Storm Resources Ltd. ("Storm" or the "Company") is Pleased to
Announce Its Financial and Operating Results for the Three Months
and Year Ended December 31, 2013
CALGARY, ALBERTA--(Marketwired - Mar 6, 2014) - Storm Resources
Ltd. (TSX-VENTURE:SRX)
Storm has also filed its audited consolidated financial
statements as at December 31, 2013 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, 2013, as well as reserve
information at December 31, 2013, appears below and should be read
in conjunction with the related financial statements and
MD&A.
Highlights
|
|
|
|
|
|
|
|
|
| Thousands of Cdn$, except volumetric and per share
amounts |
Three Months Ended December 31, 2013 |
|
Three Months Ended December 31, 2012 |
|
Year Ended December 31, 2013 |
|
Year Ended December 31, 2012 |
|
| FINANCIAL |
|
|
|
|
|
|
|
|
|
Gas sales |
7,807 |
|
3,416 |
|
21,019 |
|
8,054 |
|
|
NGL sales |
4,483 |
|
1,597 |
|
13,124 |
|
4,466 |
|
|
Oil sales |
3,090 |
|
5,399 |
|
15,435 |
|
19,793 |
|
| Revenue from product sales(1) |
15,380 |
|
10,412 |
|
49,578 |
|
32,313 |
|
| Funds from operations(2) |
7,501 |
|
5,016 |
|
21,949 |
|
13,387 |
|
|
Per share - basic ($) |
0.09 |
|
0.08 |
|
0.30 |
|
0.24 |
|
|
Per share - diluted ($) |
0.09 |
|
0.08 |
|
0.30 |
|
0.24 |
|
| Net loss |
(25,174 |
) |
(2,320 |
) |
(26,203 |
) |
(6,574 |
) |
|
Per share - basic ($) |
(0.34 |
) |
(0.04 |
) |
(0.36 |
) |
(0.12 |
) |
|
Per share - diluted ($) |
(0.34 |
) |
(0.04 |
) |
(0.36 |
) |
(0.12 |
) |
| Adjusted net income (loss) before reduction in carrying
amount of property and equipment |
826 |
|
(2,320 |
) |
(203 |
) |
(6,574 |
) |
|
Per share - basic and diluted ($) |
0.01 |
|
(0.04 |
) |
0.00 |
|
(0.12 |
) |
| Operations capital expenditures |
11,380 |
|
10,016 |
|
67,410 |
|
26,868 |
|
| Acquisitions and dispositions |
- |
|
(1,239 |
) |
(14,966 |
) |
139,208 |
|
| Debt including working capital deficiency |
12,059 |
|
44,696 |
|
12,059 |
|
40,376 |
|
| Weighted average common shares outstanding (000s) |
|
|
|
|
|
|
|
|
|
Basic |
81,994 |
|
61,824 |
|
73,391 |
|
56,067 |
|
|
Diluted |
81,994 |
|
61,824 |
|
73,391 |
|
56,067 |
|
| Common shares outstanding (000s) |
|
|
|
|
|
|
|
|
|
Basic |
87,483 |
|
61,824 |
|
87,483 |
|
61,824 |
|
|
Fully diluted |
91,379 |
|
64,547 |
|
91,379 |
|
64,547 |
|
| OPERATIONS |
|
|
|
|
|
|
|
|
| Oil equivalent (6:1) |
|
|
|
|
|
|
|
|
|
Barrels of oil equivalent (000s) |
439 |
|
259 |
|
1,328 |
|
825 |
|
|
Barrels of oil equivalent per day |
4,773 |
|
2,815 |
|
3,637 |
|
2,254 |
|
|
Average selling price (Cdn$ per Boe)(1) |
35.03 |
|
40.19 |
|
37.34 |
|
39.14 |
|
| Gas production |
|
|
|
|
|
|
|
|
|
Thousand cubic feet (000s) |
2,015 |
|
987 |
|
5,783 |
|
3,053 |
|
|
Thousand cubic feet per day |
21,898 |
|
10,728 |
|
15,843 |
|
8,342 |
|
|
Average selling price (Cdn$ per Mcf) |
3.88 |
|
3.46 |
|
3.63 |
|
2.64 |
|
| NGL Production |
|
|
|
|
|
|
|
|
|
Barrels (000s) |
64 |
|
25 |
|
187 |
|
67 |
|
|
Barrels per day |
695 |
|
274 |
|
512 |
|
185 |
|
|
Average selling price (Cdn$ per barrel) |
70.10 |
|
63.27 |
|
70.29 |
|
66.17 |
|
| Oil Production |
|
|
|
|
|
|
|
|
|
Barrels (000s) |
39 |
|
69 |
|
177 |
|
249 |
|
|
Barrels per day |
428 |
|
753 |
|
485 |
|
679 |
|
|
Average selling price (Cdn$ per barrel)(1) |
78.47 |
|
77.93 |
|
87.16 |
|
79.53 |
|
| Wells drilled |
|
|
|
|
|
|
|
|
|
Gross |
1.0 |
|
2.0 |
|
9.0 |
|
6.0 |
|
|
Net |
1.0 |
|
1.2 |
|
8.6 |
|
4.4 |
|
|
|
|
|
|
|
|
|
|
(1) Excludes hedging gains and losses.
(2) Funds from operations and funds from operations per share
are non-GAAP measurements. See discussion of Non-GAAP Measurements
on page 16 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 26 of the
MD&A.
President's Message
2013 FOURTH QUARTER AND
YEAR-END HIGHLIGHTS
- Production for the year averaged 3,637 Boe per day (27% oil
plus NGL) which represents an increase of 61% from 2012. Fourth
quarter production was 4,773 Boe per day (24% oil plus NGL), a
year-over-year increase of 70%. On a per-share basis, fourth
quarter production increased 20% from the previous year while debt
decreased by 70%, or $28.3 million. Increased production was the
result of growth at Umbach where production averaged 3,262 Boe per
day in the fourth quarter of 2013, a 480% increase from 564 Boe per
day in the fourth quarter of 2012.
- NGL production averaged 695 barrels per day in the fourth
quarter, an increase of 154% from the fourth quarter of 2012. NGL
production increased as a result of production growth from the
liquids-rich Montney formation at Umbach. With condensate and
pentane being approximately 60% of the NGL mix, the fourth quarter
NGL price of $70.10 per barrel was 81% of the average Edmonton Par
light oil price.
- Activity in 2013 was focused at Umbach where eight Montney
horizontal wells (7.6 net) plus one Montney vertical delineation
well (1.0 net) were drilled and seven horizontal wells (6.2 net)
were completed and pipeline connected. In the fourth quarter, one
Montney horizontal well (1.0 net) was drilled, one Montney
horizontal well (1.0 net) was completed and two Montney horizontal
wells (2.0 net) were pipeline connected.
- On Storm's 100% working interest lands at Umbach, five
horizontal Montney wells (5.0 net) were drilled with rates over the
first 90 operated days (excluding days shut in) averaging 3.7 Mmcf
per day gross raw gas which is equivalent to 670 Boe per day sales.
This is an improvement of 70% when compared to earlier horizontal
wells drilled in 2010 and 2011.
- Funds from operations for the year totaled $21.9 million, an
increase of 64% from the previous year. Funds from operations in
the fourth quarter was $7.5 million or $0.09 per basic share, an
increase of 12% from $0.08 per basic share in the prior year. The
increase in funds from operations was the result of significant
production growth at Umbach.
- The funds from operations netback was $16.52 per Boe in 2013,
an increase of 2% from the previous year. The funds from operations
netback improved to $17.08 per Boe in the fourth quarter.
- The field operating netback excluding hedging gains or losses
was $20.43 per Boe for the full year and increased to $20.82 per
Boe in the fourth quarter.
- Operating costs improved throughout the year. The full year
operating cost of $10.86 per Boe was 5% lower than the previous
year while the fourth quarter operating cost of $9.73 per Boe was
17% lower than the fourth quarter of 2012. Improving operating
costs are the result of production growth at Umbach where operating
costs were $8.73 per Boe in 2013 which was lower than the corporate
average of $10.86 per Boe.
- Controllable cash costs (operating, transportation, cash
G&A, interest expense) declined to $16.24 per Boe in 2013 from
$19.83 per Boe in the prior year. Controllable cash costs showed
further improvement to average $15.38 per Boe in the fourth
quarter. The largest improvement was with cash G&A which
decreased $1.52 per Boe to average $2.98 per Boe during 2013.
- Capital investment was $11.4 million in the fourth quarter and
$52.4 million for the year, net of dispositions. Investment in 2013
was focused on exploitation of the Montney formation at Umbach
including $14.0 million for infrastructure, $15.0 million to
acquire undeveloped land and $36.0 million for drilling and
completions. Dispositions in 2013 totaled $19.5 million from the
sale of non-core properties early in 2013.
- Debt plus working capital deficiency, net of investments, ended
the year at $12.1 million which is 0.4 times annualized fourth
quarter cash flow. In November 2013, Storm's bank credit line was
increased to $65.0 million from $52.0 million.
- Total proved ("1P") reserves increased 50% to 20,764 Mboe with
the all-in cost for additions being $13.19 per Boe. Total proved
plus probable ("2P") reserves increased 48% to 40,541 Mboe with the
all-in cost for additions being $9.79 per Boe. The increase in 1P
and 2P reserves was the result of continued delineation drilling in
the upper Montney formation at Umbach.
- Better than expected horizontal well performance resulted in
PDP reserves at Umbach being revised higher by 439 Mboe.
- Additions to 2P reserves replaced 910% of 2013 production.
- Recycle ratio was 2.1 for 2P reserve additions using the all-in
cost for reserve additions and the 2013 field operating netback of
$20.43 per Boe excluding hedging gains or losses.
- Cost of adding production during 2013 was $17.22 per Boe for
proved developed producing reserves ("PDP") on an all-in basis and
was approximately $20,000 per Boe per day using 2013 capital
investment of $52.4 million and production additions of 2,600 Boe
per day (average fourth quarter rate from wells starting production
in 2013).
- Subsequent to year end, Storm closed the acquisition of a 100%
working interest in 29 sections of land in the Umbach-Nig area,
prospective for liquids rich natural gas from the Montney
formation. The acquisition included two horizontal wells producing
359 Boe net per day (19% NGL) from the Montney formation. Total
cost of $87.9 million consisted of $30.0 million in cash and 13.6
million common shares of Storm with a deemed value of $4.25 per
common share (closing price on the TSX Venture Exchange January 30,
2014). The cash portion was funded with $34.8 million of gross
proceeds from a bought deal financing and non-brokered private
placement of common shares which closed on February 14, 2014 (8.5
million common shares were issued at a price of $4.10 per common
share).
OPERATIONS
REVIEW
Storm has a focused asset base with large land positions in
resource plays at Umbach and in the HRB which have multi-year
drilling upside while the Grande Prairie area, with its shallow
decline, provides cash flow available for investment.
Umbach, Northeast British Columbia
Storm's land position at Umbach is prospective for liquids-rich
natural gas from the Montney formation and currently totals 140 net
sections (168 gross sections) or 98,000 net acres. There are three
project areas at Umbach:
- Umbach South with 87 net sections at a 100% working interest
(includes the 29 sections recently acquired) where fourth quarter
production averaged 2,293 Boe per day.
- Umbach North with 33 net sections of jointly owned lands (61
gross sections with Storm's working interest being 60% on most of
the lands) where fourth quarter production average 969 Boe per
day.
- Nig with 20 net sections at a 100% working interest.
To date, Storm has been focused on exploiting the upper Montney
although the middle and lower Montney may also be productive. Since
entering the area in 2010, and including the lands acquired in
January 2014, Storm has invested $108 million to acquire this land
position ($2,750 per hectare or $1,100 per acre).
Production at Umbach grew to 3,262 net Boe per day (18% liquids)
in the fourth quarter as a result of five Montney horizontal wells
(4.6 net) that started production during August to November. Fourth
quarter NGL recovery was 40 barrels per Mmcf sales or 629 barrels
per day with approximately 60% being higher priced condensate plus
pentanes. The operating netback in the fourth quarter was $21.74
per Boe with revenue, after deducting transportation costs, of
$31.10 per Boe ($3.52 per Mcf sales and $67.49 per barrel of NGL),
a royalty rate of 3%, and operating costs of $8.36 per Boe.
Continuing production growth from the 100% working interest lands
at Umbach South is expected to result in operating costs decreasing
to approximately $7.00 per Boe in 2014.
Activity in the fourth quarter included converting a standing
vertical well to a water disposal well, drilling one Montney
horizontal well (1.0 net), completing one Montney horizontal well
(1.0 net), and pipeline connecting two Montney horizontal wells
(2.0 net) which started producing on October 19th and November
19th. To date in the first quarter, two Montney horizontal wells
(2.0 net) have been drilled and two Montney horizontal wells have
been completed with one starting production in late February.
A total of 18 horizontal wells have been drilled in the upper
Montney at Umbach (14.4 net) and there are 14 producing horizontal
wells (10.8 net). Production performance has continued to improve
based on a comparison of operated day rates over the first 30 and
90 days (operated day rates exclude days where wells were shut in
due to capacity constraints):
|
|
|
|
Start of Production |
Frac Stages |
30-Day Average Mmcf Per Day |
90-Day Average Mmcf Per Day |
1st Year Average Mmcf Per Day |
|
Hz's 1 - 5 |
60% WI |
Umbach North |
Mar/11 - Oct/12 |
7 - 11 |
2.7 Mmcf/d 5 hz's |
2.1 Mmcf/d 5 hz's |
1.4 Mmcf/d 5 hz's |
|
Hz's 6 - 8 |
60% WI |
Umbach North |
Nov/12 - Aug/13 |
14 - 16 |
3.3 Mmcf/d 3 hz's |
2.8 Mmcf/d 3 hz's |
not available |
|
Hz's 10 - 14 |
100% WI |
Umbach South |
Apr/13 - Nov/13 |
17 - 18 |
4.2 Mmcf/d 5 hz's |
3.7 Mmcf/d 3 hz's |
not available |
Comparing operated day rates over 30 and 90 days and using the
InSite Petroleum Consultant Ltd. ("InSite") 2P type curve used in
the 2013 year-end reserve evaluation, Storm management estimates
that the most recent horizontal wells (10 to 14) will average 2.4
Mmcf per day in the first year with ultimate recovery of 4.4
Bcf.
Cost to drill and complete horizontal wells in 2013 averaged
$4.6 million with the drilling cost averaging $2.2 million and the
completion cost averaging $2.4 million. Tie-in costs have been
approximately $0.5 million per horizontal well, not including cost
of longer gathering pipelines to connect multi-well pads to field
compression facilities. A decrease in costs is anticipated in 2014
with a larger program and with more horizontal wells being drilled
from common pads.
Total investment in infrastructure in 2013 at Umbach was
approximately $12.6 million which included the acquisition of field
compression for $4.5 million plus construction of 18 kilometres of
larger diameter 8-inch and 10-inch field gathering pipelines. In
2014, an additional $19.0 million will be invested in
infrastructure which includes $5.0 million for larger diameter
gathering pipelines plus $14.0 million to construct a second field
compression facility with an initial capacity of 24 Mmcf per day.
Capacity of the new field compression facility is expandable to 48
Mmmcf per day for an additional investment of $9.0 million with
this expected to occur in 2015.
At pricing of $3.50 per GJ for natural gas and Cdn$89.00 per
barrel for Edmonton Par (WTI US$93.00/Bbl, FX Cdn$0.92), the
estimated field netback is $21.00 per Boe. With this pricing held
constant, Storm management estimates that horizontal wells have an
unrisked half cycle rate of return of 37% (1.9 years to payout)
based on a first year average rate of 2.4 Mmcf per day gross raw
gas (430 Boe per day), ultimate recovery of 4.4 Bcf gross raw gas
per horizontal well, NGL recovery of 35 barrels per Mmcf sales (10%
shrinkage), and $5.0 million to drill, complete and tie in a
horizontal well.
On January 31, 2014, Storm closed the acquisition of two
producing Montney horizontal wells and 29 sections of undeveloped
land for a total cost of $87.9 million. The allocation of the
purchase price was $61.5 million for nine sections with production,
reserves and 35 horizontal drilling locations, and $26.4 million
for the remaining 20 sections ($4,700 per hectare or $1,880 per
acre). Highlights of the acquisition are as follows:
- A 100% working interest was acquired in the lands and two
producing horizontal wells (one upper Montney and one lower
Montney).
- Production from the two horizontal wells totaled 359 Boe per
day (NGL recovery 38 bbls per Mmcf sales) in the third quarter of
2013 with the majority from the C-42-A horizontal well which has
produced 1.4 Bcf to date from the upper Montney with the current
rate being 1.6 Mmcf per day gross raw gas (295 Boe per day
sales).
- The acquired lands are contiguous with Storm's Umbach South
lands where five Montney horizontal wells (5.0 net) were drilled
and commenced production in 2013 from the upper Montney with rates
averaging 4.3 Mmcf per day gross raw gas over the first 30
operating days and 3.7 Mmcf per day gross raw gas over the first 90
operating days (operating day rate excludes days shut in).
- The upper Montney formation is the primary target based on
results to date in the area; however, Storm management believes
that the middle Montney may also be productive across the acquired
lands.
- Storm management estimates DPIIP of 1.6 Tcf in the upper
Montney formation on the acquired lands based on data from existing
wells on the 29 sections (seven vertical wells plus two Montney
horizontal wells) indicating that the upper Montney formation is 52
metres thick, has average porosity of 6% and a reservoir pressure
of 18,000 to 23,000 kPa.
- Two to three horizontal wells will be drilled in the upper
Montney on the acquired lands in 2014 with additional wells being
planned for 2015.
Horn River Basin, Northeast British Columbia
Storm has a 100% 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 363 Boe per day at an operating netback of $11.59 per Boe.
Wellsite compression was installed in November 2013 and production
has increased to average 400 Boe per day to date in the first
quarter of 2014. Production is from one horizontal well with 12
fracture stimulations which currently produces 2.7 Mmcf per day
gross raw gas with cumulative production of 3.8 Bcf gross raw gas
since start-up in March 2011. A second horizontal well was also
drilled in 2011 and is awaiting completion with timing dependent on
natural gas pricing.
A resource evaluation completed by InSite effective December 31,
2011 estimates that the best estimate of DPIIP in the core
producing area is 3.1 Tcf gross raw gas with the best estimate of
contingent resources being 616 Bcf. The evaluated area includes 30
sections at a 100% working interest and represents 22% of Storm's
total land holdings in the HRB. Commerciality has been proven
across the core producing area with a horizontal well that has been
producing for 30 months plus two vertical wells that were completed
and tested with final test rates of 900 Mcf per day over the final
24 hours of each flow test.
Grande Prairie Area, Northwest Alberta and Northeast British
Columbia
Production in the fourth quarter averaged 1,147 Boe per day (44%
oil plus NGL) at an operating netback of $21.65 per Boe. No capital
was invested in this area in the fourth quarter and minimal
activity is planned during 2014. Cash flow from this area will
continue to be re-invested to grow production at Umbach.
HEDGING
UPDATE
Current commodity price hedges for 2014 include 11,500 Mcf per
day (14,000 GJ per day) of natural gas with an average floor price
of approximately $4.12 per Mcf and an average ceiling price of
$4.34 per Mcf (AECO monthly index $3.39 per GJ for floor and $3.57
per GJ for ceiling). In addition, an oil price of WTI Cdn$101.89
per barrel (WTI price in $US per barrel converted to $Cdn per
barrel) has been fixed on 338 barrels per day. It is likely that
this hedge position will be expanded with the objective of ensuring
that a decrease in commodity prices does not have a significant
impact on capital investment and growth over the next 12 to 18
months.
COMPARISON OF 2013
RESULTS VERSUS GUIDANCE
Shown below is a comparison of Storm's actual 2013 results to
guidance provided during 2013.
|
|
2013 Actual Results |
|
2013 Guidance November 14, 2013 |
|
2013 Guidance May 15, 2013 |
|
2013 Guidance February 28, 2013 |
|
|
Year-end adjusted debt plus working capital deficiency(1) |
$12.1 million |
|
$40.0 million |
|
$37.0 million |
|
$44.0 million |
|
|
Average operating costs |
$10.86 per Boe |
|
$10 - $11/Boe |
|
$10 - $11/Boe |
|
$10 - $11/Boe |
|
|
Average royalty rate (on revenue before hedging) |
12.2 |
% |
14 |
% |
13% - 14 |
% |
11% - 12 |
% |
|
Operations capital |
$67.5 million |
|
$62.0 million |
|
$62.0 million |
|
$40.0 million |
|
| Asset
dispositions |
$19.5 million |
|
$19.5 million |
|
$19.5 million |
|
$20.0 million |
|
|
Asset acquisitions |
$4.5 million |
|
$4.5 million |
|
$4.5 million |
|
$4.5 million |
|
|
Cash G&A |
$4.0 million |
|
not provided |
|
$3.7 million |
|
$3.9 million |
|
|
Exit or fourth quarter average production |
4,773 Boe/d (24% oil + NGL |
) |
4,500-5,000 Boe/d (24% oil + NGL |
) |
4,500-5,000 Boe/d (25% oil + NGL |
) |
4,000-4,500 Boe/d (25% oil + NGL |
) |
(1) Includes value of publicly listed securities.
Actual operations capital investment in 2013 of $67.5 million
was $5.5 million higher than most recent guidance of $62.0 million
because of a casing failure during completion of a horizontal well
at Umbach in the fourth quarter ($3.0 million) and because the
drilling of one horizontal well at Umbach was advanced into the
fourth quarter of 2013 instead of being drilled in 2014 ($2.5
million). Year-end adjusted debt was lower as the result of
receiving net proceeds totaling $31.9 million from two equity
financings that closed November 19, 2013.
OUTLOOK
Production in January and February averaged 4,970 Boe per day
based on field estimates and first quarter production is forecast
to be 5,000 Boe per day. Production is expected to be 5,000 to
5,500 Boe per day until September 2014 when the new facility at
Umbach will be operational.
Storm's guidance for 2014 remains unchanged from what was
provided on January 23, 2014 and is set forth below.
|
|
2014 Guidance |
|
|
Estimated year-end debt plus working capital deficiency(1) |
$ |
50.0 million |
|
|
Estimated average operating costs |
$ |
8.00 - $9.00 per Boe |
|
|
Estimated average royalty rate (on production revenue before
hedging) |
|
14% - 15 |
% |
|
Estimated operations capital, excluding acquisitions &
dispositions |
$ |
78.0 million |
|
|
Estimated acquisitions |
$ |
87.9 million |
|
|
Estimated cash G&A net of recoveries |
$ |
4.0 million |
|
|
Forecast fourth quarter average production |
|
7,500 - 7,900 Boe/d |
|
|
|
|
(20% oil + NGL |
) |
|
Forecast average annual production |
|
5,500 - 6,500 Boe/d |
|
|
|
|
(21% oil + NGL |
) |
(1) Includes value of publicly listed securities.
Major expenditures included in operations capital investment for
2014 include:
- $47.0 million at Umbach to drill 10 horizontal wells (10.0 net)
with 9 horizontal wells (9.0 net) being completed and tied in;
and
- $19.0 million to expand infrastructure at Umbach, including a
new field compression facility, expandable from initial capacity of
24 Mmcf per day to 48 Mmcf per day (expansion expected to occur in
2015).
This level of investment is forecast to increase Storm's fourth
quarter 2014 production to 7,500 to 7,900 Boe per day which
represents 60% growth on a year-over-year basis.
Guidance for 2014 assumes an average natural gas price at AECO
of $3.75 per GJ and an Edmonton Par oil price of Cdn$90 per barrel.
This reflects estimated first quarter pricing of AECO $5.00 per GJ
and Edmonton Par Cdn$98 per barrel. Adjusted net debt is forecasted
to be $50.0 million at the end of 2014 (including public company
investments), which would be approximately 1.0 times annualized
funds from operations in the fourth quarter of 2014.
At Umbach, Storm is still in the early stages of delineating a
large, higher quality, liquids-rich resource in the Montney
formation. NGL recovery increases revenue and the relatively
shallow depth (1,400 to 1,600 metres) results in a lower drilling
and completion cost with both providing Storm with a competitive
advantage. Significant future reserve growth is expected given 2P
reserves have been assigned to the upper Montney on only 8% of
Storm's land position at Umbach. In addition, showing that the
middle and lower Montney are also productive and sustained
improvements in horizontal well productivity would also lead to
reserve additions. With a strong balance sheet and a plan in place
to further expand owned and operated infrastructure, continued
rapid growth is expected from Umbach during 2014 and 2015.
Storm's land position in the HRB continues to be a core,
long-term asset with significant leverage to higher natural gas
prices.
Capital investment will be reviewed mid-year and, should natural
gas prices remain elevated and horizontal well performance at
Umbach continue to meet or exceed expectations, it is likely that
capital investment would be increased in the second half of 2014
and forecast fourth quarter production would also be increased.
In closing, I would like to thank Storm's employees for their
effort and hard work in 2013 and Storm's Directors for their advice
and guidance. A lot was accomplished in 2013 and we look forward to
providing updates on our progress throughout 2014.
Respectfully,
Brian Lavergne, President and Chief Executive Officer
March 6, 2014
Discovered-Petroleum-Initially-in-Place ("DPIIP") - is defined
in the Canadian Oil and Gas Evaluation Handbook ("COGEH") as the
quantity of hydrocarbons that are estimated to be in place within a
known accumulation. DPIIP is divided into recoverable and
unrecoverable portions, with the estimated future recoverable
portion classified as reserves and contingent resources. There is
no certainty that it will be economically viable or technically
feasible to produce any portion of this DPIIP except for those
portions identified as proved or probable reserves.
Contingent Resources - are those quantities of petroleum
estimated, as of a given date, to be potentially recoverable from
known accumulations using established technology or technology
under development, but which are not currently considered to be
commercially recoverable due to one or more contingencies.
Contingencies may include factors such as economic, legal,
environmental, political and regulatory matters, or a lack of
markets. It is also appropriate to classify as contingent resources
the estimated discovered recoverable quantities associated with a
project at an early stage of development. Estimates of contingent
resources are estimates only; the actual resources may be higher or
lower than those calculated in the independent evaluation. There is
no certainty that the resources described in the evaluation will be
commercially produced.
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.
Reserves at December 31, 2013
Storm's year-end reserve evaluation effective December 31, 2013
was prepared by InSite Petroleum Consultants Ltd. ("InSite") under
date of February 24, 2014. InSite has evaluated all of Storm's
crude oil, NGL and natural gas reserves. The InSite price forecast
at December 31, 2013 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 ("NI") 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 29% to
total 7,579 Mboe with additions of 3,046 Mboe replacing 131% of
production. The all-in cost to add PDP reserves was $17.22 per
Boe(1).
- Total proved ("1P") reserves increased 50% to total 20,764 Mboe
with the all-in cost to add 1P reserves being $13.19 per Boe(1).
This is a per-share increase of 17% on a debt adjusted basis(2).
The 1P reserve life index ("RLI") is 12 years using production in
the fourth quarter of 2013.
- Total proved plus probable ("2P") reserves increased 48% to
total 40,541 Mboe with the all-in cost to add 2P reserves being
$9.79 per Boe(1). This is a per-share increase of 15% on a debt
adjusted basis(2). The 2P RLI is 23 years using production in the
fourth quarter of 2013.
- The trailing three year all-in cost to add 1P reserves is
$18.51 per Boe and is $13.80 per Boe to add 2P reserves.
- Recycle ratio was 1.5 for 1P reserve additions and 2.1 for 2P
reserve additions using the all-in cost for reserve additions and
the 2013 field operating netback of $20.44 per Boe excluding
hedging gains or losses.
- The finding and development cost ("FDC") per NI 51-101
requirements (removing effect of acquisitions, dispositions and
revisions) was $13.98 per Boe to add 1P reserves and $10.75 per Boe
to add 2P reserves.
- The year-over-year increase in 1P reserves was 6,942 Mboe which
replaced 430% of 2013 production and the increase in 2P reserves
was 13,210 Mboe which replaced 910% of 2013 production.
- 66% of total 2P reserves are at Umbach, 20% at Horn River Basin
("HRB") and 14% at Grande Prairie.
- Storm's asset value is $3.25 per share using the before tax 2P
reserve value of $298 million (discounted at 10%) and after
deducting adjusted net debt of $12.1 million at the end of 2013.
This excludes any value for Storm's landholdings which totaled
302,000 net acres at year end.
- The majority of additions to 1P and 2P reserves in 2013 was
from drilling activity (extensions) at Umbach where 10,355 Mboe was
added on a 1P basis and 18,822 Mboe was added on a 2P basis with
all of this being from the upper Montney formation.
- FDC was $159 million on a 1P basis and $319 MM on a 2P basis
which is an increase from the end of 2012 where FDC was $103
million on a 1P basis and $229 million on a 2P basis. This
represents approximately four years of activity based on the
anticipated 2014 capital investment levels.
- Property dispositions completed during 2013 reduced 1P reserves
by 859 Mboe and 2P reserves by 1,137 Mboe. FDC associated with the
dispositions was $1.7 million on a 2P basis (there was no 1P FDC).
With net proceeds from the dispositions totaling $19.5 million and
including FDC, reserves were sold for $22.70 per Boe on a 1P basis
and $18.65 per Boe on a 2P basis.
- Technical revisions increased PDP reserves by 403 Mboe with 1P
and 2P reserves being reduced by 78 Mboe and 304 Mboe respectively.
This was related to well performance with negative 2P revisions at
Grande Prairie totaling 437 Mboe that were partially offset by
positive 2P revisions of 105 Mboe in the HRB and 28 Mboe at Umbach
North. Notably, improved horizontal well performance resulted in
PDP reserves at Umbach being revised higher by 439 Mboe.
- Economic factors reduced 1P reserves by 1,149 Mboe and reduced
2P reserves by 2,844 Mboe. This was the result of removing two
future horizontal drilling locations in the HRB due to low natural
gas prices.
- At Umbach South (100% working interest), 2P reserves totaled
16,070 Mboe which is 40% of Storm's total 2P. There are five
horizontal wells with PDP reserves and 20 future horizontal
drilling locations (20.0 net) were recognized on 6.25 gross
sections (6.25 net) with 2P reserves averaging 642 Mboe per future
drilling location (four proved plus probable future horizontal
drilling locations per producing horizontal well). An average of
3.5 Bcf of gross raw gas was assigned per future horizontal
drilling location with 10% shrinkage from raw gas to sales gas and
NGL recovery of 37 barrels per Mmcf of sales (McMahon Gas Plant).
2P FDC totalled $113 million net.
- At Umbach North (60% working interest), 2P reserves totaled
10,741 Mboe which is 26% of Storm's total 2P. There are eight
horizontal wells with PDP reserves and 26 future horizontal
drilling locations (15.6 net) were recognized on 8.5 gross sections
(5.1 net) with 2P reserves averaging 549 Mboe per future drilling
location (3.25 proved plus probable future horizontal drilling
locations per producing horizontal well). An average of 3 Bcf of
gross raw gas was assigned per future horizontal drilling location
with 17% shrinkage from raw gas to sales gas and NGL recovery of 54
barrels per Mmcf of sales (Stoddart Gas Plant). 2P FDC totalled $84
million net.
- DPIIP in the upper Montney formation at Umbach was 604 Bcf for
the area where 2P reserves were recognized, an average of 41 Bcf
per section.
- Significant additional reserves are likely to be added in the
future at Umbach given that reserves are recognized in the upper
Montney only on 8% of Storm's 140 net sections in the area.
Additionally, comparing 30 to 90 operating day rates, Storm
management estimates ultimate recovery from the horizontal wells
drilled to date at Umbach South will be 4.4 Bcf which is higher
than InSite's estimate of 3.5 Bcf for future horizontal drilling
locations. More production history is required to confirm Storm
management's estimate of ultimate recovery.
- In the HRB, 2P reserves were 8,258 Mboe with 1,466 Mboe
assigned to complete a standing horizontal shale gas well (1.0 net)
and to drill four future horizontal shale gas wells (4.0 net).
Recoverable reserves assigned to each of the future horizontal
drilling locations averaged 10 Bcf of gross raw gas. Shrinkage of
12% was used to determine sales gas volumes. 2P FDC was $84 million
gross.
(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
future development costs.
(2) Debt adjusted calculation increases 2013 year-end debt from
$12.1 million to $44.7 million to equal the 2012 year-end debt by
buying back 8 million shares at $4.05 per share (Storm's December
31, 2013 closing share price).
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, 2013, which will
include complete disclosure of oil and gas reserves and other
information in accordance with NI 51-101, will be contained within
the Annual Information Form 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,
2013 |
| (Before deduction of royalties payable, not including
royalties receivable) |
|
|
|
Light Crude Oil (Mbbls) |
Sales Gas (Mmcf) |
NGL (Mbbls) |
6:1 Oil Equivalent (Mboe) |
|
Proved producing |
1,123 |
32,719 |
1,003 |
7,579 |
|
Proved non-producing |
- |
123 |
2 |
22 |
| Total
proved developed |
1,123 |
32,842 |
1,005 |
7,601 |
|
Proved undeveloped |
300 |
65,758 |
1,903 |
13,163 |
| Total
proved |
1,423 |
98,600 |
2,908 |
20,764 |
|
Probable additional |
870 |
99,177 |
2,378 |
19,777 |
|
Total proved plus probable |
2,293 |
197,777 |
5,286 |
40,541 |
|
|
|
|
|
| Gross Company Reserve Reconciliation for 2013 |
|
| (Gross company interest reserves before deduction of
royalties payable) |
|
| 6:1 Oil Equivalent (Mboe) |
|
|
|
|
|
|
|
|
|
|
Total Proved |
|
Probable |
|
Proved plus Probable |
|
|
December 31, 2012 - opening balance |
13,822 |
|
13,509 |
|
27,331 |
|
|
Acquisitions |
- |
|
- |
|
- |
|
|
Discoveries |
- |
|
- |
|
- |
|
|
Extensions |
10,356 |
|
8,467 |
|
18,823 |
|
|
Dispositions |
(859 |
) |
(278 |
) |
(1,137 |
) |
|
Technical revisions |
(78 |
) |
(226 |
) |
(304 |
) |
|
Economic factors |
(1,149 |
) |
(1,695 |
) |
(2,844 |
) |
|
Production |
(1,328 |
) |
- |
|
(1,328 |
) |
|
December 31, 2013 - closing balance |
20,764 |
|
19,777 |
|
40,541 |
|
|
|
|
|
|
|
|
|
| Future Development Costs ("FDC") |
|
Proved |
|
|
|
HRB |
2.0 net horizontals plus infrastructure |
$ |
34.9 million |
|
Umbach |
20.6 net horizontals plus infrastructure |
$ |
117.0 million |
|
Grande Prairie |
3.0 net horizontals at Grimshaw |
$ |
7.6 million |
|
Total |
|
$ |
159.5 million |
|
|
|
|
| Proved Plus Probable Additional |
|
HRB |
5.0 net horizontals plus infrastructure |
$ |
83.8 million |
|
Umbach |
36.0 net horizontals plus infrastructure |
$ |
197.9 million |
|
Grande Prairie |
5.0 net horizontals at Grimshaw; 5.0 net horizontals at GP Montney;
and 1.0 net horizontal at GP Dunvegan |
|
$ 37.2 million |
|
Total |
|
$ |
318.9 million |
|
|
|
|
|
|
|
|
|
|
Proved Expenditures |
Proved Plus Probable Additional Expenditures |
|
2014 |
$ |
62,950 |
$ |
67,800 |
|
2015 |
$ |
13,107 |
$ |
75,888 |
|
2016 |
$ |
48,472 |
$ |
63,454 |
|
2017 |
$ |
34,946 |
$ |
78,572 |
|
2018 |
$ |
- |
$ |
33,155 |
|
2019 |
$ |
- |
$ |
- |
| Total
FDC - undiscounted |
$ |
159,475 |
$ |
318,869 |
|
Total FDC - discounted at 10% |
$ |
134,383 |
$ |
259,220 |
|
|
|
|
|
Note: InSite escalates capital costs at 2% per year after
2014.
NI 51-101 Finding and Development Costs
|
Total Proved Finding and Development Cost |
2013 |
2012 |
2011 |
3 Year Total |
|
Capital expenditures excluding acquisitions and dispositions
(000s) |
$ |
67,450 |
$ |
26,868 |
$ |
25,360 |
$ |
119,768 |
|
Net change in FDC (000s) |
|
77,282 |
|
30,863 |
|
25,541 |
|
133,686 |
|
Total capital including the net change in future capital
(000s) |
$ |
144,732 |
$ |
57,731 |
$ |
50,901 |
$ |
253,364 |
|
Reserve additions excluding acquisitions, dispositions, revisions
and economic factors (Mboe) |
|
10,356 |
|
4,067 |
|
2,505 |
|
16,928 |
|
Total proved finding and development costs (per Boe) |
$ |
13.98 |
$ |
14.20 |
$ |
20.32 |
$ |
14.97 |
|
|
|
|
|
|
|
|
Total Proved Plus Probable Finding and Development Cost |
|
2013 |
|
2012 |
|
2011 |
|
3 Year Total |
|
Capital expenditures excluding acquisitions and dispositions
(000s) |
$ |
67,450 |
$ |
26,868 |
$ |
25,360 |
$ |
119,678 |
|
Net change in FDC (000s) |
|
134,903 |
|
40,341 |
|
51,725 |
|
226,969 |
|
Total capital including the net change in future capital
(000s) |
$ |
202,353 |
$ |
67,209 |
$ |
77,085 |
$ |
346,647 |
|
Reserve additions excluding acquisitions, dispositions, revisions
and economic factors (Mboe) |
|
18,823 |
|
5,514 |
|
5,278 |
|
29,615 |
|
Total proved plus probable finding and development costs (per
Boe) |
$ |
10.75 |
$ |
12.19 |
$ |
14.60 |
$ |
11.71 |
|
|
|
|
|
|
|
|
|
All-In Finding, Development and Acquisition Costs
|
Total Proved All-In Finding, Development and Acquisition Cost
including FDC, Acquisitions, Dispositions, Revisions |
2013 |
2012 |
2011 |
3 Year Total |
|
Capital expenditures including acquisitions and dispositions
(000s) |
$ |
52,444 |
$ |
166,076 |
$ |
40,795 |
$ |
259,315 |
|
Net change in FDC (000s) |
|
56,600 |
|
72,655 |
|
25,541 |
|
154,796 |
|
Total capital including the net change in future capital
(000s) |
$ |
109,044 |
$ |
238,731 |
$ |
66,336 |
$ |
414,111 |
|
Reserve additions including acquisitions, dispositions revisions
and economic factors (Mboe) |
|
8,270 |
|
10,927 |
|
3,178 |
|
22,375 |
|
All-in total proved finding and development costs (per Boe) |
$ |
13.19 |
$ |
21.85 |
$ |
20.87 |
$ |
18.51 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Proved Plus Probable All-In Finding, Development and
Acquisition Cost including FDC, Acquisitions, Dispositions,
Revisions |
|
2013 |
|
2012 |
|
2011 |
|
3 Year Total |
|
Capital expenditures including acquisitions and dispositions
(000s) |
$ |
52,444 |
$ |
166,076 |
$ |
40,795 |
$ |
259,315 |
|
Net change in FDC (000s) |
|
89,829 |
|
156,258 |
|
51,725 |
|
297,812 |
|
Total capital including the net change in future capital
(000s) |
$ |
142,273 |
$ |
322,334 |
$ |
92,520 |
$ |
557,127 |
|
Reserve additions including acquisitions, dispositions revisions
and economic factors (Mboe) |
|
14,538 |
|
19,828 |
|
6,012 |
|
40,378 |
|
All-In total proved plus probable finding and development costs
(per Boe) |
$ |
9.79 |
$ |
16.26 |
$ |
15.39 |
$ |
13.80 |
|
|
|
|
|
|
|
|
|
|
Operating netback per Boe excluding hedging |
$ |
20.43 |
$ |
21.22 |
$ |
22.81 |
|
|
|
|
|
|
|
|
|
|
|
|
Recycle ratio based on operating netback (excluding hedging gains
or losses |
|
|
|
|
|
|
|
|
|
Proved plus probable |
|
2.1 |
|
1.3 |
|
1.5 |
|
|
|
|
|
|
|
|
|
|
|
Net Present Value Summary (before tax) as at December 31,
2013
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.
|
|
Undiscounted (000s) |
Discounted at 5% (000s) |
Discounted at 10% (000s) |
Discounted at 15% (000s) |
Discounted at 20% (000s) |
|
Proved producing |
$ |
184,439 |
$ |
146,816 |
$ |
122,247 |
$ |
105,198 |
$ |
92,774 |
|
Proved non-producing |
|
92 |
|
87 |
|
82 |
|
78 |
|
74 |
|
Total proved developed |
$ |
184,531 |
$ |
146,903 |
$ |
122,329 |
$ |
105,276 |
$ |
92,848 |
|
Proved undeveloped |
|
184,537 |
|
107,293 |
|
62,108 |
|
34,079 |
|
15,855 |
|
Total proved |
$ |
369,068 |
$ |
254,196 |
$ |
184,438 |
$ |
139,355 |
$ |
108,704 |
|
Probable additional |
|
364,989 |
|
197,446 |
|
113,383 |
|
67,039 |
|
39,544 |
|
Total proved plus probable |
$ |
734,058 |
$ |
451,643 |
$ |
297,821 |
$ |
206,393 |
$ |
148,248 |
Numbers in this table may not add due to rounding.
Net Present Value Summary (after tax) as at December 31,
2013
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.
|
|
Undiscounted (000s) |
Discounted at 5% (000s) |
Discounted at 10% (000s) |
Discounted at 15% (000s) |
Discounted at 20% (000s) |
|
Proved producing |
184,439 |
146,816 |
122,247 |
105,198 |
92,774 |
|
Proved non-producing |
92 |
87 |
82 |
78 |
74 |
|
Total proved developed |
184,531 |
146,903 |
122,329 |
105,276 |
92,848 |
|
Proved undeveloped |
162,353 |
95,685 |
55,755 |
30,462 |
13,725 |
|
Total proved |
346,884 |
242,588 |
178,084 |
135,738 |
106,574 |
|
Probable additional |
274,236 |
146,917 |
82,937 |
47,569 |
26,517 |
|
Total proved plus probable |
621,121 |
389,504 |
261,021 |
183,308 |
133,091 |
Numbers in this table may not add due to rounding.
InSite Escalating Price Forecast as at December 31, 2013
|
|
WTI Crude Oil (US$/Bbl) |
Edmonton Light Crude Oil (Cdn$/Bbl) |
Henry Hub Natural Gas (US$/Mmbtu) |
AECO Natural Gas (Cdn$/Mmbtu) |
Propane (Cdn$/Bbl) |
Butane (Cdn$/Bbl) |
|
2014 |
96.00 |
96.05 |
4.25 |
3.99 |
48.03 |
76.84 |
|
2015 |
95.00 |
97.50 |
4.40 |
4.14 |
53.63 |
78.00 |
|
2016 |
95.00 |
97.45 |
4.75 |
4.50 |
53.60 |
77.96 |
|
2017 |
95.00 |
97.40 |
5.00 |
4.75 |
53.57 |
77.92 |
|
2018 |
96.00 |
98.40 |
5.25 |
5.01 |
54.12 |
78.72 |
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", "expect", "anticipate", "intend", "believe", "plan",
"potential", "outlook", "forecast", "estimate" 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 plans; reserve volumes; capital
expenditures; royalties; financing; commodity prices; and
production, operating and general and administrative costs.
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: 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; environmental risks; competition; ability to access
sufficient capital from internal and external sources; 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 company's MD&A
for the three months and year ended December 31, 2013.
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.
Storm Resources Ltd.Brian LavergnePresident & Chief
Executive Officer(403) 817-6145Storm Resources Ltd.Donald
McLeanChief Financial Officer(403) 817-6145Storm Resources
Ltd.Carol KnudsenManager, Corporate Affairs(403)
817-6145www.stormresourcesltd.com