HIGHLIGHTS & OUTLOOK
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 price with new annual marketing agreements commencing in April (price declined by 85% 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 Alliance Pipeline totaling 12 days reduced production by approximately 9% or 2,000 Boe per day.
- Liquids production (field condensate plus gas plant NGL) increased by 6% year over year and represented 18% of total production and 38% of production revenue.
- At the Nig land block, the first three wells have been producing for more than twelve months with the first year calendar day rate averaging 1,415 Boe per day sales (21% 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 Mcf, or $1.54 per Mcf after deducting transportation costs, which was significantly higher than Western Canadian pricing (Station 2 $0.57 per GJ and AECO $0.98 per GJ). Realized price was reduced by approximately 10% as the 12 days of outages reduced sales into the higher priced Chicago market by 11%.
- Controllable cash costs including transportation, production, general and administrative, and interest were $13.24 per Boe in the quarter and consistent with $13.11 per Boe in the prior year. Outages during the quarter increased cash costs per Boe by approximately 7% (unused firm transportation plus less production to cover fixed production costs).
- Funds flow was $12.6 million, or $0.10 per share, a decrease of 47% on a per-share basis year over year with the decrease largely the result of lower pricing (natural gas -16%, condensate -18%, NGL -87%).
- 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%, invested into future growth (Nig gas plant $15.4 million and 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% utilization of the $205 million bank line.
- Commodity price hedges currently protect approximately 39% of forecast production for the remainder of 2019.
- Return on capital employed was 11% and cash return on capital employed was 18%, both on a 12-month trailing basis.
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 August 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% 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 $0.64 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 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 $45 million with approximately 70% allocated to the Nig gas plant.
Updated guidance for 2019 is provided below. Changes include reducing capital investment in response to the ongoing decline in natural gas prices, reducing forecast annual production while increasing estimated operating costs to reflect the multiple outages (total of 43 days), and updating forecast pricing to reflect actual prices to date plus the approximate forward strip for the remainder of the year.
May 14, 2019
August 13, 2019
|Cdn$/US$ exchange rate||0.76||0.755|
|Chicago daily natural gas – US$/Mmbtu||$2.65||$2.45|
|Sumas monthly natural gas – US$/Mmbtu||$3.40||$3.40|
|AECO daily natural gas – Cdn$/GJ||$1.65||$1.55|
|Station 2 daily natural gas – Cdn$/GJ||$1.20||$1.00|
|WTI – US$/Bbl||$55.00||$55.00|
|Edmonton condensate diff – US$/Bbl||-$5.50||-$5.10|
May 14, 2019
August 13, 2019
|Est revenue net of transport (excl hedges) – $/Boe||$17.75 – $18.25||$16.50 – $17.00|
|Est operating costs – $/Boe||$5.50 – $5.75||$5.75 – $6.00|
|Est royalty rate (% revenue net transportation)||5% – 7%||5% – 7%|
|Est mid-point field operating netback – $/Boe||$11.30||$9.87|
|Est hedging loss – $ million||$8.0 – $10.0||$4.0 – $5.0|
|Est cash G&A – $ million||$6.0 – $7.0||$6.0 – $6.5|
|– $/Boe||$0.66 – $0.91||$0.75 – $0.89|
|Est interest expense – $ million||$5.5 – $6.5||$5.5 – $6.5|
|Est capital investment (excl A&D) – $ million||$128.0||$110.0|
|Forecast fourth quarter production – Boe/d
|23,000 – 25,000
|23,000 – 25,000
|Forecast annual production – Boe/d
|21,000 – 24,000
|20,000 – 22,000
|Est annual funds flow – $ million||$65.0 – $77.0(1)||$55.0 – $61.0(1)|
|Horizontal wells drilled – gross
Horizontal wells completed – gross
Horizontal wells starting production – gross
|9 (7.5 net)
11 (9.5 net)
9 (9.0 net)
|9 (7.5 net)
8 (6.5 net)
7 (7.0 net)
(1) 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.
|Nov 13, 2018||$2.50||$1.25||$60.00||$128.0||$72.0 – $88.0||21,000 – 24,000|
|Feb 28, 2019||$2.60||$1.25||$55.00||$128.0||$67.0 – $79.0||21,000 – 24,000|
|May 14, 2019||$2.65||$1.20||$55.00||$128.0||$65.0 – $77.0||21,000 – 24,000|
|Aug 13, 2019||$2.45||$1.00||$55.00||$110.0||$55.0 – $61.0||20,000 – 22,000|
Natural gas prices have declined since last winter with US 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% to as much as 45% 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 ongoing and 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% to 20% 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 forecasted 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% of capital investment in 2019 is being directed towards 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.
Funding for growth from Nig and Fireweed will come from re-investing 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% and using the first year average calendar day rate of 1,415 Boe per day 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 per-Boe operating costs 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 $1.25 per GJ, WTI US$55 per barrel and a Cdn$/US$ 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).