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CALGARY, AB, Nov. 10, 2021 /CNW/ – Storm Resources Ltd. (TSX: SRX)

Storm has also filed its unaudited condensed interim consolidated financial statements as at September 30, 2021 and for the three and nine months then ended along with Management’s Discussion and Analysis (“MD&A”) for the same period.  This information appears on SEDAR at and on Storm’s website at

Selected financial and operating information for the three and nine months ended September 30, 2021 appears below and should be read in conjunction with the related financial statements and MD&A.


Thousands of Cdn$, except volumetric and

Three Months to
Sept. 30, 2021

Three Months to
Sept. 30, 2020

Nine Months to
Sept. 30, 2021

Nine Months to
Sept. 30, 2020

per-share amounts


Revenue from product sales(1)





Funds flow





Per share – basic and diluted ($)





Net income (loss)





Per share – basic and diluted ($)





Cash return on capital employed (“CROCE”)(2)





Return on capital employed (“ROCE”)(2)(4)





Capital expenditures





Debt including working capital deficiency(2)(3)





Common shares (000s)

Weighted average – basic





Weighted average – diluted





Outstanding end of period – basic






(Cdn$ per Boe)

Revenue from product sales(1)





Transportation costs





Revenue net of transportation










Production costs





Field operating netback(2)





Realized gain (loss) on risk management






General and administrative





Interest and finance costs





Decommissioning expenditures




Funds flow per Boe





Barrels of oil equivalent per day (6:1)





Natural gas production

Thousand cubic feet per day





Price (Cdn$ per Mcf)(1)





Condensate production

Barrels per day





Price (Cdn$ per barrel)(1)





NGL production

Barrels per day





Price (Cdn$ per barrel)(1)





Wells drilled (net)





Wells completed (net)




Wells started production (net)




Excludes gains and losses on risk management contracts.


Certain financial amounts shown above are non-GAAP measurements. See discussion of Non-GAAP Measurements on page 23 of the MD&A. CROCE and ROCE are presented on a 12-month trailing basis.


Excludes the fair value of risk management contracts, decommissioning liability and lease liability.


Includes a non-cash unrealized loss on risk management contracts of $31.1 million for the three months ended September 30, 2021 (three months ended September 30, 2020 – unrealized loss of $18.0 million) and an unrealized loss of $70.1 million for the nine months ended September 30, 2021 (nine months ended September 30, 2020 – unrealized loss of $21.4 million).



Stronger than expected well performance along with continued improvement in commodity prices resulted in funds flow increasing to $33 million in the quarter while capital investment at $37 million was less than guidance for $43 to $48 million due to weather related delays in July.  Production and funds flow are both forecast to increase in the fourth quarter and into 2022 with 12.5 net new wells expected to start production at Nig Creek, Umbach and Fireweed in the fourth quarter and early 2022 (first production was achieved from the Fireweed area on November 4).

Subsequent to the end of the quarter, on November 9, 2021, Storm entered into a definitive arrangement agreement with Canadian Natural Resources Limited (“Purchaser”) pursuant to which the Purchaser has agreed to acquire all of the issued and outstanding common shares of Storm (“Storm Shares“) for cash consideration of $6.28 per Storm Share (the “Purchase Price“).  The proposed transaction is expected to close in December 2021 and offers attractive value for Storm shareholders with the Purchase Price implying an enterprise value for Storm of approximately $965 million using financial results from the third quarter of 2021 and including transaction related expenses plus the decommissioning liability. This represents 4.8 times annualized funds flow in the third quarter of 2021 excluding the loss on risk management contracts (hedging losses).  The Purchase Price also represents an all-time high share price for Storm as well as a premium of 10% to Storm’s 10-day volume weighted average trading price on the Toronto Stock Exchange as of the close of markets on November 9, 2021.

  • Production was 27,499 Boe per day, a 45% increase year over year and a 2% increase from the previous quarter. This was at the higher end of guidance for an average of 25,000 to 28,000 Boe per day and was achieved with the Nig Creek Gas Plant shut in for nine days in July to install inlet compression and to conduct a maintenance turnaround. Comparisons to the previous year are less meaningful given the effect of planned maintenance turnarounds at third party gas plants which reduced production in the third quarter of 2020.
  • Liquids production (condensate plus NGL) totaled 5,094 barrels per day which was 19% of total production and provided 32% of total revenue. Liquids production increased 35% from last year.
  • Well performance continues to be strong with third quarter corporate production increasing by 6% from the first quarter of 2021 which was accomplished with only three new wells starting production at Umbach.
  • Recent well performance continues to exceed expectations with the calendar day IP365 for the last four wells starting production at Nig Creek averaging 1,940 Boe per day sales (22% liquids) and the calendar day IP180 for the last three wells starting production at Umbach averaging 1,080 Boe per day sales (21% liquids).
  • Revenue net of transportation was $29.08 per Boe, a 172% increase from last year as a result of higher commodity prices and a 28% decrease in the per-Boe transportation cost as incremental sales volumes are directed to BC Station 2 which has the lowest pipeline tariff.
  • Production, general and administrative, and interest and finance costs totaled $5.44 per Boe, a year-over-year reduction of 18%. Production costs are expected to decline as volumes directed to the Nig Creek Gas Plant are increased.
  • Realized hedging loss was $16.6 million, or $6.57 per Boe, a result of the continued improvement in commodity prices.
  • Funds flow was $33.4 million, or $0.27 per share, an increase of 400% from last year. This was largely from both higher production and higher commodity prices, partially offset by a $16.6 million hedging loss.
  • Net loss was $8.9 million, or $0.07 per share, and was largely due to the unrealized loss on risk management contracts totaling $31.1 million (non-cash hedging loss) which reflects the change in the mark-to-market valuation of future contracts.
  • Cash return on capital employed (CROCE) was 24% and return on capital employed (ROCE) was 4% with both calculated on a 12-month trailing basis. ROCE was reduced by non-cash hedging losses of $31.1 million in the quarter and $70.1 million for the year to date.
  • Capital investment was $36.8 million and included $23.1 million to drill 6.5 net and complete 1.5 net horizontal wells, $6.9 million to advance construction of the new facility at Fireweed, and $2.0 million to complete installation of inlet compression at the Nig Creek Gas Plant.
  • Total debt including working capital deficiency was $104 million which represents 0.8 X annualized quarterly funds flow.
  • Commodity price hedges protect revenue for approximately 41% of forecast production for the fourth quarter of 2021. The financial liability for future hedging contracts totaled $78 million using forward strip pricing at the end of the quarter.


Umbach, Nig Creek and Fireweed Areas, Northeast British Columbia

Storm’s land position is prospective for liquids-rich natural gas from the Montney formation and totals approximately 120,000 net acres (189 gross sections, 170 net sections) with 98 horizontal wells (90.9 net) drilled to the end of the third quarter.

The third quarter was busy in terms of field activity.

  • At Fireweed, construction of the new field compression facility continued to advance, one well (0.5 net) was drilled, and three wells (1.5 net) were completed.
  • At Nig Creek, installation of inlet compression and a maintenance turnaround were completed at the gas plant in July and four wells (4.0 net) were drilled in the lower Montney with completions starting in late September.
  • At Umbach, two wells (2.0 net) were drilled with completions planned for October.

The fourth quarter will also be busy for field activity.

  • At Fireweed, the new facility was completed, four wells (2.0 net) will be drilled, two wells (1.0 net) completed, and four wells (2.0 net) are expected to start producing.
  • At Nig Creek, four wells (4.0 net) in the lower Montney were completed in October and are scheduled to start producing in mid-November.
  • At Umbach, three wells (3.0 net) will be drilled, five wells (5.0 net) will be completed, and five wells (5.0 net) are expected to start producing.

At the end of the third quarter, there were 14 Montney horizontal wells (10.5 net) that had not started producing which  included five completed wells (2.5 net), all at Fireweed.

At Umbach,  production is directed to third-party gas plants for processing via Storm’s 100% working interest field compression facilities where capacity totals 150 Mmcf raw per day.  Firm processing commitments at third-party gas plants total 80 Mmcf raw per day.  Third quarter inlet volumes averaged 98 Mmcf per day gross raw gas (approximate 98% working interest) resulting in 17,015 Boe per day sales (84.0 Mmcf per day, 1,525 barrels per day condensate, 1,490 barrels per day NGL).

At Nig Creek (100% working interest), third quarter inlet volumes at the sour gas plant averaged 54 Mmcf per day raw resulting in 10,280 Boe per day sales (49.4 Mmcf per day, 877 barrels per day condensate, 1,167 barrels per day NGL) at a production cost of $1.30 per Boe.  Total production from the area averaged 69 Mmcf per day raw with approximately 22% directed to the Umbach field compression facilities.  Capacity of the sour gas plant is estimated to be 70 Mmcf raw per day and the plant is expected to be full once the four lower Montney wells are pipeline connected and start producing.

At Fireweed (50% working interest), the new field compression facility was completed and production started on November 4 from three wells (1.5 net) with a fourth well (0.5 net) starting up in mid-November and another three wells (1.5 net) expected to be tied in and producing in early January 2022.  Net sales are currently approximately 2,100 Boe per day (approximately 5.8 Mmcf per day sales, 1,070 barrels per day condensate, 65 barrels per day NGL).  A firm processing commitment was added at a third-party gas plant for 11 Mmcf raw per day net to Storm.

Recent wells at Nig Creek and Umbach continue to meet or exceed expectations:

  • The four wells completed at Nig Creek in 2020, have an average calendar day IP365 of 9.8 Mmcf per day raw or approximately 1,940 Boe per day sales (9.1 Mmcf per day, 200 barrels per day condensate, 230 barrels per day NGL), and cumulative operating income from all four wells was $53 million to the end of August.  Payout of the $17 million cost to drill, complete and equip was achieved in four months after the start of production in late October 2020.
  • The three wells completed at Umbach in 2021, have an average calendar day IP180 of 5.7 Mmcf per day raw or approximately 1,080 Boe per day sales (5.1 Mmcf per day, 145 barrels per day condensate, 80 barrels per day NGL), and cumulative operating income from all three wells was $10 million to the end of August. Payout of the $15 million cost to drill, complete and equip is forecast to be achieved within seven months after the start of production in April 2021.


The objective of the commodity price hedging program is to support longer-term growth by protecting revenue on up to 50% of current production for the next 18 months and up to 25% for 19 to 36 months forward.  The current hedge position is shown below (excludes price differential contracts which are shown in the financial statements).  Future production growth is not hedged.



Natural Gas Hedges

   % Current Nat Gas Production(1)




11,300 Mcf/d(2)

15,500 Mcf/d(2)

Floor Cdn$4.02 per Mcf(3)

Floor Cdn$3.78 per Mcf(3)

Ceiling Cdn$5.30 per Mcf(3)

Ceiling Cdn$5.28 per Mcf(3)

   Fixed Price

50,400 Mcf/d(2)

37,600 Mcf/d(2)

Cdn$3.39 per Mcf(3)

Cdn$3.36 per Mcf(3)

Crude Oil Hedges

   % Current Liquids Production(1)




1,250 Bpd

1,100 Bpd

Floor WTI Cdn$53.66 per barrel(3)

Floor WTI Cdn$61.78 per barrel(3)

Ceiling WTI Cdn$64.54 per barrel(3)

Ceiling WTI Cdn$76.01 per barrel(3)

   Fixed Price

650 Bpd

150 Bpd

WTI Cdn$54.33 per barrel

WTI Cdn$65.58 per barrel(3)

400 Bpd Propane

100 Bpd Propane

Cdn$52.17 per barrel(3)

Cdn$58.91 per barrel(3)


Using Q3 2021 actual production.


Using corporate average heat content 1.22 GJ per Mcf and 1.16 Mmbtu per Mcf.


Hedges in US$ are converted using an exchange rate of Cdn$1.275 per US$1.


Production in the fourth quarter of 2021 is forecast to average 30,000 to 32,000 Boe per day (production to date in the quarter has averaged approximately 28,400 Boe per day based on field estimates). Capital investment in the quarter is forecast to be $40 to $45 million which includes $10 million to drill 5.0 net wells, $27 million to complete and equip 10.0 net wells, and $6 million ($3.0 million net) to complete construction of the Fireweed facility.

Updated guidance for 2021 is provided below.  Capital investment is expected to be $115 to $120 million, an increase of $5 million from previous guidance in order to drill and complete an additional well at Umbach.  Forecast pricing was updated to reflect actual prices to date with assumed prices for the remainder of the year being approximately equal to the current forward strip.

2021 Guidance

August 11, 2021

November 10, 2021

Cdn$/US$ exchange rate



Chicago daily natural gas – US$/Mmbtu(1)



AECO daily natural gas – Cdn$/GJ(1)



BC Station 2 daily natural gas – Cdn$/GJ



WTI – US$/Bbl



Edmonton condensate diff – US$/Bbl



Est transportation cost – $/Boe

$4.50 – $4.75

$4.50 – $4.75

Est revenue net of transport (excl hedges) – $/Boe

$26.25 – $26.75

$29.00 – $30.50

Est royalty rate (% revenue net transportation)

8% – 9%

10% – 12%

Est production cost – $/Boe

$4.00 – $4.50

$4.25 – $4.50

Est mid-point field operating netback – $/Boe(2)



Est realized hedging gains or (losses) – $ million

($40.0 – $45.0)

($55.0 – $60.0)

Est cash G&A – $ million

$5.0 – $6.0


Est interest expense – $ million

$6.0 – $7.0

$6.0 – $7.0

Est capital investment (excluding A&D) – $ million

$110 – $115

$115 – $120

Forecast fourth quarter Boe/d

Forecast fourth quarter liquids Bbls/d

30,000 – 32,000

6,800 – 7,300

30,000 – 32,000

6,800 – 7,300

Forecast annual Boe/d

Forecast annual liquids Bbls/d

26,000 – 28,000

5,600 – 6,000

27,000 – 28,000

5,600 – 6,000

Est annual funds flow – $ million(3)

$135 – $149

$148 – $156

Horizontal wells drilled – gross

Horizontal wells completed – gross

Horizontal wells starting production – gross

16 (12.0 net)

17 (14.0 net)

19 (15.0 net)

17 (13.0 net)

17 (14.5 net)

16 (14.0 net)


Approximately 50% of natural gas sales are at the daily or spot price and 50% at the monthly index price.


Based on the mid-point for each of revenue net of transportation, royalty rate and production costs.


Based on the range for forecast annual production and using the mid-points for the estimated field operating netback, estimated cash G&A, estimated hedging gain or loss and estimated interest expense.

2021 Investment and Activity by Area

Capital Investment

% for

Net Wells

Net Wells

Net Wells
Starting Production


$42 – $45





Nig Creek

$31 – $32






$42 – $43





$115 – $120




2021 Guidance History




BC Station 2





Capital Investment

($ million)



Funds Flow

($ million)

Forecast Annual



Nov 10, 2020




$85 – $90

$90 – $99

26,000 – 28,000

Mar 2, 2021




$85 – $90

$109 – $120

26,000 – 28,000

May 12, 2021




$85 – $90

$112 – $122

26,000 – 28,000

Aug 11, 2021




$110 – $115

$135 – $149

26,000 – 28,000

Nov 10, 2021




$115 – $120

$148 – $156

27,000 – 28,000

First production was achieved from the Fireweed area after start-up of the new facility on November 4, 2021 with net sales currently being approximately 2,100 Boe per day from three wells (1.5 net).  Four additional wells (2.0 net) are expected to start production by early January. To date, completion results have been encouraging and management is optimistic regarding future well performance.

The financial liability for future hedges increased to $78 million at the end of the third quarter from $47 million at the end of the previous quarter.  With the improvement in the balance sheet and given the backwardation in pricing (future prices are below current spot prices), hedging activity has been reduced since last summer. This will result in approximately 45% of current production being hedged six to nine months forward with a lesser volume 10 to 18 months forward (future growth is not hedged).

There is no additional information available at this time regarding the Judgement in the Supreme Court of British Columbia in the Yahey (Blueberry River First Nations) v. British Columbia case on June 29, 2021 which declared that cumulative effects of industrial development have infringed on rights guaranteed under Treaty 8.  At this time, the Judgement is not expected to affect Storm’s planned activity.  Potential longer term effects, if any, are not known at this time.

The summer and fall were busy in terms of field operations with two drilling rigs running from August to October and completion results to date being very encouraging.  This is translating into higher production levels in the fourth quarter of 2021 with the successful and safe start-up of the new Fireweed facility being a notable contributor.


B. Lavergne

Brian Lavergne,
President and Chief Executive Officer

November 10, 2021

Boe Presentation  For the purpose of calculating unit revenues and costs, natural gas is converted to a barrel of oil equivalent (“Boe”) using six thousand cubic feet (“Mcf”) of natural gas equal to one barrel of oil unless otherwise stated. Boe may be misleading, particularly if used in isolation. A Boe conversion ratio of six Mcf to one barrel (“Bbl”) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All Boe measurements and conversions in this press release are derived by converting natural gas to oil in the ratio of six thousand cubic feet of gas to one barrel of oil. Mboe means 1,000 Boe.

Initial Production Rates – References to initial production rates (“IP”), and other short-term production rates are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long-term performance or of ultimate recovery. Additionally, such rates may also include recovered “load oil” fluids used in well completion stimulation. Readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. A pressure transient analysis or well-test interpretation has not been carried out in respect of all wells. Accordingly, the Company cautions that the test results should be considered to be preliminary.

Non-GAAP Measures – This document may refer to the terms “debt including working capital deficiency”, “field operating netbacks”, “field operating netbacks including hedging”, “CROCE”, “ROCE”, the terms “cash” and “non-cash”, “cash costs”, “free cash flow” (defined as funds flow less capital expenditures required to maintain current production levels), and measurements “per commodity unit” and “per Boe” which are not recognized under Generally Accepted Accounting Principles (“GAAP”) and are regarded as non-GAAP measures. These non-GAAP measures may not be comparable to the calculation of similar amounts for other entities and readers are cautioned that use of such measures to compare enterprises may not be valid. Non-GAAP terms are used to benchmark operations against prior periods and peer group companies and are widely used by investors, analysts and other parties.  Additional information relating to certain of these non-GAAP measures can be found in Storm’s MD&A dated November 10, 2021 for the period ended September 30, 2021 which is available on Storm’s SEDAR profile at and on Storm’s website at

Forward-Looking Information – This press release contains forward-looking statements and forward-looking information within the meaning of applicable securities laws. The use of any of the words “will”, “would”, “expect”, “anticipate”, “intend”, “believe”, “plan”, “potential”, “outlook”, “forecast”, “estimate”, “budget” and similar expressions are intended to identify forward-looking statements or information. More particularly, and without limitation, this press release contains forward-looking statements and information concerning: the Transaction, including the anticipated benefits thereof to Storm and its shareholders and the closing thereof; current and future years’ guidance in respect of certain operational and financial metrics, including, but not limited to, commodity pricing, estimated average production costs, estimated average royalty rate, estimated operations capital, estimated general and administrative costs, estimated quarterly and annual production and estimated number of horizontal wells drilled, completed and connected, capital investment plans, infrastructure plans, anticipated United States exports, pipeline capacity, price volatility mitigation strategy and cost reductions. Statements of “reserves” are also deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.

The forward-looking statements and information in this press release are based on certain key expectations and assumptions made by Storm, including: prevailing commodity prices and exchange rates; applicable royalty rates and tax laws; future well production rates; reserve and resource volumes; the performance of existing wells; success to be expected in drilling new wells; the adequacy of budgeted capital expenditures to carry out planned activities; the availability and cost of services; and the receipt, in a timely manner, of regulatory and other required approvals. Although the Company believes that the expectations and assumptions on which such forward-looking statements and information are based are reasonable, undue reliance should not be placed on these forward-looking statements and information because of their inherent uncertainty. In particular, there is no assurance that exploitation of the Company’s undeveloped lands and prospects will result in the emergence of profitable operations.

Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to the risks associated with the oil and gas industry in general such as: general economic conditions in Canada, the United States and internationally; operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to reserves, production, costs and expenses; health, safety and environmental risks; commodity price and exchange rate fluctuations; marketing and transportation of petroleum and natural gas and loss of markets; competition; ability to access sufficient capital from internal and external sources; geopolitical risk; stock market volatility; and changes in legislation, including but not limited to tax laws, royalty rates and environmental regulations.

Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect the operations or financial results of the Company are included or are incorporated by reference in the Company’s Annual Information Form dated March 31, 2021 and the MD&A dated November 10, 2021 for the period ended September 30, 2021 which are available on Storm’s SEDAR profile at and on Storm’s website at

In respect of the forward-looking statements concerning the anticipated benefits and completion of the Transaction, Storm has provided such in reliance on certain assumptions that the Company believes are reasonable at this time, including assumptions as to the time required to prepare and mail special meeting materials, including the information circular; the ability of the parties to receive, in a timely manner, the necessary securityholder, court, regulatory, stock exchange and other third party approvals, including but not limited to the receipt of applicable competition approvals; and the ability of the parties to satisfy, in a timely manner, the other conditions to the closing of the Transaction. By their nature, forward-looking statements are subject to numerous risks and uncertainties, some of which are beyond Storm’s control. Completion of the Transaction is subject to a number of conditions which are typical for transactions of this nature. Failure to satisfy any of these conditions, the emergence of a superior proposal or the failure to obtain approval of securityholders may result in the termination of the Arrangement Agreement. Additional information on these and other risks that could affect completion of the Transaction will be set forth in the information circular, which will be available on SEDAR at

The forward-looking statements and information contained in this press release are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.


Brian Lavergne, President & Chief Executive Officer; Michael J. Hearn, Chief Financial Officer, Carol Knudsen, Manager, Corporate Affairs, (403) 817-6145,