CALGARY, Alberta – (PIPE – TSX) — Pipestone Energy Corp. (“Pipestone” or the “Company”) is pleased to report its Q2 2021 financial and operational results, as well as provide an update on its operations.
During Q2 2021, Pipestone delivered record quarterly production and cash flow, underpinned by the continued efficient execution of its organic development program. The Company remains on track to generate free cash flow beginning in Q4 2021, with forecast annual free cash flow of $95 million in 2022 and $190 million in 2023 (US$65 WTI | C$2.50 AECO).
SECOND QUARTER 2021 CORPORATE HIGHLIGHTS:
- Record average quarterly production of 23,336 boe/d (31% condensate, 46% total liquids), an 8% quarterly increase over Q1 2021 and a 39% increase over Q2 2020. The record production was achieved despite processing curtailments due to high ambient temperatures experienced in Alberta during late June;
- Improvement in operating netback to a corporate record of $19.60/boe, an increase of 12% over Q1 2021 and an 88% increase over Q2 2020;
- The Company generated record revenue of $82.3 million and record adjusted funds flow from operations of $35.5 million ($0.19 per share basic and $0.13 per share fully diluted);
- The Company continued the effective execution of its 2021 capital program with 8 wells drilled and rig-released and 6 wells completed during the second quarter of 2021. Total capital expenditures, including capitalized G&A, were $47.6 million during the three months ended June 30, 2021; and
- The Company generated strong returns on invested capital, with Q2 2021 annualized ROCE and CROIC of 14.1% and 18.9%, respectively, as compared to a Q2 2020 annualized ROCE and CROIC of (0.5%) and 8.6%, respectively.
As a result of continued efficiencies with its drilling program, the Company plans to accelerate $10 million of completion and tie-in capital from early 2022 to Q4 2021. Pipestone’s revised 2021 capital guidance is now $170 – $175 million (up from $155 – $165 million), with its 2022 forecast capital spending reduced to $185 million (down from $195 million). The incremental 2021 capital will be spent completing and equipping 3 additional wells on the 6-13 pad.
With material free cash flow generation forecast to begin in Q4 2021, Pipestone will initially prioritize the repayment of debt, with a target of less than 0.5x debt to cash flow prior to the end of 2022. The Company also believes its common shares are trading at a significant discount to their intrinsic value. As such, the Company plans to implement a normal course issuer bid in Q4 2021, concurrent with the transition to free cash flow generation. In addition, the Pipestone board is assessing all options to maximize shareholder returns through potential uses for future free cash flow, which could include additional share buyback programs, a future dividend, as well as investment in further growth or potential acquisitions.
|Three months ended June 30,
||Six months ended June 30,
|($ thousands, except per unit and per share amounts)||2021||2020||2021||2020|
|Sales of liquids and natural gas||$||82,319||$||26,380||$||153,804||$||58,397|
|Cash from (used in) operating activities||33,732||(175||)||51,829||30,892|
|Adjusted funds flow from operations (1)||35,498||11,231||63,740||23,051|
|Per share, basic||0.19||0.06||0.33||0.12|
|Per share, diluted (4)||0.13||0.06||0.23||0.12|
|Per share, basic and diluted||(0.01||)||(0.10||)||(0.01||)||(0.02||)|
|Adjusted working capital deficit (end of period) (1)||$||(23,912||)||$||(13,435||)|
|Bank debt (end of period)||184,115||183,248|
|Net debt (end of period) (1)||208,027||196,683|
|Undrawn credit facility capacity (end of period)||40,498||26,856|
|Available funding (end of period) (1)||16,586||13,421|
|Shareholders’ equity (end of period)||354,639||367,298|
|Annualized cash return on invested capital (CROIC) (1)||18.9||%||8.6||%||17.1||%||8.9||%|
|Annualized return on capital employed (ROCE) (1)||14.1||%||(0.5||%)||12.3||%||0.7||%|
|Shares outstanding (end of period)||191,548||190,295|
|Weighted-average basic shares outstanding||191,466||190,136||191,180||189,990|
|Weighted-average diluted shares outstanding (4)||278,668||190,253||278,247||190,229|
|Other natural gas liquids (NGLs) (bbls/d)||3,211||2,306||2,980||1,786|
|Total NGLs (bbls/d)||10,556||7,087||10,155||6,154|
|Crude oil (bbls/d)||83||104||87||95|
|Natural gas (Mcf/d)||76,180||57,488||73,369||55,017|
|Total (boe/d) (2)||23,336||16,772||22,470||15,419|
|Condensate and crude oil (% of total production)||32||%||29||%||33||%||29||%|
|Total liquids (% of total production)||46||%||43||%||46||%||41||%|
|Crude oil – WTI (C$/bbl)||$||81.04||$||38.34||$||77.13||$||49.84|
|Condensate – Edmonton Condensate (C$/bbl)||79.47||31.38||77.03||45.75|
|Natural gas – AECO 5A (C$/GJ)||2.91||1.90||2.93||1.91|
|Average realized prices (3)|
|Condensate (per bbl)||76.56||29.21||70.96||39.92|
|Other NGLs (per bbl)||26.32||10.92||26.54||13.42|
|Total NGLs (per bbl)||61.27||23.26||57.93||32.23|
|Crude oil (per bbl)||68.79||19.88||63.97||29.49|
|Natural gas (per Mcf)||3.31||2.14||3.49||2.18|
|Revenue (per boe)||38.76||17.28||37.82||20.81|
|Realized (loss) gain on commodity risk|
|management contracts (per boe) (5)||(5.09||)||6.85||(4.72||)||5.92|
|Royalties (per boe)||(0.24||)||0.28||(0.92||)||(0.37||)|
|Operating expenses (per boe)||(11.11||)||(10.64||)||(10.89||)||(11.00||)|
|Transportation (per boe)||(2.72||)||(3.32||)||(2.67||)||(3.47|
|Operating netback (per boe) (1) (5)||19.60||10.45||18.62||11.89|
|Adjusted funds flow netback (per boe) (1)||$||16.72||$||7.37||$||15.67||$||8.22|
|(1)||See “Non-GAAP measures” included in the Advisories of this press release.|
|(2)||For a description of the boe conversion ratio, see “Basis of Barrel of Oil Equivalent”. References to crude oil in production amounts are to the product type “tight oil” and references to natural gas in production amounts are to the product type “shale gas”. References to total liquids include oil and natural gas liquids (including condensate, butane and propane).|
|(3)||Figures calculated before hedging.|
|(4)||Weighted-average number of diluted shares outstanding for the purpose of calculating diluted adjusted funds flow from operations per share in the 2021 periods presented includes 86,667,329 common shares that are issuable at the discretion of preferred shareholders as of June 30, 2021 for no additional proceeds to the Company. The preferred shares have a total convertible value of $73.7 million at June 30, 2021 and are convertible at $0.85 per common share. The impact of other dilutive instruments is also factored into this calculation.|
|(5)||Realized (loss) gain on commodity risk management contracts reclassified to be included under operating netback for 2021, prior period figures have been adjusted to conform with current presentation.|
UPDATED 2021 GUIDANCE & 3-YEAR FORECAST(1)
The Company now expects to drill 26 and complete 24 new wells this year, with total capital spending of $170 – $175 million (increased from $155 – $165 million guidance previously). An estimated 15 new wells will be brought on production during H2 2021. Pipestone Energy’s production guidance range for 2021 remains unchanged at 24,000 – 26,000 boe/d as the additional completions will be performed late in 2021.
In addition, the Company has refined its 2021 Guidance and 2022 and 2023 Outlook in the table below to reflect an improvement in expected commodity prices.
|Price Forecast||US$65 WTI | $3.00 AECO | $0.80 CAD||US$65 WTI | $2.50 AECO | $0.80 CAD||US$65 WTI | $2.50 AECO | $0.80 CAD|
|Full Year Production (boe/d)||24,000 – 26,000||33,000 – 36,000||37,000 – 40,000|
|Cash Flow (C$ million) (2)||$160 – $170||$280||$320|
|Capex (C$ million) (3)||$170 – $175||$185||$130|
|Free Cash Flow (C$ million) (2)||($13)||$95||$190|
|Reinvestment Rate (4)||104%||66%||41%|
|YE Net Debt (C$ million) (2)||$183||$88||+$102 net cash|
|LTM Debt / Cash Flow (x)||1.1x||0.3x||0.0x|
|1)||3-year plan as at August 2021, derived by utilizing, among other assumptions, historical Pipestone Energy production performance and current capital and operating cost assumptions held flat for illustration only. Budgets and forecasts beyond 2021 have not been finalized and are subject to a variety of factors, thus forecast results for 2022 and 2023 may change materially. Where a range is not provided, guidance and forecast values represent the mid-point estimate. 2021 production guidance incorporates currently known planned midstream outages.|
|2)||See “Advisory Regarding Non-GAAP Measures”. Net debt excludes convertible preferred shares as there is no cash settled liability and includes adjusted working capital deficit.|
|3)||Capex includes all anticipated DCE&T, infrastructure and other capital expenditures, but excludes capitalized G&A.|
|4)||Reinvestment Rate is calculated as Capex divided by Cash Flow for each given year. For 2021, the mid-point estimates were used.|
PIPESTONE DEVELOPMENT MAP:
RECENT OPERATIONS HIGHLIGHTS:
- Sustained Production Growth: During July 2021, a planned 10-day outage at the 3rd party Wapiti gas processing facility was successfully completed to permanently address the cause of an unscheduled outage that occurred during Q3 2020. Based on field estimates, month-to-date August 2021 production averaged approximately 27,000 boe/d, including all 6 wells from the 15-25 pad now on-stream, keeping us well on-track to achieve our 2021 annual production guidance. In addition to the 15-25 pad, the Company expects to bring 9 additional wells on production after August 2021, which includes six wells from the 6-24 pad and three wells from the 14-4 pad.
- Successful Infrastructure Expansion: All necessary regulatory permits required for the new 12” gathering pipeline from Pipestone’s 6-30 pad to Veresen Midstream’s 16-28 battery and compressor station are in place and construction commenced in early August. Additionally, installation of the production handling and water disposal facilities on the 6-30 pad began earlier in Q3 2021. Everything remains on-track for a Q4 2021 start-up. As previously disclosed, these facilities will add an additional 50 MMcf/d (25 MMcf/d firm + 25 MMcf/d IT) plus associated liquids of processing capacity for Pipestone;
- Strong Well Results: The three new wells on the condensate-rich 6-13 pad, including one Lower Montney well, achieved an average per well IP60 of 536 bbl/d wellhead condensate and 2.8 MMcf/d raw gas (condensate gas ratio, or “CGR”, of 191 bbl/MMcf), which is in-line with type curve expectations. The three well 8-15 pad has achieved an average per well IP90 of 662 bbl/d wellhead condensate and 3.6 MMcf/d raw gas (CGR of 184 bbl/MMcf). The six well 3-12 pad has achieved an IP180 of 405 bbl/d wellhead condensate and 4.3 MMcf/d raw gas (CGR of 94 bbl/MMcf). Preliminary results from the 15-25 pad are demonstrating strong deliverability, with more details to be provided once longer-term production data is available.
Second Quarter 2021 Conference Call
A conference call has been scheduled for August 11th, 2021 at 9:00 a.m. Mountain Daylight Time (11:00 a.m. Eastern Daylight Time) to update interested investors, analysts, brokers, and media representatives on the Company’s operations and Q2 2021 highlights.
Conference Call Details:
Toll-Free: (866) 953-0776
International: (630) 652-5852
Conference ID: 9086924
An archived recording of the conference call will be available shortly after the event and will be available until August 18th, 2021. To access the replay please dial toll free in North America (855) 859-2056 or International (404) 537-3406 and enter 9086924 when prompted.
Pipestone Energy Corp.
Pipestone Energy is an oil and gas exploration and production company focused on developing its large contiguous and condensate-rich Montney asset base in the Pipestone area near Grande Prairie. Pipestone Energy is fully funded to grow its production from 15.6 Mboe/d in 2020 to 35 Mboe/d (midpoint) in 2022, while maintaining a conservative leverage profile. Beginning in 2022, the Company expects to generate annual free cash flow above growth and maintenance expenditures. Pipestone Energy is committed to building long term value for our shareholders while maintaining the highest possible environmental and operating standards, as well as being an active and contributing member to the communities in which it operates. Pipestone Energy shares trade under the symbol PIPE on the TSX. For more information, visit www.pipestonecorp.com.
Pipestone Energy Contacts:
President and Chief Executive Officer
Chief Financial Officer
|Dan van Kessel
VP Corporate Development
Advisory Regarding Non-GAAP Measures
This press release includes references to financial measures commonly used in the oil and natural gas industry. The terms “adjusted funds flow from operations”, “cash flow”, “free cash flow, “operating netback”, “adjusted funds flow netback”, “net debt”, “available funding”, “CROIC”, and “ROCE” are not defined under IFRS, which have been incorporated into Canadian GAAP, as set out in Part 1 of the Chartered Professional Accountants Canada Handbook – Accounting, are not separately defined under GAAP, and may not be comparable with similar measures presented by other companies. The reconciliations of these non-GAAP measures to the nearest GAAP measure are discussed in the MD&A dated August 11, 2021, a copy of which is available electronically on Pipestone Energy’s SEDAR at www.sedar.com.
Management believes the presentation of the non-GAAP measures provide useful information to investors and shareholders as the measures provide increased transparency and the opportunity to better analyze and compare performance against prior periods.
Adjusted funds flow from operations
Pipestone Energy uses “adjusted funds flow from operations” (cash from operating activities before changes in non-cash working capital and decommissioning provision costs incurred), a measure that is not defined under IFRS. Adjusted funds flow from operations should not be considered an alternative to, or more meaningful than, cash from operating activities, income (loss) or other measures determined in accordance with IFRS as an indicator of the Company’s performance. Management uses adjusted funds flow from operations to analyze operating performance and leverage and believes it is a useful supplemental measure as it provides an indication of the funds generated by Pipestone Energy’s principal business activities prior to consideration of changes in working capital.
“Cash flow” is a non-GAAP measure that is calculated as cash from operating activities plus changes in non-cash working capital and decommissioning provision costs incurred, and is not defined under IFRS. Cash flow should not be considered an alternative to, or more meaningful than, cash from operating activities, income (loss) or other measures determined in accordance with IFRS as an indicator of the Company’s performance. Management uses cash flow to analyze operating performance and leverage and believes it is a useful supplemental measure as it provides an indication of the funds generated by Pipestone Energy’s principal business activities prior to consideration of changes in working capital.
Free cash flow
“Free cash flow” is a non-GAAP measure that is calculated as cash from operating activities plus changes in non-cash working capital and decommissioning provision costs incurred, less capital expenditures incurred, and is not defined under IFRS. Free cash flow should not be considered an alternative to, or more meaningful than, cash from operating activities, income (loss) or other measures determined in accordance with IFRS as an indicator of the Company’s performance. Management uses free cash flow to analyze operating performance and leverage and believes it is a useful supplemental measure as it provides an indication of the funds generated by Pipestone Energy’s principal business activities, inclusive of ongoing capital expenditures, prior to consideration of changes in working capital.
Operating netback and Adjusted funds flow netback
Operating netback is calculated on either a total dollar or per-unit-of-production basis and is determined by deducting royalties, operating and transportation expenses from liquids and natural gas sales adjusted for realized gains/losses on commodity risk management contracts.
Adjusted funds flow netback reflects adjusted funds flow from operations on a per-unit-of-production basis and is determined by dividing adjusted funds flow by total production on a per-boe basis. Adjusted funds flow netback can also be determined by deducting G&A, transaction costs, cash financing expenses, adding financing income and adjusting for realized gains/losses on interest rate risk management contracts on a per-unit-of-production basis from the operating netback. Refer to “Financial and Operating Results” section above for further details.
Operating netback and adjusted funds flow netback are common metrics used in the oil and natural gas industry and are used by Company management to measure operating results on a per boe basis to better analyze and compare performance against prior periods, as well as formulate comparisons against peers.
Net debt is a non-GAAP measure that equals bank debt outstanding plus adjusted working capital. The Company does not consider its convertible preferred share obligation to be part of net debt as this represents a non-cash obligation that will ultimately be settled by conversion into Pipestone Energy common shares and reclassified from a liability to share capital on the Company’s statement of financial position. Net debt is considered to be a useful measure in assisting management and investors to evaluate Pipestone Energy’s financial strength.
Available funding and Adjusted working capital
Available funding is comprised of adjusted working capital and undrawn portions of the Company’s Credit Facility. Adjusted working capital is comprised of current assets less current liabilities on the Company’s consolidated statement of financial position and excludes the current portion of risk management contracts and lease liabilities. The available funding measure allows management and others to evaluate the Company’s short-term liquidity.
CROIC and ROCE
Adjusted EBITDA is calculated as profit or loss before interest, income taxes, depletion and depreciation, adjusted for certain non-cash and extraordinary items primarily relating to unrealized gains and losses on risk management contracts. Adjusted EBITDA is used to calculate CROIC. Adjusted EBIT is calculated as adjusted EBITDA less depletion and depreciation. Adjusted EBIT is used to calculate ROCE.
CROIC is determined by dividing adjusted EBITDA by the gross carrying value of the Company’s oil and gas assets at a point in time. For the purposes of the CROIC calculation, the net carrying value of the Company’s exploration and evaluation assets, property and equipment and ROU assets, is taken from the Company’s consolidated statement of financial position, and excludes accumulated depletion and depreciation as disclosed in the financial statement notes to determine the gross carrying value.
ROCE is determined by dividing adjusted EBIT by the carrying value of the Company’s net assets. For the purposes for the ROCE calculation, net assets are defined as total assets on the Company’s consolidated statement of financial position less current liabilities at a point in time.
CROIC and ROCE allow management and others to evaluate the Company’s capital spending efficiency and ability to generate profitable returns by measuring profit or loss relative to the capital employed in the business.
Advisory Regarding Forward-Looking Statements
In the interest of providing shareholders of Pipestone Energy and potential investors information regarding Pipestone Energy, this news release contains certain information and statements (“forward-looking statements”) that constitute forward-looking information within the meaning of applicable Canadian securities laws. Forward-looking statements relate to future results or events, are based upon internal plans, intentions, expectations and beliefs, and are subject to risks and uncertainties that may cause actual results or events to differ materially from those indicated or suggested therein. All statements other than statements of current or historical fact constitute forward-looking statements. Forward-looking statements are typically, but not always, identified by words such as “anticipate”, “estimate”, “expect”, “intend”, “forecast”, “continue”, “propose”, “may”, “will”, “should”, “believe”, “plan”, “target”, “objective”, “project”, “potential” and similar or other expressions indicating or suggesting future results or events.
Forward-looking statements are not promises of future outcomes. There is no assurance that the results or events indicated or suggested by the forward-looking statements, or the plans, intentions, expectations or beliefs contained therein or upon which they are based, are correct or will in fact occur or be realized (or if they do, what benefits Pipestone Energy may derive therefrom).
In particular, but without limiting the foregoing, this news release contains forward-looking statements pertaining to: plans to accelerate completion and tie-in capital; estimated production and increased free cash flow generation; revised 2021 production guidance and outlook; forecasted spending; plans for the repayment of debt; plans regarding a normal course issuer bid; other potential uses of free cash flow; timing for drilling 26 wells and completing 24 wells, and the associated cost; estimated production dates for 15 new wells; plans to bring on-stream six wells from Pipestone Energy’s 6-24 pad and three wells from the 14-4 pad; the connection date of Pipestone Energy’s 6-30 pad to the Veresen Midstream battery and compressor station and the associated increased processing capacity; and plans to complete and equip three additional wells on the 6-13 pad.
With respect to the forward-looking statements contained in this news release, Pipestone Energy has assessed material factors and made assumptions regarding, among other things: future commodity prices and currency exchange rates, including consistency of future oil, natural gas liquids (NGLs) and natural gas prices with current commodity price forecasts; the economic impacts of the COVID-19 pandemic ; the ability to integrate Blackbird’s and Pipestone Oil’s historical businesses and operations and realize financial, operational and other synergies from the combination transaction completed on January 4, 2019; Pipestone Energy’s continued ability to obtain qualified staff and equipment in a timely and cost-efficient manner; the predictability of future results based on past and current experience; the predictability and consistency of the legislative and regulatory regime governing royalties, taxes, environmental matters and oil and gas operations, both provincially and federally; Pipestone Energy’s ability to successfully market its production of oil, NGLs and natural gas; the timing and success of drilling and completion activities (and the extent to which the results thereof meet expectations); Pipestone Energy’s future production levels and amount of future capital investment, and their consistency with Pipestone Energy’s current development plans and budget; future capital expenditure requirements and the sufficiency thereof to achieve Pipestone Energy’s objectives; the successful application of drilling and completion technology and processes; the applicability of new technologies for recovery and production of Pipestone Energy’s reserves and other resources, and their ability to improve capital and operational efficiencies in the future; the recoverability of Pipestone Energy’s reserves and other resources; Pipestone Energy’s ability to economically produce oil and gas from its properties and the timing and cost to do so; the performance of both new and existing wells; future cash flows from production; future sources of funding for Pipestone Energy’s capital program, and its ability to obtain external financing when required and on acceptable terms; future debt levels; geological and engineering estimates in respect of Pipestone Energy’s reserves and other resources; the accuracy of geological and geophysical data and the interpretation thereof; the geography of the areas in which Pipestone Energy conducts exploration and development activities; the timely receipt of required regulatory approvals; the access, economic, regulatory and physical limitations to which Pipestone Energy may be subject from time to time; and the impact of industry competition.
The forward-looking statements contained herein reflect management’s current views, but the assessments and assumptions upon which they are based may prove to be incorrect. Although Pipestone Energy believes that its underlying assessments and assumptions are reasonable based on currently available information, undue reliance should not be placed on forward-looking statements, which are inherently uncertain, depend upon the accuracy of such assessments and assumptions, and are subject to known and unknown risks, uncertainties and other factors, both general and specific, many of which are beyond Pipestone Energy’s control, that may cause actual results or events to differ materially from those indicated or suggested in the forward-looking statements. Such risks and uncertainties include, but are not limited to, volatility in market prices and demand for oil, NGLs and natural gas and hedging activities related thereto; the ability to successfully integrate Blackbird’s and Pipestone Oil’s historical businesses and operations; general economic, business and industry conditions; variance of Pipestone Energy’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; and risks related to the exploration, development and production of oil and natural gas reserves and resources. Additional risks, uncertainties and other factors are discussed in the MD&A dated August 11, 2021 and in Pipestone Energy’s annual information form dated March 10, 2021, copies of which are available electronically on Pipestone Energy’s SEDAR at www.sedar.com.
Certain information in this news release is “financial outlook” within the meaning of applicable securities laws. The purpose of this financial outlook is to provide readers with disclosure of the company’s reasonable expectations of our anticipate results. The financial outlook is provided as of the date of this news release. Readers are cautioned that this financial outlook may not be appropriate for other purposes. The forward-looking statements contained in this news release are made as of the date hereof and Pipestone Energy assumes no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, unless required by applicable securities laws. All forward-looking statements herein are expressly qualified by this advisory.
Initial Production Rates and Short-Term Test Rates
This document may disclose test rates of production for certain wells over short periods of time (i.e. IP90), which are preliminary and not determinative of the rates at which those or any other wells will commence production and thereafter decline. Short-term test rates are not necessarily indicative of long-term well or reservoir performance or of ultimate recovery. Although such rates are useful in confirming the presence of hydrocarbons, they are preliminary in nature, are subject to a high degree of predictive uncertainty as a result of limited data availability and may not be representative of stabilized on-stream production rates.
Production over a longer period will also experience natural decline rates, which can be high in the Montney play and may not be consistent over the longer term with the decline experienced over an initial production period. Initial production or test rates may also include recovered “load” fluids used in well completion stimulation operations. Actual results will differ from those realized during an initial production period or short-term test period, and the difference may be material.
Oil and Gas Measures
Basis of Barrel of Oil Equivalent
Petroleum and natural gas reserves and production volumes are stated as a “barrel of oil equivalent” (boe), derived by converting natural gas to oil equivalency in the ratio of 6,000 cubic feet of gas to one barrel of oil. Readers are cautioned that boe figures may be misleading, particularly if used in isolation. A boe conversion ratio of 6,000 cubic feet of gas to one barrel of oil is based on energy equivalency, which is primarily applicable at the burner tip, and does not represent a value equivalency at the wellhead.
Any references herein to “CGR” mean condensate/gas ratio and is expressed as a volume of condensate (expressed in barrels) per million cubic feet (mmcf) of natural gas.
References to natural gas and condensate production in this press release refer to the shale gas and natural gas liquids (which includes condensate), respectively, product types as defined in National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities. References to liquids include tight oil and natural gas liquids (including condensate, butane and propane).
Disclosure of production on a per boe basis in this press release consists of the constituent product types and their respective quantities as disclosed in the following table:
|Crude Oil (1)
|Natural Gas (2)
|August 2021 MTD
(1) References to crude oil in production amounts are to the product type “tight oil”.
(2) References to natural gas in production amounts are to the product type “shale gas”.
(3) NMN – not meaningful number.