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Calgary, Alberta–(Newsfile Corp. – May 12, 2021) – Storm Resources Ltd. (TSX: SRX) ("Storm" or the "Company") has also filed its unaudited condensed interim consolidated financial statements as at March 31, 2021 and for the three 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 months ended March 31, 2021 appears below and should be read in conjunction with the related financial statements and MD&A.
|Thousands of Cdn$, except volumetric and per-share amounts||Three Months Ended March 31, 2021||Three Months Ended
March 31, 2020
|Revenue from product sales(1)||73,674||41,923|
|Per share – basic and diluted ($)||0.30||0.14|
|Per share – basic and diluted ($)||0.09||0.09|
|Cash return on capital employed ("CROCE")(2)||15%||12%|
|Return on capital employed ("ROCE")(2)(4)||2%||7%|
|Debt including working capital deficiency(2)(3)||120,021||138,632|
|Common shares (000s)|
|Weighted average – basic||121,713||121,557|
|Weighted average – diluted||123,404||121,557|
|Outstanding end of period – basic||121,769||121,557|
|(Cdn$ per Boe)|
|Revenue from product sales(1)||31.59||19.24|
|Revenue net of transportation||26.64||14.27|
|Field operating netback(2)||19.83||8.13|
|Realized gain (loss) on risk management contracts||(2.25)||1.26|
|General and administrative||(0.78)||(0.86)|
|Interest and finance costs||(0.89)||(0.74)|
|Funds flow per Boe||15.67||7.75|
|Barrels of oil equivalent per day (6:1)||25,910||23,946|
|Natural gas production|
|Thousand cubic feet per day||124,523||115,957|
|Price (Cdn$ per Mcf)(1)||4.62||2.54|
|Barrels per day||2,405||2,623|
|Price (Cdn$ per barrel)(1)||70.54||60.66|
|Barrels per day||2,752||1,998|
|Price (Cdn$ per barrel)(1)||26.79||3.27|
|Wells drilled (net)||1.5||1.0|
|Wells completed (net)||3.0||3.5|
|Wells started production (net)||2.0||2.0|
(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 22 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 $8.7 million for the three months ended March 31, 2021 (March 31, 2020 – unrealized gain of $10.5 million).
2021 FIRST QUARTER HIGHLIGHTS
Quarterly funds flow was a record high, mainly as a result of production growth and a significant improvement in the natural gas price, which was $4.62 per Mcf (82% increase from last year). The natural gas price benefitted from higher pricing in all markets with Chicago daily pricing seeing the largest increase as a result of extreme cold experienced across North America in February.
- Production was 25,910 Boe per day, an 8% increase year over year and unchanged 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 5,157 barrels per day, which was 20% of total production and 30% of total revenue. Notably, NGL production increased 38% from last year, largely as a result of higher recoveries realized at the Nig Creek Gas Plant which started operations in February 2020.
- During the quarter, three horizontal wells were completed at Umbach with two wells starting production in late March that are averaging approximately 7.4 MMcf per day raw over the last 20 days (rates were restricted for most of April due to downtime at the facility).
- Revenue net of transportation was $26.64 per Boe, an 87% increase from last year as a result of higher commodity prices. Higher natural gas prices at all sales points was the largest contributor to higher revenue.
- Production, general and administrative, and interest and finance costs totaled $5.95 per Boe, a year-over-year reduction of 12%. This was mainly driven by lower production costs resulting from the start-up of the Nig Creek Gas Plant in February 2020 which reduced third-party processing fees.
- Realized hedging loss was $5.3 million, or $2.25 per Boe, and resulted from the continuing recovery in commodity prices since mid-2020.
- Funds flow was a record $36.5 million, or $0.30 per share, an increase of 116% from last year. This was largely the result of higher production, higher commodity prices and lower production costs which were partially offset by the $5.3 million hedging loss and by abandonment and reclamation costs totaling $0.6 million.
- Net income was $11.1 million, or $0.09 per share, and was reduced by non-cash charges including $8.7 million for an unrealized hedging loss (change in the mark-to-market valuation of future hedging contracts) and $4.1 million for deferred income tax expense.
- Cash return on capital employed (CROCE) was 15% and return on capital employed (ROCE) was 2%. ROCE includes the effect of non-cash hedging gains or losses which can make it less meaningful as a way to measure return on capital.
- Capital investment was $24.9 million (versus guidance for $25 million). At Fireweed, $12.4 million net was invested to drill three horizontal wells (1.5 net), build 19 kilometres of pipeline, and for equipment deposits for the facility. At Umbach, $12.5 million was invested which included the completion and tie-in of a three-well pad.
- Total debt including working capital deficiency was $120 million which is a reduction of $12 million from the previous quarter and represents 0.8X annualized quarterly funds flow.
- Commodity price hedges for the remainder of 2021 protect revenue on approximately 47% of current production. At quarter end, the financial liability for future hedging contracts totaled $17 million.
- Carbon taxes paid to the BC government, which are included in production costs, totaled $1.4 million (direct and indirect), a decrease of $0.3 million from last year as a result of the start-up of the Nig Creek Gas Plant which has a lower emissions intensity versus alternative third-party gas processing plants.
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 first quarter.
Field activity in the first quarter at Umbach included the completion and tie-in of three wells (3.0 net) and, at Fireweed, included drilling three wells (1.5 net) plus constructing 19 kilometres of large diameter gathering and sales pipelines.
Expected field activity in the second quarter will include drilling a lower Montney well (1.0 net) at Nig Creek, delivery of the inlet compressor for the Nig Creek Gas Plant which will be installed in early July, and finishing pipeline construction at Fireweed.
At the end of the first quarter, there were eight Montney horizontal wells (5.0 net) that had not started producing which included two wells (2.0 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. First quarter gross raw gas averaged 85 Mmcf per day (Storm working interest approximately 98%) while net sales were 15,020 Boe per day (73.6 Mmcf per day, 1,365 barrels per day condensate, 1,380 barrels per day NGL). Activity in the remainder of 2021 is expected to include drilling and completing the remaining three wells (3.0 net) on a six-well pad.
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 first quarter averaged 54 Mmcf per day raw, sales were 10,530 Boe per day (48.8 Mmcf per day, 1,030 barrels per day condensate, 1,365 barrels per day NGL), and the production cost was $1.35 per Boe. Capacity of the gas plant is estimated to be 70 Mmcf per day at current average H2S of 0.3% (versus design capacity of 50 Mmcf per day at 0.5% H2S). Activity in the remainder of 2021 will be focused on filling the gas plant which will come from adding inlet compression in July and drilling and completing four wells (4.0 net) this summer in the lower Montney where H2S is below 0.1% based on results to date.
Recent wells at Nig Creek and Umbach continue to meet or exceed expectations:
- the four most recent wells at Nig Creek started producing in late October 2020 from the upper Montney with the IP180 averaging 9.5 Mmcf per day raw which is approximately 1,950 Boe per day sales (8.9 Mmcf per day, 230 barrels per day condensate, 240 barrels per day NGL).
- the two most recent wells at Umbach started producing in late March 2021 from the upper Montney, were restricted until late-April due to downtime at the facility, and have averaged 7.4 Mmcf per day raw over the last 20 days which is approximately 1,400 Boe per day sales (6.5 Mmcf per day, 200 barrels per day condensate, 120 barrels per day NGL).
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, completion and testing of the recently installed 19 kilometres of gathering and sales pipelines, drilling two wells (1.0 net), and completing three wells (1.5 net). First production is expected in the fourth quarter of 2021 from five wells (2.5 net).
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.
|Q2 – Q4 2021||2022|
|Natural Gas Hedges|
|% Current Nat Gas Production(1)||48%||31%|
|Collars||2,800 Mcf/d(2)||6,400 Mcf/d(2)|
|Floor Cdn$4.00 per Mcf(3)||Floor Cdn$3.75 per Mcf(3)|
|Ceiling Cdn$4.68 per Mcf(3)||Ceiling Cdn$4.69 per Mcf(3)|
|Fixed Price||57,100 Mcf/d(2)||32,300 Mcf/d(2)|
|Cdn$3.14 per Mcf(3)||Cdn$3.27 per Mcf(3)|
|Crude Oil Hedges|
|% Current Liquids Production(1)||44%||24%|
|Collars||1,100 Bpd||1,100 Bpd|
|Floor WTI Cdn$52.82 per barrel(3)||Floor WTI Cdn$61.31 per barrel(3)|
|Ceiling WTI Cdn$63.21 per barrel(3)||Ceiling WTI Cdn$74.66 per barrel(3)|
|Fixed Price||750 Bpd||150 Bpd|
|WTI Cdn$53.68 per barrel||WTI Cdn$64.81 per barrel(3)|
|400 Bpd Propane|
|Cdn$50.03 per barrel(3)|
(1) Using Q1 2021 actual production.
(2) Using corporate average heat content 1.22 GJ per Mcf and 1.16 Mmbtu per Mcf.
(3) Hedges in US$ are converted using an exchange rate of Cdn$1.26 per US$1.
Production in the second quarter of 2021 is forecast to average 25,000 to 27,000 Boe per day (production to date in the quarter has averaged approximately 26,000 Boe per day). Capital investment in the quarter is forecast to be $14 million which includes $5 million for the inlet compressor at the Nig Creek Gas Plant plus $7 million ($3.5 million net) for equipment deposits for the Fireweed facility.
Updated guidance for 2021 is provided below. Forecast pricing was updated to reflect actual prices to date with prices for the remainder of the year being unchanged from previous guidance except for the WTI price which was increased to US$55 per barrel from US$50.
March 2, 2021
May 12, 2021
|Cdn$/US$ exchange rate||0.79||0.79|
|Chicago daily natural gas – US$/Mmbtu(1)||$3.50||$3.50|
|AECO daily natural gas – Cdn$/GJ(1)||$2.60||$2.60|
|BC Station 2 daily natural gas – Cdn$/GJ||$2.55||$2.55|
|WTI – US$/Bbl||$51||$57|
|Edmonton condensate diff – US$/Bbl||($2.25)||($1.30)|
|Est transportation cost – $/Boe||$4.50 – $4.75||$4.50 – $4.75|
|Est revenue net of transport (excl hedges) – $/Boe||$19.50 – $20.50||$20.50 – $21.50|
|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)||$14.05||$14.95|
|Est realized hedging gains or (losses) – $ million||($10.0 – $12.0)||($15.0 – $17.0)|
|Est cash G&A – $ million||$6.0 – $7.0||$6.0 – $7.0|
|Est interest expense – $ million||$6.0 – $7.0||$6.0 – $7.0|
|Est capital investment (excluding A&D) – $ million||$85 – $90||$85 – $90|
|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)||$109 – $120||$112 – $122|
|Horizontal wells drilled – gross
Horizontal wells completed – gross
Horizontal wells starting production – gross
|11 – 12 (8.5 – 9.5 net)
11 – 12 (10.5 – 11.5 net)
14 – 15 (11.5 – 12.5 net)
|11 – 12 (9.0 – 9.5 net)
13 (11.5 net)
14 – 15 (11.5 – 12.5 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|
|BC Station 2
|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|
|2021 Investment and Activity by Area|
|% for Infrastructure||Net Wells
|Fireweed||$30 – $35||58%||2.0 – 2.5||1.5||2.5|
|Nig Creek||$28||25%||4.0||4.0||3.0 – 4.0|
|Total||$85 – $90|
'Free cash flow' in 2021 is estimated to be approximately $83 million using the mid-point for estimated annual funds flow and based on investment to maintain production of approximately $33 million to drill, complete and tie-in 6.0 net wells. 'Free cash flow' is being directed to development at Fireweed, growth from Nig Creek and debt reduction. As always, capital investment will remain flexible and may be adjusted up or down depending on commodity prices.
Transportation costs are expected to decline in 2021 given that natural gas sales into Canadian markets where pipeline tariffs are lower will increase to 54% of total sales from 38% in 2020. The natural gas sales split in 2021 is expected to be 46% at Chicago, 36% at BC Station 2, 11% at AECO and 7% at Alliance ATP. The marketing strategy for natural gas continues to be based on diversifying physical sales to mitigate the effect of regional price differences that are difficult to predict in terms of timing and duration.
Development at Fireweed continues to progress with the majority of large diameter gathering and sales pipelines having been constructed while initial equipment deliveries to the site will start in July. First production of approximately 2,500 Boe per day net remains on track for the fourth quarter of 2021.
The focus of the business plan is on growing asset value and funds flow per share and, in 2021, this will come from:
- Filling the Nig Creek Gas Plant which reduces production cost and increases the proportion of liquids;
- Advancing Fireweed development where condensate is forecast to be a higher proportion of production; and
- Reducing debt which increases future financial flexibility to pursue acquisitions, accelerate organic growth or return capital to shareholders.
With the material improvement in commodity prices over the last six months, an increase to capital investment in the second half of 2021 is currently being evaluated. Additional activity would be focused on increasing asset value and accessing underutilized facility capacity which is expected to result in attractive rates of return at current forward strip commodity prices. A number of opportunities are being reviewed including step-out wells at Umbach that would test the mid and/or lower Montney and accelerating development at Fireweed to fill the facility sooner. Production guidance for 2021 is not expected to change as any incremental wells would start producing in late 2021 or early 2022. Further details will be provided when second quarter results are released on August 11, 2021 with any increase to capital investment being contingent on continued strength in commodity prices and achieving minimum debt reduction of $10 to $15 million in 2021 relative to year end 2020.
President and Chief Executive Officer
May 12, 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 May 12, 2021 for the period ended March 31, 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 May 12, 2021 for the period ended March 31, 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:
President & Chief Executive Officer
Michael J. Hearn
Chief Financial Officer
Manager, Corporate Affairs
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