HIGHLIGHTS & OUTLOOK

 

HIGHLIGHTS – FOURTH QUARTER AND YEAR END 2014

 

  • 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 Boe per day (21% oil plus NGL), a per-share increase of 51% from 2013 (notable given the 28% increase in shares outstanding). Fourth quarter production was 10,173 Boe per day (20% oil plus NGL), an increase of 69% 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% from 3,262 Boe per day in the fourth quarter of 2013.
  • NGL production was 1,605 barrels per day in the fourth quarter, year-over-year growth of 131%. The increase was the result of production growth from the liquids-rich Montney formation at Umbach where NGL recovery was 35 barrels per Mmcf sales in the fourth quarter.  With approximately 60% of the NGL mix being condensate plus pentanes, the NGL price of $56.15 per barrel was 74% 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% 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 Mmcf per day gross raw gas (865 Boe per day sales), an improvement of 37% 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 includes 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 totaled $45.4 million, or $0.42 per share, an increase of 40% on a per-share basis from the previous year. Funds from operations in the fourth quarter was $13.9 million, or $0.13 per basic share, an increase of 44% from the prior year. 
  • The funds from operations netback for the year was $17.83 per Boe, a year-over-year increase of 8% which was primarily the result of a decline in operating costs and cash G&A totaling $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, interest expense) were $13.23 per Boe in 2014, a year-over-year decrease of 19%. 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%.  Operating costs for the year decreased by 14% 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 $0.04 per share, a significant improvement when compared to 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 totaled $194.5 million for the year which included $88.0 million to acquire a 100% 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 $0.12 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 $0.5 million 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.

 

2014 YEAR-END RESERVE EVALUATION HIGHLIGHTS

 

Dec 31, 2014

Dec 31, 2013

Change

Reserves

Proved Producing (Mboe)

13,487

7,579

+78%

Total Proved (Mboe)

59,551

20,764

+187%

Total proved plus Probable (Mboe)

88,024

40,541

+117%

Reserves per share

Proved Producing (Mboe per million shares)

121

87

+39%

Total Proved (Mboe per million shares)

535

237

+125%

Total proved plus Probable (Mboe per million shares)

791

463

+71%

Finding and Development (“F&D”) Cost

including the change in future development capital and excluding revisions, acquisitions, dispositions

Proved Producing ($/Boe)

$13.73

$19.53

-30%

Total Proved ($/Boe)

$10.20

$13.98

-27%

Total proved plus Probable ($/Boe)

$8.76

$10.75

-18%

All-in Finding, Development, and Acquisition (“FD&A”) Cost

including the change in future development capital

Proved Producing ($/Boe)

$23.01

$17.22

+34%

Total Proved ($/Boe)

$11.68

$13.19

-11%

Total proved plus Probable ($/Boe)

$9.64

$9.79

-1%

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

+63%

Total Proved ($M)

$493,000

$184,000

+168%

Total proved plus Probable ($M)

$684,000

$298,000

+130%

 

  • Reserve additions replaced 332% of 2014 production on a proved producing basis, 1,522% on a total proved basis, and 1,863% on a total proved plus probable basis.
  • The all-in 2P 2014 FD&A 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 remainder to acquiring production and reserves. The 2P F&D cost of $8.76 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% of Storm’s 141 net sections from 8% last year and this included 73.4 net horizontal drilling locations which represents 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 (“FDC”) and $12.85 per Boe on a 2P basis including FDC (using 111.3 million shares outstanding, the December 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%.

 HEDGING UPDATE

 For 2015, commodity price hedges include both fixed price swaps and collars with:

  • 22,500 Mcf per day (27,900 GJ per day) of natural gas from January to December at an average floor price of approximately $4.28 per Mcf and an average ceiling price of $4.54 per Mcf (AECO monthly index $3.45 per GJ for floor and $3.66 per GJ for ceiling);
  • 533 barrels per day of oil from January to September at a price of WTI Cdn$98.43 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% 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

  

 

2014 Guidance

 

  

January 23, 2014

 Original Guidance

  

May 14, 2014

Revised Guidance

 November 13, 2014

 Revised Guidance

  

 

Actual 2014 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 operating costs

$8.00 - $9.00 per Boe

$8.00 - $9.00 per Boe

$9.00 - $9.50 per Boe

$9.33 per Boe

Average royalty rate

(% of revenue before hedging)

14% - 15%

15% - 16%

15%

13.7%

Operations capital (excluding acquisitions & dispositions)

$78.0 million

$97.0 million

$105.0 million

$106.7 million

Land & 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 quarter production

7,500 – 7,900 Boe/d

(20% oil + NGL)

8,900 – 9,200 Boe/d

(20% oil + NGL)

10,500 Boe/d

(20% oil + NGL)

10,173 Boe/d(1)

(20% oil + NGL)

Forecast annual production

 

5,500 – 6,500 Boe/d

(21% oil + NGL)

6,000 – 6,700 Boe/d

(21% oil + NGL)

 7,000 Boe/d

(21% oil + NGL)

6,980 Boe/d

(21% oil + NGL)

Umbach horizontal wells drilled

 

10 gross

 (10.0 net)

14 gross

 (14.0 net)

16 gross

 (16.0 net)

16 gross

 (16.0 net)

Umbach horizontal wells completed

9 gross

 (9.0 net)

13 gross

(12.6 net)

13 gross

 (12.6 net)

13 gross

 (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 to $38.0 million which includes drilling six Montney horizontal wells (6.0 net), completing two horizontal wells (2.0 net), constructing a 15-kilometer 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 to 55 Mmcf per day raw gas in late March.

Guidance for 2015 is being revised from original guidance provided November 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 Mmcf per day raw gas which has exceeded the design capacity of 24 Mmcf per day and the expansion in March is now expected to increase capacity to 55 Mmcf per day raw gas versus previous expectations of 48 Mmcf per day.

2015 Guidance

November 13, 2014

 Original Guidance

February 26, 2015

Revised Guidance

AECO natural gas price

$3.25 per GJ

$2.35 - $2.90 per GJ

BC 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 & dispositions)

$110.0 million

$80.0 million

Estimated land & property acquisitions

$0.0 million

$0.0 million

Estimated cash G&A net of recoveries

$5.3 million

$5.3 million

Forecast fourth quarter production

14,000 – 14,500 Boe/d

(18% oil + NGL)

14,000 – 14,500 Boe/d

(19% oil + NGL)

Forecast annual production

11,500 – 12,700 Boe/d

(19% oil + NGL)

11,000 – 12,000 Boe/d

(20% oil + NGL)

Umbach horizontal wells drilled

Umbach horizontal wells completed

Umbach horizontal wells starting production

9 gross (9.0 net)

14 gross (14.0 net)

16 gross (16.0 net)

6 gross (6.0 net)

11 gross (11.0 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 Mmcf per day to 55 Mmcf per day in late March; and
  • $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% 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 mid-point representing an increase of 67% from average production in 2014.  This includes approximately 60% 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 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 GJ and Edmonton light oil Cdn$53.00 to $62.00 per barrel).  The year-over-year increase in debt is forecast to be 30% to 50% which is consistent with year-over-year production growth.  Debt is primarily funding 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% 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 frac stages and completion techniques is 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.