STORM RESOURCES LTD. Calgary, Alberta--(Newsfile Corp. - August 11, 2021) - Storm Resources Ltd. (TSX: SRX) Storm has also filed its unaudited condensed interim consolidated financial statements as at June 30, 2021 and for the three and six months then ended along with Management's Discussion and Analysis ("MD&A") for the same period. This information appears on SEDAR at www.sedar.com and on Storm's website at www.stormresourcesltd.com.
Selected financial and operating information for the three and six months ended June 30, 2021 appears below and should be read in conjunction with the related financial statements and MD&A.
Highlights
| Thousands of Cdn$, except volumetric and per-share amounts | Three Months to June 30, 2021 | Three Months to June 30, 2020 | Six Months to June 30, 2021 | Six Months to June 30, 2020 | ||||||||
| FINANCIAL | ||||||||||||
| Revenue from product sales(1) | | 65,554 | | | 30,191 | | | 139,228 | 72,114 | |||
| Funds flow | 27,902 | 10,904 | 64,434 | 27,793 | ||||||||
| Per share - basic and diluted ($) | 0.23 | 0.09 | 0.53 | 0.23 | ||||||||
| Net income (loss) | (11,843 | ) | (11,665 | ) | (694 | ) | (1,153 | ) | ||||
| Per share - basic and diluted ($) | (0.10 | ) | (0.10 | ) | (0.01 | ) | (0.01 | ) | ||||
| Cash return on capital employed ("CROCE")(2) | 19% | 12% | 19% | 12% | ||||||||
| Return on capital employed ("ROCE")(2)(4) | 2% | 2% | 2% | 2% | ||||||||
| Capital expenditures | 10,017 | 2,394 | 34,869 | 28,869 | ||||||||
| Debt including working capital deficiency/ surplus(2)(3) | 101,712 | 130,317 | 101,712 | 130,317 | ||||||||
| Common shares (000s) | ||||||||||||
| Weighted average - basic | 121,892 | 121,557 | 121,804 | 121,557 | ||||||||
| Weighted average - diluted | 121,892 | 121,557 | 121,804 | 121,557 | ||||||||
| Outstanding end of period - basic | 122,042 | 121,557 | 122,042 | 121,557 | ||||||||
| OPERATIONS | ||||||||||||
| (Cdn$ per Boe) | ||||||||||||
| Revenue from product sales(1) | 26.82 | 13.86 | 29.15 | 16.55 | ||||||||
| Transportation costs | (4.85 | ) | (5.50 | ) | (4.90 | ) | (5.24 | ) | ||||
| Revenue net of transportation | 21.97 | 8.36 | 24.25 | 11.31 | ||||||||
| Royalties | (0.97 | ) | (0.44 | ) | (1.74 | ) | (0.70 | ) | ||||
| Production costs | (4.64 | ) | (4.50 | ) | (4.47 | ) | (4.83 | ) | ||||
| Field operating netback(2) | 16.36 | 3.42 | 18.04 | 5.78 | ||||||||
| Realized gain (loss) on risk management contracts | (3.71 | ) | 2.99 | (3.00 | ) | 2.12 | ||||||
| General and administrative | (0.50 | ) | (0.72 | ) | (0.64 | ) | (0.79 | ) | ||||
| Interest and finance costs | (0.65 | ) | (0.68 | ) | (0.77 | ) | (0.71 | ) | ||||
| Decommissioning expenditures | (0.08 | ) | (0.01 | ) | (0.16 | ) | | (0.03 | ) | |||
| Funds flow per Boe | 11.42 | 5.00 | 13.47 | 6.37 | ||||||||
| Barrels of oil equivalent per day (6:1) | 26,862 | 23,935 | 26,389 | 23,941 | ||||||||
| Natural gas production | ||||||||||||
| Thousand cubic feet per day | 130,173 | 114,772 | 127,364 | 115,365 | ||||||||
| Price (Cdn$ per Mcf)(1) | 3.58 | 2.23 | 4.08 | 2.39 | ||||||||
| Condensate production | ||||||||||||
| Barrels per day | 2,434 | 2,305 | 2,420 | 2,464 | ||||||||
| Price (Cdn$ per barrel)(1) | 78.53 | 25.92 | 74.58 | 44.41 | ||||||||
| NGL production | ||||||||||||
| Barrels per day | 2,732 | 2,501 | 2,742 | 2,249 | ||||||||
| Price (Cdn$ per barrel)(1) | 23.28 | 6.23 | 25.03 | 4.92 | ||||||||
| Wells drilled (net) | - | - | 1.5 | 1.0 | ||||||||
| Wells completed (net) | - | - | 3.0 | 3.5 | ||||||||
| Wells started production (net) | 1.0 | 1.0 | | 3.0 | 3.0 |
(1) Excludes gains and losses on risk management contracts.
(2) Certain financial amounts shown above are non-GAAP measurements. See discussion of Non-GAAP Measurements on page 24 of the MD&A. CROCE and ROCE are presented on a 12-month trailing basis.
(3) Excludes the fair value of risk management contracts, decommissioning liability and lease liability.
(4) Includes a non-cash unrealized loss on risk management contracts of $30.3 million for the three months ended June 30, 2021 (three months ended June 30, 2020 - unrealized loss of $13.8 million) and an unrealized loss of $39.0 million for the six months ended June 30, 2021 (six months ended June 30, 2020 - unrealized loss of $3.3 million).
PRESIDENT’S MESSAGE
2021 SECOND QUARTER HIGHLIGHTS
Improving commodity prices continue to provide a 'tail wind' with funds flow exceeding capital investment for the second consecutive quarter which resulted in debt being reduced by $18 million from the previous quarter and by $30 million in the first half of 2021. Capital efficiencies remain strong with production increasing 4% from the previous quarter with only one new well starting production in early June.
- Production was 26,862 Boe per day which is a 12% increase year over year and a 4% increase from the previous quarter. This was consistent with guidance for an average of 25,000 to 27,000 Boe per day.
- Liquids production (condensate plus NGL) totaled 5,166 barrels per day which was 19% of total production and 35% of total revenue. Liquids production increased 7% from last year.
- During the quarter, one new horizontal well started production in early June at Umbach and, year to date, three new horizontal wells started production, all at Umbach.
- Performance of recent wells continues to be strong with the Nig Creek wells completed in 2020 having an average IP270 of 1,900 Boe per day sales (23% liquids) and the Umbach wells completed in 2021 having an average IP90 of 1,080 Boe per day sales (22% liquids).
- Revenue net of transportation was $21.97 per Boe, a 163% increase from last year as a result of higher commodity prices and a 12% decrease in the per-Boe transportation cost. Liquids prices saw the biggest improvement with condensate and NGL prices rising 203% and 274% respectively.
- Production, general and administrative, and interest and finance costs totaled $5.79 per Boe, a year-over-year reduction of 2%.
- Realized hedging loss was $9.1 million, or $3.71 per Boe, which is a result of the rapid and unexpected improvement in commodity prices over the last 12 months.
- Funds flow was $27.9 million, or $0.23 per share, an increase of 155% from last year. This was largely from higher production and higher commodity prices which were partially offset by the $9.1 million hedging loss.
- The net loss was $11.8 million, or $0.10 per share, which was largely the result of an unrealized hedging loss of $30.3 million (change in the mark-to-market valuation of future hedging contracts).
- Cash return on capital employed (CROCE) was 19% and return on capital employed (ROCE) was 2% with both calculated on a 12-month trailing basis. ROCE was reduced by non-cash hedging losses of $30.3 million in the quarter and $39.0 million for the year to date.
- Capital investment was $10 million (versus guidance for $14 million). At Fireweed, investment included $2.2 million net for equipment deposits for the facility and $0.8 million net to complete the gathering and sales pipelines. At Nig Creek, $5.2 million was invested to purchase an inlet compressor for the gas plant which was installed in July.
- Total debt including working capital surplus was $102 million which is a reduction of $18 million from the previous quarter and represents 0.9 X annualized quarterly funds flow.
- Commodity price hedges protect revenue on approximately 47% of current production for the remainder of 2021 and on approximately 33% of current production for 2022. The financial liability for future hedging contracts totaled $47 million using forward strip pricing at the end of the quarter.
OPERATIONS REVIEW
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 90 horizontal wells (83.4 net) drilled to the end of the second quarter.
Field activity in the second quarter was minimal and included completing construction of gathering and sales pipelines at Fireweed plus work to upgrade leases and roads in preparation for a busy third quarter. Wet weather in June and early July delayed some activity including the movement of a drilling rig to Nig Creek by approximately three weeks.
Expected field activity in the third quarter will include drilling and starting completions on four lower Montney wells (4.0 net) at Nig Creek, drilling three wells (3.0 net) at Umbach, drilling one well (0.5 net) and completing three wells (1.5 net) at Fireweed, installing inlet compression at the Nig Creek Gas Plant in early July, and starting construction of the field compression facility at Fireweed.
At the end of the second quarter, there were seven Montney horizontal wells (4.0 net) that had not started producing which included one well (1.0 net) at Umbach and six wells (3.0 net) at Fireweed.
At Umbach, produced raw natural gas contains 1.2% H2S, field compression capacity totals 150 Mmcf raw per day, and firm processing commitments total 80 Mmcf raw per day. Second quarter gross raw gas averaged 96 Mmcf per day (Storm working interest approximately 98%) while net sales were 16,450 Boe per day (80.8 Mmcf per day, 1,515 barrels per day condensate, 1,470 barrels per day NGL). Activity in the remainder of 2021 is expected to include drilling and completing four wells (4.0 net).
At Nig Creek (100% working interest), produced raw natural gas contains up to 0.5% H2S and is directed to Storm's 100% working interest sour gas plant. Gas plant inlet volumes in the second quarter averaged 52 Mmcf per day raw, sales were 10,065 Boe per day (47.4 Mmcf per day, 910 barrels per day condensate, 1,255 barrels per day NGL), and the production cost was $1.25 per Boe. Capacity of the gas plant is estimated to be 70 Mmcf per day at current average H2S of 0.3%. Activity in the remainder of 2021 is expected to fill the gas plant and will include adding inlet compression in July plus drilling and completing four wells (4.0 net) this summer in the lower Montney.
At Fireweed (50% working interest), activity in the remainder of 2021 is expected to include construction of a 50 Mmcf raw per day field compression facility, drilling five wells (2.5 net) and completing six wells (3.0 net). First production of approximately 2,500 Boe per day net is expected in the fourth quarter of 2021 from five wells (2.5 net).
Recent wells at Nig Creek and Umbach continue to meet or exceed expectations:
- The four wells completed at Nig Creek in 2020 started producing in late October, have an average calendar day IP270 of 9.5 Mmcf per day raw or approximately 1,900 Boe per day sales (8.8 Mmcf per day, 200 barrels per day condensate, 235 barrels per day NGL), and cumulative operating income from all four wells was $41 million to the end of June. Payout of the $17 million cost to drill, complete and equip was achieved in five months.
- The three wells completed at Umbach in 2021 started producing in late March and early June, have an average calendar day IP90 of 5.7 Mmcf per day raw or approximately 1,080 Boe per day sales (5.1 Mmcf per day, 155 barrels per day condensate, 80 barrels per day NGL), and cumulative operating income from all three wells was $5 million to the end of June. The cost was $15 million to drill, complete and equip.
HEDGING
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.
| H2/21 | 2022 | |
| Natural Gas Hedges | ||
| % Current Nat Gas Production(1) | 48% | 36% |
| Collars | 4,500 Mcf/d(2) | 10,300 Mcf/d(2) |
| Floor Cdn$3.92 per Mcf(3) | Floor Cdn$3.57 per Mcf(3) | |
| Ceiling Cdn$4.74 per Mcf(3) | Ceiling Cdn$4.56 per Mcf(3) | |
| Fixed Price | 56,200 Mcf/d(2) | 35,100 Mcf/d(2) |
| Cdn$3.19 per Mcf(3) | Cdn$3.25 per Mcf(3) | |
| Crude Oil Hedges | ||
| % Current Liquids Production(1) | 45% | 26% |
| Collars | 1,250 Bpd | 1,100 Bpd |
| Floor WTI Cdn$53.41 per barrel(3) | Floor WTI Cdn$60.95 per barrel(3) | |
| Ceiling WTI Cdn$64.24 per barrel(3) | Ceiling WTI Cdn$74.98 per barrel(3) | |
| Fixed Price | 650 Bpd | 150 Bpd |
| WTI Cdn$54.33 per barrel | WTI Cdn$63.78 per barrel(3) | |
| 400 Bpd Propane | 100 Bpd Propane | |
| Cdn$47.14 per barrel(3) | Cdn$58.30 per barrel(3) |
(1) Using Q2 2021 actual production.
(2) Using corporate average heat content 1.22 GJ per Mcf and 1.16 Mmbtu per Mcf.
(3) Hedges in US$ are converted using an exchange rate of Cdn$1.24 per US$1.
OUTLOOK
Production in the third quarter of 2021 is forecast to average 25,000 to 28,000 Boe per day (production to date in the quarter has averaged approximately 26,500 Boe per day based on field estimates). Capital investment in the quarter is forecast to be $43 to $48 million which includes $18 million ($9.0 million net) for construction of the Fireweed facility, $17 million to drill 7.5 net wells and $15 million to complete and equip 5.5 net wells.
Updated guidance for 2021 is provided below. Capital investment is being increased to a range of $110 to $115 million from $85 to $90 million. Forecast pricing and annual funds flow was updated to reflect actual prices to date with assumed prices for the remainder of the year being approximately equal to the current forward strip.
| 2021 Guidance | ||
| Previous May 12, 2021 | Current August 11, 2021 | |
| Cdn$/US$ exchange rate | 0.79 | 0.80 |
| Chicago daily natural gas - US$/Mmbtu(1) | $3.50 | $4.10 |
| AECO daily natural gas - Cdn$/GJ(1) | $2.60 | $3.25 |
| BC Station 2 daily natural gas - Cdn$/GJ | $2.55 | $3.20 |
| WTI - US$/Bbl | $57 | $65 |
| Edmonton condensate diff - US$/Bbl | ($1.30) | ($0.00) |
| Est transportation cost - $/Boe | $4.50 - $4.75 | $4.50 - $4.75 |
| Est revenue net of transport (excl hedges) - $/Boe | $20.50 - $21.50 | $26.25 - $26.75 |
| Est royalty rate (% revenue net transportation) | 8% - 9% | 8% - 9% |
| Est production cost - $/Boe | $4.00 - $4.50 | $4.00 - $4.50 |
| Est mid-point field operating netback - $/Boe(2) | $14.95 | $20.00 |
| Est realized hedging gains or (losses) - $ million | ($15.0 - $17.0) | ($40.0 - $45.0) |
| Est cash G&A - $ million | $6.0 - $7.0 | $5.0 - $6.0 |
| Est interest expense - $ million | $6.0 - $7.0 | $6.0 - $7.0 |
| Est capital investment (excluding A&D) - $ million | $85 - $90 | $110 - $115 |
| 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 | 26,000 - 28,000 5,600 - 6,000 |
| Est annual funds flow - $ million(3) | $112 - $122 | $135 - $149 |
| Horizontal wells drilled - gross Horizontal wells completed - gross Horizontal wells starting production - gross | 11 - 12 (9.0 - 9.5 net) 13 (11.5 net) 14 - 15 (11.5 - 12.5 net) | 16 (12.0 net) 17 (14.0 net) 19 (15.0 net) |
(1) Approximately 50% of natural gas sales are at the daily or spot price and 50% at the monthly index price.
(2) Based on the mid-point for each of revenue net of transportation, royalty rate and production costs.
(3) Based on the range for forecast annual production and using the mid-points for the estimated field operating netback, estimated cash G&A, estimated hedging gain or loss and estimated interest expense.
| 2021 Guidance History | | | | | | |||||||||||||
| Chicago Daily (US$/Mmbtu) | BC Station 2 Daily (Cdn$/GJ) | WTI (US$/Bbl) | Capital Investment ($ million) | Forecast Annual Funds Flow ($ million) | Forecast Annual Production (Boe/d) | |||||||||||||
| Nov 10, 2020 | $ | 2.65 | $ | 2.50 | $ | 40 | $ | 85 - $90 | $ | 90 - $99 | 26,000 - 28,000 | |||||||
| Mar 2, 2021 | $ | 3.50 | $ | 2.55 | $ | 51 | $ | 85 - $90 | $ | 109 - $120 | 26,000 - 28,000 | |||||||
| May 12, 2021 | $ | 3.50 | $ | 2.55 | $ | 57 | $ | 85 - $90 | $ | 112 - $122 | 26,000 - 28,000 | |||||||
| August 11, 2021 | $ | 4.10 | $ | 3.20 | $ | 65 | $ | 110 - $115 | $ | 135 - $149 | 26,000 - 28,000 | |||||||
| 2021 Investment and Activity by Area | |||||||||||||||
| Capital Investment ($million) | % for Infrastructure | Net Wells Drilled | Net Wells Completed | Net Wells Starting Production | |||||||||||
| Fireweed | $ | 42 - $47 | 46% | 4.0 | 3.0 | 4.0 | |||||||||
| Nig Creek | $ | 29 | 28% | 4.0 | 4.0 | 4.0 | |||||||||
| Umbach | $ | 39 | 4.0 | 7.0 | 7.0 | ||||||||||
| Total | $ | 110 - $115 | 12.0 | 14.0 | 15.0 | ||||||||||
Capital investment is being increased by $25 million which represents approximately half of the increase in forecast annual funds flow from the initial estimate in November 2020 (remainder will be directed to debt reduction which also increases asset value per share). The increase adds 3.0 net drills and 2.5 net completions, includes $3 million to advance construction of a multi-well pad and access road into 2021 from 2022, and assumes that inflation adds $2 million to the cost of previously planned drills and completions in the second half of 2021. The additional wells will start production late in the fourth quarter, are expected to benefit from higher winter pricing for natural gas and are forecast to add approximately 2,000 Boe per day to average production in 2022. Strong rates of return are anticipated from the incremental capital investment given unused capacity at existing facilities with half-cycle payouts estimated to be less than one year at current forward strip commodity prices.
Development at Fireweed continues to progress as planned with construction of the large diameter gathering and sales pipelines completed early in the second quarter while site preparation for the facility has been completed and equipment deliveries will start in late August. Wet weather in June resulted in a delayed start to site preparation for the facility; however, first production of approximately 2,500 Boe per day net is still expected in the fourth quarter of 2021.
The financial liability for future hedges totaled $47 million at the end of the second quarter. The large future liability is the result of the rapid and unexpected increase in commodity prices over the last 12 months since the hedges were layered on. In response to the backwardation in pricing where future prices are below current spot prices, additional hedges for the second half of 2022 will be layered on more slowly depending on pricing and market conditions. This is expected to result in approximately 45% of current production being hedged six to nine months forward with a lesser volume 10 to 18 months forward. Currently, approximately 45% of production is hedged 12 months forward through the first half of 2022 while the second half of 2022 is approximately 25% 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 for 2021 and 2022. Potential longer term effects, if any, are not known at this time.
The focus of the business plan in 2021 remains on growing asset value and funds flow per share which will largely be accomplished by:
- Filling the Nig Creek Gas Plant which reduces production cost and increases the proportion of liquids;
- Adding future drilling inventory in the lower Montney at Nig Creek;
- Starting production from the Fireweed area where condensate is forecast to be a higher proportion of production;
- Continuing to evolve drilling and completion techniques to reduce well costs while improving performance; and
- Reducing debt to increase future financial flexibility for acquisitions, accelerating organic growth or returning capital to shareholders.
This summer will be busy in terms of field operations and we look forward to reporting on our progress in the second half of the year.
Respectfully,
/s/ B Lavergne
Brian Lavergne,
President and Chief Executive Officer
August 11, 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 August 11, 2021 for the period ended June 30, 2021 which is available on Storm's SEDAR profile at www.sedar.com and on Storm's website at www.stormresourcesltd.com.
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: 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 August 11, 2021 for the period ended June 30, 2021 which are available on Storm's SEDAR profile at www.sedar.com and on Storm's website at www.stormresourcesltd.com.
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.
For further information please contact:
Brian Lavergne
President & Chief Executive Officer
Michael J. Hearn
Chief Financial Officer
Carol Knudsen
Manager, Corporate Affairs
(403) 817-6145
www.stormresourcesltd.com
To view the source version of this press release, please visit https://www.newsfilecorp.com/release/92865
