Storm Resources Ltd. (“Storm” or the “Company”) is Pleased to Announce Its Financial and Operating Results for the Three and Six Months Ended June 30, 2020

Source Company Press Release
Company Storm Resources Ltd.
Tags Corporate: Corporate Results, Guidance, Overview/Strategy, Country: Canada, Financial - Costs & Metrics: Capital Expenditures, Hedging
Date August 12, 2020

Storm has also filed its unaudited condensed interim consolidated financial statements as at June 30, 2020 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 sedar.com and on Storm’s website at  stormresourcesltd.com.

Selected financial and operating information for the three and six months ended June 30, 2020 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, 2020 
  Three Months to
June 30, 2019 
  Six Months to
June 30, 2020 
  Six Months to
June 30, 2019 
 
FINANCIAL         
Revenue from product sales(1)  30,191    37,568    72,114    93,334   
Funds flow  10,904    12,590    27,793    29,107   
  Per share – basic and diluted ($)  0.09    0.10    0.23    0.24   
Net income (loss)  (11,665  7,864    (1,153  8,471   
  Per share – basic and diluted ($)  (0.10  0.06    (0.01  0.07   
Cash return on capital employed (“CROCE”)(2)  12%    18%    12%    18%   
Return on capital employed (“ROCE”)(2)  2%    11%    2%    11%   
Capital expenditures  2,394    23,145    28,869    40,089   
Debt including working capital deficiency(2)(3)  130,317    102,268    130,317    102,268   
Common shares (000s)         
  Weighted average - basic  121,557    121,557    121,557    121,557   
  Weighted average - diluted  121,557    121,557    121,557    121,557   
  Outstanding end of period – basic  121,557    121,557    121,557    121,557   
OPERATIONS         
(Cdn$ per Boe)         
Revenue from product sales(1)  13.86    20.72    16.55    25.95   
Transportation costs  (5.50  (5.96  (5.24  (5.84 
Revenue net of transportation  8.36    14.76    11.31    20.11   
Royalties  (0.44  (0.32  (0.70  (1.46 
Production costs  (4.50  (5.89  (4.83  (5.99 
Field operating netback(2)  3.42    8.55    5.78    12.66   
Realized gain (loss) on risk management contracts  2.99    (0.22  2.12    (2.78 
General and administrative  (0.72  (0.68  (0.79  (1.13 
Interest and finance costs  (0.68  (0.71  (0.71  (0.66 
Decommissioning expenditures  (0.01    (0.03   
Funds flow per Boe  5.00    6.94    6.37    8.09   

Barrels of oil equivalent per day (6:1) 
23,935     19,923    23,941    19,873   
Natural gas production         
  Thousand cubic feet per day  114,772    97,510    115,365    97,026   
  Price (Cdn$ per Mcf)(1)  2.23    2.64    2.39    3.55   
Condensate production         
  Barrels per day  2,305    2,081    2,464    2,140   
  Price (Cdn$ per barrel)(1)  25.92    71.12    44.41    66.85   
NGL production         
  Barrels per day  2,501    1,591    2,249    1,563   
  Price (Cdn$ per barrel)(1)  6.23    4.87    4.92    17.83   
Wells drilled (net)      1.0    5.0   
Wells completed (net)      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 25 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. 


PRESIDENT'S MESSAGE

2020 SECOND QUARTER HIGHLIGHTS

The considerable efforts made by Storm’s employees mitigated the many impacts of the COVID-19 pandemic on the business. Compared to last year, production grew by 20% and there was a large realized hedging gain, however, this was offset by lower natural gas and condensate prices which reduced revenue. Production costs showed a significant improvement as a result of the start-up of the Nig Creek Gas Plant in February 2020. With capital expenditures minimized in the quarter, debt was reduced by $8.3 million from the previous quarter. 

  • Production was 23,935 Boe per day, effectively unchanged from the previous quarter and an increase of 20% year over year. This was consistent with guidance for production to average 23,000 to 25,000 Boe per day. Year to date, three wells (3.0 net) have started production, all at West Umbach.
  • Liquids production (condensate plus NGL) totaled 4,806 barrels per day, an increase of 4% from the previous quarter and an increase of 31% year over year. Liquids as a proportion of total production has increased as a result of higher NGL recoveries at the Nig Creek Gas Plant which started up in February 2020.
  • The benefits of the Nig Creek Gas Plant were realized with corporate production costs declining by 31%, or $1.39 per Boe, from last year while higher liquids recovery added approximately 500 barrels per day. The Nig Creek area represented 36% of corporate production while providing 60% of field operating income before hedging.
  • Production from the Nig Creek wells continues to meet or exceed expectations with declines from the upper/mid Montney being shallower than expected while the first well in the lower Montney has a higher field condensate rate. The four most recent wells started production in November 2019 with rates over the first eight months averaging approximately 1,550 Boe per day sales (100 barrels per day field condensate) for the three wells in the upper/mid and approximately 875 Boe per day sales (170 barrels per day field condensate) for the lower.
  • Revenue was $13.86 per Boe, a 33% decline from last year mainly due to lower condensate and natural gas prices. The condensate price declined 64% as a result of the collapse in the WTI price (partially offset by a hedging gain). The natural gas price declined 16% as a result of declines in the Chicago and Sumas prices (66% of sales) which more than offset an increase in the AECO and BC Station 2 prices (29% of sales).
  • Liquids increased to 20% of sales volumes (from 18% last year); however, the proportion of production revenue from liquids decreased to 23% from 38% last year as a result of the decline in the condensate price.
  • Production, general and administrative, and interest and finance costs were $5.90 per Boe, a year-over-year decrease of $1.38 per Boe as a result of lower production costs resulting from the start-up of the Nig Creek Gas Plant in February.
  • Hedging provided a realized gain of $6.5 million versus a realized loss of $0.4 million in the prior year. The majority of the gain, $4.9 million, was from WTI crude oil contracts.
  • Funds flow was $10.9 million, or $0.09 per share, a decrease of $1.7 million from last year as a result of lower revenue per Boe which more than offset production growth, lower production costs per Boe and the hedging gain.
  • Net loss was $11.7 million with the largest contributor to the decrease from net income of $7.9 million last year being an unrealized hedging loss (non-cash) of $13.8 million which represents the change in the value of future hedging contracts. 
  • Capital investment was $2.4 million (within guidance for less than $3 million) and included $1.5 million to complete the Nig Creek Gas Plant project.
  • Total debt including working capital deficiency was $130 million which is 3.0 times annualized quarterly funds flow. As part of the annual review, the bank line was voluntarily reduced to $190 million (from $205 million) in order to reduce the associated fees.
  • The undiscounted and inflated decommissioning liability totaled $35.4 million. The liability for currently inactive wells and facilities is approximately $10 million with approximately 75% of this expected to be incurred by 2025.

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 121,000 net acres (172 net sections) with 79 horizontal wells (74.4 net) drilled to the end of the second quarter.

Field activity in the second quarter was minimal while activity in the second half of the year will include drilling four (4.0 net) horizontal wells at the Nig Creek area in the third quarter which are planned for completion and tie-in early in the fourth quarter. In addition, there are three contingent horizontal wells (3.0 net) planned for the Umbach area in the fourth quarter depending on commodity prices and forecasted funds flow.

At the end of the quarter, there were four (2.5 net) drilled Montney horizontal wells that had not started producing which included two (1.0 net) completed wells, both at Fireweed.

At Umbach (average 90% working interest), produced raw natural gas contains 1.2% H2S with approximately 80% directed to the McMahon Gas Plant and 20% to the Stoddart Gas Plant. Firm processing commitments total 80 Mmcf raw gas per day (65 Mmcf per day at McMahon and 15 Mmcf per day at Stoddart). There remains significant capacity for future growth given second quarter volumes averaged 83 Mmcf per day raw which is significantly less than field compression capacity at 150 Mmcf per day raw gas. 

At Nig Creek (100% working interest), produced raw natural gas contains 0.1% H2S and is directed to the 50 Mmcf per day sour gas plant that started up in February 2020. During the second quarter, inlet volumes averaged 43 Mmcf per day raw, sales were 8,510 Boe per day with liquids at 48 barrels per Mmcf sales, the operating cost for the area was $1.03 per Boe, and the operating netback was $5.77 per Boe ($2.34 per Boe higher than the corporate average). With the decline in the WTI crude oil price in the first half of 2020, the plant has been ‘warmed up’ since mid-April which has reduced NGL recovery by approximately 8 barrels per Mmcf sales (propane and butane). The plant is expected to reach fully capacity in the fourth quarter after the next four wells are drilled and completed (from an existing pad which is already pipeline connected). 

At Fireweed (50% working interest), there was no activity in the quarter as development was deferred on May 12, 2020 by up to one year in response to the collapse in the WTI crude oil price. With the recent improvement in the WTI crude oil price, activity is likely to resume in the first quarter of 2021 with first production in the second half of 2021. There are currently three standing wells (1.5 net) with two wells (1.0 net) having been completed. Based on production history from offsetting horizontal wells, first year average field condensate-gas ratios are expected to be 30 to 70 barrels per Mmcf raw which is 100% to 400% higher than at Umbach. 

A summary of horizontal well results at Nig Creek and Umbach is provided below. IP90 and IP180 rates are less reliable indicators of relative longer-term performance since wells are initially rate restricted to manage fluid rates. 

Year of Completion  Frac
Stages 
Completed
Length 
IP90 Cal Day   IP180 Cal Day   IP365 Cal Day 
Umbach 2017 - 2018
19 hz’s 
34  1895 m  4.6 Mmcf/d(1)
24 Bbls/Mmcf(2)
19 hz’s 
4.4 Mmcf/d(1)
20 Bbls/Mmcf(2)
19 hz’s 
4.0 Mmcf/d(1)
15 Bbls/Mmcf(2)
19 hz’s 
Nig Creek 2018 upper
3 hz’s 
37  2180 m  8.1 Mmcf/d(1)
29 Bbls/Mmcf(2)
3 hz’s 
8.2 Mmcf/d(1)
25 Bbls/Mmcf(2)
3 hz’s 
7.5 Mmcf/d(1)
21 Bbls/Mmcf(2)
3 hz’s 
Nig Creek 2019 upper/mid
3 hz’s 
42  2240 m  8.1 Mmcf/d(1)
20 Bbls/Mmcf(2)
3 hz’s 
7.9 Mmcf/d(1)
15 Bbls/Mmcf(2)
3 hz’s 
 
Year of Completion  Frac
Stages 
Completed
Length 
IP90 Cal Day   IP180 Cal Day  IP365 Cal Day 
Nig Creek 2019 lower
1 hz 
42  2280 m  5.5 Mmcf/d(1)
57 Bbls/Mmcf(2)
1 hz 
4.1 Mmcf/d(1)
49 Bbls/Mmcf(2)
1 hz 
 
Umbach 2020
3 hz’s 
38  2420 m  4.4 Mmcf/d(1)
15 Bbls/Mmcf(2)
3 hz’s 
   
(1)  Raw gas rate. 
(2)  Bbls/Mmcf is the condensate-gas ratio or barrels of field condensate per Mmcf raw. 


Based on results from the 2017 and 2018 wells, Storm management is using 8 Bcf and 14 Bcf raw gas type curves (internal estimates) to forecast production at Umbach and Nig Creek respectively. More detail on well performance and management’s type curve is available in the presentation on Storm’s website at stormresourcesltd.com.

HEDGING

Commodity price hedges are used to support longer-term growth by protecting pricing on up to 50% of current production for the next 18 months and up to 25% for 19 to 36 months forward (future production growth is not hedged). The current hedge position is shown below (excludes price differential contracts which are shown in the financial statements) with hedges for the remainder of 2020 protecting approximately 47% of current production (based on production in the first half of 2020).

  H2/20  2021 
Natural Gas Hedges     
  % Current Nat Gas Production(1)  49%  48% 
  Collars



 
31,800 Mcf/d(2)
Floor Cdn$2.82 per Mcf(3)
Ceiling Cdn$3.06 per Mcf(3) 
8,400 Mcf/d(2)
Floor Cdn$3.83 per Mcf(3)
Ceiling Cdn$4.40 per Mcf(3) 
  Fixed Price

 
24,500 Mcf/d(2)
Cdn$2.97 per Mcf(3) 
46,900 Mcf/d(2)
Cdn$2.89 per Mcf(3) 
Crude Oil Hedges     
  % Current Liquids Production(1)  41%  28% 
  Collars

 
800 Bpd
Floor WTI Cdn$57.81 per barrel
Ceiling WTI Cdn$67.08 per barrel 
650 Bpd
Floor WTI Cdn$50.54 per barrel
Ceiling WTI Cdn$59.93 per barrel 
  Fixed Price



 
950 Bpd
WTI Cdn$59.56 per barrel
200 Bpd Propane
Conway Cdn$28.25 per barrel 
625 Bpd
WTI Cdn$52.64 per barrel
50 Bpd Propane
Conway Cdn$27.30 per barrel 
(1)  Using H1/20 actual production. 
(2)  Using corporate average heat content 1.23 GJ per Mcf and 1.17 Mmbtu per Mcf. 
(3)  Hedges in US$ are converted using an exchange rate of Cdn$1.34 per US$1. 


OUTLOOK

Production in the third quarter of 2020 is forecast to average 19,000 to 21,000 Boe per day which includes the effect of a 28-day planned maintenance turnaround at the McMahon Gas Plant in September plus a 6-day unplanned outage which occurred in July. Approximately 11,000 Boe per day will be affected by the planned and unplanned outages. The financial cost for the outages is estimated to be $2 million which includes unused firm pipeline transportation, natural gas purchased to fulfill marketing commitments related to hedging and unused firm gas processing commitments.

Capital investment in the third quarter is expected to be $10 to $15 million which will include drilling four wells (4.0 net) from an existing pad at Nig Creek plus starting the completions in late September. 

Updated guidance for 2020 is provided below. Forecast production includes the effect of the third quarter outages described above and reduced NGL recovery after ‘warming up’ the Nig Creek Gas Plant. The reduction in forecast annual production reflects the effect of outages in the third quarter being greater than previously anticipated. The increase in fourth quarter production comes from the completion and tie-in of four wells at Nig Creek. Capital investment is intended to be approximately equal to or less than forecast funds flow. Forecast pricing reflects actual prices to date plus the approximate forward strip for the remainder of the year.

2020 Guidance 


 
Previous
May 12, 2020 
Current
August 13, 2020 
Cdn$/US$ exchange rate  0.72  0.74 
Chicago daily natural gas - US$/Mmbtu  $2.05  $1.85 
Sumas monthly natural gas - US$/Mmbtu  $2.20  $2.00 
AECO daily natural gas - Cdn$/GJ  $2.20  $2.00 
BC Station 2 daily natural gas - Cdn$/GJ  $2.15  $1.95 
WTI - US$/Bbl  $30.50  $38.50 
Edmonton condensate diff - US$/Bbl  ($4.50)  ($3.50) 
Est revenue net of transport (excl hedges) - $/Boe  $12.00 - $13.00  $12.00 - $12.50 
Est production costs - $/Boe  $4.50 - $4.75  $4.50 - $4.75 
Est royalty rate (% revenue net transportation)  5% - 6%  5% - 6% 
Est mid-point field operating netback - $/Boe(1)  $7.20  $6.70 
Est realized hedging gains or (losses) - $ million  $11.0 - $12.0  $10.0 - $11.0 
Est cash G&A - $ million   $6.0 - $7.0  $6.0 - $7.0 
Est interest expense - $ million  $7.0 - $8.0  $7.0 - $8.0 
Est capital investment (excluding A&D) - $ million

 
$52.0 - $60.0
(Nig Crk GP $12.0 million) 
$52.0 - $60.0
(Nig Crk GP $12.0 million) 
Forecast fourth quarter Boe/d
Forecast fourth quarter liquids Bbls/d 
25,000 - 28,000
5,100 - 5,600 
25,000 - 28,000
5,100 - 5,600 
Forecast annual Boe/d
Forecast annual liquids Bbls/d 
23,500 - 26,000
4,500 - 5,000 
22,500 - 24,000
4,300 - 4,800 
Est annual funds flow - $ million  $59.0 - $66.0(2)  $53.0 - $57.0(2) 
Horizontal wells drilled - gross
Horizontal wells completed - gross
Horizontal wells starting production - gross 
6 - 9 (5.0 - 8.0 net)
8 (7.5 net)
7 (7.0 net) 
6 - 9 (5.0 - 8.0 net)
8 (7.5 net)
7 (7.0 net) 
(1)  Based on the mid-point for each of revenue net of transportation, royalty rate and production costs. 
(2)  Based on the range for forecast annual production and using the mid-point for each of the estimated field operating netback, estimated cash G&A, estimated hedging gain or loss and estimated interest expense. 


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 12, 2019  $2.45  $1.60  $54.00  $75.0 - $90.0  not provided  24,000 - 26,000 
Feb 27, 2020  $1.90  $1.65  $50.50  $75.0 - $85.0  $62.0 - $69.0  23,500 - 26,000 
May 12, 2020  $2.05  $2.15  $30.50  $52.0 - $60.0  $59.0 - $66.0  23,500 - 26,000 
Aug 13, 2020  $1.85  $1.95  $38.50  $52.0 - $60.0  $53.0 - $57.0  22,500 - 24,000 


Capital investment in 2020 will be allocated as follows:

  • $7 million at Fireweed to drill two horizontal wells (1.0 net), complete one well (0.5 net); and start construction of the associated road and facility site;
  • $33 million at Nig Creek includes $12 million to complete the gas plant (100% working interest), drill four horizontal wells (4.0 net) and complete and pipeline connect four wells (4.0 net); and
  • $12 - $20 million at Umbach to complete and pipeline connect three horizontal wells (3.0 net) plus drill three horizontal wells (3.0) which are contingent on commodity prices and forecast funds flow.

Firm pipeline capacity and marketing arrangements are expected to result in approximately 54% of forecast natural gas production in 2020 being sold into Chicago, 19% at AECO, 14% at BC Station 2, 9% at Sumas and 4% at Alliance ATP.

Liquids production in the second quarter was reduced as much as possible after the collapse in the WTI price triggered by the COVID-19 pandemic and the subsequent effect on condensate and NGL prices. This was mainly done by curtailing wells with higher condensate-gas ratios in April and May when prices were the lowest and by ‘warming up’ the Nig Creek Gas Plant to reduce NGL recovery. Condensate production is no longer being curtailed since the price has improved significantly since the low in May; however, further improvement in propane prices is required before NGL recovery is maximized at the Nig Creek Gas Plant.

The decline in Storm’s natural gas price in the first half of 2020 is largely from having 66% of sales into US markets at Chicago and Sumas where average prices declined by approximately 30% from last year and has more than offset a large improvement in Western Canadian natural gas prices at AECO and BC Station 2. This is a reverse of the situation from mid-2017 to late 2019 where higher Chicago and Sumas prices more than offset weak Western Canadian prices. Future sales are expected to become more balanced between US and Western Canadian markets as incremental production growth is directed to BC Station 2, expiry of the sales commitment at Sumas occurs in October 2020, and Storm has the option every year to renew all or a lesser amount of the capacity to Chicago. Storm’s natural gas marketing strategy will continue to be based on diversifying sales as much as possible to mitigate regional price differences caused by supply/demand imbalances that are difficult to predict in terms of timing and duration. 

Results from the first lower Montney horizontal well at Nig Creek are encouraging in terms of adding a second layer for development where condensate represents a higher proportion of production. The economics are currently being evaluated and, with less natural gas and more condensate, the WTI price will have the greatest effect on the timing and pace of development.

The improvement in the WTI price since May supports restarting development at Fireweed which could add approximately $30 million to capital investment mainly in 2021. This was the amount that would have been invested in 2020 before the decision was made to delay development up to one year after the collapse in the WTI price. A final decision on restarting development, along with details around timing for capital investment and first production, will be provided when third quarter results are released in mid-November. 

Given the recent volatility in commodity prices and continuing uncertainty in the world with respect to the longer-term financial effects from COVID-19, the plan for the second half of 2020 is to remain cautious by ensuring capital investment is less than or equal to funds flow. Although activity is being limited in 2020, forecast average production is still expected to grow by approximately 15% to 20% year over year. 

The efforts of everyone at Storm in successfully managing the many operational and personal challenges caused by the ongoing COVID-19 pandemic have allowed for a seamless transition to a new business environment and are greatly appreciated. 

Financial results are expected to improve significantly in the fourth quarter of 2020 and into 2021 based on higher forward strip prices which are expected to provide a ‘tailwind’ (instead of the ‘headwind’ since early 2019 resulting from declining commodity prices) and with the financial benefits being realized from the Nig Creek Gas Plant.

Respectfully,

Brian Lavergne,
President and Chief Executive Officer

Source: EvaluateEnergy® ©2024 EvaluateEnergy Ltd