2,118.2||5||2,206.8||1|
|Weighted average shares - basic||353.0||354.9||(1||)||359.2||(2||)|
|Weighted average shares - diluted||355.6||363.5||(2||)||362.3||(2||)|
(1) Excludes the purchase and resale of condensate and natural gas in respect of the Company's transportation commitment utilization and marketing activities.
(2) See “Non-IFRS Financial Measures” under Reader Advisory. Certain comparative figures have been adjusted to conform to current period presentation.
(3) Represents the total of liquids and natural gas sales, net of royalties, gains (losses) on risk management contracts and other income.
(4) Refer to Note 13 of the Q1 2019 condensed interim consolidated financial statements for further details.
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|Nest Activity||2019||2018||% Change||2018||% Change|
|Horizontal wells rig released||18||27||(33||)||19||(5||)|
|Average measured depth (m)||5,911||5,621||5||6,010||(2||)|
|Average horizontal length (m)||2,598||2,459||6||2,776||(6||)|
|Average drilling days per well||30||28||7||28||7|
|Average drill cost per metre ($)(2)||614||642||(4||)||560||10|
|Average well cost ($ millions)(2)||3.6||3.6||—||3.4||6|
|Average number of stages per well||55||39||41||46||20|
|Average tonnes pumped per metre||1.9||2.4||(21||)||1.9||—|
|Average tonnes pumped per well||4,750||5,923||(20||)||4,417||8|
|Average cost per tonne(2)||1,215||1,218||—||1,282||(5||)|
|Average well cost ($ millions)(2)||5.8||7.2||(19||)||5.7||2|
|Total D&C cost per well ($ millions)(2)||9.4||10.8||(13||)||9.1||3|
(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 is subject to change.
OPERATIONS AND RESOURCE DEVELOPMENT
Operating costs in the first quarter improved to $4.93 per boe, benefitting from investments in water handling infrastructure. At this time, 7G is not updating its previously disclosed 2019 operating expense budget of $5.00 to $5.50 per boe, and will continue to progress its water management initiatives, including increased recycling of produced water.
Lower Montney resource delineation update
7G’s second partial triple-stack pad, located in the western edge of Nest 2, came on stream slightly ahead of schedule and on budget. It targeted a single well in the lower Montney, below simultaneous completions of the upper and middle Montney. The lower Montney location delivered initial rates during the first 30 days of production of approximately 1,250 boe/d (63 percent condensate), while the middle and upper locations performed as expected. The pad is located approximately a township west of the company’s first partial triple-stack that was announced last year and enhances 7G’s understanding of the lower Montney resource across a broader areal extent. With continued lower Montney success, the company could materially expand its highly economic drilling inventory, while improving full cycle returns as surface costs are allocated across a larger well count.
Full triple-stack pad and advanced completions design
The company’s first full triple-stack pad, located in the north-western portion of Nest 2, has proceeded according to plan and budget, with three wells in each of the upper, middle and lower Montney completed in the first quarter and in the process of being tied-in. This triple-stack pad will help further delineate the lower Montney potential and evaluate the effectiveness of co-completions across all three Montney benches. In addition, 7G has deployed fibre-optic monitoring, micro-seismic, and image logging to improve understanding of the subsurface fracture network and to enhance future completion designs. 7G plans to use its expanding dataset to help analyze and advance the economic benefits of increasing intra-stage clusters that could materially improve the company’s capital efficiencies.
Nest 1 update
7G’s previously announced Nest 1 perimeter test continues to flow at rates and pressures exceeding expectations. Initial rates during the first 60 days of production averaged 1,898 boe/d (72 percent condensate) while flowing at restricted rates during most of the second month. This prolific result, located 12 kilometres east of the company’s existing Nest 1 development, provides important initial production data that will help guide development planning of the company’s inventory of 480 Nest 1 locations.
MARKET ACCESS INITIATIVES
During the first quarter, 7G acquired an additional 55 MMcf/d of market access from the US Midwest to the Gulf Coast. When combined with 7G’s existing 100 MMcf/d of direct Henry Hub sales, the company can potentially sell nearly one third of its Montney natural gas production directly into the global LNG market. This pipeline capacity provides price diversification and differentiated egress optionality for the company’s natural gas production. 7G remains committed to expanding its market access options to enhance price realizations across its entire production suite.
NORMAL COURSE ISSUER BID UPDATE
With benchmark WTI prices exceeding the assumptions used in the company’s 2019 budget, 7G has entered into incremental oil hedges subsequent to the first quarter to establish floor pricing on 5,000 bbl/d of its production above US$65/bbl for the balance of 2019. With hedged cash flows exceeding budgeted WTI pricing, and a commitment to execute the original $1.25 billion capital program, 7G intends to allocate excess free cash flow to a combination of its NCIB and net debt reduction.
GENERATIONS – 7G’S STAKEHOLDER AND SUSTAINABILITY REPORT
7G has published on its website the fourth annual edition of Generations, its stakeholder and sustainability report. Generations 2019 highlights 7G’s commitment to differentiated stakeholder service, responsible energy development and stakeholder engagement. Generations 2019 expands 7G’s reporting of quantitative and qualitative environmental, social and governance performance. Generations is available at:
2019 guidance remains unchanged. The company has provided additional details regarding expected royalty rates to reflect the current commodity price environment. During the second quarter of 2019, brief outages are planned for turnaround work at third party processing facilities and natural gas pipeline systems. The previously provided outlook reflects these maintenance-related events.
|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 at US$50 WTI (%)||5 - 7|
|Royalties at US$60 WTI (%)||7 - 9|
|Operating ($/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|
BOARD OF DIRECTORS UPDATE
As previously announced, 7G’s board of directors renewal process is currently underway with Mark Monroe taking on the chair role as of January 1, 2019 and Ronnie Irani joining 7G’s board of directors as of February 27, 2019. Founding chair Kent Jespersen did not stand for re-election at the company’s annual general meeting that took place on Wednesday, May 1, 2019. Additionally, directors Kevin Brown, Kaush Rakhit and Jeff van Steenbergen did not stand for re-election. Seven Generations thanks these directors for their guidance and contributions to the conception, evolution and foundational success of the company.
Additionally, 7G’s board of directors has appointed Leontine Atkins as a board member effective May 2, 2019. Atkins was previously a board member of KPMG Canada’s National Board of Directors until early 2019, having sat on the National Acquisitions and Admissions and Succession committees. She served as a Partner at KPMG Canada from 2006 until early 2019 and was previously a Partner at KPMG Netherlands until she moved to Canada in 2006. Atkins has 30 years of experience in the global oil and gas industry, with a focus on corporate strategy in each of the upstream, midstream and downstream sectors of the energy value chain.
Atkins currently serves as a director of Points International, a leading global loyalty ecommerce platform, the board of Calgary Economic Development as the chair of the audit committee and on the board of Heritage Park Museum where she also is a member of the audit committee. She was also the vice chair and past chair of the audit/investment committee of the Glenbow Museum board. Atkins holds a Bachelor of Business Administration in Finance from Acadia University and a Master of Business Administration from Dalhousie University. She has also obtained her CPA, CA designation as well as the ICD.D designation from the Institute of Corporate Directors.
7G management will hold a conference call to discuss results and address investor questions today, May 3, 2019, at 9 a.m. MT (11 a.m. ET).
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May 17, 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 .
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” 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 May 2, 2019, for the three months ended March 31, 2019 and 2018.
Net debt and adjusted funds flow have been included in Note 13 in the company’s condensed interim consolidated financial statements for the three months ended March 31, 2019 and 2018 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’ condensed interim consolidated financial statements for the three months ended March 31, 2019 and 2018 and 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: expected free cash flow generation in 2019; anticipated transportation and processing capacity and market access; commitment to responsible energy development with leading governance, social and environmental performance; planned transition to a sustainable free cash flow growth entity; plans to allocate cash flow in excess of the 2019 capital budget to a combination of share repurchases and debt reduction; the timing of the production from the company’s first full triple-stack pad; the potential to materially expand the company’s highly economic drilling inventory and full cycle returns with lower Montney success; expected reductions in future infrastructure capital as a percent of total cash flow; continued progress on water management initiatives, including increased recycling of produced water; cost reductions; planned delineation of the lower Montney and further evaluation of the effectiveness of co-completions across all three Montney benches; further enhancement of the company’s completion designs; plans to use the company’s expanding dataset to analyze and advance the potential economic benefits of increasing intra-stage clusters applied during hydraulic fracturing, which has the potential to materially improve the company’s capital efficiencies; the expected drilling inventory in the company’s Nest 1 area; development plans; planned outages; and the guidance provided under the heading “Outlook”.
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; 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$60/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; 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; political risk; the rescission, or amendment to the conditions, of groundwater licenses of the company; 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 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; 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 concentration of the company’s assets in the Kakwa River Project; unforeseen title defects; claims by indigenous peoples; 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; 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; government regulations; changes in the application, interpretation and enforcement of applicable laws and regulations; actual results differing materially from management estimates and assumptions; 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; terrorist attacks or armed conflict; cyber security risks, loss of information and computer systems; the potential for security deposits to be required under provincial liability management programs; reassessment by taxing or regulatory 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; breach of agreements by counterparties and potential enforceability issues in contracts; impact of expansion into new activities on risk exposure; 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 Industry Metrics and Early Production
This presentation includes certain metrics, including barrels of oil equivalent (boe), carbon intensity and free cash flow, 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.
The carbon intensity estimates for 7G that are provided herein were calculated by the company with the assistance of third parties. For the 2018 reporting year, based on 2017 performance, 7G’s carbon intensity of 0.0136 tonnes of CO2e per boe was ranked by CDP as the lowest compared to six peer companies. 7G quantified and reported its GHG emissions using what is referred to as the “operational control” approach. 7G’s deemed organizational boundary included its corporate offices and all natural gas extraction and processing facilities (including well pads). 7G elected to report its Scope 1 and 2 GHG emissions and not to report its Scope 3 GHG emissions. For the purposes of 7G’s GHG emissions reporting:
- Scope 1 emissions were defined as direct emissions from GHG sources that 7G owned or controlled (including, but not limited to, emissions from stationary equipment, mobile combustion, and process emissions and fugitive emissions);
- Scope 2 emissions were defined as indirect GHG emissions that resulted from 7G’s consumption of energy in the form of purchased electricity; and
- Scope 3 emissions were defined as 7G’s indirect emissions other than those covered in Scope 2, including from all sources not owned or controlled by 7G, but which occurred as a result of 7G’s activities.
Notably, 7G’s drilling and completion activities in the relevant periods were conducted by third parties and, consequently, those activities were deemed to be Scope 3.
7G retained Brightspot Climate Inc. to support the quantification of its 2018 GHG emissions. Emissions for all facilities were quantified in accordance with the methodologies specified in Alberta’s Carbon Competitiveness Incentive Regulation (CCIR) and Specified Gas Reporting Regulation (SGRR), and Environment and Climate Change Canada’s Greenhouse Gas Emissions Reporting Program, as applicable. Measured quantities, such as fuel volume, fuel carbon content, flare volumes, venting volumes, fugitive volumes, and electricity consumption were used, where metered data was available. Emission factors from published government sources were applied to the calculations. A third party verification was conducted by Millennium EMS Solutions. This verification was completed in accordance with the ISO 14064:3 standard and the requirements of CCIR.
References to “free cash flow” are referring to any adjusted funds flow that is in excess of total capital expenditures during a particular period of time.
The lower Montney well production that is described in this news release is from a well drilled in the Nest 2 area. The results have been obtained during a 30 day initial flow period (includes completions flowback and flow through permanent facilities). The average gas production rate observed to date is 2,732 Mcf/d and the average condensate production rate observed to date is 782 bbl/d. Cumulative gas production has been 82 MMcf, cumulative condensate production has been 23,445 bbls and cumulative produced water has been 45,536 bbls. Gas, condensate, and water rates ramped up over a period of 10 days. Gas maintained a plateau rate of about 3,300 Mcf/d while condensate gradually declined as expected. Tubing pressure reached a maximum of 17,000 KPa (2,460 psi) after 5 days of flow and gradually decreased to about 10,000 KPa (1,450 psi), consistent with a relatively high liquid/gas ratio of about 840 bbl/MMcf. No pressure transient analysis or well-test interpretation has been carried out to date.
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 60 day initial flow period (includes completions flowback and flow through permanent facilities). The average gas production rate observed to date is 3,136 Mcf/d and the average condensate production rate observed to date is 1,375 bbl/d. Cumulative gas production has been 188 MMcf, cumulative condensate production has been 82,505 bbls and cumulative produced water has been 59,082 bbls. Gas, condensate, and water rates ramped up over a period of 12 days. Gas maintained a plateau rate of about 4,100 Mcf/d) while condensate gradually declined as expected. Tubing pressure reached a maximum of 9,300 KPa (1,350 psi) after 5 days of flow and gradually decreased to about 3,500 KPa (510 psi), consistent with a relatively high liquid/gas ratio of about 750 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 and Drilling Locations
Estimates of the company’s reserves and contingent resources, as at December 31, 2018, are based upon the reports prepared by McDaniel & Associates Consultants Ltd. (McDaniel), dated February 27, 2019 (the McDaniel Reports). Estimates of reserves and contingent resources 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 and the differences may be material. 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. 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 conducted by McDaniel, please refer to the AIF, which is available on SEDAR.
For the purposes of estimating potential drilling locations or drilling opportunities in the Nest 1 area, the company has assumed well spacing of 12 wells per section and a lateral well lengths of 2,310 metres based upon industry practice and internal review. The anticipated well spacing and lateral well length is expected to change over time as technology and the company’s understanding of the reservoir changes. Of the 480 potential drilling locations or drilling opportunities estimated to be contained within the company’s Nest 1 area, as at December 31, 2018, 64% were attributed proved plus probable reserves and 36% were attributed best estimate contingent resources in the McDaniel Reports. There is no certainty that the company will drill all of the identified drilling opportunities or drilling locations and there is no certainty that such locations will result in additional reserves, resources or production. The drilling locations on which the company will actually drill wells, including the number and timing thereof will be dependent upon the availability of funding, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained, and other factors. While certain of the estimated undeveloped drilling locations have been de-risked by wells drilled in relative close proximity to such locations, some of the locations are further away from existing wells and management has less information about the characteristics of the reservoir in such locations and there is more uncertainty regarding such locations.
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.
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.
|AECO||physical storage and trading hub for natural gas on the TransCanada Alberta transmission system|
|bbl or bbls||barrel or barrels|
|boe||barrels of oil equivalent|
CO 2 e
carbon dioxide equivalent
the Canadian Oil and Gas Evaluation Handbook maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter), as amended from time to time.
|CROIC||cash return on invested capital|
|C*||the drilling and completion cost allowance under Alberta’s Modernized Royalty Framework|
|D&C||drilling and completions|
|G&A||general and administrative expenses|
|H1||first half of the year|
|H2||second half of the year|
International Financial Reporting Standards
|LNG||liquefied natural gas|
|mboe||thousand barrels of oil equivalent|
|mbbl||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 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|
|NGL or NGLs||natural gas liquids|
|nm||not meaningful information|
|psi||pounds per square inch|
|ROCE||return on capital employed|
the System for Electronic Document Analysis and Retrieval maintained by the Canadian Securities Administrators available at www.sedar.com.
|TSX||Toronto Stock Exchange|
|US$||United States dollars|
|WTI||West Texas Intermediate|
Seven Generations Energy Ltd. is also referred to as Seven Generations, Seven Generations Energy, 7G, we, our, the Company and the company.