CALGARY, Alberta, Nov. 11, 2020 (GLOBE NEWSWIRE) — (PIPE – TSX-V) Pipestone Energy Corp. (“Pipestone Energy” or the “Company”) is pleased to report its Q3 2020 financial and operational results, as well as provide an update to its development program and corporate guidance for 2021.
“I am extremely proud of the efforts of our team as we continue to safely navigate the global pandemic and its impact on oil prices,” said Paul Wanklyn, President and CEO. “The recently completed financing was an important step in enabling Pipestone Energy to resume its growth in production and cashflow in order to achieve critical mass. We have modified our capital spending profile to reflect some of the continued challenges our industry faces but we retain significant flexibility to accelerate our development pace in response to higher future commodity prices. The revised plan will continue to generate top-decile growth in both production and cashflow, while delivering strong full cycle returns on capital invested. Starting in 2022, Pipestone Energy is positioned to generate material free cash flow annually in excess of forecast maintenance and growth capital.”
THIRD QUARTER 2020 CORPORATE HIGHLIGHTS
- In September 2020 the Company successfully closed its convertible preferred share financing which provided net proceeds of $66.9 million, after all related transaction costs. The proceeds were used to immediately pay down existing bank debt and create additional available liquidity that will fund the Company’s development program;
- Production averaged 13,701 boe/d (comprised of 31% condensate and 48% total liquids) for the three months ended September 30, 2020, despite an unplanned third-party processing facility outage at the Keyera Wapiti Plant which spanned 38 days from August 17th to September 24th;
- As a result of modestly improved commodity pricing from Q2 2020, the Company generated revenue and adjusted funds flow of $31.7 million and $6.4 million, respectively, during the three months ended September 30, 2020. Adjusted funds flow does not include any accrual for the business interruption insurance claim filed by the Company in relation to the 38-day unplanned outage at the Keyera Wapiti gas plant; and
- During September 2020 the Company re-started its drilling program with 2 wells drilled and rig-released from the 3-12 pad. In the first week of October 2020 the Company rig-released 2 additional wells from the 3-12 pad that were in progress at September 30, 2020. Total drilling expenditures were $7.1 million for the quarter.
Pipestone Energy Corp. – Financial and Operating Highlights
|Three months ended September 30,
||Nine months ended September 30,
|($ thousands, except per unit and per share amounts)||2020||2019||2020||2019|
|Sales of liquids and natural gas||$||31,700||$||7,808||$||90,097||$||13,725|
|Cash from (used in) operating activities||660||(6,626||)||31,552||(20,188||)|
|Adjusted funds flow from (used in) operations (1)||6,359||(2,734||)||29,410||(13,820||)|
|Per share, basic (2)||0.03||(0.01||)||0.15||(0.07||)|
|Per share, basic and diluted (2)||(0.06||)||(0.01||)||(0.08||)||(0.00||)|
|Working capital (deficit) surplus (end of period)||(25,478||)||20,893|
|Bank debt (end of period)||120,477||156,983|
|Net debt (end of period) (1)||136,411||144,326|
|Shareholders’ equity (end of period)||356,355||382,687|
|Available funding (end of period) (1)||$||87,692||$||32,655|
|Annualized cash return on invested capital (CROIC) (%) (1)||6.2||%||NMN (5)||7.9||%||NMN (5)|
|Annualized return on capital employed
(ROCE) (%) (1)
|(1.3||%)||NMN (5)||0.0||%||NMN (5)|
|Shares outstanding (end of period) (2)||190,572||189,627|
|Weighted-average basic shares outstanding (2)||190,468||189,627||190,150||187,949|
|Weighted-average diluted shares outstanding (2)||190,468||189,627||190,150||187,949|
|Crude oil (bbls/d)||126||96||106||69|
|Other natural gas liquids (NGL) (bbls/d)||2,196||139||1,923||82|
|Total NGL (bbls/d)||6,461||1,155||6,257||613|
|Natural gas (Mcf/d)||42,683||7,298||50,876||4,011|
|Total (boe/d) (3)||13,701||2,467||14,842||1,351|
|Condensate and crude oil (% of total production)||32||%||45||%||30||%||44||%|
|Total liquids (% of total production)||48||%||51||%||43||%||50||%|
|Crude oil – WTI (C$/bbl)||$||54.48||$||74.52||$||51.39||$||75.82|
|Condensate – Edmonton Condensate (C$/bbl)||51.74||68.24||47.81||70.21|
|Natural gas – AECO 5A (C$/GJ)||2.15||0.96||1.99||1.49|
|Average realized prices (4)|
|Crude oil (per bbl)||44.94||61.87||35.66||55.07|
|Condensate (per bbl)||48.24||65.51||42.67||67.83|
|Other NGL (per bbl)||16.41||12.57||14.57||19.47|
|Total NGL (per bbl)||37.42||59.11||34.03||61.38|
|Natural gas (per Mcf)||2.28||1.46||2.20-||2.21|
|Revenue (per boe)||25.15||34.40||22.15||37.21|
|Royalties (per boe)||(0.87||)||(1.85||)||(0.53||)||(1.95||)|
|Operating expenses (per boe)||(10.26||)||(15.29||)||(10.77||)||(15.27||)|
|Transportation (per boe)||(3.80||)||(5.65||)||(3.57||)||(7.26||)|
|Operating netback (per boe) (1)||10.22||11.61||7.28||12.73|
|Adjusted funds flow netback (per boe) (1)||$||5.05||$||(12.04||)||$||7.23||$||(37.48||)|
|1)||See “Advisories Regarding Non-GAAP Measures” section of the MD&A dated November 11, 2020 and within this press release for further details.|
|2)||The number of common shares has been adjusted retrospectively to reflect the 10:1 share consolidation, as well as the 0.5996 exchange ratio, as part of the Corporate Acquisition that closed on January 4, 2019.|
|3)||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 liquids include oil and natural gas liquids (including condensate, butane and propane).|
|4)||Figures calculated before hedging.|
|5)||NMN – not meaningful number at this time as Pipestone Energy had minimal production throughout the majority of 2019.|
|6)||Prior period production and average realized price figures have been adjusted to conform with current period presentation.|
UPDATED THREE-YEAR DEVELOPMENT PLAN (1)
Pipestone Energy has modified its three-year development plan to reflect a moderated growth profile in 2022 and 2023. This program is expected to generate free cash flow starting in 2022, while realizing positive returns on capital employed and continuing to organically grow production. The revised outlook includes a substantially smaller outspend of cash flow in 2021 and lower peak draws against the Company’s $225 million reserve based loan (“RBL”) than previously forecast, in addition to significant net debt reduction through 2022 and 2023.
|Full Year Production (boe/d)||24,000 – 26,000||33,000 – 35,000||37,000 – 40,000|
|Cash Flow (C$ million) (2)(3)||$120 – $130||$195||$220|
|Capex (C$ million) (4)||$145 – $155||$160||$165|
|Free Cash Flow(3)||($25)||$35||$55|
|YE Net Debt (C$ million) (3)||$200||$165||$110|
|YE RBL Draw (C$ million)||$175||$145||$90|
|LTM Debt / CF (x)||1.6x||0.8x||0.5x|
|1)||3-year plan as at November 2020, 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 and as a result forecast results for 2022 and 2023 may change materially. Where a range is not provided, guidance and forecast values represent the mid-point estimate.|
|2)||Price assumptions: 2021 = US$42 WTI; $2.50 AECO; $0.75 CAD | 2022+ = US$44 WTI; $2.50 AECO; $0.75 CAD.|
|3)||See “Advisories Regarding non-GAAP Measures”. Net debt excludes convertible preferred shares as there is no cash settled liability and includes adjusted working capital deficit.|
|4)||Capex includes all anticipated DCE&T, infrastructure and other capital expenditures, but excludes capitalized G&A.|
2021 Capital Program and Guidance
In 2021, Pipestone Energy will execute a continuous one-rig drilling program focused on development along the North-South gathering system. The Company expects to drill 23 and complete 21 new wells next year, with total forecast capital spending of $145 – $155 million (reduced from $210 million forecast previously), approximately 90% of which will be on drilling, completion, and equip & tie-in costs (“DCE&T”). Based on results achieved to date, the forecast average DCE&T cost per well in 2021 has been reduced from $6.0 million per well to $5.7 million, reflecting continued strong capital cost performance, including the average cost of $5.3 million per well on the recent 6-30 pad.
An estimated 27 new wells will be brought on production in 2021, including 6 wells from the in-progress 3-12 pad (completion in Q4 2020) and 3 wells from the 8-15 pad, which is currently drilling. Pipestone Energy’s production guidance range for 2021 remains unchanged at 24,000 – 26,000 boe/d. Given its concentrated asset base, existing multi-well pads, and in-field infrastructure, Pipestone Energy maintains the optionality to accelerate its development activity in response to an improving macro environment.
Drilling & Completions
Pipestone Energy commenced drilling 6 wells on the 3-12 pad in early September, with the final well rig released in mid-October. This pad demonstrates continued operational success, achieving a pacesetter average spud to rig release time of 14 days and average cost to drill was ~$1.9 million per well. The 6 wells averaged 2,650 meters in lateral length and were approximately 10% under budget. The 3-12 pad will be completed during November 2020, with equipping activities to proceed shortly thereafter and is expected to be on-stream in early January 2021.
During October, the Company began drilling the first of 3 wells on the 8-15 pad, which have an average lateral length of ~3,000 metres. These wells are expected to be completed in early January 2021 and are targeted to be on-stream in March 2021. Once drilling is complete at 8-15, Pipestone Energy expects to finish drilling 1 well (of 6) on an additional pad prior to year end.
Production & Well Results
During the third quarter, average third-party plant run-times for the Company were adversely impacted by the extended 38-day outage at the Keyera Wapiti gas plant during August and September. Since resuming processing in the final week of September, the Keyera Wapiti gas plant runtime has been greater than 95%. In early October, the compression capacity at 8-15 was increased from 60 MMcf/d to 90 MMcf/d of raw gas in order to handle growing production volumes through 2021. Based on field estimates, October 2020 production averaged approximately 18,000 boe/d (46% liquids, including 34% condensate).
During Q3 2020, Pipestone Energy intermittently brought 6 new wells from its 6-30 pad on-stream. Thus far, 5 wells on the pad have reached an IP30, with average condensate production over that period of ~519 bbl/d and raw gas production of ~2.3 MMcf/d, resulting in an average CGR of 225 bbl/MMcf. The 6-24 pad has now achieved an IP90 on all 6 new wells, with average condensate production over that period of ~558 bbl/d and raw gas production of ~3.4 MMcf/d, resulting in an average CGR of 164 bbl/MMcf.
Pipestone Energy remains committed to focusing on minimizing its emissions from operations through state-of-the-art facilities design. This includes the use of in-field fuel gas to partially displace diesel on drilling rigs and frac fleets. Pipestone Energy’s pad-sites are also designed for zero flaring during normal operating conditions. The Company expects to release its inaugural ESG report during 2021.
RISK MANAGEMENT UPDATE
Pipestone Energy continues to implement its robust commodity price hedging program to reduce volatility in expected future cash flows. Currently for full year 2021, the Company has ~41,750 GJ/d of AECO natural gas hedged at a weighted-average price of ~C$2.35/GJ, and 5,000 GJ/d for full year 2022 at ~C$2.49/GJ. Additionally, ~2,750 bbl/d of Canadian Dollar WTI is hedged at a weighed-average price of ~C$57/bbl. With the recent strengthening in Edmonton condensate pricing relative to WTI, Pipestone Energy has swapped 3,000 bbl/d of differentials in Q1 2021 at a net premium of ~US$0.17/bbl.
Q3 2020 Conference Call
A conference call has been scheduled for November 11th, 2020 at 9:00 a.m. Mountain Daylight Time (11:00 a.m. Eastern Daylight Time) for interested investors, analysts, brokers, and media representatives.
Conference Call Details:
Toll-Free: (866) 953-0776
International: (630) 652-5852
Conference ID: 4555285
An archived recording of the conference call will be available shortly after the event and will be available until November 18, 2020. To access the replay please dial toll free in North America (855) 859-2056 or International (404) 537-3406 and enter 4555285 when prompted.
Pipestone Energy Corp.
Pipestone Energy Corp. is an oil and gas exploration and production company with its head office located in Calgary, Alberta. The company is focused on developing its pure-play condensate-rich Montney asset in the Pipestone area near Grande Prairie. Pipestone Energy is committed to building long term value for our shareholders and values the partnerships that it is developing within its operating community. Pipestone Energy shares trade under the symbol PIPE on the TSX Venture Exchange. 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”, “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.
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
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.
Operating netback and Adjusted funds flow netback
Operating netback is calculated on a per-unit-of-production basis and is determined by deducting royalties, operating and transportation expenses from liquids and natural gas sales.
Adjusted funds flow netback reflects adjusted funds flow 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 financial derivative instruments on a per-unit-of-production basis from the operating netback.
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.
“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.
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 financial derivative instruments 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, depreciation and amortization, adjusted for certain non-cash and extraordinary items primarily relating to unrealized gains and losses on financial instruments. 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: growth of production volumes and cashflow; full cycle returns on invested capital; strategic plans and growth strategies; our expected development activity summary and three-year corporate growth trajectory, including expectations for number of wells to be drilled, completed and on production and three-year production growth, cash flow, capex, net debt, YE RBL draw, and LTM debt / cash flow; locations of wells to be developed; expectations to generate free cash flow and positive returns on capital; reduced outspend of cash flow and lower peak net debt, in addition to net debt reduction; total forecast capital spending for drilling program and the average DCE&T cost per well; expected completion and production date for 6 wells at Pipestone’s pad 3-12 and 3 wells at pad 8-15, with 27 wells being brought on production in 2021; on-stream dates for pads 3-12 and 8-15; production guidance range for 2021 to 2023; the optionality to accelerate development activity; completion and on-stream dates for pad 3-12; and the release of the Corporation’s ESG report.
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 and current oversupply of oil caused by OPEC; 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 November 11, 2020 and in Pipestone Energy’s annual information form dated March 17, 2020, 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. IP30, 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.
This document contains certain other oil and gas metrics, including DCE&T (drilling, completion, equip and tie-in costs), 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 measures to evaluate the Company’s performance; however, such measures are not reliable indicators of the future performance and future performance may not compare to the performance in previous periods and therefore such metrics should not be unduly relied upon. DCE&T includes all capital spent to drill, complete, equip and tie-in a well.
References herein to “CGR” mean condensate/gas ratio and is expressed as a volume of condensate and NGLs (expressed in barrels) per million cubic feet (mmcf) of natural gas.
TSX Venture Exchange Disclaimer
Neither TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.
A photo accompanying this announcement is available at https://www.globenewswire.com/NewsRoom/AttachmentNg/b1e86481-6323-472e-82a3-299b11e20eb6