10:12:02 EST Sun 15 Dec 2019
Enter Symbol
or Name

Storm Resources Ltd
Symbol SRX
Shares Issued 121,556,812
Close 2019-08-13 C$ 1.60
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Storm Resources earns $7.86-million in Q2

2019-08-13 19:53 ET - News Release

Mr. Brian Lavergne reports


Storm Resources Ltd. has released its financial and operating results for the three and six months ended June 30, 2019. Storm has also filed its unaudited condensed interim consolidated financial statements as at June 30, 2019, and for the three and six months then ended, along with its management's discussion and analysis (MD&A) for the same period. This information appears on SEDAR and on Storm's website.

Selected financial and operating information for the three and six months ended June 30, 2019, appears herein and should be read in conjunction with the related financial statements and MD&A.

             (in thousands of dollars, except volumetric and per-share amounts)

                                      Three months to June 30,         Six months to June 30,
                                           2019          2018            2019           2018
Revenue from product sales (1)        $  37,568     $  48,104       $  93,334     $  100,206
Funds flow                               12,590        23,405          29,107         46,924
Per share -- basic and
diluted ($)                                0.10          0.19            0.24           0.39
Net income (loss)                         7,864        (2,815)          8,471          6,079
Per share -- basic and
diluted ($)                                0.06         (0.02)           0.07           0.05
Cash return on capital
employed (CROCE) (2)                        18%           19%             18%            19%
Return on capital
employed (ROCE) (2)                         11%            4%             11%             4%
Capital expenditures                     23,145         2,918          40,089         25,818
Debt including working
capital deficiency (2)(3)               102,268        85,073         102,268         85,073
Operations ($ per boe)
Revenue from product sales (1)            20.72         27.07           25.95          28.22
Transportation costs                      (5.96)        (6.25)          (5.84)         (5.92)
Revenue net of transportation             14.76         20.82           20.11          22.30
Royalties                                 (0.32)        (1.11)          (1.46)         (1.41)
Production costs                          (5.89)        (5.46)          (5.99)         (5.51)
Field operating netback (2)                8.55         14.25           12.66          15.38
Realized (loss) gain on
risk management contracts                 (0.22)         0.31           (2.78)         (0.44)
General and administrative                (0.68)        (0.69)          (1.13)         (1.05)
Interest and finance costs                (0.71)        (0.71)          (0.66)         (0.68)
Funds flow per boe                         6.94         13.16            8.09          13.21
Barrels of oil equivalent
per day (6:1)                            19,923        19,529          19,873         19,618
Natural gas production
Thousand cubic feet per day              97,510        96,426          97,026         96,248
Price ($ per mcf) (1)                      2.64          3.15            3.55           3.49
Condensate production
Barrels per day                           2,081         1,984           2,140          2,023
Price ($ per barrel) (1)                  71.12         86.33           66.85          81.15
NGL production
Barrels per day                           1,591         1,473           1,563          1,554
Price ($ per barrel) (1)                   4.87         36.43           17.83          34.66
Wells drilled (net)                           -             -             5.0              -
Wells completed (net)                         -             -               -            3.0

(1) Excludes gains and losses on risk management contracts.
(2) Certain financial amounts shown herein are non-GAAP (generally accepted accounting 
    principles) measurements.
(3) Excludes the fair value of risk management contracts and lease liability.

President's message

2019 second quarter highlights

  • Funds flow decreased year over year, primarily as a result of production being reduced by 12 days of planned third party outages, a decline in natural gas prices and a lower NGL (natural gas liquids) price with new annual marketing agreements commencing in April (price declined by 85 per cent from the first quarter). Activity included commencing construction of the Nig gas plant and starting completion of a four-well pad at Nig which is evaluating different intervals in the Montney (two wells in the upper, one in the mid and one in the lower).
  • Production was largely unchanged year over year and was consistent with the low end of guidance for the quarter. Planned third party outages at the McMahon gas plant and the Alliance pipeline totalling 12 days reduced production by approximately 9 per cent or 2,000 barrels of oil equivalent (boe) per day.
  • Liquids production (field condensate plus gas plant NGL) increased by 6 per cent year over year and represented 18 per cent of total production and 38 per cent of production revenue.
  • At the Nig land block, the first three wells have been producing for more than 12 months, with the first-year calendar day rate averaging 1,415 boe per day sales (21 per cent liquids including liquids recovered at the gas plant). Flow test results from the recently completed four wells appear to be consistent with the first three wells, with the lower Montney well having the highest condensate-gas ratio (flow tests are short duration and not reliable indicators of future performance).
  • Diversified natural gas sales resulted in the realized price averaging $2.64 per thousand cubic feet, or $1.54 per thousand cubic feet after deducting transportation costs, which was significantly higher than Western Canadian pricing (Station 2 -- 57 cent per gigajoule, AECO -- 98 cents per GJ). Realized price was reduced by approximately 10 per cent as the 12 days of outages reduced sales into the higher-priced Chicago market by 11 per cent.
  • Controllable cash costs, including transportation, production, general and administrative, and interest, were $13.24 per boe in the quarter, consistent with $13.11 per boe in the prior year. Outages during the quarter increased cash costs per boe by approximately 7 per cent (unused firm transportation plus less production to cover fixed production costs).
  • Funds flow was $12.6-million, or 10 cents per share, a decrease of 47 per cent on a per-share basis year over year, with the decrease largely the result of lower pricing (natural gas -- 16 per cent, condensate -- 18 per cent, NGL -- 87 per cent).
  • Net income of $7.9-million was an increase from a net loss of $2.8-million in the prior year, with the improvement largely from a non-cash mark-to-market gain on hedging ($9.6-million) that was partially offset by a non-cash deferred income tax expense ($2.5-million).
  • Capital investment was $23-million, which included $12-million for the Nig gas plant plus $8-million to begin completions on a four-well pad at Nig. Investment was higher than guidance of $15-million to $20-million as a result of advancing the timing of well completions at Nig which were originally budgeted for the third quarter of 2019.
  • Year-to-date capital investment is $40.1-million, with $17.3-million, or 43 per cent, invested into future growth (Nig gas plant -- $15.4-million, Fireweed -- $1.9-million).
  • Debt including the working capital deficiency was $102-million, or 2.0 times annualized quarterly funds flow, and represents approximately 50-per-cent utilization of the $205-million bank line.
  • Commodity price hedges currently protect approximately 39 per cent of forecast production for the remainder of 2019.
  • Return on capital employed was 11 per cent and cash return on capital employed was 18 per cent, both on a 12-month trailing basis.

Operations review

Umbach, Nig and Fireweed areas, northeast British Columbia

Storm's land position is prospective for liquids-rich natural gas from the Montney formation and totalled 121,000 net acres (172 net sections) at the end of the quarter.

Most of the land position is delineated with the 78 horizontal wells (73.9 net) drilled to date by Storm and by multiple producing horizontal wells on adjacent lands. The majority of the horizontal wells in the area have been drilled in the upper part of the Montney formation.

Second quarter field activity included commencing construction of the Nig gas plant and starting the completion of a pad with four horizontal wells (4.0 net) at Nig. The four-well pad at Nig is testing different intervals in the Montney, with two wells in the upper, one well in the mid and one well in the lower.

At the end of the quarter, there was an inventory of nine drilled Montney horizontal wells (8.5 net) that had not started producing, which included one completed well (0.5 net). During the quarter, one well (1.0 net) started production.

Field activity in the second half of 2019 will be focused on the Nig area and will include constructing the 50-million-cubic-foot-per-day sour gas plant, drilling and completing an acid gas injection well, constructing a sales gas pipeline, and finishing the completion and tie-in of a four-well pad at Nig.

At Umbach (100-per-cent working interest), production in the quarter averaged 16,494 boe per day, with 18 per cent liquids, and was reduced by 12 days of planned third party outages. There are currently four standing wells (4.0 net) with none having been completed. Produced raw natural gas is sour (1.2 per cent hydrogen sulphide (H2S)), with approximately 85 per cent directed to the McMahon gas plant and 15 per cent to the Stoddart gas plant. Firm processing commitments total 80 million cubic feet raw gas per day (65 million cubic feet per day at McMahon plus 15 million cubic feet per day at Stoddart). Field compression capacity totals 150 million cubic feet per day of raw gas, with throughput in the second quarter reduced by 12 days of outages and averaging 106 million cubic feet per day of raw gas (includes 18 million cubic feet per day raw from Nig). Growth at Umbach, where there is unused field compression capacity, depends on the natural gas price at Station 2.

At Nig (100-per-cent working interest), production in the quarter averaged 3,362 boe per day, with 18 per cent liquids, and was reduced by 12 days of planned third party outages plus 12 days where the wells were shut in for completion of the adjacent four-well pad. There are currently four standing and completed wells (4.0 net) which will be pipeline connected by the end of September. Produced raw natural gas contains approximately 0.2 per cent H2S. The 50-million-cubic-foot-per-day sour gas plant that is currently under construction is expected to be completed in January, 2020, with the total estimated cost being $81-million ($11.4-million invested in 2018 and the remainder to be invested in 2019). This includes $73-million for the gas plant, $4-million for an acid gas injection well and $4-million for a sales pipeline. Total sales from the gas plant are expected to be 10,500 boe per day with an estimated operating cost of less than $2 per boe (reduces corporate operating cost to approximately $4.25 per boe). Liquids is forecast to be 27 per cent of total production (43 per cent condensate, 57 per cent NGL).

At Fireweed (50-per-cent working interest), approximately $7-million (net) will be invested in 2019, primarily to drill and complete one horizontal well (0.5 net) and for equipment deposits for a field compression facility. Depending on the timing for regulatory approvals, construction is anticipated to begin in 2020 with start-up in the second half of 2020. The total estimated cost of the facility is $34-million (gross) and it is designed to be expandable to 100 million cubic feet per day. Preliminary planning for 2020 includes net investment of approximately $50-million to $55-million to drill and complete eight horizontal wells (4.0 net) and construct the field compression facility. There is currently one standing well (0.5 net) that was completed in 2018 with a length of 1,520 metres (36 frac stages) that averaged 10.9 million cubic feet per day of raw gas, 660 barrels per day of field condensate and 1,140 barrels per day of frac water, with a final flowing casing pressure of 4,800 kilopascals over the last 12 hours of a six-day cleanup. Based on production history from offsetting horizontal wells, first-year average field condensate-gas ratios are expected to be 30 to 70 barrels per million cubic feet raw, which is 100 per cent to 400 per cent higher than at Umbach. Production exiting 2020 is forecast to be over 4,000 boe per day net to Storm, with 25 per cent liquids (67 per cent condensate, 33 per cent NGL).

A summary of horizontal well results at Nig and Umbach is provided in the accompanying table. Note that IP90 (initial production over 90 days) and IP180 (initial production over 180 days) rates are not reliable indicators of relative performance, as wells are initially rate restricted for several months to manage fluid rates. In addition, recent wells have been affected by outages totalling 43 days to date in 2019.

                           Frac      Completed
Year of completion       stages         length     IP90 cal. day       IP180 cal. day       IP365 cal. day

Umbach 2014 to 2016          22        1,350 m        4.9 mmcf/d (2)       4.3 mmcf/d (2)       3.4 mmcf/d (2)
33 hz's (1)                                          19 bbl/mmcf (3)      16 bbl/mmcf (3)         bbl/mmcf (3)
                                                         33 hz's           33 hz's 13              33 hz's

Umbach 2017 to 2018          34        1,895 m        4.6 mmcf/d (2)       4.3 mmcf/d (2)       4.3 mmcf/d (2)
19 hz's                                              24 bbl/mmcf (3)         bbl/mmcf (3)      14 bbl/mmcf (3)
                                                      18 hz's 20              16 hz's              12 hz's

Nig 2018                     37        2,180 m        8.1 mmcf/d (2)       8.2 mmcf/d (2)       7.5 mmcf/d (2)
3 hz's                                               29 bbl/mmcf (3)      25 bbl/mmcf (3)      21 bbl/mmcf (3)
                                                          3 hz's               3 hz's               3 hz's

(1) The 2014 to 2016 wells exclude a middle Montney well (this table provides analysis of upper Montney wells 
(2) Raw gas rate.
(3) Bbl/mmcf is the condensate-gas ratio or barrels of field condensate per million cubic feet raw.

Based on results from the 2017 and 2018 wells, Storm management is using 8.5-billion-cubic-foot and 14-billion-cubic-foot raw gas type curves (internal estimates) to forecast production at Umbach and Nig respectively. More detail on well performance and management's type curve is available in the presentation on Storm's website.

Hedging and transportation

Commodity price hedges are used to support longer-term growth, with the objective being to protect pricing on 50 per cent of current production for the next 12 months and 25 per cent for 13 to 24 months forward (future production growth is not hedged). Approximately 80 per cent of Storm's liquids production (condensate and butane) is priced in reference to WTI (West Texas Intermediate). The current hedge position protects approximately 39 per cent of forecast production for the remainder of 2019.

Q3 to Q4 2019      Crude oil       850 bpd             WTI $73.28/bbl floor, $87.95/bbl ceiling
                                   650 bpd             WTI $81.51/bbl
                   Propane         200 bpd             Conway $42.87/bbl
                   Natural gas     38,000 mmbtu/d 
                                  (32.0 mmcf/d)        Chicago $3.24/mmbtu
                                   8,500 mmbtu/d 
                                  (7.2 mmcf/d)         Sumas $2.67/mmbtu                          
                                   500 GJ/d 
                                  (0.4 Mmcf/d)         AECO $2.00/GJ
2020               Crude oil       200 bpd             WTI $76.35/bbl floor, $85.06/bbl ceiling

                   Natural gas     10,750 mmbtu/d 
                                  (9.1 mmcf/d)         Chicago $3.32/mmbtu                        
                                   375 GJ/d 
                                  (0.3 mmcf/d)         AECO $2.00/GJ                              

Note: The Alliance pipeline tariff to Chicago is approximately $1.20 per mmbtu including the cost of fuel.

In addition to the commodity price hedges shown in the table, there are also condensate and natural gas price differential swaps.

Q3 to Q4 2019               400 bpd                    Edm. condensate WTI -- $6.13/bbl

2020                        200 bpd                    Edm. condensate WTI -- $8.00/bbl
                            12,500 mmbtu/d 
                           (10.6 mmcf/d)               NYMEX -- Chicago -- U.S.$0.27/mmbtu  

Firm transportation commitments for natural gas provide sales diversification and are summarized in the accompanying table.

Alliance to Chicago (1)                       56 to 70 mmcf/d
Enbridge T-north to Station 2                       16 mmcf/d
Enbridge T-north and TCPL to AECO                   13 mmcf/d
Enbridge T-north to Station 2/Sumas (2)             12 mmcf/d
Alliance to ATP                                      5 mmcf/d
Total                                       102 to 116 mmcf/d

(1) When available, preferential interruptible service (PITS) 
    adds up to 14 million cubic feet per day of capacity on 
    the Alliance pipeline.
(2) Sumas price less 69 U.S. cents per mmbtu (million British
    thermal units).

In the second quarter, 56 per cent of natural gas sales were at a Chicago price, 32 per cent at Western Canadian pricing and 12 per cent at the Sumas price less a marketing adjustment. Production exceeding firm capacity is directed to Chicago and/or Station 2 on an interruptible basis depending on which sales point offers a higher net price.


Production in the third quarter of 2019 is expected to average 18,000 to 20,000 boe per day and includes the effect of an unplanned outage at the McMahon gas plant from July 30 to Aug. 12 which was required to repair piping leaks and resulted in approximately 16,000 boe per day being shut in. This is the third outage at the McMahon gas plant in 2019, which has resulted in approximately 77 per cent of corporate production being shut in for a total of 37 days (completing the gas plant at Nig will diversify processing, which significantly reduces the effect of future outages). In addition, production in 2019 has also been frequently reduced to a level that fulfills firm transportation and processing commitments as a result of low Western Canadian natural gas prices (July averaged 64 cents per GJ at Station 2 and $1.23 per GJ at AECO) in order to avoid selling production below its replacement cost. Western Canadian natural gas prices are not expected to improve in the near term given numerous maintenance outages scheduled on the NGTL and Enbridge T-south pipeline systems this summer. Capital investment in the third quarter is estimated to be $45-million, with approximately 70 per cent allocated to the Nig gas plant.

Updated guidance for 2019 is provided in the accompanying table. Changes include: reducing capital investment in response to the continuing decline in natural gas prices; reducing forecast annual production while increasing estimated operating costs to reflect the multiple outages (total of 43 days); and updating forecast pricing to reflect actual prices to date plus the approximate forward strip for the remainder of the year.

                                              2019 GUIDANCE
                                                     Previous May 14, 2019              Current Aug. 13, 2019

$/US$ exchange rate                                                   0.76                              0.755
Chicago daily natural gas -- U.S.$/mmbtu                             $2.65                              $2.45
Sumas monthly natural gas -- U.S.$/mmbtu                             $3.40                              $3.40
AECO daily natural gas -- $/GJ                                       $1.65                              $1.55
Station 2 daily natural gas -- $/GJ                                  $1.20                              $1.00
WTI -- U.S.$/bbl                                                    $55.00                             $55.00
Edmonton condensate diff. -- U.S.$/bbl                              -$5.50                             -$5.10
Est. revenue net of transport
(excl. hedges) -- $/boe                                   $17.75 to $18.25                   $16.50 to $17.00
Est. operating costs -- $/boe                               $5.50 to $5.75                     $5.75 to $6.00
Est. royalty rate (% revenue
net transportation)                                               5% to 7%                           5% to 7%
Est. midpoint field operating
netback -- $/boe                                                    $11.30                              $9.87
Est. hedging loss -- $ million                               $8.0 to $10.0                       $4.0 to $5.0
Est. cash G&A -- $ million                                    $6.0 to $7.0                       $6.0 to $6.5
Est. cash G&A -- $/boe                                      $0.66 to $0.91                     $0.75 to $0.89
Est. interest expense -- $ million                            $5.5 to $6.5                       $5.5 to $6.5
Est. capital investment (excl.
A&D) -- $ million                                                   $128.0                             $110.0
Forecast fourth quarter   
production -- boe/d, % liquids                       23,000 to 25,000, 18%              23,000 to 25,000, 18%
Forecast annual production --
boe/d, % liquids                                     21,000 to 24,000, 18%              20,000 to 22,000, 18%
Est. annual funds flow -- $ million                         $65.0 to $77.0 (1)                 $55.0 to $61.0 (1)
Horizontal wells drilled -- gross                               9 (7.5 net)                        9 (7.5 net)
Horizontal wells completed -- gross                            11 (9.5 net)                        8 (6.5 net)
Horizontal wells starting
production -- gross                                             9 (9.0 net)                        7 (7.0 net)

(1) Based on the range for forecast annual production and using the midpoint for each of the estimated field 
    operating netback, estimated cash G&A (general and administrative), estimated hedging gain or loss, and 
    estimated interest expense.

                                               GUIDANCE HISTORY

                     Chicago    Station 2                     Capital    Forecast annual      Forecast annual
                       daily        daily          WTI     investment         funds flow           production)
                (U.S.$/mmbtu)       ($/GJ)  (U.S.$/bbl)    ($ million)        ($ million)              (boe/d)

Nov. 13, 2018          $2.50        $1.25       $60.00         $128.0      $72.0 to $88.0    21,000 to 24,000
Feb. 28, 2019          $2.60        $1.25       $55.00         $128.0      $67.0 to $79.0    21,000 to 24,000
May 14, 2019           $2.65        $1.20       $55.00         $128.0      $65.0 to $77.0    21,000 to 24,000
Aug. 13, 2019          $2.45        $1.00       $55.00         $110.0      $55.0 to $61.0    20,000 to 22,000

Natural gas prices have declined since last winter, with U.S. natural gas prices reduced by supply growing faster than demand (primarily weather related, with the milder start to the summer reducing natural gas used for electric power generation), while Western Canadian natural gas prices have been reduced by recurring restrictions or outages for pipeline maintenance exacerbating an oversupply situation. There are indications that the oversupply in Western Canada may be shrinking given the recent narrowing of the NYMEX-AECO price differential.

Since the failure on the Enbridge T-south natural gas pipeline in October, 2018, throughput has decreased by 15 per cent to as much as 45 per cent when engineering assessments are being conducted. This has reduced the Station 2 price in relation to AECO. There is currently no certainty on if, or when, capacity can be restored, although engineering assessments are continuing and are expected to be completed by late August, 2019, with review of the results by the National Energy Board expected by November, 2019. Until capacity is restored or until the NGTL North Montney extension into northeast British Columbia is in service (fourth quarter of 2019), the Station 2 price is expected to remain depressed in relation to AECO. The financial effect on Storm has not been material given that typically 15 per cent to 20 per cent of total natural gas sales are at Station 2.

Capital investment in 2019 has been reduced to $110-million from $128-million as a result of the challenges experienced to date in 2019 from both the decline in natural gas prices and the multiple outages experienced at the McMahon gas plant, which have reduced forecast funds flow. The reduction comes mainly from deferring the completion and tie-in of three horizontal wells at Umbach into mid-2020. Preliminary estimated capital investment for 2020 is $80-million, which is expected to be approximately equal to funds flow. Reducing capital investment will reduce production growth in 2020 but is not expected to affect 2019 production guidance, given that the outages to date in 2019 (43 days total) have effectively resulted in production being deferred, plus the corporate decline rate continues to flatten with improving well performance. Changes to capital investment are the primary method used to preserve a strong balance sheet, given that commodity prices are not controllable.

More than 90 per cent of capital investment in 2019 is being directed toward Nig and Fireweed, with $70-million for the sour gas plant at Nig, $26-million to drill, complete and tie in a four-well pad at Nig, and $7-million at Fireweed.

Financing for growth from Nig and Fireweed will come from reinvesting funds flow exceeding maintenance capital requirements and from available capacity on the bank line. Maintaining corporate production at 20,000 to 22,000 boe per day requires approximately $18-million to drill, complete and tie in three horizontal wells at Nig, based on an estimated corporate decline rate of 20 per cent and using the first-year average calendar day rate of 1,415 boe per day in sales that was achieved by the first three wells at Nig.

In the second half of 2019, debt including working capital deficiency is expected to exceed the targeted level of 1.0 to 1.5 times annualized funds flow during the construction of the Nig gas plant, as the entire $81-million project cost must be invested before any incremental funds flow is realized. After the Nig gas plant is completed, debt to funds flow is expected to return to targeted levels. If required, capital investment in 2020 can be reduced to maintain debt at targeted levels.

The near-term plan continues to be focused on growing funds flow by adding infrastructure at Nig in 2019 to reduce operating costs per boe and increase liquids production, while development at Fireweed in 2020 will grow condensate production. Growth at Umbach is contingent on a higher natural gas price at Station 2. Both Nig and Fireweed offer attractive full-cycle rates of return, assuming Station 2 pricing of $1.25 per GJ, WTI pricing of $55 (U.S.) per barrel and a Canadian-U.S.-dollar exchange rate of 0.76 (see the presentation on Storm's website for further details). Corporate production is forecast to increase to approximately 24,000 boe per day in the fourth quarter of 2019 (4,300 barrels per day of liquids) and to approximately 28,000 boe per day in the fourth quarter of 2020 (6,500 barrels per day of liquids).

We seek Safe Harbor.

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