CALGARY, ALBERTA–(Marketwired – March 2, 2017) – Storm Resources Ltd. (TSX VENTURE:SRX) –
Storm has also filed its audited consolidated financial statements as at December 31, 2016 and for the three months and year then ended along with Management’s Discussion and Analysis (“MD&A”) for the same periods. This information appears on SEDAR at www.sedar.com and on Storm’s website at www.stormresourcesltd.com.
Selected financial and operating information for the three months and year ended December 31, 2016, as well as reserves information at December 31, 2016, appears below and should be read in conjunction with the related financial statements and MD&A.
Highlights
| Thousands of Cdn$, except volumetric and per-share amounts | Three Months to Dec. 31, 2016 |
Three Months to Dec. 31, 2015 |
Year Ended Dec. 31, 2016 |
Year Ended Dec. 31, 2015 |
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| FINANCIAL | |||||||||
| Revenue from product sales(1) | 26,244 | 14,480 | 77,283 | 67,736 | |||||
| Funds flow | 11,985 | 9,182 | 34,380 | 39,046 | |||||
| Per share – basic ($) | 0.10 | 0.08 | 0.29 | 0.34 | |||||
| Per share – diluted ($) | 0.10 | 0.08 | 0.29 | 0.34 | |||||
| Net income (loss) | (12,898 | ) | 1,850 | (38,460 | ) | (6,867 | ) | ||
| Per share – basic ($) | (0.11 | ) | 0.02 | (0.32 | ) | (0.06 | ) | ||
| Per share – diluted ($) | (0.11 | ) | 0.02 | (0.32 | ) | (0.06 | ) | ||
| Operations capital expenditures(2) | 33,399 | 30,998 | 65,538 | 95,099 | |||||
| Land and property acquisitions/(dispositions) | – | 83 | (600 | ) | (23,590 | ) | |||
| Debt including working capital deficiency(2)(3) | 89,841 | 61,721 | 89,841 | 61,721 | |||||
| Common shares (000s) | |||||||||
| Weighted average – basic | 120,488 | 119,388 | 120,053 | 115,821 | |||||
| Weighted average – diluted | 120,488 | 119,388 | 120,053 | 115,821 | |||||
| Outstanding end of period – basic | 120,764 | 119,467 | 120,764 | 119,467 | |||||
| OPERATIONS | |||||||||
| (Cdn$ per Boe) | |||||||||
| Revenue from product sales | 21.42 | 14.67 | 15.97 | 18.64 | |||||
| Royalties | (0.99 | ) | 0.05 | (0.79 | ) | (0.82 | ) | ||
| Production | (6.95 | ) | (7.01 | ) | (6.78 | ) | (8.00 | ) | |
| Transportation | (0.55 | ) | (0.79 | ) | (0.45 | ) | (1.13 | ) | |
| Field operating netback | 12.93 | 6.92 | 7.95 | 8.69 | |||||
| Realized (losses) gains on hedging | (1.45 | ) | 4.20 | 0.93 | 4.20 | ||||
| General and administrative | (0.95 | ) | (1.27 | ) | (1.10 | ) | (1.51 | ) | |
| Interest and finance costs | (0.74 | ) | (0.54 | ) | (0.68 | ) | (0.62 | ) | |
| Funds flow per Boe | 9.79 | 9.31 | 7.10 | 10.76 | |||||
| Barrels of oil equivalent per day (6:1) | 13,320 | 10,730 | 13,219 | 9,956 | |||||
| Gas production | |||||||||
| Thousand cubic feet per day | 66,173 | 53,147 | 65,478 | 48,656 | |||||
| Price (Cdn$ per Mcf) | 2.86 | 1.78 | 2.05 | 2.39 | |||||
| Condensate production | |||||||||
| Barrels per day | 1,381 | 1,072 | 1,303 | 997 | |||||
| Price (Cdn$ per barrel) | 57.17 | 47.90 | 49.34 | 50.78 | |||||
| NGL production | |||||||||
| Barrels per day | 910 | 800 | 1,003 | 670 | |||||
| Price (Cdn$ per barrel) | 18.64 | 14.21 | 12.51 | 14.30 | |||||
| Oil production | |||||||||
| Barrels per day | – | – | – | 179 | |||||
| Price (Cdn$ per barrel) | – | – | – | 50.84 | |||||
| Wells drilled (100% working interest) | 5.0 | 4.0 | 12.0 | 10.0 | |||||
| Wells completed (100% working interest) | 5.0 | 6.0 | 10.0 | 12.0 | |||||
| (1) | Excludes gains and losses on commodity price contracts. |
| (2) | Certain financial amounts shown above are non-GAAP measurements including operations capital expenditures, debt including working capital deficiency and all measurements per Boe. See discussion of Non-GAAP Measurements on page 37 of the MD&A. |
| (3) | Excludes the fair value of commodity price contracts. |
PRESIDENT’S MESSAGE
2016 FOURTH QUARTER HIGHLIGHTS
- Production was 13,320 Boe per day (17% condensate and NGL), a year-over-year increase of 24% (23% on a per-share basis) and flat on a quarter-over-quarter basis. With the improvement in natural gas prices late in the quarter, two additional standing horizontal wells were turned on and production increased in December to 14,670 Boe per day.
- Condensate and NGL production increased 22% from the previous year to average 2,291 barrels per day. Condensate and NGL volumes are now being reported separately with condensate including field condensate plus pentane recovered at gas plants while NGL is the propane and butane recovered at gas plants.
- Montney horizontal well performance at Umbach continues to improve as the length and number of frac stages are increased. The first seven wells completed in 2016 with enough production history averaged 5.3 Mmcf per day gross raw gas over the first 90 calendar days, a 10% improvement from the average 2014 and 2015 wells.
- Controllable cash costs (production, general and administrative, interest and finance) were $8.64 per Boe.
- Funds flow was $12.0 million ($9.79 per Boe), an increase of 31% from a year ago and a 173% increase when realized gains and losses from hedging are excluded. The increase was driven by a 24% increase in production volumes.
- Net loss was $12.9 million which includes an unrealized mark to market hedging loss of $13.9 million (excluding the unrealized hedging loss, net profit was $1.0 million or $0.01 per share).
- Capital investment was $33.4 million including $11.8 million for construction of the third field compression facility at Umbach which was started up on January 12, 2017. In addition, five horizontal wells (5.0 net) were drilled and five horizontal wells (5.0 net) were completed.
- At the end of the quarter, there was an inventory of nine horizontal wells (9.0 net) that had not started producing (includes three completed wells).
- Debt including working capital deficiency was $89.8 million which is 1.9 times annualized fourth quarter funds flow (the bank credit facility is $130.0 million).
- Commodity price hedges continue to be layered in with approximately 40% of forecast 2017 production currently hedged.
2016 YEAR-END HIGHLIGHTS
- Production for the year averaged 13,219 Boe per day (17% condensate and NGL), a year-over-year increase of 34% on a per-share basis.
- During 2016, seven horizontal wells were turned on which offset declines and maintained production at approximately 13,000 Boe per day through November. Production in December increased to 14,670 Boe per day after two more horizontal wells were turned on.
- Controllable cash costs (production, general and administrative, interest and finance) averaged $8.56 per Boe for the year, a decrease of $1.57 per Boe or 15% from the previous year. Production costs declined to $6.78 per Boe, an improvement of 15%.
- Capital investment totaled $64.9 million with $22.4 million to drill 12.0 net horizontal wells, $18.5 million to complete 10.0 net horizontal wells and $23.1 million for infrastructure ($18.8 million or 29% of 2016 capital investment was for the third field compression facility at Umbach).
- The average cost to drill and complete a Montney horizontal well at Umbach in 2016 was $3.9 million, a decrease of 11% from 2015.
- Storm entered into a natural gas processing arrangement at Umbach with Spectra Energy (“Spectra”) which is effective January 1, 2017 and is expected to reduce corporate operating costs by approximately 15% to 20%.
- Proved developed producing (“PDP”) reserves increased 21% per share, additions replaced 195% of production and the all-in Finding, Development & Acquisition (“FD&A”) cost was $6.89 per Boe ($4.90 per Boe excluding $18.8 million for the third field compression facility at Umbach which started up in January 2017).
- Total proved (“1P”) reserves increased 4% per share, additions replaced 175% of production and the all-in FD&A cost was $4.97 per Boe.
- Total proved plus probable (“2P”) reserves increased 2% per share, additions replaced 172% of production and the all-in FD&A cost was $5.48 per Boe.
- All reserve additions in the 2016 evaluation were from Storm’s 100% working interest lands at Umbach. Wells completed in 2016 were assigned average 2P reserves of 5.8 Bcf gross raw gas with the actual drill and complete cost being $3.9 million. The actual results were an improvement over what was recognized in last year’s evaluation where average 2P reserves of 4.7 Bcf were assigned to future drilling locations with an estimated drill and complete cost of $4.5 million.
- The corporate decline rate was approximately 33% in 2016 (December 2015 corporate production was 13,602 Boe per day with the same wells producing 9,210 Boe per day in December 2016).
- Cost of production additions in 2016 was $12,800 per Boe per day using total capital investment and fourth quarter production of 5,080 Boe per day from wells starting production in 2016 (last year was $11,000 per Boe per day). This is reduced to $9,100 per Boe per day when the $18.8 million invested in the third field compression facility is excluded (approximates the sustaining cost to maintain production).
SUMMARY OF YEAR-END RESERVE EVALUATION
The year-end reserve evaluation is effective December 31, 2016 and was prepared by InSite Petroleum Consultants Ltd. (“InSite”), independent qualified reserve evaluators of Calgary, Alberta.
| Reserves (Mboe) |
2016 vs 2015 |
2016 | 2015 | 2014 | ||||
| PDP | 22 | % | 25,395 | 20,810 | 13,487 | |||
| 1P | 5 | % | 77,097 | 73,434 | 59,551 | |||
| 2P | 3 | % | 104,192 | 100,722 | 88,024 | |||
| PDP as % of 2P | 24 | % | 21 | % | 15 | % | ||
| 1P as a % of 2P | 74 | % | 73 | % | 68 | % | ||
- Reserve quality continues to improve with PDP increasing to 24% of 2P from 21%.
- PDP reserve growth was consistent with growth in corporate production while 1P and 2P reserve growth was limited by fewer step-out wells being drilled (more infill wells were drilled to improve capital efficiency in response to the significant decline in commodity prices and funds flow).
- Technical revisions added 7% to PDP, 4% to 1P and 3% to 2P.
| Reserves Per Share Outstanding (Mboe per million shares) |
2016 vs 2015 |
2016 | 2015 | 2014 | |
| PDP | 21 | % | 210 | 174 | 121 |
| 1P | 4 | % | 638 | 615 | 535 |
| 2P | 2 | % | 862 | 844 | 791 |
- Reserve growth on a per-share basis was reduced by issuance of 1.3 million shares for exercised stock options.
| Future Development Capital (“FDC”) ($ million) |
2016 | 2015 | 2014 | |||
| 1P | $ | 413 | $ | 435 | $ | 448 |
| 2P | $ | 524 | $ | 543 | $ | 607 |
- The year-over-year decline in FDC resulted from a decrease in the number of future drilling locations. With fewer step-out wells drilled, the number of future drilling locations that were added (7.0 net 2P) was less than the number of wells drilled (12.0 net).
- The cost to drill and complete a future horizontal well in the Montney at Umbach in the 2016 evaluation was $4.5 million which is unchanged from 2015.
- FDC is fully funded by forecast net operating income.
| All-in FD&A Cost Including Change in FDC ($/Boe) |
2016 | 2015 | 2014 | 3 Year Total | ||||
| PDP | $ | 6.89 | $ | 6.53 | $ | 23.01 | $ | 11.48 |
| 1P | $ | 4.97 | $ | 3.38 | $ | 11.68 | $ | 8.68 |
| 2P | $ | 5.48 | $ | 0.50 | $ | 9.64 | $ | 7.18 |
- The all-in FD&A cost reflects the result of Storm’s entire capital investment program, including acquisitions, dispositions and revisions.
- PDP FD&A is the most realistic as it reflects actual financial results (actual capital spending and actual well results). 1P and 2P FD&A is less likely to reflect past or future financial results given they are largely based on estimates of future well performance, estimates of future FDC, and changes to estimates of future FDC.
| Recycle Ratio Using All-in FD&A Cost | 2016 | 2015 | 2014 | 3 Year Total | ||||
| Field operating netback including hedging | $ | 8.88 | $ | 12.89 | $ | 19.93 | $ | 12.76 |
| PDP Recycle | 1.3 | 2.0 | 0.9 | 1.1 | ||||
| 1P Recycle | 1.8 | 3.8 | 1.7 | 1.5 | ||||
| 2P Recycle | 1.6 | 25.8 | 2.1 | 1.8 | ||||
- Recycle ratios were weak in 2016 primarily as a result of very low natural gas prices in the first half of 2016 (AECO averaged $1.53 per GJ) which reduced revenue and the field operating netback.
| Net Present Value Discounted @ 10% Before Tax InSite Price Forecast December 31, 2016 ($ million) |
2016 vs 2015 |
2016 |
2015 |
2014 |
||||
| PDP | +49 | % | $ | 317 | $ | 213 | $ | 199 |
| 1P | +36 | % | $ | 600 | $ | 442 | $ | 493 |
| 2P | +28 | % | $ | 758 | $ | 592 | $ | 684 |
- Net present value improved primarily from forecast operating costs being reduced over the life of the reserves by 21% for PDP (to $7.28 per Boe from $9.27 per Boe) and 25% for both 1P and 2P.
- Revenue over the life of the reserves increased 7% (+$2.06 per Boe) for PDP and decreased 1% and 3% for 1P and 2P respectively.
OPERATIONS REVIEW
Umbach, Northeast British Columbia
Storm’s land position at Umbach is prospective for liquids-rich natural gas from the Montney formation and currently totals 108,000 net acres (154 net sections). To date, Storm has drilled 58 horizontal wells (54.4 net).
Production in the fourth quarter was 12,945 Boe per day and liquids recovery was 36 barrels per Mmcf sales with 60% being higher priced field condensate plus pentanes recovered at the gas plant. Year over year, the number of producing wells has increased by 9.0 net wells while production has increased by 21%.
During the fourth quarter, five horizontal wells (5.0 net) were drilled, five horizontal wells (5.0 net) were completed and three horizontal wells (3.0 net) started production. At the end of the fourth quarter, there was an inventory of nine horizontal wells (9.0 net) that had not started producing which included three completed wells.
Activity in the first quarter of 2017 will include drilling six horizontal wells (6.0 net) and completing four horizontal wells (4.0 net).
With start-up of the third field compression facility on January 12, 2017, field compression now totals 115 Mmcf per day raw gas. Throughput in the fourth quarter averaged 68 Mmcf per day raw gas and has averaged approximately 90 Mmcf per day raw gas in January and February 2017. The third field compression facility has initial capacity of 35 Mmcf per day with the estimated final cost being $25.0 million (2015: $4.8 million, 2016: $18.8 million, 2017: $1.4 million) and it is expandable to 70 Mmcf per day for an additional $7.0 million. Once the expansion is completed, total capacity will be 150 Mmcf per day which supports growth in corporate production to approximately 27,000 Boe per day.
Raw gas from Storm’s field compression facilities is sent to the McMahon and Stoddart Gas Plants where firm processing commitments average 75 Mmcf per day raw gas in 2017. A new processing arrangement with Spectra at the McMahon Gas Plant started on January 1, 2017, has a total commitment of 65 Mmcf per day of raw gas at terms ranging from 5 to 15 years, and is expected to reduce corporate operating costs by 15% to 20%. The arrangement with Spectra supports future growth with an option to increase contracted capacity and provides for continued diversification of natural gas sales as the McMahon Gas Plant is connected to three sales pipelines (Alliance Pipeline to Chicago, TransCanada NGTL system to AECO, Spectra T-north to BC Station 2).
A summary of horizontal well performance and costs is provided below. For the wells completed in 2016, the drill and complete cost declined by 22% on a per-stage basis from 2015 and the IP90 improved by 13%. The majority of future horizontal wells are expected to have greater than 1,600 metres of completed length with more than 30 frac stages.
| Year of Completion | Frac Stages |
Completed Length |
Actual Drill & Complete Cost |
IP 90 Cal Day Mmcf/d Raw |
IP 180 Cal Day Mmcf/d Raw |
IP 365 Cal Day Mmcf/d Raw |
| 2013 6 hz’s |
17 | 1,190 m | $4.6 million $270 K/stage |
3.5 Mmcf/d 6 hz’s |
2.9 Mmcf/d 6 hz’s |
2.2 Mmcf/d 6 hz’s |
| 2014 12 hz’s* |
19 | 1,170 m | $4.6 million $240 K/stage |
4.9 Mmcf/d 12 hz’s |
4.4 Mmcf/d 12 hz’s |
3.5 Mmcf/d 12 hz’s |
| 2015 11 hz’s |
22 | 1,360 m | $4.4 million $200 K/stage |
4.7 Mmcf/d 11 hz’s |
4.2 Mmcf/d 11 hz’s |
3.3 Mmcf/d 10 hz’s |
| 2016 10 hz’s |
25 | 1,301 m | $3.9 million $156 K/stage |
5.3 Mmcf/d 7 hz’s |
4.8 Mmcf/d 3 hz’s |
|
| 2017 4 hz’s |
35 | 1,671 m |
* 2014 wells exclude a middle Montney well (this table provides analysis of upper Montney wells only).
Horn River Basin, Northeast British Columbia
Storm has a 100% working interest in 119 sections in the Horn River Basin (78,000 net acres) which are prospective for natural gas from the Muskwa, Otter Park and Evie/Klua shales. Storm’s one horizontal well averaged 310 Boe per day in the fourth quarter. Cumulative production to date from this well is 5.3 Bcf raw.
HEDGING AND TRANSPORTATION
Commodity price hedges are used to support longer term growth by providing some certainty regarding future revenue and funds flow. The objective is to hedge 50% of most recent quarterly or monthly production for the next 12 months and 25% for 13 to 24 months forward. Anticipated production growth is not hedged. The WTI price is also hedged given that approximately 80% of Storm’s liquids production is priced in reference to WTI (condensate, plant pentane and butane). The hedge position is updated periodically in the presentation posted on Storm’s website. For 2017, approximately 40% of forecast production is currently hedged.
| 2017 | ||||
| Crude Oil | 875 Bopd | WTI Cdn$64.57/Bbl floor, Cdn$69.55/Bbl ceiling | ||
| Natural Gas | 34,100 GJ/d (27,200 Mcf/d) | AECO Cdn$2.66/GJ ($3.32/Mcf) | ||
| 9,200 Mmbtu/d (7,750 Mcf/d) | Chicago Cdn$4.17/Mmbtu ($4.93/Mcf) | |||
| 2018 | ||||
| Crude Oil | 260 Bopd | WTI Cdn$63.38/Bbl floor, Cdn$70.53/Bbl ceiling | ||
| Natural Gas | 750 GJ/d (600 Mcf/d) | AECO Cdn$2.80/GJ ($3.50/Mcf) | ||
| 10,900 Mmbtu/d (9,200 Mcf/d) | Chicago Cdn$4.00/Mmbtu ($4.73/Mcf) | |||
The Company also has natural gas price differential hedges in place (Chicago – AECO and AECO – BC Station 2) with details provided in Note 14 to the financial statements.
Storm’s strategy with respect to natural gas transportation commitments is to mitigate risk by diversifying sales and selling at multiple points including Chicago, AECO and BC Station 2. As per the summary below, transportation commitments total 72 Mmcf per day in 2017 and increase to 102 Mmcf per day in 2018 (in addition to this firm capacity, interruptible capacity on the Alliance Pipeline adds up to 14 Mmcf per day in 2017 and up to 15 Mmcf per day in 2018). During the fourth quarter, the deduction from revenue for Alliance transportation was $6.6 million. Further information on pipeline tariffs and price deductions is provided in the presentation on Storm’s website.
| 2017 | 2018 | ||
| Alliance Pipeline(1) 51 Mmcf/d Chicago price |
Alliance Pipeline(1) 55 Mmcf/d Chicago price |
||
| 5 Mmcf/d ATP price | 5 Mmcf/d ATP price | ||
| Spectra T-north 16 Mmcf/d BC Stn 2 price |
Spectra T-north 29 Mmcf/d BC Stn 2 price |
||
| Spectra T-north & TCPL 13 Mmcf/d AECO price |
|||
(1) Interruptible capacity on the Alliance Pipeline adds up to 25% of contracted capacity.
ORGANIZATIONAL UPDATE
On November 15, 2016, the pending retirements of Mr. Donald McLean, Chief Financial Officer, and Mr. John Devlin, Vice President, Finance, were announced. Both are planning to retire in mid-2017. Successors joined Storm in late 2016 and will be announced when 2017 first quarter results are released on May 15, 2017.
OUTLOOK
Production in the first quarter of 2017 is forecast to be 16,000 to 17,000 Boe per day (January and February averaged 16,500 Boe per day based on field estimates). Capital investment in the first quarter is expected to be approximately $30.0 million and will include drilling six horizontal wells, completing four horizontal wells and $8.0 million for pipelines plus a second fuel gas conditioning unit at Umbach (back-up to avoid downtime associated with equipment failures).
Guidance for 2017 is largely unchanged from what was previously provided except for updating commodity prices.
| 2017 Guidance | Initial Guidance September 7, 2016 |
Updated November 15, 2016 |
Updated March 2, 2017 |
||||
| Chicago natural gas (US$/Mmbtu) | $3.00 | $3.00 | $3.00(1 | ) | |||
| AECO natural gas (Cdn$/GJ) | $2.65 | $2.65 | $2.50(1 | ) | |||
| BC Stn 2 natural gas (Cdn$/GJ) | $2.25 | $2.20 | $2.00(1 | ) | |||
| Edmonton light oil (Cdn$/bbl) | $55 | $55 | $59(1 | ) | |||
| Estimated average operating costs ($/Boe) | $5.50 – $5.75 | $5.50 – $5.75 | $5.50 – $6.00 | ||||
| Estimated average royalty rate (% production revenue before hedging) | 9% – 11 | % | 9% – 11 | % | 9% – 11 | % | |
| Estimated operations capital ($ million) (excluding acquisitions & dispositions) | $75.0 – $80.0 | $75.0 – $80.0 | $75.0 – $80.0 | ||||
| Estimated cash G&A | |||||||
| – $ million | $5.3 | $5.3 | $5.3 | ||||
| – $/Boe | $0.85 | $0.85 | $0.85 | ||||
| Forecast fourth quarter production (Boe/d) | 18,000 – 20,000 | 18,000 – 20,000 | 18,000 – 20,000 | ||||
| % condensate and NGL | 17 | % | 17 | % | 17 | % | |
| Forecast annual production (Boe/d) | 16,500 – 18,000 | 16,500 – 18,000 | 16,500 – 18,000 | ||||
| % condensate and NGL | 17 | % | 17 | % | 17 | % | |
| Umbach horizontal wells drilled | 12 gross (12.0 net | ) | 12 gross (12.0 net | ) | 12 gross (12.0 net | ) | |
| Umbach horizontal wells completed | 13 gross (13.0 net | ) | 14 gross (14.0 net | ) | 14 gross (14.0 net | ) | |
| Umbach horizontal wells connected | 15 gross (15.0 net | ) | 15 gross (15.0 net | ) | 15 gross (15.0 net | ) | |
(1) Assumed commodity prices are approximately equal to realized prices to date and the current forward strip.
2017 Guidance History
|
Chicago |
BC Station 2 (Cdn$/GJ) |
AECO |
Estimated Operations Capital ($ million) |
Forecast Fourth Quarter Production (Boe/d) |
Forecast Annual Production (Boe/d) |
|
| September 7, 2016 | $3.00 | $2.25 | $2.65 | $75.0 – $80.0 | 18,000 – 20,000 | 16,500 – 18,000 |
| November 15, 2016 | $3.00 | $2.20 | $2.65 | $75.0 – $80.0 | 18,000 – 20,000 | 16,500 – 18,000 |
| March 2, 2017 | $3.00 | $2.00 | $2.50 | $75.0 – $80.0 | 18,000 – 20,000 | 16,500 – 18,000 |
Capital investment in 2017 will be directed entirely to Umbach and will include $55.0 million for drilling and completions plus $21.0 million for infrastructure (pipelines, wellsite equipping, facilities). Approximately 55% will be invested in the first half of 2017. A cost of $4.2 million is assumed for drilling and completing a horizontal well at Umbach, an increase of 8% from the 2016 actual cost. There is flexibility in the capital program and investment may be adjusted up or down depending on commodity prices and funds flow which will affect forecast production. Commodity price hedges will partially mitigate potential declines in pricing.
Storm’s infrastructure plan at Umbach will support growth to 27,000 Boe per day which is approximately double average production in the fourth quarter of 2016. Depending on natural gas pricing and funds flow, preliminary planning would see this achieved in the second half of 2018.
An effort has been made to diversify natural gas sales which will mitigate the effect of the recent widening of price differentials with US markets. Approximately 84% of forecast natural gas production in 2017 is covered by firm transportation agreements with 60% to be sold at Chicago, 18% at BC Station 2 and 6% at Alliance Transfer Point (“ATP”). The remainder will be sold at BC Station 2 and/or Chicago using interruptible pipeline capacity. For January 2017, approximately 66% of production was sold at Chicago, 27% at BC Station 2 and 7% at ATP.
The outlook for natural gas prices remains positive as a result of a tighter supply/demand balance in the United States. Data from the Energy Information Administration (“EIA”) shows that 2016 production declined by 1.6 Bcf per day while 2016 demand increased by 0.5 Bcf per day, a year-over-year deficit of 2.1 Bcf per day. Based on the EIA Short Term Energy Outlook February 2017, exports are forecast to increase a further 1.3 Bcf per day in 2017 (primarily LNG and Mexico) which increases the deficit to 3.4 Bcf per day if production doesn’t decline any further. Over the last five years, almost all of the growth in US production has come from the Marcellus/Utica region and increasing production to meet higher demand will require higher natural gas prices as many producers in the Marcellus/Utica have higher cost structures and receive lower prices after pipeline tariffs are deducted. Longer term, the outlook is increasingly bullish with demand continuing to increase as a result of five LNG export facilities currently operating or under construction on the US Gulf Coast, plus US pipeline capacity to Mexico is expected to increase by more than 6 Bcf per day by the end of 2018 from six new pipelines.
Western Canadian natural gas prices relative to US markets have weakened with the NYMEX – AECO price differential widening to -US$1.08 per Mmbtu in January 2017 from -US$0.56 per Mmbtu in January 2016. This is the result of production growth exceeding demand growth which has mostly been from the Alberta oilsands as export pipelines to the US are fully contracted and eastern Canada demand has been flat to declining. Storm’s exposure to Western Canadian pricing is primarily at BC Station 2 where prices can be volatile because it’s a smaller market in terms of trading volumes, especially if there are outages or restrictions on the TCPL system which causes more natural gas to be directed to BC Station 2 (more than 50% of NE BC production is directed onto TCPL to AECO). Price volatility will be mitigated by using interruptible capacity to maximize sales onto the Alliance Pipeline, hedging the AECO – BC Station 2 price differential and by reducing production growth if the price is too low to generate an acceptable rate of return.
Storm is still in the early stages of delineating the large and high quality resource in the Montney formation at Umbach. The relatively shallow depth results in a lower cost to drill and complete horizontal wells (12 days to drill and case a well) while liquids recovery increases revenue (36% of revenue in 2016 was from condensate and NGL). With 154 net sections, there remains room for significant future growth with producing horizontal wells on only 7% of the lands (10 net sections) and proved plus probable reserves assigned on only 21% of the lands (33 net sections). Most of this land position is expected to be economically exploitable given results from Storm’s wells and encouraging results achieved by other operators on adjacent lands.
With multiple years of drilling inventory in the Montney at Umbach, the focus continues to be on increasing net asset value per share by converting resource into per-share growth in production and funds flow. At current forward strip commodity prices, annual average and fourth quarter production is forecast to increase by more than 30% in 2017 and the preliminary plan is for a further 25% to 35% increase in 2018. Reducing costs is also important (in all price environments) and further improvement is expected in 2017 as operating costs decline from the new processing arrangement with Spectra while the cost of adding PDP reserves will decline by drilling longer horizontal wells to increase rates and reserves.
In closing, I would like to thank Storm’s employees for their considerable efforts in 2016 which resulted in record levels of production, continuing improvements in capital efficiency and a further reduction in controllable cash costs. In addition, I would like to thank Storm’s Board of Directors whose advice, guidance and support continue to be invaluable.
Respectfully,
Brian Lavergne, President and Chief Executive Officer
March 2, 2017
RESERVES AT DECEMBER 31, 2016
Storm’s year-end reserve evaluation effective December 31, 2016 was prepared by InSite Petroleum Consultants Ltd. (“InSite”) in a report dated of February 24, 2017. InSite has evaluated all of Storm’s natural gas and NGL reserves. The InSite price forecast at December 31, 2016 was used to determine estimates of net present value (“NPV”). Storm’s Reserves Committee, which is made up of independent and appropriately qualified directors, has reviewed and approved the evaluation prepared by InSite, and the report of the Reserves Committee has been accepted by the Company’s Board of Directors.
Reserves included herein are stated on a company gross basis (working interest before deduction of royalties without including any royalty interests) unless noted otherwise. All reserves information has been prepared in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). In addition to the information disclosed in this report, more detailed information will be included in Storm’s Annual Information Form for the year ended December 31, 2016 (the “AIF”).
Summary
- Reserve additions in 2016 replaced 195% of production for proved developed producing (“PDP”), 175% for total proved (“1P”) and 172% for total proved plus probable (“2P”).
- 2P reserves include 529 Bcf of natural gas and 16 Mmbbl of NGL at year-end 2016. The NGL component includes 60% condensate (9.6 Mmbbl), 24% butane (3.8 Mmbbl) and 16% propane (2.6 Mmbbl).
- The all-in finding, development, and acquisition (“FD&A”) cost(1) to add reserves was $6.89 per Boe for PDP, $4.97 per Boe for 1P and $5.48 per Boe for 2P.
- Technical revisions were primarily due to horizontal well performance exceeding the InSite forecast from the previous year which increased PDP reserves by 1,392 Mboe (7%), 1P reserves by 3,319 Mboe (5%) and 2P reserves by 3,419 Mboe (3%).
- Breaking down 2P reserves by area, 96.3% is at Umbach, 3.3% is at the HRB and 0.4% is at Grande Prairie.
- Future development costs (“FDC”) were $412.8 million on a 1P basis and $524.0 million on a 2P basis and are fully financeable from forecast revenue and production within five years which complies with the Canadian Oil and Gas Evaluation (“COGE”) Handbook.
- At Umbach, the 100% working interest lands were assigned 61 net 2P horizontal drilling locations at an average of 4.9 Bcf gross raw gas (last year was 66 net 2P locations with 4.7 Bcf gross raw gas). On the 60% working interest lands, 20.4 net 2P horizontal drilling locations were assigned an average of 3.7 Bcf gross raw gas (unchanged from last year).
- For the wells drilled in 2016 at Umbach, ultimate 2P recovery is forecast to average 5.6 Bcf gross raw gas.
- At Umbach, 2P reserves were recognized in the upper Montney only on 21% or 32.6 net sections of Storm’s 154 net sections in the area (an increase of 2.2 net sections from last year). DPIIP averages 48 Bcf gross raw gas per section in the upper Montney (total net DPIIP 1.6 Tcf on 32.6 net sections). Forecast recovery of DPIIP totals 36% for 2P reserves.
- Umbach 2P FDC includes $53.0 million net for future infrastructure expansion (last year was $31.0 million net for future infrastructure expansion).
- The estimated cost to drill and complete a future Montney horizontal well at Umbach was unchanged year over year at approximately $4.5 million (actual cost in 2016 was $3.9 million).
(1) The all-in calculation reflects the result of Storm’s entire capital investment program as it takes into account the effect of acquisitions, dispositions and revisions, as well as the change in FDC.
INFORMATION REGARDING DISCLOSURE ON OIL AND GAS RESERVES AND RESOURCES
All amounts are stated in Canadian dollars unless otherwise specified. Where applicable, natural gas has been converted to barrels of oil equivalent (“Boe”) based on 6 Mcf:1 Boe. The Boe rate is based on an energy equivalent conversion method primarily applicable at the burner tip and does not recognize a value equivalent at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of the 6:1 conversion ratio, utilizing the 6:1 conversion ratio may be misleading as an indication of value. Production volumes and revenues are reported on a company gross basis, before deduction of Crown and other royalties, unless otherwise stated. Unless otherwise specified, all reserves volumes are based on “company gross reserves” using forecast prices and costs. The oil and gas reserves statement for the year ended December 31, 2016, which will include complete disclosure of oil and gas reserves and other information in accordance with NI 51-101, will be contained within the AIF which will be available on SEDAR.
References to estimates of oil and gas classified as DPIIP are not, and should not be confused with, oil and gas reserves.
Gross Company Interest Reserves as at December 31, 2016
(Before deduction of royalties payable, not including royalties receivable)
| Sales Gas (Mmcf) |
NGL (Mbbls) |
6:1 Oil Equivalent (Mboe) | |
| Proved producing | 128,363 | 4,001 | 25,395 |
| Proved non-producing | 6,175 | 194 | 1,223 |
| Total proved developed | 134,538 | 4,195 | 26,618 |
| Proved undeveloped | 255,980 | 7,815 | 50,479 |
| Total proved | 390,518 | 12,011 | 77,097 |
| Probable additional | 138,591 | 3,997 | 27,095 |
| Total proved plus probable | 529,109 | 16,007 | 104,192 |
Numbers in this table may not add due to rounding.
Gross Company Reserve Reconciliation for 2016
(Gross company interest reserves before deduction of royalties payable)
| 6:1 Oil Equivalent (Mboe) | ||||||||
| Proved Developed Producing |
Total Proved |
Probable |
Proved plus Probable |
|||||
| December 31, 2015 – opening balance | 20,810 | 73,434 | 27,288 | 100,722 | ||||
| Acquisitions | – | – | – | – | ||||
| Discoveries | – | – | – | – | ||||
| Extensions | 8,032 | 5,182 | (292 | ) | 4,890 | |||
| Category transfer | – | – | – | – | ||||
| Dispositions | – | – | – | – | ||||
| Technical revisions | 1,392 | 3,319 | 100 | 3,419 | ||||
| Economic factors | – | – | – | – | ||||
| Production | (4,838 | ) | (4,838 | ) | – | (4,838 | ) | |
| December 31, 2016 – closing balance | 25,395 | 77,097 | 27,096 | 104,192 | ||||
Numbers in this table may not add due to rounding.
Reserve Life Index (“RLI”) Using Fourth Quarter Production
| (years) | 2016 | 2015 | 2014 |
| PDP | 5.2 | 5.3 | 3.6 |
| 1P | 15.9 | 18.8 | 15.9 |
| 2P | 21.4 | 25.7 | 23.5 |
The 1P and 2P RLI declined as a result of fewer step-out wells being drilled which limited additions to reserves and due to fourth quarter 2016 production increasing by 24% from fourth quarter 2015.
Future Development Costs (“FDC”)
| Proved ($M) |
Proved Plus Probable ($M) |
|||
| 2017 | 68,700 | 82,350 | ||
| 2018 | 125,613 | 161,058 | ||
| 2019 | 151,763 | 170,584 | ||
| 2020 | 66,697 | 97,154 | ||
| 2021 | – | 12,827 | ||
| Remainder | – | – | ||
| Total FDC – undiscounted | 412,773 | 523,972 | ||
| Total FDC – discounted at 10% | 347,044 | 435,644 | ||
| Umbach | $ | 400.4 million | $ | 495.1 million |
| HRB | $ | 12.3 million | $ | 28.9 million |
Note: InSite escalates capital costs at 2% per year after 2017.
Numbers in this table may not add due to rounding.
All-In Finding, Development and Acquisition Costs (“FD&A”)
(including acquisitions, dispositions and revisions)
| Proved Developed Producing FD&A Cost (All-In) | 2016 | 2015 | 2014 | 3 Year Total | ||||||
| Net capital investment (000s) | $ | 64,938 | $ | 71,509 | $ | 194,555 | $ | 331,002 | ||
| Total capital | $ | 64,938 | $ | 71,509 | $ | 194,555 | $ | 331,002 | ||
| Total reserve additions (Mboe) | 9,424 | 10,956 | 8,456 | 28,836 | ||||||
| All-in PDP FD&A cost (per Boe) | $ | 6.89 | $ | 6.53 | $ | 23.01 | $ | 11.48 | ||
| Total Proved FD&A Cost (All-In) | 2016 | 2015 | 2014 | 3 Year Total | ||||||
| Net capital investment (000s) | $ | 64,938 | $ | 71,509 | $ | 194,555 | $ | 331,002 | ||
| Change in FDC (000s) | (22,669 | ) | (12,275 | ) | 288,242 | 253,298 | ||||
| Total capital including change in FDC (000s) | $ | 42,269 | $ | 59,234 | $ | 482,797 | $ | 584,300 | ||
| Total reserve additions (Mboe) | 8,501 | 17,517 | 41,334 | 67,352 | ||||||
| All-in 1P FD&A cost (per Boe) | $ | 4.97 | $ | 3.38 | $ | 11.68 | $ | 8.68 | ||
| Total Proved Plus Probable FD&A Cost (All-In) | 2016 | 2015 | 2014 | 3 Year Total | ||||||
| Net capital investment (000s) | $ | 64,938 | $ | 71,509 | $ | 194,555 | $ | 331,002 | ||
| Change in FDC (000s) | (19,395 | ) | (63,288 | ) | 287,686 | 205,003 | ||||
| Total capital including change in FDC (000s) | $ | 45,543 | $ | 8,221 | $ | 482,241 | $ | 536,005 | ||
| Total reserve additions (Mboe) | 8,308 | 16,332 | 50,030 | 74,670 | ||||||
| All-In 2P FD&A cost (per Boe) | $ | 5.48 | $ | 0.50 | $ | 9.64 | $ | 7.18 | ||
NI 51-101 Finding and Development Costs (“F&D”)
(excluding acquisitions, dispositions and revisions)
| Total Proved F&D Cost | 2016 | 2015 | 2014 | 3 Year Total | |||||
| Capital expenditures excluding acquisitions and dispositions (000s) | $ | 64,938 | $ | 95,099 | $ | 106,604 | $ | 266,641 | |
| Change in FDC (000s) | (22,669 | ) | 18,604 | 288,242 | 284,177 | ||||
| Total capital including change in FDC (000s) | $ | 42,269 | $ | 113,703 | $ | 394,846 | $ | 550,818 | |
| Reserve additions excluding acquisitions, dispositions, and revisions (Mboe) | 5,182 | 14,950 | 38,707 | 58,863 | |||||
| 1P F&D cost (per Boe) | $ | 8.16 | $ | 7.61 | $ | 10.20 | $ | 9.36 | |
| Total Proved Plus Probable F&D Cost | 2016 | 2015 | 2014 | 3 Year Total | |||||
| Capital expenditures excluding acquisitions and dispositions (000s) | $ | 64,938 | $ | 95,099 | $ | 106,604 | $ | 266,641 | |
| Change in FDC (000s) | (19,395 | ) | 30,717 | 287,686 | 299,008 | ||||
| Total capital including change in FDC (000s) | $ | 45,543 | $ | 125,816 | $ | 394,290 | $ | 565,649 | |
| Reserve additions excluding acquisitions, dispositions, and revisions (Mboe) | 4,890 | 19,457 | 45,001 | 69,371 | |||||
| 2P F&D cost (per Boe) | $ | 9.31 | $ | 6.47 | $ | 8.76 | $ | 8.15 | |
Net Present Value Summary (before tax) as at December 31, 2016
Benchmark oil and NGL prices used are adjusted for quality of oil or NGL produced and for transportation costs. The calculated NPV include a deduction for estimated future well abandonment costs. The NPV disclosed does not represent fair market value of reserves.
| (000s) | Undiscounted | Discounted at 5% |
Discounted at 10% |
Discounted at 15% |
Discounted at 20% |
| Proved producing | 486,861 | 383,254 | 316,836 | 271,495 | 238,896 |
| Proved non-producing | 21,559 | 16,257 | 12,978 | 10,806 | 9,285 |
| Total proved developed | 508,420 | 399,511 | 329,814 | 282,301 | 248,181 |
| Proved undeveloped | 660,527 | 416,812 | 270,511 | 177,437 | 115,375 |
| Total proved | 1,168,947 | 816,323 | 600,324 | 459,738 | 363,556 |
| Probable additional | 511,202 | 272,727 | 157,811 | 96,661 | 61,309 |
| Total proved plus probable | 1,680,149 | 1,089,050 | 758,135 | 556,398 | 424,865 |
Numbers in this table may not add due to rounding.
Net Present Value Summary (after tax) as at December 31, 2016
Benchmark oil and NGL prices used are adjusted for quality of oil or NGL produced and for transportation costs. The calculated NPV each include a deduction for estimated future well abandonment costs. The NPV disclosed does not represent fair market value of reserves.
| (000s) | Undiscounted | Discounted at 5% |
Discounted at 10% |
Discounted at 15% |
Discounted at 20% |
| Proved producing | 478,916 | 379,518 | 315,007 | 270,567 | 238,410 |
| Proved non-producing | 15,916 | 13,256 | 11,326 | 9,870 | 8,741 |
| Total proved developed | 494,832 | 392,774 | 326,333 | 280,437 | 247,151 |
| Proved undeveloped | 487,961 | 303,815 | 192,667 | 121,593 | 73,984 |
| Total proved | 982,794 | 696,588 | 519,001 | 402,030 | 321,134 |
| Probable additional | 378,529 | 199,417 | 112,882 | 66,808 | 40,221 |
| Total proved plus probable | 1,361,323 | 896,005 | 631,883 | 468,838 | 361,355 |
Numbers in this table may not add due to rounding.
InSite Escalating Price Forecast as at December 31, 2016
| WTI Crude Oil (US$/Bbl) |
Edmonton Par Crude Oil (Cdn$/Bbl) |
Henry Hub Natural Gas (US$/Mmbtu) |
AECO Natural Gas (Cdn$/Mmbtu) |
|
| 2017 | 55.00 | 68.33 | 3.50 | 3.47 |
| 2018 | 60.00 | 72.32 | 3.50 | 3.42 |
| 2019 | 65.00 | 76.05 | 3.75 | 3.59 |
| 2020 | 70.00 | 79.54 | 3.90 | 3.93 |
| 2021 | 75.00 | 82.82 | 4.10 | 4.01 |
To view the graphs associated with this press release, please visit the following link: http://media3.marketwire.com/docs/srx0302graphs.pdf.
Boe Presentation – For the purpose of calculating unit revenues and costs, natural gas is converted to a barrel of oil equivalent (“Boe”) using six thousand cubic feet (“Mcf”) of natural gas equal to one barrel of oil unless otherwise stated. Boe may be misleading, particularly if used in isolation. A Boe conversion ratio of six Mcf to one barrel (“Bbl”) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All Boe measurements and conversions in this report are derived by converting natural gas to oil in the ratio of six thousand cubic feet of gas to one barrel of oil. Mboe means 1,000 Boe.
Non-GAAP Measures – This document contains the terms “debt including working capital deficiency”, “netbacks”, “field netbacks”, “field operating netbacks”, “field operating netbacks excluding hedging”, “cash”, “cash costs”, and measurements “per commodity unit” and “per Boe” which are not recognized under Generally Accepted Accounting Principles (“GAAP”) and are regarded as non-GAAP measures. These non-GAAP measures may not be comparable to the calculation of similar amounts for other entities and readers are cautioned that use of such measures to compare enterprises may not be valid. Non-GAAP terms are used to benchmark operations against prior periods and peer group companies and are widely used by investors, analysts and other parties. These measurements are also used by lenders to measure compliance with debt covenants and thus set interest costs. Additional information relating to certain of these non-GAAP measures can be found in Storm’s MD&A for the three months and year ended December 31, 2016, which is available on Storm’s SEDAR profile at www.sedar.com and on Storm’s website at www.stormresourcesltd.com.
Oil and Gas Metrics – This press release contains a number of oil and gas metrics, including FD&A, recycle ratio, FDC, and reserves life index or RLI, which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies. Such metrics have been included herein to provide readers with additional measures to evaluate the Company’s performance; however, such measures are not reliable indicators of the future performance of the Company and future performance may not compare to the performance in previous periods.
Initial Production Rates – References in this press release to initial production rates, and other short-term production rates are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long term performance or of ultimate recovery. Additionally, such rates may also include recovered “load oil” fluids used in well completion stimulation. Readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. A pressure transient analysis or well-test interpretation has not been carried out in respect of all wells. Accordingly, the Company cautions that the test results should be considered to be preliminary.
DPIIP – Original Oil in Place (OOIP) is the equivalent to Discovered Petroleum Initially In Place (DPIIP) for the purposes of this press release. DPIIP is defined as quantity of hydrocarbons that are estimated to be in place within a known accumulation. There is no certainty that it will be commercially viable to produce any portion of the resources. A recovery project cannot be defined for this volume of DPIIP at this time, and as such it cannot be further sub-categorized.
Forward-Looking Information – This press release contains forward-looking statements and forward-looking information within the meaning of applicable securities laws. The use of any of the words “will”, “would”, “expect”, “anticipate”, “intend”, “believe”, “plan”, “potential”, “outlook”, “forecast”, “estimate”, “budget” and similar expressions are intended to identify forward-looking statements or information. More particularly, and without limitation, this press release contains forward-looking statements and information concerning: production; drilling and completion plans; the third field compression facility and expansion plans in connection therewith; the arrangement with Spectra; hedging; transportation; organizational and personnel changes; 2017 guidance in respect of certain operational and financial metrics, including, but not limited to, commodity pricing, estimated average operating costs, estimated average royalty rate, estimated operations capital, estimated general and administrative costs, estimated first quarter, fourth quarter and annual production and estimated number of Umbach horizontal wells drilled, completed and connected, capital investment plans, infrastructure plans, anticipated United States exports, pipeline capacity, price volatility mitigation strategy and cost reductions. Statements of “reserves” are also deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.
The forward-looking statements and information in this press release are based on certain key expectations and assumptions made by Storm, including: prevailing commodity prices and exchange rates; applicable royalty rates and tax laws; future well production rates; reserve and resource volumes; the performance of existing wells; success to be expected in drilling new wells; the adequacy of budgeted capital expenditures to carrying out planned activities; the availability and cost of services; and the receipt, in a timely manner, of regulatory and other required approvals. Although the Company believes that the expectations and assumptions on which such forward-looking statements and information are based are reasonable, undue reliance should not be placed on these forward-looking statements and information because of their inherent uncertainty. In particular, there is no assurance that exploitation of the Company’s undeveloped lands and prospects will result in the emergence of profitable operations.
Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to the risks associated with the oil and gas industry in general such as: general economic conditions in Canada, the United States and internationally; operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to reserves, production, costs and expenses; health, safety and environmental risks; commodity price and exchange rate fluctuations; marketing and transportation of petroleum and natural gas and loss of markets; competition; ability to access sufficient capital from internal and external sources; geopolitical risk; stock market volatility; and changes in legislation, including but not limited to tax laws, royalty rates and environmental regulations.
Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect the operations or financial results of the Company are included or are incorporated by reference in the AIF and the MD&A.
The forward-looking statements and information contained in this press release are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.
NEITHER THE TSX VENTURE EXCHANGE NOR ITS REGULATION SERVICES PROVIDER (AS THAT TERM IS DEFINED IN THE POLICIES OF THE TSX VENTURE EXCHANGE) ACCEPTS RESPONSIBILITY FOR THE ADEQUACY OR ACCURACY OF THIS PRESS RELEASE.
Brian Lavergne
President & Chief Executive Officer
(403) 817-6145
Storm Resources Ltd.
Donald McLean
Chief Financial Officer
(403) 817-6145
Storm Resources Ltd.
Carol Knudsen
Manager, Corporate Affairs
(403) 817-6145
www.stormresourcesltd.com