Mr. Brian Lavergne reports
STORM RESOURCES LTD. IS PLEASED TO ANNOUNCE ITS FINANCIAL AND OPERATING RESULTS FOR THE THREE MONTHS AND YEAR ENDED DECEMBER 31, 2014
Storm Resources Ltd. has filed its audited consolidated financial statements as at Dec. 31, 2014, and for the three months and year then ended along with management's discussion and analysis for the same periods. This information appears on SEDAR and on Storm's website.
Selected financial and operating information for the three months and year ended Dec. 31, 2014, as well as reserves information at Dec. 31, 2014, appears herein and should be read in conjunction with the related financial statements and MD&A.
HIGHLIGHTS
Three Three
months months Year Year
ended ended ended ended
Thousands of Cdn$, except volumetric Dec. Dec. Dec. Dec.
and per-share amounts 31, 2014 31, 2013 31, 2014 31, 2013
Financial
Revenue from product sales $28,070 $15,380 $95,480 $49,578
Funds from operations 13,892 7,501 45,412 21,949
Per share -- basic ($) 0.13 0.09 0.42 0.30
Per share -- diluted ($) 0.12 0.09 0.41 0.30
Net income (loss) (7,422) (25,174) 4,855 (26,203)
Per share -- basic ($) (0.07) (0.34) 0.04 (0.36)
Per share -- diluted ($) (0.07) (0.34) 0.04 (0.36)
Operations capital expenditures 20,219 11,380 106,604 67,410
Land and property
acquisitions/dispositions (124) -- 87,951 (14,966)
Debt including working capital
deficiency 63,080 12,059 63,080 12,059
Operations
Revenue (Cdn$ per boe) $29.99 $35.02 $37.48 $37.34
Royalties (Cdn$ per boe) (3.69) (2.65) (5.16) (4.55)
Production (Cdn$ per boe) (8.40) (9.73) (9.33) (10.86)
Transportation (Cdn$ per boe) (1.91) (1.82) (1.80) (1.50)
Field operating netback 15.99 20.82 21.19 20.43
Hedging gains (losses) (Cdn$ per boe) 0.52 0.09 (1.26) (0.03)
General and administrative (Cdn$ per
boe) (1.16) (3.25) (1.50) (2.98)
Interest (Cdn$ per boe) (0.50) (0.58) (0.60) (0.90)
Funds from operations netback (Cdn$ per
boe) 14.85 17.10 17.83 16.52
Barrels of oil equivalent per day (6:1) 10,173 4,773 6,980 3,637
Gas production
Thousand cubic feet per day 49,094 21,898 33,067 15,843
Price (Cdn$ per Mcf) 3.85 3.88 4.58 3.63
NGL production
Barrels per day 1,605 695 1,064 512
Price (Cdn$ per barrel) 56.15 70.10 69.90 0.29
Oil production
Barrels per day 385 428 405 485
Price (Cdn$ per barrel) 68.01 78.47 88.10 87.16
Wells drilled
Gross 2.0 1.0 17.0 9.0
Net 2.0 1.0 17.0 8.6
President's message
Fourth quarter and year-end
2014 highlights:
- In 2014, significant per-share growth in production and reserves was
achieved, and material improvements were realized in controllable cash
costs and the cost of reserve additions.
- Production for the year averaged 6,980 barrels of oil equivalent per day (21 per cent oil plus natural gas liquids), a
per-share increase of 51 per cent from 2013 (notable given the 28-per-cent increase in
shares outstanding). Fourth quarter production was 10,173 boe per day
(20 per cent oil plus NGL), an increase of 69 per cent on a per-share basis from the
previous year. The increase was the result of growth at Umbach, where
fourth quarter production was 8,775 boe per day, an increase of 169 per cent
from 3,262 boe per day in the fourth quarter of 2013.
- NGL production was 1,605 barrels per day in the fourth quarter, a year-over-year growth of 131 per cent. The increase was the result of production
growth from the liquids-rich Montney formation at Umbach, where NGL
recovery was sales of 35 barrels per million cubic feet in the fourth quarter. With
approximately 60 per cent of the NGL mix being condensate plus pentanes, the NGL
price of $56.15 per barrel was 74 per cent of the average Edmonton light oil
price.
- Activity during 2014 was focused at Umbach, where 16 Montney horizontal
wells (16.0 net) plus one Montney vertical delineation well (1.0 net)
were drilled, 13 horizontal wells (12.6 net) were completed, 10
horizontal wells (9.6 net) began producing and a 100-per-cent-working-interest
field compression facility was started up in August. In the fourth
quarter, two Montney horizontal wells (2.0 net) were drilled, four
Montney horizontal wells (4.0 net) were completed and three Montney
horizontal wells (3.0 net) began producing.
- For the 2014 Montney horizontal wells at Umbach, calendar day rates
(including downtime) over the first 90 days averaged 4.8 million cubic feet per day
gross raw gas (865 boe per day sales), an improvement of 37 per cent from the
average 2013 horizontal well.
- Both operated facilities at Umbach have been full since mid-September,
and there is currently an inventory of 11 horizontal wells (11.0 net)
that have not started producing, which include four completed horizontal
wells. In addition, two more horizontal wells (2.0 net) remain to be
drilled in the first quarter. Storm will achieve 2015 production
guidance with forecast production from these horizontal wells.
- Funds from operations for the year totalled $45.4-million, or 42 cents per
share, an increase of 40 per cent on a per-share basis from the previous year.
Funds from operations in the fourth quarter were $13.9-million, or 13
cents per basic share, an increase of 44 per cent from the prior year.
- The funds from operations netback for the year was $17.83 per boe, a
year-over-year increase of 8 per cent, which was primarily the result of a
decline in operating costs and cash general and administrative totalling $3.01 per boe that was
partially offset by an increased hedging loss of $1.23 per boe.
- Controllable cash costs (operating, transportation, cash G&A and interest
expense) were $13.23 per boe in 2014, a year-over-year decrease of 19 per cent.
Controllable cash costs showed further improvement to average $11.97 per
boe in the fourth quarter. Cash G&A was $1.50 per boe in 2014, a year-over-year decrease of 50 per cent. Operating costs for the year decreased by 14 per cent
to average $9.33 per boe and further improved to $8.40 per boe in the
fourth quarter.
- Net income for the year was $4.9-million, or four cents per share, a
significant improvement when compared with the loss of $26.2-million in
the previous year. This included a $22.7-million reduction in the
carrying amount of the Grande Prairie properties, which was partially
offset by a $14.2-million unrealized gain on commodity price hedges.
- Capital investment was focused on the Umbach area and totalled $194.5-million for the year, which included $88.0-million to acquire a 100-per-cent
working interest in 29 sections of land at Umbach, $34.3-million for
infrastructure, and $68.1-million for drilling and completions.
- Cost of adding production during 2014 was approximately $16,400 per boe
per day using 2014 operations capital investment of $106.6-million and
average fourth quarter production of 6,520 boe per day from wells that
started production in 2014 (excludes 350 boe per day acquired in January,
2014).
- Operating income for the year, being net income adjusted for impairment
charges and unrealized hedging gains, was $13.4-million, or 12 cents per
share.
- The unrealized value of the commodity price contracts was $12.9-million
at year-end, and during the fourth quarter, a cash gain of $500,000 was realized.
- Debt plus working capital deficiency was $63.1-million at year-end, which
is 1.1 times annualized fourth quarter cash flow. In November, 2014,
Storm's bank credit line was increased to $130.0-million from $90.0-million.
YEAR-END 2014 RESERVE EVALUATION HIGHLIGHTS
Dec. 31, 2014 Dec. 31, 2013
Reserves
Proved producing (Mboe) 13,487 7,579
Total proved (Mboe) 59,551 20,764
Total proved plus probable (Mboe) 88,024 40,541
Reserves per share
Proved producing (Mboe per million
shares) 121 87
Total proved (Mboe per million
shares) 535 237
Total proved plus probable (Mboe
per million shares) 791 463
Finding and development (F&D) cost
including the change in future
development capital and excluding
revisions,
acquisitions and dispositions
Proved producing ($/boe) $13.73 $19.53
Total proved ($/boe) $10.20 $13.98
Total proved plus probable ($/boe) $8.76 $10.75
All-in finding, development and
acquisition (FD&A) cost
including the change in future
development capital
Proved producing ($/boe) $23.01 $17.22
Total proved ($/boe) $11.68 $13.19
Total proved plus probable ($/boe) $9.64 $9.79
Recycle ratio using F&D
Annual field operating netback
excluding hedging $21.19 $20.43
Proved producing 1.5 X 1.0 X
Total proved recycle 2.1 X 1.5 X
Total proved plus probable recycle 2.4 X 1.9 X
Recycle ratio using all-in FD&A
Annual field operating netback
excluding hedging $21.19 $20.43
Proved producing 0.9 X 1.2 X
Total proved recycle 1.8 X 1.6 X
Total proved plus probable recycle 2.2 X 2.1 X
Reserve life index using fourth
quarter production
Total proved 16.1 years 11.9 years
Total proved plus probable 23.7 years 23.3 years
Net present value discounted at
10% (before tax)
Proved producing ($M) $199,000 $122,000
Total proved ($M) $493,000 $184,000
Total proved plus probable ($M) $684,000 $298,000
Reserve additions replaced 332 per cent of 2014 production on a proved producing
basis, 1,522 per cent on a total proved basis and 1,863 per cent on a total proved plus
probable basis.
The all-in 2P 2014 finding, development and acquisition cost of $9.64 was impacted by an acquisition in
the Umbach area in January, 2014, for a total cost of $88.0-million with
$78.2-million allocated to acquiring undeveloped land and the rest
to acquiring production and reserves. The 2P F&D cost of $8.76 as per NI
51-101 guidelines more realistically reflects the cost of developing the
Montney at Umbach in 2014 as this excludes the effect of acquisitions,
dispositions and revisions.
At Umbach, the area where total proved plus probable reserves were
assigned grew to 18 per cent of Storm's 141 net sections from 8 per cent last year, and
this included 73.4 net horizontal drilling locations, which represent
approximately five years of activity.
Storm's enterprise value at the end of 2014 was $523.9-million, which is
equal to $16.32 per boe on a 1P basis, including future development costs
and $12.85 per boe on a 2P basis, including FDC (using 111.3
million shares outstanding, the Dec. 31 closing share price of $4.14
and year-end debt of $63.1-million).
Storm's asset value using shares outstanding at year-end grew to $5.58
per share from $3.25 per share last year, and this excludes any amount
for undeveloped land. Asset value was determined by deducting net debt
at year-end from the before-tax net present value for proved plus
probable reserves discounted at 10 per cent.
Operations review
Storm has a focused asset base with large land positions in resource plays at Umbach and in the Horn River basin, each of which has multiyear drilling upside while the Grande Prairie area, with its shallow decline, provides cash flow available for investment.
Umbach in northeast British Columbia
Storm's land position at Umbach is prospective for liquids-rich natural gas from the Montney formation and currently totals 141 net sections (167 gross sections), or 100,000 net acres. To date, 30.4 net horizontal wells (34.0 gross) have been drilled into the Montney formation with 20.4 net being on production.
Fourth quarter production from Umbach was 8,775 barrels of oil equivalent per day with NGL production of 1,540 barrels per day representing a sales recovery of 35 barrels per million cubic feet (approximately 60 per cent higher-priced condensate plus pentanes). Revenue from Umbach was $29.08 per boe ($3.88-per-thousand-cubic-foot sales and $56.33 per barrel of NGL), transportation costs were $1.81 per boe, royalties were $3.86 per boe, or 13 per cent of revenue, operating costs were $7.90 per boe and the operating netback was $15.51 per boe.
Activity in the fourth quarter included drilling two Montney horizontal wells (2.0 net) and completing four Montney horizontal wells (4.0 net) with three horizontal wells (3.0 net) starting production. In 2014, 16 Montney horizontal wells (16.0 net) were drilled and 13 horizontal wells (12.6 net) were completed, which include two wells (1.6 net) drilled in 2012 and 2013. Ten (9.6 net) of the completed horizontal wells started producing in 2014. There remains an inventory of 11 horizontal wells (11.0 net) that have not started producing, which include four completed horizontal wells and seven standing horizontal wells awaiting completion. In addition, two horizontal wells (2.0 net) remain to be drilled during the first quarter of 2015.
Storm operates two field compression facilities (both 100-per-cent working interest) that have total capacity of 45 million cubic feet per day raw gas with the gas from both directed to the McMahon gas plant for processing. The first field compression facility with capacity of 18 million cubic feet per day raw gas had average throughput of 17 million cubic feet per day raw gas in the fourth quarter, with NGL sales recovery of 30 barrels per million cubic feet. The second field compression facility with 27 million cubic feet per day of capacity was started up in August, 2014, and throughput in the fourth quarter averaged 24 million cubic feet per day of gross raw gas with NGL recovery of 34 barrels per million cubic feet of sales. Final cost of the second facility was $15.3-million (9 per cent higher than initial guidance). Capacity of the second facility is being increased to 55 million cubic feet per day raw gas in late March, 2015, with the estimated cost being $13.5-million ($3.9-million to purchase equipment in 2014 and the remaining $9.6-million in the first quarter of 2015). In the second quarter of 2015, a condensate stabilizer and other equipment will be installed at the second facility with the estimated cost being $5.1-million.
During the first quarter of 2015, a 15-kilometre pipeline will be constructed to connect the first field compression facility to the Stoddart gas plant. The estimated gross cost is $4.8-million with Storm's working interest being 60 per cent. This will increase NGL recovery from 30 to 55 barrels per million cubic feet for production from the first field compression facility, which has capacity of 18 million cubic feet per day raw gas.
Construction of a third field compression facility (announced on Nov. 13, 2014) is being deferred given the recent decline in NGL and natural gas prices. Engineering design has been completed, and $5.0-million will be invested to purchase major equipment in 2015, which will shorten the construction period to six months once a decision is made to go ahead (likely in 2016). Total cost of the third facility is estimated to be $24.0-million for a raw gas capacity of 35 million cubic feet per day, and it will be expandable to 70 million cubic feet per day for an additional investment of $7.0-million.
Comparing calendar day rates (includes downtime) over the first 180 days, the five 2014 Montney horizontal wells with enough history are 72 per cent better than the average 2013 horizontal well. The producing Montney horizontal wells table is a comparison of calendar day rates for all of the producing Montney horizontal wells.
PRODUCING MONTNEY HORIZONTAL WELLS
IP 90 cal day IP 180 cal day IP 365 cal day
Frack gross gross gross
stages raw MMcf per day raw MMcf per day raw MMcf per day
2011 HZs (4 7-11 2.0 MMcf/d 1.5 MMcf/d 1.3 MMcf/d
wells) 360 boe/d sales 270 boe/d sales 235 boe/d sales
4 HZs 4 HZs 4 HZs
2012 HZs (3 14 1.6 MMcf/d 1.3 MMcf/d 1.5 MMcf/d
wells) 290 boe/d sales 235 boe/d sales 270 boe/d sales
3 HZs 3 HZs 3 HZs
2013 HZs (6 16-18 3.5 MMcf/d 2.9 MMcf/d 2.2 MMcf/d
wells) 630 boe/d sales 525 boe/d sales 400 boe/d sales
6 HZs 6 HZs 6 HZs
2014 HZs (7 16-20 4.8 MMcf/d 5.0 MMcf/d 4.3 MMcf/d
wells) 865 boe/d sales 900 boe/d sales 780 boe/d sales
10 HZs 5 HZs 1 HZ
Sales volume is calculated using 8-per-cent shrinkage from raw gas to
sales and 30 barrels of NGL per million cubic feet sales.
Based on the performance of the 2014 horizontal wells and given that the majority of horizontal wells that will be completed in 2015 are 20 per cent longer with more frack stages (20 to 24), Storm management is now using a 6.3-billion-cubic-foot-raw-gas type curve for internal budgeting purposes (this type curve has the same decline profile as the 3.2-billion- and 4.4-billion-cubic-foot-raw-gas 2P type curves used by InSite in the 2014 reserve evaluation). Previously, a 5.0-billion-cubic-foot-raw-gas type curve was used- which was based on the performance of the 2013 and 2014 horizontal wells. With a 6.3-billion-cubic-foot-raw-gas type curve, the first-year average rate is 3.6 million cubic feet per day gross raw gas or sales of 650 boe per day (8-per-cent shrinkage from raw gas to sales and sales of 30 barrels of NGL per million cubic feet). Based on a cost of $5.4-million to drill, complete and tie in a horizontal well with 20 to 24 frack stages, the payout is approximately 23 months, and the rate of return is 35 per cent, assuming flat pricing of $3 per gigajoule at AECO and $66 (Canadian) per barrel for Edmonton light oil (see presentation on website for further details). In 2014, the cost to drill a horizontal well averaged $2.1-million with the completion cost averaging $2.5-million for 16 to 20 frack stages. Drilling times have averaged approximately 14 days. Tie-in costs have averaged $300,000 per horizontal well, which does not include the cost of longer gathering pipelines to connect multiwell pads to field compression facilities. With the 2015 horizontal wells having an increased number of frack stages (20 to 24), the cost to drill, complete and tie in a horizontal well was also increased to $5.4-million. These results do not recognize any improvement in service costs in 2015.
Horn River basin in northeast British Columbia
Storm has a 100-per-cent working interest in 123 sections in the HRB (81,000 net acres), which is prospective for natural gas from the Muskwa, Otter Park and Evie/Klua shales. Fourth quarter production averaged 307 boe per day (100 per cent natural gas), a year-over-year decline of 15 per cent. The operating netback was $5.91 per boe with revenue of $18.41 per boe, transportation costs of 66 cents per boe, an operating cost of $9.95 per boe, and a royalty of $1.89 per boe, or 10 per cent of revenue.
Grande Prairie area in northwest Alberta and northeast British Columbia
Production in the fourth quarter was 1,091 boe per day (41 per cent oil plus NGL), a year-over-year decline of 5 per cent. The operating netback was $19.96 per boe with revenue of $41.35 per boe, a transportation cost of $3.14 per boe, an operating cost of $12.04 per boe, and a royalty of $6.20 per boe, or 15 per cent of revenue. Cash flow from this area continues to be reinvested to increase production at Umbach.
In mid-January, 2015, approximately 150 boe per day was shut in as a result of the recent decline in the natural gas price.
Hedging update
For 2015, commodity price hedges include both fixed-price swaps and collars:
- With 22.5 million cubic feet per day (27,900 gigajoules per day) of natural gas from January to
December at an average floor price of approximately $4.28 per thousand cubic feet and an
average ceiling price of $4.54 per thousand cubic feet (AECO monthly index $3.45 per gigajoule
for floor and $3.66 per gigajoule for ceiling);
- With 533 barrels per day of oil from January to September at a price of WTI
$98.43 (Canadian) per barrel. This hedge was sold in January, 2015, for net
proceeds of $5.1-million.
At the end of 2014, the unrealized gain on the 2015 commodity prices hedges was $12.9-million.
The purpose of Storm's commodity price hedges is to reduce the effect of commodity price fluctuations on capital investment and growth over the next 12 months. A maximum of 50 per cent of current production (most recent monthly or quarterly average), before royalties, will be hedged. Anticipated production growth is not hedged.
Comparison of 2014 results versus guidance
The attached comparison of 2014 results versus guidance table contains a comparison of Storm's actual 2014 results with guidance provided during 2014.
COMPARISON OF 2014 RESULTS VERSUS GUIDANCE
Jan. 23, Nov. 13,
2014, May 14, 2014, 2014,
original revised revised Actual 2014
2014 guidance guidance guidance guidance results
AECO natural gas
price $3.35 per GJ $4.25 per GJ $4.30 per GJ $4.27 per GJ
Edmonton light
oil price Cdn$89 per bbl Cdn$94 per bbl Cdn$97 per bbl Cdn$95 per bbl
Average $8.00-$9.00 $8.00-$9.00 $9.00-$9.50
operating costs per boe per boe per boe $9.33 per boe
Average royalty
rate
(% of revenue
before hedging) 14%-15% 15%-16% 15% 13.7%
Operations
capital
(excluding
acquisitions and
dispositions) $78.0-million $97.0-million $105.0-million $106.7-million
Land and property
acquisitions $88.0-million $88.0-million $88.0-million $88.0-million
Cash G&A $4.0-million $4.0-million $3.8-million $3.8-million
Forecast fourth 7,500-7,900 8,900-9,200
quarter boe/d boe/d 10,500 boe/d 10,173 boe/d
production (20% oil+NGL) (20% oil+NGL) (20% oil+NGL) (20% oil+NGL)
Forecast annual 5,500-6,500 6,000-6,700 7,000 boe/d 6,980 boe/d
production boe/d boe/d (21% oil+NGL) (21% oil+NGL)
(21% oil+NGL) (21% oil+NGL)
Umbach
horizontal 10 gross 14 gross 16 gross 16 gross
wells drilled (10.0 net) (14.0 net) (16.0 net) (16.0 net)
Umbach
horizontal 9 gross 13 gross 13 gross 13 gross
wells completed (9.0 net) (12.6 net) (12.6 net) (12.6 net)
Outlook
Production in January, 2015, averaged 10,060 boe per day based on field estimates, and production in the first quarter of 2015 is forecast to be 9,500 to 10,000 boe per day, which includes three to five days of downtime at Umbach for piping connections associated with the expansion of the second field compression facility. Capital investment in the first quarter is expected to total $35.0-million to $38.0-million, which includes drilling six Montney horizontal wells (6.0 net), completing two horizontal wells (2.0 net), constructing a 15-kilometre pipeline connection to the Stoddart gas plant and expanding the second field compression facility at Umbach. At Umbach, the existing field compression facilities are full, and there is currently an inventory of 11 horizontal wells (11.0 net) that will start production after the second field compression facility is expanded from 27 million to 55 million cubic feet per day raw gas in late March.
Guidance for 2015 is being revised from original guidance provided on Nov. 13, 2014. Due to the recent decline in oil and natural gas prices, operations capital expenditures will be reduced to $80.0-million from $110.0-million. The effect on production guidance is expected to be minimal because Umbach horizontal well performance has been higher than that used in the production forecast. In addition, throughput at the second Umbach field compression facility has been 27 million cubic feet per day raw gas, which has exceeded the design capacity of 24 million cubic feet per day, and the expansion in March is now expected to increase capacity to 55 million cubic feet per day raw gas versus previous expectations of 48 million cubic feet per day.
GUIDANCE FOR 2015
Nov. 13, 2014, Feb. 26, 2015,
original guidance revised guidance
AECO natural gas price $3.25 per GJ $2.35-$2.90 per GJ
B.C. STN 2 natural gas price $3.00 per GJ $2.05-$2.60 per GJ
Edmonton light oil price Cdn$83 per bbl Cdn$53-$62 per bbl
Estimated average operating
costs $7.50-$8.00 per boe $8.00-$8.50 per boe
Estimated average royalty rate
(on production revenue before
hedging) 12%-14% 6%-10%
Estimated operations capital
(excluding acquisitions and
dispositions) $110.0-million $80.0-million
Estimated land and property
acquisitions $0.0-million $0.0-million
Estimated cash G&A net of
recoveries $5.3-million $5.3-million
Forecast fourth quarter 14,000-14,500 boe/d 14,000-14,500 boe/d
production (18% oil+NGL) (19% oil+NGL)
Forecast annual production 11,500-12,700 boe/d 11,000-12,000 boe/d
(19% oil+NGL) (20% oil+NGL)
Umbach horizontal wells
drilled 9 gross (9.0 net) 6 gross (6.0 net)
Umbach horizontal wells
completed 14 gross (14.0 net) 11 gross (11.0 net)
Umbach horizontal wells
starting production 16 gross (16.0 net) 14 gross (14.0 net)
Capital investment for 2015 includes:
- $47.8-million at Umbach for drilling and completions;
- $18.4-million to expand infrastructure at Umbach, including expansion of
the second field compression facility from 27 million cubic feet per day to 55 million cubic feet
per day in late March;
- $5.0-million to order major equipment for a third field compression
facility at Umbach, which will shorten the construction period to six
months once a decision is made to build it.
This level of investment is forecast to increase production in the fourth quarter of 2015 to 14,000 to 14,500 boe per day, which represents 40-per-cent growth per share on a year-over-year basis.
Average production in 2015 is forecast to be 11,000 to 12,000 boe per day with the midpoint representing an increase of 67 per cent from average production in 2014. This includes approximately 60 per cent of Umbach production being shut in for 35 days from June 6 to July 11 for a scheduled maintenance turnaround at the McMahon gas plant.
Total debt at the end of 2015 is forecast to be $85.0-million to $96.0-million, which would be approximately 1.2 to 1.9 times annualized funds from operations in the fourth quarter of 2015 (assuming commodity prices in 2015 average AECO $2.35 to 2.90 per gigajoule and Edmonton light oil $53 (Canadian) to $62 (Canadian) per barrel). The year-over-year increase in debt is forecast to be 30 per cent to 50 per cent, which is consistent with year-over-year production growth. Debt is primarily financing infrastructure expansion at Umbach in 2015, which is an investment in a long-life asset.
Storm is still in the early stages of delineating a large, higher-quality, liquids-rich resource in the Montney formation at Umbach. At the end of 2014, proved plus probable reserves were assigned on only 18 per cent of Storm's land position (25.5 net sections of 141 net sections), leaving room for significant future reserve growth from drilling horizontal wells to test the remaining lands, which appear to be highly prospective, given horizontal well results on offsetting acreage. In addition, continuing to optimize horizontal well length, spacing between horizontal wells, number of frack stages and completion techniques are also likely to increase reserve bookings per horizontal well and will reduce the cost of reserve additions.
Although the recent decline in commodity prices is going to make 2015 much more challenging, Storm's commodity price hedges will mitigate the impact. In addition, the liquids-rich natural gas in the Montney at Umbach provides Storm with a competitive advantage from increased revenue through NGL recovery while the relatively shallow depth (1,400 to 1,600 metres) results in a lower drilling and completion cost. With an evolving long-term plan in place to continue expanding infrastructure, plus a large inventory of horizontal drilling locations that provide reasonable rates of return at relatively low commodity prices, high levels of growth are expected to continue for the next three to five years.
Storm's land position in the HRB continues to be a core, long-term asset with significant leverage to higher natural gas prices.
In closing, the company thanks its employees for their efforts and Storm's directors for their valuable advice and guidance in 2014, which resulted in record levels of production plus significant growth in reserves and asset value.
Respectfully,
Brian Lavergne, president and chief executive officer
Reserves at Dec. 31, 2014
Storm's year-end reserve evaluation, effective Dec. 31, 2014, was prepared by InSite Petroleum Consultants Ltd. under the date of Feb. 18, 2015. InSite has evaluated all of Storm's crude oil, NGL and natural gas reserves. The InSite price forecast at Dec. 31, 2014, was used to determine all estimates of future net revenue (also referred to as net present value or 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. In addition to the information disclosed in this report, more detailed information will be included in Storm's annual information form.
Summary:
- Proved developed producing (PDP) reserves increased 78 per cent to total
13,487,000 boe with additions replacing 332 per cent of 2014 production.
- Total proved (1P) reserves increased 187 per cent to total 59,551,000 with
additions replacing 1,522 per cent of 2014 production.
- Total proved plus probable (2P) reserves increased 117 per cent to total
88,024,000 with additions replacing 1,863 per cent of 2014 production.
- Total proved reserves were 68 per cent of total proved plus probable reserves, a
significant improvement from 51 per cent in 2013.
- The finding and development (F&D) cost for reserve additions per NI
51-101 requirements (removing effect of acquisitions, dispositions and
revisions) was $13.73 per boe for PDP, $10.20 per boe for 1P and $8.76
per boe for 2P.
- The all-in finding, development and acquisition (FD&A) cost to add
reserves was $23.01 per boe for PDP, $11.68 per boe for 1P and was $9.64
per boe for 2P.
- Reserve life index using average production in the fourth quarter of
2014 was 3.6 years for PDP reserves, 16.1 years for 1P reserves and 23.3
years for 2P reserves.
- Recycle ratio using the F&D cost was 2.1 for 1P reserve additions and
2.4 for 2P reserve additions using the 2014 field operating netback of
$21.19 per boe excluding hedging gains or losses.
- Recycle ratio using the FD&A cost was 1.8 for 1P reserve additions and
2.2 for 2P reserve additions using the 2014 field operating netback of
$21.19 per boe excluding hedging gains or losses.
- Technical revisions increased PDP reserves by 130,000, 1P reserves by
2,068,000 and 2P reserves by 4,352,000.
- Breaking down 2P reserves by area, 86 per cent is at Umbach, 9 per cent at the Horn
River basin and 5 per cent at Grande Prairie.
- Future development costs (FDC) were $447.7-million on a 1P basis and
$606.6-million on a 2P basis, which represent approximately five years
of activity in the evaluation.
- At Umbach, there are 30.4 net producing and non-producing horizontal
wells with 21,749,000 of 2P reserves plus 73.4 net future horizontal
drilling locations with 53,519,000 of 2P reserves. Associated 2P FDC
was $484.0-million, net.
- At Umbach, 53 net 2P horizontal drilling locations were assigned an
average of 4.4 billion cubic feet gross raw gas on the 100-per-cent-working-interest lands, an
increase of 26 per cent from 3.5 billion cubic feet gross raw gas assigned in 2013. On the 60-per-cent-working-interest lands, 20.4 net 2P horizontal drilling locations were
assigned an average of 3.2 billion cubic feet gross raw gas, an increase of 7 per cent from 3.0
billion cubic feet gross raw gas assigned in 2013.
- At Umbach, 2P reserves were recognized in the Upper Montney only on 18 per cent of
or 25.5 net sections of Storm's 141 net sections in the area with discovered petroleum initially in place
averaging 43 billion cubic feet gross raw gas per section in the Upper Montney (total
net DPIIP 1.1 trillion cubic feet on 25.5 net sections). Forecast recovery of DPIIP
totals 40 per cent for 2P reserves.
- The forecast decline in 2015 is 35 per cent for wells on production at Dec.
31, 2014 (decline from January, 2015, to December, 2015).
GROSS COMPANY INTEREST RESERVES AS AT DEC. 31, 2014
(before deduction of royalties payable, not including royalties receivable)
6:1 oil
Light crude Sales gas NGL equivalent
oil (Mbbl) (MMcf) (Mbbl) (Mboe)
Proved producing 940 62,696 2,098 13,487
Proved non-producing -- 10,676 373 2,153
Total proved developed 940 73,372 2,471 15,640
Proved undeveloped 300 222,301 6,560 43,911
Total proved 1,240 295,673 9,032 59,551
Probable additional 846 144,778 3,498 28,473
Total proved plus probable 2,086 440,452 12,530 88,024
GROSS COMPANY RESERVE RECONCILIATION FOR 2014
(gross company interest reserves before deduction of royalties payable)
6:1 oil equivalent (Mboe)
Proved Proved
developed Total plus
producing proved Probable probable
Dec. 31, 2013 -- opening
balance 7,579 20,764 19,777 40,541
Acquisitions 558 558 119 677
Discoveries -- -- -- --
Extensions 7,766 38,707 6,295 45,002
Dispositions -- -- -- --
Technical revisions -- Umbach 292 2,284 2,514 4,798
Technical revisions -- other
properties (162) (216) (230) (446)
Economic factors -- -- -- --
Production (2,547) (2,547) -- (2,547)
Dec. 31, 2014 -- closing
balance 13,487 59,551 28,473 88,024
FUTURE DEVELOPMENT COSTS
Proved
HRB Drill 2.0 net horizontals plus $ 35.5-million
infrastructure
Umbach Drill 59.0 net horizontals plus $ 404.5-million
infrastructure
Grande Prairie Drill 3.0 net horizontals at $ 7.7-million
Grimshaw
Total $ 447.7-million
Proved plus probable
additional
HRB Drill 5.0 net horizontals plus $ 85.5-million
infrastructure
Umbach Drill 73.4 net horizontals plus $ 483.7-million
infrastructure
Grande Prairie Drill 5.0 net horizontals at $ 37.4-million
Grimshaw; 5.0 net horizontals at GP
Montney; and
1.0 net horizontal at GP Dunvegan
Total $ 606.6-million
Proved plus probable
additional
Proved expenditures expenditures
2015 $57,250 $63,250
2016 75,154 89,678
2017 122,819 152,793
2018 129,637 153,461
2019 62,857 141,907
2020 -- 5,465
Total FDC --
undiscounted 447,717 606,555
Total FDC --
discounted at 10 per cent 356,196 470,717
NI 51-101 FINDING AND DEVELOPMENT COSTS
(excluding acquisitions, dispositions and revisions)
Proved developed producing F&D Three-year
cost 2014 2013 2012 total
Capital expenditures excluding
acquisitions and dispositions
(000s) $ 106,604 $ 67,450 $ 26,868 $ 200,922
Net change in FDC (000s) -- -- -- --
Total capital $ 106,604 $ 67,450 $ 26,868 $ 200,922
Reserve additions excluding
acquisitions, dispositions and
revisions (Mboe) 7,766 3,464 840 12,070
Proved developed producing F&D
cost $ 13.73 $ 19.47 $ 31.99 $ 16.64
Three-year
Total proved F&D cost 2014 2013 2012 total
Capital expenditures excluding
acquisitions and dispositions
(000s) $ 106,604 $ 67,450 $ 26,868 $ 200,922
Net change in FDC (000s) 288,242 77,282 30,863 396,387
Total capital including the net
change in future capital (000s) $ 394,846 $ 144,732 $ 57,731 $ 597,309
Reserve additions excluding
acquisitions, dispositions and
revisions (Mboe) 38,707 10,356 4,067 53,130
Total proved F&D cost (per boe) $ 10.20 $ 13.98 $ 14.20 $ 11.24
Total proved plus probable F&D Three-year
cost 2014 2013 2012 total
Capital expenditures excluding
acquisitions and dispositions
(000s) $ 106,604 $ 67,450 $ 26,868 $ 200,922
Net change in FDC (000s) 287,686 134,903 40,341 462,930
Total capital including the net
change in future capital (000s) $ 394,290 $ 202,353 $ 67,209 $ 663,852
Reserve additions excluding
acquisitions, dispositions and
revisions (Mboe) 45,001 18,823 5,514 69,338
Total proved plus probable F&D
cost $ 8.76 $ 10.75 $ 12.19 $ 9.57
Operating netback per boe
excluding hedging $ 21.19 $ 20.43 $ 21.22 $ 20.97
Recycle ratio for proved plus
probable F&D cost using
operating netback (excluding
hedging) 2.4 1.9 1.7 2.2
ALL-IN FINDING, DEVELOPMENT AND ACQUISITION COSTS
(including acquisitions, dispositions and revisions)
Proved developed producing FD&A Three-year
cost 2014 2013 2012 total
Capital expenditures including
acquisitions and dispositions
(000s) $ 194,555 $ 52,444 $ 166,076 $ 413,075
Net change in FDC (000s) -- -- -- --
Total capital $ 194,555 $ 52,444 $ 166,076 $ 413,075
Total reserve additions (Mboe) 8,456 3,047 5,117 16,620
All-in proved developed
producing F&D cost $ 23.01 $ 17.21 $ 32.46 $ 24.85
Three-year
Total proved FD&A cost 2014 2013 2012 total
Capital expenditures including
acquisitions and dispositions
(000s) $ 194,555 $ 52,444 $ 166,076 $ 413,075
Net change in FDC (000s) 288,242 56,600 72,655 417,497
Total capital including the net
change in future capital (000s) $ 482,797 $ 109,044 $ 238,731 $ 830,572
Total reserve additions (Mboe) 41,334 8,270 10,927 60,531
All-in total proved F&D cost
(per boe) $ 11.68 $ 13.19 $ 21.85 $ 13.72
Total proved plus probable FD&A Three-year
cost 2014 2013 2012 total
Capital expenditures including
acquisitions and dispositions
(000s) $ 194,555 $ 52,444 $ 166,076 $ 413,075
Net change in FDC (000s) 287,686 89,829 156,258 533,773
Total capital including the net
change in future capital (000s) $ 482,241 $ 142,273 $ 322,334 $ 946,848
Total reserve additions (Mboe) 50,030 14,538 19,828 84,396
All-in total proved plus
probable F&D cost (per boe) $ 9.64 $ 9.79 $ 16.26 $ 11.22
Operating netback per boe
excluding hedging $ 21.19 $ 20.43 $ 21.22 $ 20.97
Recycle ratio for proved plus
probable FD&A cost using
operating netback (excluding
hedging) 2.2 2.1 1.3 1.9
Net present value summary (before tax) as at Dec. 31, 2014
Benchmark oil and NGL prices used are adjusted for quality of oil or NGL produced and for transportation costs. The calculated NPVs include a deduction for estimated future well abandonment costs.
BEFORE-TAX NET PRESENT VALUE SUMMARY
Discounted Discounted Discounted Discounted
Undiscounted at 5% at 10% at 15% at 20%
(000s) (000s) (000s) (000s) (000s)
Proved producing $ 301,021 $ 239,533 $ 199,069 $ 170,841 $ 150,201
Proved non-
producing 48,474 38,290 31,796 27,351 24,134
Total proved
developed $ 349,495 $ 277,823 $ 230,865 $ 198,192 $ 174,335
Proved undeveloped 694,842 421,652 262,392 163,942 100,157
Total proved $ 1,044,338 $ 699,476 $ 493,257 $ 362,133 $ 274,492
Probable additional 629,545 332,499 190,573 115,724 73,005
Total proved plus
probable $ 1,673,883 $ 1,031,974 $ 683,829 $ 477,858 $ 347,497
Net present value summary (after tax) as at Dec. 31, 2014
Benchmark oil and NGL prices used are adjusted for quality of oil or NGL produced and for transportation costs. The calculated NPVs each include a deduction for estimated future well abandonment costs.
AFTER-TAX NET PRESENT VALUE SUMMARY
Discounted Discounted Discounted Discounted
Undiscounted at 5% at 10% at 15% at 20%
(000s) (000s) (000s) (000s) (000s)
Proved producing $ 301,021 $ 239,533 $ 199,069 $ 170,841 $ 150,201
Proved non-
producing 48,474 38,290 31,796 27,351 24,134
Total proved
developed $ 349,495 $ 277,823 $ 230,865 $ 198,192 $ 174,335
Proved undeveloped 531,153 318,100 193,246 115,727 65,343
Total proved $ 880,649 $ 595,923 $ 424,111 $ 313,919 $ 239,677
Probable additional 473,166 246,451 138,292 81,451 49,208
Total proved plus
probable $ 1,353,814 $ 842,374 $ 562,403 $ 395,370 $ 288,885
INSITE ESCALATING PRICE FORECAST AS AT DEC. 31, 2014
Edmonton
WTI Par Henry Hub AECO
crude oil crude oil natural gas natural gas Propane Butane
(U.S.$/bbl) (Cdn$/bbl) (U.S.$/MMBtu) (Cdn$/MMBtu) (Cdn$/bbl) (Cdn$/bbl)
2015 $65.00 $68.58 $3.50 $3.58 $34.29 $48.01
2016 75.00 80.07 4.00 4.15 40.03 56.05
2017 80.00 85.74 4.25 4.43 42.87 60.02
2018 85.00 91.41 4.50 4.71 45.70 63.99
2019 90.00 97.07 4.75 4.99 48.54 67.95
We seek Safe Harbor.
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