HIGHLIGHTS & OUTLOOK
2018 Fourth Quarter Highlights
Production and funds flow reached record highs in the quarter as a result of diversified natural gas sales along with the performance of recent horizontal wells continuing to exceed expectations at both Nig and Umbach.
- Production increased to a record of 22,432 Boe per day which represents growth of 25% on a per-share basis from the prior year and also exceeded guidance of 19,000 to 21,000 Boe per day (production was rapidly increased in mid-November in response to a strengthening natural gas price at Chicago).
- Liquids production (field condensate plus gas plant NGL) grew by 24% year over year with liquids representing 19% of total production and 25% of production revenue.
- At the end of the quarter, there was an inventory of seven Montney horizontal wells (6.5 net) that had not started producing which included four completed wells (3.5 net). During the quarter, three wells (3.0 net) started production.
- At the Nig land block, the three wells completed in early 2018 have been producing for eight to eleven months with no decline to date and averaged 8.2 Mmcf per day raw gas in February which is approximately 1,520 Boe per day sales (20% liquids including liquids recovered at the gas plant).
- Diversified natural gas sales resulted in the realized price averaging $5.56 per Mcf which was significantly higher than Western Canadian pricing (AECO $1.48 per GJ and Station 2 $0.64 per GJ). Firm pipeline commitments required to diversify sales also result in a higher natural gas transportation cost which was $1.02 per Mcf (only 18% of the realized price).
- Hedging loss totaled $17.9 million with 69%, or $12.3 million, from Sumas price hedges. This was the result of a failure on the Enbridge T-south pipeline system on October 9th which materially reduced flows and increased the Sumas price to Cdn$14.67 per Mmbtu in the quarter versus the average hedged price of Cdn$2.92 per Mmbtu.
- Production costs, general and administrative, and interest and finance costs averaged $6.46 per Boe, a decrease of 11% year over year.
- Funds flow was a record $30.9 million, or $0.25 per share, a 39% increase on a per-share basis from last year which was largely from a higher natural gas price and higher production volumes.
- Capital investment was $37.1 million which included drilling four horizontal wells (4.0 net), completing three horizontal wells (2.5 net), and initial equipment deposits of $8.9 million for the gas plant at Nig.
- The balance sheet remains strong with debt including working capital deficiency being $91 million which represents 0.7 times annualized quarterly funds flow and 50% of the bank credit facility of $180 million.
- Commodity price hedges currently protect approximately 43% of forecast production for 2019.
2018 Year-End Highlights
Financial and operational results were consistent with or better than guidance for production, funds flow, operating costs per Boe and capital investment. Notably, year-over-year production growth per share of 28% was achieved while reducing debt including the working capital deficiency by $15 million.
- Production averaged 20,538 Boe per day which was consistent with guidance and represents growth of 28% on a per-share basis from last year.
- This was the eighth consecutive year that production per share has grown with growth averaging 28% per year over the last five years.
- Liquids production grew by 26% (condensate by 27%) with liquids representing 18% of total production and 35% of production revenue.
- Due to diversified natural gas sales, the realized natural gas price was $3.98 per Mcf which was materially higher than Western Canadian pricing (AECO $1.42 per GJ and Station 2 $1.19 per GJ).
- The corporate decline rate in 2018 was approximately 26% (December 2017 corporate production was 19,220 Boe per day with the same wells producing 14,160 Boe per day in December 2018 based on field estimates). This is a reduction from the 32% decline rate in 2017.
- Cost structure continues to decrease with production, general and administrative, and interest and finance expense averaging $6.89 per Boe, a decline of 11% from the previous year.
- Funds flow was a record $100.1 million ($0.82 per share), a year-over-year increase of 56% on a per-share basis with the improvement coming from production growth (+28%) and a higher funds flow netback (+22%) which resulted from higher commodity prices and a decrease in costs on a per-Boe basis.
- Return on capital employed was 10% and cash return on capital employed was 21%. Cash return on capital employed is based on funds flow which is a more meaningful measure of profitability given that return on capital employed is based on net income which can be significantly affected by non-cash mark-to-market gains and losses on hedging (for example, 2018 was a non-cash hedging loss of $5.8 million while 2017 was a non-cash hedging gain of $24.6 million).
- Capital investment totaled $85 million and included $14 million of investment into longer-term growth projects that will not contribute to production and funds flow until 2020 ($11 million in equipment deposits for the Nig gas plant and $3 million at Fireweed).
Year-End Reserve Evaluation Highlights
Reserve growth was consistent with production growth while capital efficiency continued to improve with the all-in PDP FD&A setting a record low at $5.24 per Boe while PDP recycle ratio using the funds flow netback set a record high at 2.5 times.
|(Mboe)||Increase From Last Year||2018||2017||2016|
|Proved Developed Producing (“PDP”)||+25%||42,204||33,729||25,395|
|Total Proved (“1P”)||+54%||149,905||97,617||77,097|
|Total Proved plus Probable (“2P”)||+41%||182,370||128,963||104,192|
|PDP as % of 2P||23%||26%||24%|
|1P as a % of 2P||82%||76%||74%|
|Reserve Life Index using fourth quarter production||PDP||5.2||5.2||5.2|
|All-in Finding, Development & Acquisition (“FD&A”) Cost|
|Including Change in Future Development Capital (“FDC”)|
|Recycle Ratio Using All-in FD&A Cost|
|Funds Flow (000s)||$100,092||$64,080||$34,380||$198,552|
|Funds Flow netback ($/Boe)||$13.34||$10.96||$7.10||$10.92|
- Reserve additions for PDP replaced 113% of annual production (698% for 1P and 712% for 2P).
- On a per-share basis, PDP reserves increased by 25%, 1P increased by 54% and 2P increased by 41%.
- Liquids reserves increased by 31% for PDP, 69% for 1P and 56% for 2P.
- Material future upside remains given that 2P reserves are recognized in only the upper Montney on 41.7 net sections which is 24% of the total Montney land position (172 net sections).
- Actual results achieved in 2018 were better than what was predicted in last year’s evaluation with new wells completed in 2018 assigned estimated ultimate recoverable reserves averaging 8.9 Bcf gross raw gas which is 44% higher than the 2P estimate of 6.2 Bcf gross raw gas for future drilling locations in last year’s evaluation. As a result of drilling longer horizontal wells with more frac stages, the actual cost to drill and complete a horizontal well in 2018 averaged $6.2 million which was higher than the estimated cost of $4.8 million used in last year’s reserve evaluation.
- The before-tax PDP net present value (“NPV”) discounted at 10% was $477 million, or $3.17 per share, after deducting debt including working capital deficiency, a year-over-year increase of 68% when the same price forecast is used (this year’s price forecast used in last year’s evaluation).
For the first quarter of 2019, production is forecast to be 17,500 to 20,000 Boe per day. As was previously communicated in a press release dated January 15, 2019, the McMahon Gas Plant was shut in for 17 days starting January 2nd to repair a failure on the flare system piping. During this time, production was reduced to 4,500 Boe per day. Production to date has averaged 18,000 Boe per day based on field estimates.
Production in the second and third quarters of 2019 is expected to be approximately 20,000 to 21,000 Boe per day based on current indications for Western Canadian natural gas prices during this period ($0.75 per GJ at Station 2 and $1.25 per GJ at AECO). This level of production is the minimum that would fulfill firm transportation commitments and assumes interruptible service on the Alliance Pipeline is not available.
Updated guidance for 2019 is summarized below:
- forecast commodity prices updated to reflect pricing to date in 2019 plus the approximate current forward strip for the remainder of the year;
- estimated annual funds flow decreased primarily as a result of weaker Western Canadian propane and butane prices (primarily butane) which decreases the NGL price net of transportation to approximately 10% to 15% of WTI in Cdn$ for the next NGL contract period from April 2019 to March 2020 (versus an average of 42% in 2018); and
- the number of horizontal wells starting production decreased to 9.0 gross from 11.0 gross with the start-up of two horizontal wells accelerated into the fourth quarter of 2018 to take advantage of stronger natural gas prices.
November 13, 2018
|February 28, 2019|
|Cdn$/US$ exchange rate||0.78||0.76|
|Chicago daily natural gas – US$/Mmbtu||$2.50||$2.60|
|Sumas monthly natural gas – US$/Mmbtu||$2.50||$3.10|
|AECO daily natural gas – Cdn$/GJ||$1.50||$1.60|
|Station 2 daily natural gas – Cdn$/GJ||$1.25||$1.25|
|WTI – US$/Bbl||$60.00||$55.00|
|Edmonton condensate diff – US$/Bbl||-$8.00||-$5.50|
|Est revenue net of transport (excl hedges) – $/Boe||$17.50 – $18.00||$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||$11.05||$11.30|
|Est hedging loss – $ million||$7.0 – $8.0|
|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||$72.0 – $88.0||$67.0 – $79.0(1)|
|Horizontal wells drilled – gross
Horizontal wells completed – gross
Horizontal wells starting production – gross
|8 (6.5 net)
11 (9.5 net)
11 (11.0 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 of the field operating netback, estimated cash G&A, estimated hedging gain or loss and estimated interest expense.
A failure on the Enbridge T-south pipeline system on October 9, 2018 affected the natural gas price at Station 2 which averaged $0.64 per GJ in the fourth quarter of 2018, a differential to AECO of -$0.84 per GJ (compared to an average price of $1.37 per GJ and differential of -$0.04 per GJ in the nine months before the failure). Flow has been restored to approximately 80% to 85% of the flow prior to the failure and the timing to fully restore capacity is not currently known although is unlikely to be before August 2019 (requires completion of engineering assessments on various segments along with review and approval from the National Energy Board). The Station 2 price is expected to remain depressed until capacity is restored or until the NGTL North Montney extension into northeast British Columbia is in service which is anticipated to be in the fourth quarter of 2019 (contracted capacity 1.5 Bcf per day). The financial effect on Storm has not been material given that less than 15% of natural gas sales are at Station 2 pricing.
Since 2015, financial results have improved materially with funds flow reaching a record $100 million in 2018, an increase of 141% on a per-share basis. Importantly, debt including working capital deficiency has increased by only 47% during this period (from $62 million at the end of 2015 to $91 million at the end of 2018). This has been a result of production growth (+103% per share), increased revenue per Boe net of transportation (+39%), and a per-Boe decrease in production, general and administrative, and interest and finance expense (-32%).
In 2019, estimated capital investment to maintain production at 2018 levels of 20,000 to 21,000 Boe per day is less than $10 million which includes connection and start-up of three horizontal wells that were completed in 2018 plus expenditures for various minor projects. The remaining investment of $118 million will be directed to growth opportunities that offer attractive full-cycle rates of return at current commodity prices. At Nig, a 50 Mmcf per day sour gas plant will be constructed in the second half of 2019 which will significantly reduce per-Boe operating costs and increase liquids recovery. At Fireweed, a 50 Mmcf per day field compression facility will be constructed in mid-2020 where higher field condensate rates are expected from horizontal wells. At Umbach, activity and production can and will be increased relatively quickly if supported by the Station 2 natural gas price given existing unused field compression capacity.
Growth has been accomplished while improving the cash return on average capital employed to 21% in 2018 from 10% in 2015. Generating a strong return on invested capital will continue to be a focus of Storm’s business plan.
The Company’s near-term growth plan is expected to increase the proportion of liquids and decrease per-Boe operating costs which reduces exposure to current low Western Canadian natural gas prices. Production is expected to grow to approximately 25,000 Boe per day by the end of 2019 (18% liquids) and to more than 30,000 Boe per day by the end of 2020 (21% liquids). Growth will be financed with funds flow and debt. Maintaining a strong balance sheet remains a priority and, as a result, capital investment and activity will continue to be flexible and may be accelerated or reduced depending on commodity prices.
With horizontal well results continuing to improve as length is increased and with 2P reserves recognized in only the upper Montney on less than 25% of the total land position at Umbach, Nig and Fireweed, material future upside remains. This leaves Storm well positioned to continue growing funds flow and asset value on a per-share basis and is a consideration when evaluating acquisition or diversification opportunities.