CALGARY, ALBERTA–(Marketwired – May 12, 2016) – Storm Resources Ltd. (“Storm” or the “Company”) (TSX VENTURE:SRX) has also filed its unaudited condensed interim consolidated financial statements as at March 31, 2016 and for the three months then ended along with Management’s Discussion and Analysis (“MD&A”) for the same period. 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 ended March 31, 2016 appears below and should be read in conjunction with the related financial statements and MD&A.
|Thousands of Cdn$, except volumetric and per-share amounts||Three Months Ended
March 31, 2016
|Three Months Ended
March 31, 2015
|Revenue from product sales(1)||16,121||18,512|
|Funds from operations(2)||7,855||13,712|
|Per share – basic ($)||0.07||0.12|
|Per share – diluted ($)||0.07||0.12|
|Per share – basic ($)||(0.04||)||(0.03||)|
|Per share – diluted ($)||(0.04||)||(0.03||)|
|Net capital invested|
|Operations capital expenditures||23,946||35,680|
|Debt including working capital deficiency(3)||77,162||85,098|
|Common shares (000s)|
|Weighted average – basic||119,591||111,322|
|Weighted average – diluted||119,591||111,322|
|Outstanding end of period – basic||119,742||111,322|
|(Cdn$ per Boe)|
|Field operating netback||5.20||10.15|
|General and administrative||(1.25||)||(2.24||)|
|Interest and finance costs||(0.56||)||(0.70||)|
|Funds from operations – per Boe||6.42||15.57|
|Barrels of oil equivalent per day (6:1)||13,418||9,776|
|Thousand cubic feet per day||66,012||47,713|
|Price (Cdn$ per Mcf)||1.62||2.85|
|Barrels per day||2,416||1,493|
|Price (Cdn$ per barrel)||29.12||37.10|
|Barrels per day||–||330|
|Price (Cdn$ per barrel)||–||43.08|
|Wells drilled (100% working interest)||7.0||6.0|
|Wells completed (100% working interest)||2.0||3.0|
|(1)||Excludes hedging gains and losses.|
|(2)||Certain financial amounts shown above are non-GAAP measurements, including funds from operations and funds from operations per share, operations capital expenditures, debt including working capital deficiency and all measurements per Boe. See discussion of Non-GAAP Measurements on page 24 of the MD&A and the reconciliation of funds from operations to the most directly comparable measurement under GAAP, cash flows from operating activities, on page 17 of the MD&A.|
|(3)||Excludes the fair value of commodity price contracts.|
2016 FIRST QUARTER HIGHLIGHTS
- Production averaged 13,418 Boe per day (18% NGL), a per-share increase of 25% from the previous quarter and 27% from the previous year. Low natural gas prices resulted in production being reduced to meet firm processing and transportation commitments with approximately 800 Boe per day shut in at Umbach plus the startup of new horizontal wells was delayed.
- NGL production was 2,416 barrels per day, an increase of 62% from the previous year. The price was $29.12 per barrel which was 71% of the average Edmonton light oil price (60% of the NGL volume was higher value condensate and plant pentanes).
- NGL was 18% of total production but amounted to 40% of revenue from product sales versus 27% in the prior year period.
- Activity was focused at Umbach where seven horizontal wells were drilled, two horizontal wells were completed and one horizontal well commenced production.
- At the end of the quarter, there was an inventory of 12 horizontal wells (12.0 net) that had not started producing (includes three completed wells).
- Montney horizontal well performance at Umbach continues to improve with the four most recent wells averaging 5.8 Mmcf per day gross raw gas over the first 90 calendar days, a 23% increase from the average 2014 and 2015 wells. As a result, the type curve used for forecasting future horizontal well performance is being increased to 7.0 Bcf raw from 6.3 Bcf raw.
- Controllable cash costs (operating, cash G&A, interest expense) were $8.52 per Boe, a year-over-year decrease of 27%. Transportation cost is excluded given that the sales price for volumes sold on the Alliance Pipeline includes a deduction for the pipeline tariff (artificially reduces the transportation cost).
- Funds from operations was $7.9 million which is a decrease of 42% from the previous year. Production growth of 37% was more than offset by a 45% decrease in revenue plus hedging gains per Boe.
- With 67% of first quarter natural gas production being sold in the higher priced Chicago market, the natural gas price net of transportation was approximately 9% higher versus selling at BC Station 2.
- Net loss was $5.0 million or $4.09 per Boe and reflects the extremely low first quarter commodity prices with funds from operations at $6.42 per Boe being less than the depletion and depreciation rate of $8.15 per Boe.
- Net capital investment was $23.9 million and included $15.9 million for drilling and completions plus $6.1 million to purchase major equipment for the third field compression facility at Umbach.
- Debt including working capital deficiency was $77.2 million, which is 2.4 times annualized first quarter funds flow. Subsequent to quarter end, the bank credit facility was set at $130.0 million after the annual review was completed (previously $140.0 million).
Umbach, Northeast British Columbia
Storm’s land position at Umbach is prospective for liquids-rich natural gas from the Montney formation and currently totals 109,000 net acres (155 net sections). Two sections (2.0 net) were acquired during the first quarter of 2016. To date, 48 horizontal wells have been drilled (44.4 net) with 36 horizontal wells producing at the end of the first quarter (32.4 net).
First quarter 2016 production was 13,398 Boe per day with NGL recovery at 37 barrels per Mmcf sales (60% of the NGL volume is higher priced field condensate plus pentanes recovered at the gas plant).
In the first quarter of 2016, seven horizontal wells (7.0 net) were drilled, two wells (2.0 net) were completed, and one well (1.0 net) started production. There is currently an inventory of 12 horizontal wells (12.0 net) that have not started producing which includes three completed wells.
Storm’s two operated field compression facilities have total capacity of 80 Mmcf per day raw gas with actual throughput in the first quarter averaging 70 Mmcf per day raw gas. As a result of the low natural gas price at AECO and BC Station 2, construction of the third field compression facility with initial capacity of 35 Mmcf per day is being deferred with startup now planned for April 2017 (was November 2016). Estimated total cost is unchanged at $25.0 million (expandable to 70 Mmcf per day raw gas for an additional $7.0 million) with $10.9 million invested to date for site preparation and to purchase major equipment ($6.1 million Q1 2016, $4.8 million 2015).
Raw gas from Storm’s field compression facilities is sent to the McMahon and Stoddart Gas Plants where Storm has firm processing commitments totaling 65 Mmcf per day raw gas in 2016.
A summary of horizontal well performance and costs is provided below. The four most recent horizontal wells have averaged 5.8 Mmcf per day gross raw gas over the first 90 calendar days, a 23% improvement from the average 2014 and 2015 horizontal well. On a per-stage basis, the drill and complete cost in 2015 has decreased by 17% from 2014.
|Year of Completion||Frac
|17||1,190 m||$4.6 million
|19||1,170 m||$4.6 million
|22||1,360 m||$4.4 million
|Q4/15 (62-A pad)
|23||1,435 m||$4.3 million
* Performance to date of the 2015 wells was reduced by the downtime experienced in the second half of 2015.
Based on the performance of the most recent horizontal wells completed in Q4/15, which are longer and have more frac stages, Storm management is increasing the type curve used for forecasting performance of future horizontal wells to 7.0 Bcf raw from 6.3 Bcf raw (type curve has the same decline profile as the type curve used by InSite in the 2015 reserve evaluation). Future horizontal wells are being planned for greater than 1,600 metres of completed length with more than 28 frac stages. For reference, the previous 6.3 Bcf type curve was based on performance of the average 2014 and 2015 wells which have a completed length of 1,265 metres and an average of 21 frac stages. More information on the type curve and well economics is provided in the presentation on Storm’s website.
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, producing 280 Boe per day, was shut in during July 2015 due to the low natural gas price at BC Station 2.
HEDGING AND TRANSPORTATION
Commodity price hedges are used to support longer term growth by providing some certainty regarding future revenue and funds flow. A maximum of 50% of the most recent monthly production will be hedged; anticipated production growth is not hedged. Although Storm has no oil production, the WTI price is hedged as approximately 80% of NGL production is priced in reference to WTI (condensate, plant pentane and butane). A summary for 2016 is provided below.
|Crude Oil||500 Bopd||Collar – WTI Cdn$75.00 X Cdn$90.75/Bbl|
|Natural Gas||21,250 GJ/d (17,000 Mcf/d)||AECO Cdn$2.98/GJ ($3.72/Mcf)|
|11,000 GJ/d (8,800 Mcf/d)||BC Stn 2 price = AECO – Cdn$0.3375/GJ|
|33,000 Mmbtu/d (27,800 Mcf/d)||Chicago price = AECO + US$0.672/Mmbtu|
Storm’s strategy with respect to natural gas transportation commitments is to ensure natural gas sales are diversified by selling at Chicago, AECO and BC Station 2. Current transportation commitments total 63 Mmcf per day in 2016 and increase to 92 Mmcf per day in 2018 (interruptible capacity on the Alliance Pipeline adds up to 11 Mmcf per day in 2016 and 13 Mmcf per day in 2018). A summary is provided below.
|44 Mmcf/d (55,000 GJ/d)(1)||48 Mmcf/d (61,000 GJ/d)(1)||53 Mmcf/d (67,000 GJ/d)(1)|
|sale at McMahon (Alliance Pipeline)||sale at McMahon (Alliance Pipeline)||sale at McMahon (Alliance Pipeline)|
|Chicago price – Cdn$1.30/GJ(2)||Chicago price – Cdn$1.30/GJ(2)||Chicago price – Cdn$1.30/GJ(2)|
|9.0 Mmcf/d (11,400 GJ/d)
sale at BC Stn 2
-Cdn$0.15/GJ pipeline tariff
|24.0 Mmcf/d (30,200 GJ/d)
sale at BC Stn 2
-Cdn$0.15/GJ pipeline tariff
|29.0 Mmcf/d (36,500 GJ/d)
sale at BC Stn 2
-Cdn$0.15/GJ pipeline tariff
|9.8 Mmcf/d (12,400 GJ/d)
sale at McMahon
AECO – Cdn$0.68/GJ differential
|10.0 Mmcf/d (12,600 GJ/d)
sale at AECO
-Cdn$0.43/GJ pipeline tariffs
|(1)||Interruptible capacity on the Alliance Pipeline adds up to 25% of contracted capacity.|
|(2)||The Alliance Pipeline tariff of $1.30 per GJ is determined assuming US$1 = Cdn$1.29, Chicago US$2.20 per Mmbtu and 5.25% shrinkage for fuel gas (fuel gas shrinkage adds $$0.14 per GJ).|
Production in the second quarter is forecast to be approximately 12,500 Boe per day and, until the natural gas price improves, production will be maintained at this level which fulfills firm processing and transportation commitments. Capital investment in the second quarter is expected to be under $2.0 million.
Natural gas prices remain weak with April daily spot prices averaging US$1.92 per Mmbtu at Chicago and $1.04 per GJ at AECO. Forward strip pricing for natural gas for the remainder of 2016 is not materially different from pricing realized in the first quarter where the operating netback excluding hedging gains was $5.20 per Boe. This is less than the cost of adding reserves (the 2015 all-in PDP FD&A cost was $6.53 per Boe) and, as a result, producing more than what’s required to fulfill firm processing and transportation commitments is not economically justifiable. As a result, capital investment in 2016 will be reduced to between $37.0 and $42.0 million with the startup of the third facility at Umbach deferred to April 2017 when the forward strip is supportive of production growth. With the benefit of commodity price hedges and with the majority of natural gas production being sold in Chicago at a higher price than at BC Station 2, forecast funds flow in 2016 is expected to provide most of the capital required to maintain production at current levels. Revised guidance is provided below with assumed commodity prices being approximately equal to realized prices to date and the current forward strip.
|2016 Guidance||Original Guidance
Nov 11, 2015
Feb 25, 2016
May 12, 2016
|Chicago natural gas price||US$2.20 per Mmbtu||US$2.20 per Mmbtu|
|AECO natural gas price||$2.50 per GJ||$2.00 per GJ||$1.60 per GJ|
|BC STN 2 natural gas price||$1.90 per GJ||$1.45 per GJ||$1.25 per GJ|
|Edmonton light oil price||Cdn$57 per Bbl||Cdn$46 per Bbl||Cdn$50 per Bbl|
|Estimated average operating costs||$7.00 – $7.50 per Boe||$7.00 per Boe||$7.00 per Boe|
|Estimated average royalty rate (% production revenue before hedging)||7% – 8%||5% – 6%||5% – 6%|
|Estimated operations capital(excluding acquisitions & dispositions)||$105.0 million||$80.0 million||$37.0 – $42.0 million|
|Estimated cash G&A net of recoveries||$5.0 million
$0.80 per Boe
$0.95 per Boe
$1.20 per Boe
|Estimated funds flow||$39.0 million||$31.0 million|
|Forecast fourth quarter production||20,000 – 21,000 Boe/d
|15,500 – 16,500 Boe/d
|13,000 – 14,000 Boe/d
|Forecast annual production||16,000 – 18,000 Boe/d
(17% oil + NGL)
|14,000 – 15,000 Boe/d
(18% oil + NGL)
|12,500 – 13,500 Boe/d
(18% oil + NGL)
|Umbach horizontal wells drilled||14 gross (14.0 net)||12 gross (12.0 net)||8 gross (8.0 net)|
|Umbach horizontal wells completed||14 gross (14.0 net)||10 gross (10.0 net)||6 gross (6.0 net)|
|Umbach horizontal wells connected||16 gross (16.0 net)||12 gross (12.0 net)||8 gross (8.0 net)|
With respect to the revised guidance, estimated cash G&A net of recoveries for 2016 has increased as a result of lower overhead recoveries associated with lower capital investment (no change to gross G&A excluding overhead recoveries). As well, capital investment in 2016 includes $6.1 million incurred in the first quarter to purchase major equipment for the third field compression facility.
The AECO – BC Station 2 price differential was -$0.41 per GJ in the first quarter, an improvement from -$0.85 per GJ in 2015 and closer to historical levels (-$0.20 per GJ for 2010 to 2014). Although the low AECO price in the first quarter ($1.74 per GJ) has more than offset the improvement, having the differential return to historical levels is supportive of Storm’s future production growth given that incremental production would be sold at BC Station 2.
Reducing cash costs and improving capital efficiency has always been a focus at the current and predecessor ‘Storm’ companies. Further improvements are expected in 2016 with the largest being the transition to drilling longer horizontal wells with more frac stages which is expected to result in a reduction of the cost to add reserves. Cash costs are also expected to decrease by reducing third party processing fees and through initiatives to reduce field level operating expenses.
Further weakening of natural gas prices in North America over the last three months is the result of reduced demand from a warmer than normal winter combined with continued growth in natural gas production. At current pricing, the business is ‘broken’ for natural gas producers in Western Canada as funds flow excluding hedges fails to generate sufficient capital to offset declines; as well, rates of return are too low to justify growing production on a full-cycle basis (including the cost of expanding infrastructure). Pricing will improve once the oversupply of natural gas is reduced through natural declines and shut-ins. Not knowing when the natural gas price will improve, Storm’s primary objective in 2016 is to maintain a strong balance sheet by ensuring capital investment is approximately equal to funds flow and thus avoid increasing debt. This will preserve the ability to accelerate growth when the price does improve.
Although Storm is reducing capital investment in 2016 as a result of deterioration in the price of natural gas, annual average production in 2016 is still forecast to increase by 30% on a year-over-year basis.
Storm’s land position in the Horn River Basin continues to be a core, long-term asset with significant leverage to higher natural gas prices.
Brian Lavergne, President and Chief Executive Officer
May 12, 2016