HIGHLIGHTS & OUTLOOK
2019 First Quarter Highlights
An unplanned 17-day outage at the McMahon Gas Plant in January affected both production and funds flow while capital investment was largely equal to funds flow. Horizontal well performance continues to exceed expectations with declines to date shallower than forecast by management’s type curve. Regulatory approval for the sour gas plant at Nig was received in April with site construction expected to start in May. In April, the bank credit facility was increased to $205 million.
- Production was largely unchanged year over year and was consistent with revised guidance provided January 15, 2019. The unplanned 17-day outage at the McMahon Gas Plant reduced production in the period by approximately 15%, or 3,700 Boe per day (January was 12,765 Boe per day while February and March was 23,530 Boe per day).
- Liquids production (field condensate plus gas plant NGL) totaled 3,733 barrels per day which was largely unchanged year over year and represented 19% of total production, or 30% of production revenue.
- At the end of the quarter, there was an inventory of ten Montney horizontal wells (9.5 net) that had not started producing which included two completed wells (1.5 net). During the quarter, two wells (2.0 net) started production.
- At the Nig land block, the first three wells have been producing for ten to twelve months with declines being minimal over this period. First year calendar day rates are forecast to average 7.7 Mmcf per day raw gas or approximately 1,400 Boe per day sales with 21% liquids (including liquids recovered at the gas plant).
- Diversified natural gas sales resulted in the realized price averaging $4.49 per Mcf, or $3.43 per Mcf after deducting pipeline transportation costs, which was significantly higher than Western Canadian pricing (Station 2 $1.24 per GJ and AECO $2.49 per GJ). Firm pipeline commitments required to diversify natural gas sales also result in a higher gas transportation cost which was $1.06 per Mcf in the quarter.
- Realized hedging loss increased to $9.6 million from $2.1 million in the prior year with the majority of the increase resulting from the increase in the natural gas price at Sumas after a pipeline failure in October 2018 reduced capacity by approximately 20%. For the quarter, Sumas monthly index averaged Cdn$9.06 per Mmbtu versus the hedged price of Cdn$3.35 per Mmbtu.
- Controllable cash costs, including transportation, production, general and administrative and interest, increased to $14.02 per Boe in the quarter from $13.20 per Boe in the prior year with the increase resulting from the unplanned outage at the McMahon Gas Plant.
- Funds flow was $16.5 million, or $0.14 per share, a decrease of 26% on a per-share basis year over year which was largely the result of a higher hedging loss, lower condensate prices, and costs associated with the unplanned outage at the McMahon Gas Plant which were approximately $5.3 million ($0.6 million from increased production costs, $1.2 million from unused firm pipeline transportation and $3.5 million to purchase natural gas that was pre-sold at a monthly index price).
- Capital investment was $16.9 million which included $11.3 million to drill five horizontal wells (5.0 net), including a four-well pad at Nig and $3.4 million to purchase equipment for the gas plant at Nig.
- The balance sheet remains strong with debt including working capital deficiency being $92 million or 1.4 times annualized quarterly funds flow and is a reduction from $106 million last year.
- Subsequent to quarter end, the bank credit facility was increased to $205 million from $180 million.
- Commodity price hedges currently protect approximately 40% of forecast production for the remainder of 2019.
- Return on capital employed was 8% and cash return on capital employed was 20% on a 12-month trailing basis. Cash return on capital employed is a more meaningful measure of profitability given it is not affected by non-cash mark-to-market gains and losses on hedging (non-cash hedging loss in the first quarter was $4.8 million).
Production in April was approximately 21,800 Boe per day based on field estimates with approximately 2,500 Boe per day shut in as a result of low natural gas prices. Production in the second and third quarters of 2019 is expected to average 20,000 to 22,000 Boe per day which includes the impact of a five-day planned maintenance outage at the McMahon Gas Plant in May and a five-day planned maintenance outage on the Alliance Pipeline in June. As a result of the decline in Western Canadian natural gas prices since the end of the winter heating season (April averaged $0.70 per GJ at Station 2 and $0.80 per GJ at AECO), production has been reduced to the minimum level required to fill firm processing and transportation commitments. Prices are not expected to improve until the winter heating season starts in the fourth quarter given numerous maintenance outages scheduled on the NGTL, Alliance and Spectra T-south pipeline systems that will reduce export capacity between May and August. Capital investment in the second quarter is estimated to be $15 to $20 million with approximately 70% allocated to the sour gas plant at Nig.
The failure on the Enbridge T-south natural gas pipeline system in October 2018 has reduced capacity by approximately 20% which has depressed the Station 2 price in relation to AECO while increasing the price at Sumas. To fully restore capacity, inspections are required on various segments and these are expected to be completed by August 2019, however, additional time will also be required for the National Energy Board to complete its review of the results. Until capacity on the T-south pipeline is restored or until the NGTL North Montney extension into northeast British Columbia is in service (possibly early in the fourth quarter of 2019), the Station 2 price is expected to remain depressed in relation to AECO. The financial impact on Storm has not been material given that firm transportation commitments result in less than 15% of produced natural gas being sold at Station 2.
Updated guidance for 2019 is provided below. Pricing has been updated to reflect actual year-to-date prices with pricing for the remainder of 2019 being unchanged.
February 28, 2019
May 14, 2019
|Cdn$/US$ exchange rate||0.76||0.76|
|Chicago daily natural gas – US$/Mmbtu||$2.60||$2.65|
|Sumas monthly natural gas – US$/Mmbtu||$3.10||$3.40|
|AECO daily natural gas – Cdn$/GJ||$1.60||$1.65|
|Station 2 daily natural gas – Cdn$/GJ||$1.25||$1.20|
|WTI – US$/Bbl||$55.00||$55.00|
|Edmonton condensate differential – US$/Bbl||-$5.50||-$5.50|
|Est revenue net of transport (excl hedges) – $/Boe||$17.75 – $18.25||$17.75 – $18.25|
|Est operating costs – $/Boe||$5.50 – $5.75||$5.50 – $5.75|
|Est royalty rate (% revenue before hedging)||5% – 7%||5% – 7%|
|Est mid-point field operating netback – $/Boe||$11.30||$11.30|
|Est hedging loss – $ million||$7.0 – $8.0||$8.0 – $10.0|
|Est cash G&A – $ million||$6.0 – $7.0||$6.0 – $7.0|
|– $/Boe||$0.66 – $0.91||$0.66 – $0.91|
|Est interest expense – $ million||$5.5 – $6.5||$5.5 – $6.5|
|Est capital investment (excl A&D) – $ million||$128.0||$128.0|
|Forecast fourth quarter production – Boe/d
|23,000 – 25,000
|23,000 – 25,000
|Forecast annual production – Boe/d
|21,000 – 24,000
|21,000 – 24,000
|Est annual funds flow – $ million||$67.0 – $79.0(1)||$65.0 – $77.0(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)
11 (9.5 net)
9 (9.0 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|
With the corporate average decline rate estimated to be 20% in 2019, approximately three new horizontal wells at Nig would be required to offset the decline and maintain 20,000 to 22,000 Boe per day. Wells at Nig are averaging more than 1,400 Boe per day sales in the first year. As a result, at current forward strip commodity prices, funds flow is expected to materially exceed capital investment required to maintain production in 2019.
Capital investment in 2019 remains at $128 million with a significant portion (88%) being directed towards future growth including $70 million for the sour gas plant at Nig, $28 million to drill, complete, and pipeline connect a four-well pad at Nig, and $15 million to advance development at Fireweed. Attractive full-cycle rates of return are expected to be achieved assuming WTI US$55 per barrel, Cdn$/US$ exchange rate 0.76 and Station 2 $1.25 per GJ. Debt including working capital deficiency is forecast to increase by $50 to $60 million by the end of 2019 in order to fund planned growth. This may result in debt including working capital deficiency exceeding the targeted level of 1.0 to 1.5 times annualized funds flow on a short-term basis during construction of the sour gas plant as the full project cost of $81 million must be invested before incremental funds flow is realized. Maintaining a strong balance sheet remains a priority and capital investment and activity are designed to be flexible and can be accelerated or reduced depending on commodity prices.
The near-term plan remains focused on growing funds flow by advancing development of the Nig and Fireweed areas which will be financed using funds flow and available capacity on the bank line. Growth from both areas is expected to reduce per-Boe operating costs while increasing liquids as a proportion of total production with corporate production forecast to increase to approximately 25,000 Boe per day by the end of 2019 (4,600 barrels per day of liquids) and to more than 30,000 Boe per day by the end of 2020 (6,600 barrels per day of liquids). Additional growth from Umbach, where there is under-utilized field compression capacity, is contingent on a higher natural gas price.