Natural Gas Well Productivity
Productivity Analysis of Gas Producing Wells in Alberta from 1994 to 2008. Please note that final numbers for 2006, 2007 and 2008 may change slightly when final reports have been submitted. These posted rates may also vary from other sources as these numbers have been rounded.
Productivity is defined as monthly production divided by total producing hours, multiplied by 24.
- Gas wells are conventional gas wells.
- Solution gas is produced from oil wells.
- CBM is natural gas from coal.
Note, the following tables are;
- subject to periodic industry amendments
- not exact, numbers have been rounded
- and for clarity, the reported numbers are not broken down by vintage
Number of Producing Gas, Solution Gas and CBM Well Events at Year End
2008 and 2009 Tables added in September 2010
Natural Gas Average Daily Production (ADP) Rate
Alberta Wellhead Natural Gas Production
Crown Natural Gas Royalty and Royalty Rate by Productivity Range - 2005
Crown Natural Gas Royalty Volume and Royalty Rate by Productivity Range - 2006
Crown Royalty and Royalty Rate by Productivity Range - 2007
Crown Natural Gas Royalty Volume and Royalty Rate by Productivity Range - 2008
Analysis of Gas Wells by Depth, Production and Gross Royalty
Number of Well Events Producing Natural Gas by Depth Range in 2008
Natural Gas Royalty Wellhead Production by Depth Range in 2008
Total Crown and Freehold Natural Gas Production by Depth Range
Natural Gas and Natural Gas By-Products Gross Royalty
Costs - Annual Natural Gas Crown Gas Cost Allowance (GCA)
Alberta Natural Gas Production and Royalty Revenues
Royalty Rates Before Gas Cost Allowance (GCA)
Alberta Combined Natural Gas and NGL Net Royalty
Net Royalty and Deductible Items as Percent of Gross Royalty
Holiday, Injection Credits, Raw Gas Adjustments and Other Misc. Deductions from Royalty
Alberta Natural Gas Royalty Rate Without Liquids Royalty
Alberta Natural Gas Royalty Rate With Liquids
Natural Gas Royalty Programs
Deep Gas Royalty Holiday Program (DGRHP) Information
Otherwise Flared Solution Gas (OFSG) - OFSG Credits by Production Year
Sulphur Emission Control Assistance Program (SECAP) Credits
Number of Producing Gas, Solution Gas and CBM Well Events at Year End
| Year | Gas | Solution Gas | CBM only 1 | CBM others 2 | Total |
| 1994 | 37,141 | 29,035 | - | - | 66,176 |
| 1995 | 29,386 | 30,338 | - | - | 69,624 |
| 1996 | 41,696 | 31,784 | - | - | 73,480 |
| 1997 | 45,265 | 34,163 | - | - | 79,428 |
| 1998 | 48,962 | 33,003 | - | - | 82,965 |
| 1999 | 53,552 | 33,937 | - | - | 87,489 |
| 2000 | 60,903 | 35,296 | - | - | 96,199 |
| 2001 | 69,365 | 36,113 | - | - | 105,478 |
| 2002 | 64,494 | 29,428 | 701 | 31 | 94,654 |
| 2003 | 72,072 | 29.995 | 990 | 229 | 103,286 |
| 2004 | 82,058 | 30,725 | 1,538 | 938 | 115,259 |
| 2005 | 90,746 | 31,431 | 2,439 | 2,587 | 127,203 |
| 2006 | 98,760 | 32,090 | 3,657 | 4,346 | 138,853 |
| 2007 | 104,860 | 32,461 | 4,775 | 5,436 | 147,532 |
| 2008 | 109,471 | 33,002 | 5,891 | 6,073 | 154,437 |
| 2009 | 108.465 | 31,931 | 6,799 | 6,775 | 153,970 |
Source: Alberta Energy
Notes:
1. CBM (Coalbed Methane) production prior to 2002 was insignificant and the number of well events
prior to 2002 include CBM and CBM and others well events.
2. CBM and others include CBM mixed (commingled), and shale gas well events
Number of Natural Gas Well Events and Gas Production - 2008 and 2009
Productivity Range
Average Number of Well Events
Crown Volume (Bcf)Total Crown and Freehold Production (Bcf)
| E3M3/Day | 2008 | 2009 | 2008 | 2009 |
| 0.0 <= ADP < 0.5 | 62,197 | 66,544 | 153.8 | 170.9 |
| 0.5 <= ADP < 1.0 | 32,422 | 33,172 | 289.4 | 295.3 |
| 1.0 <= ADP < 1.5 | 16,090 | 15,820 | 242.3 | 238.4 |
| 1.5 <= ADP < 2.0 | 9,660 | 9,346 | 204.3 | 197.1 |
| 2.0 <= ADP < 5.0 | 22,045 | 21,286 | 830.6 | 804.6 |
| 5.0 <= ADP < 8.0 | 7,690 | 7,252 | 569.8 | 538.3 |
| 8.0 <= ADP < 16.9 | 7,773 | 7,029 | 1,006.7 | 915.2 |
| 16.9 <= ADP < 50.0 | 3,733 | 3,225 | 1,109.2 | 970.5 |
| 50.0 <= ADP < 100.0 | 627 | 527 | 461.9 | 386.4 |
| ADP>=100.0 | 308 | 282 | 700.9 | 660.8 |
| Total | 162,546 | 164,482 | 5,569 | 5,177 |
Crown Gas Volume, Gross Royalty and Royalty Rate by Productivity Range - 2008 and 2009
| Productivity Range | Crown Volume (Bcf) | Gross Royalty ($Million) | Royalty Rate |
| E3M3/Day | 2008 | 2009 | 2008 | 2009 | 2008 | 2009 |
| 0.0 <= ADP < 0.5 | 78.97 | 88.1 | $79.2 | $22.2 | 13.07% | 6.23% |
| 0.5 <= ADP < 1.0 | 156.06 | 159.5 | $127.7 | $37.0 | 10.10% | 5.84% |
| 1.0 <= ADP < 1.5 | 136.53 | 132.2 | $125.8 | $32.1 | 11.21% | 6.07% |
| 1.5 <= ADP < 2.0 | 119.29 | 113.3 | $121.3 | $28.5 | 12.18% | 6.26% |
| 2.0 <= ADP < 5.0 | 538.80 | 525.2 | $707.2 | $147.3 | 15.34% | 6.74% |
| 5.0 <= ADP < 8.0 | 409.66 | 392.1 | $732.9 | $151.3 | 20.68% | 8.80% |
| 8.0 <= ADP < 16.9 | 767.05 | 703.5 | $1,785.1 | $482.1 | 26.98% | 15.69% |
| 16.9 <= ADP < 50.0 | 858.84 | 767.3 | $2,201.0 | $755.8 | 29.22% | 22.58% |
| 50.0 <= ADP < 100.0 | 364.56 | 305.3 | $938.7 | $342.9 | 29.56% | 26.03% |
| ADP>=100.0 | 364.74 | 324.5 | $908.1 | $361.0 | 30.47% | 26.58% |
| Total | 3,794.49 | 3,510.9 | $7,727.1 | 2,360.3 |
Crown Gas Royalty Take and Holiday Amounts - 2008 and 2009
| Productivity Range | Crown Royalty Take (% of Total) | Holiday Amount ($Million)1 |
| E3M3/Day | 2008 | 2009 | 2008 | 2009 |
| 0.0 <= ADP < 0.5 | 1.0% | 0.9% | 0.33 | 0.10 |
| 0.5 <= ADP < 1.0 | 1.6% | 1.6% | 0.40 | 0.06 |
| 1.0 <= ADP < 1.5 | 1.6% | 1.4% | 0.83 | 0.08 |
| 1.5 <= ADP < 2.0 | 1.6% | 1.2% | 1.34 | 0.09 |
| 2.0 <= ADP < 5.0 | 9.0% | 6.2% | 17.20 | 0.49 |
| 5.0 <= ADP < 8.0 | 9.4% | 6.4% | 25.59 | 0.69 |
| 8.0 <= ADP < 16.9 | 23.2% | 20.4% | 85.56 | 5.63 |
| 16.9 <= ADP < 50.0 | 28.7% | 32.0% | 149.91 | 25.20 |
| 50.0 <= ADP < 100.0 | 12.1% | 14.5% | 78.73 | 20.93 |
| ADP>=100.0 | 11.7% | 15.3% | 65.76 | 21.02 |
| Total | 100% | 100% | 425.70 | $74.30 |
1. In 2008 Deep Gas Royalty Holiday Program (DGRHP) was the only holiday program for true vertical depths greater than 2,500 meters; 2009 Holiday includes Natural Gas Deep Drilling Program (NGDDP) and New Well Royalty Reduction (NWRR).
Natural Gas Average Daily Production (ADP) Rate
|
Year |
Daily Gas Well Average Productivity |
Daily CBM Well Average Productivity |
Daily Solution Gas Well Average Productivity |
|
1994 |
12.78 |
- |
2.47 |
|
1995 |
12.43 |
- |
2.33 |
|
1996 |
12.13 |
- |
2.29 |
|
1997 |
11.48 |
- |
2.15 |
|
1998 |
10.97 |
- |
2.08 |
|
1999 |
10.27 |
- |
2.06 |
|
2000 |
9.21 |
- |
1.92 |
|
2001 |
7.98 |
- |
1.79 |
|
2002 |
7.07 |
2.90 |
1.70 |
|
2003 |
6.21 |
2.47 |
1.63 |
|
2004 |
5.47 |
2.60 |
1.62 |
|
2005 |
4.89 |
2.60 |
1.58 |
|
2006 |
4.34 |
2.62 |
1.48 |
|
2007 |
4.00 |
2.42 |
1.33 |
|
2008 |
3.59 |
2.16 |
1.18 |
| 2009 | 3.27 | 1.90 | 1.13 |
Average daily production (ADP) = (Total production/Total number of hours of production)*24
Total gas is the sum of gas from CBM and solution gas wells.
Alberta Wellhead1 Natural Gas Production
|
Year |
Gas - Tcf |
Solution Gas - Tcf |
CBM2 - Tcf |
Total - Tcf |
Solution Gas % of Total Gas |
CBM % of Total Gas |
|
1994 |
4.67 |
0.68 |
- |
5.35 |
12.7% |
- |
|
1995 |
4.89 |
0.68 |
- |
5.57 |
12.1% |
- |
|
1996 |
5.08 |
0.69 |
- |
5.77 |
12.0% |
- |
|
1997 |
5.12 |
0.69 |
- |
5.81 |
11.8% |
- |
|
1998 |
5.29 |
0.68 |
- |
5.96 |
11.3% |
- |
|
1999 |
5.38 |
0.66 |
- |
6.04 |
10.9% |
- |
|
2000 |
5.43 |
0.65 |
- |
6.09 |
10.7% |
- |
|
2001 |
5.34 |
0.63 |
- |
5.97 |
10.5% |
- |
|
2002 |
5.30 |
0.60 |
0.01 |
5.91 |
10.1% |
0.13% |
|
2003 |
5.16 |
0.58 |
0.01 |
5.75 |
10.1% |
0.20% |
|
2004 |
5.17 |
0.59 |
0.03 |
5.79 |
10.2% |
0.60% |
|
2005 |
5.15 |
0.58 |
0.09 |
5.83 |
10.0% |
1.52% |
|
2006 |
5.05 |
0.56 |
0.18 |
5.80 |
9.7% |
3.19% |
|
2007 |
5.00 |
0.52 |
0.25 |
5.76 |
9.0% |
4.30% |
|
2008 |
4.76 |
0.46 |
0.27 |
5.50 |
8.4% |
4.96% |
| 2009 | 4.36 | 0.43 | 0.31 | 5.10 | 8.5% | 6.05% |
Notes:
1. Wellhead production includes all producing zones of the well.
2. CBM production prior to 2002 was insignificant
Crown Natural Gas Royalty and Royalty Rate by Productivity Range - 2005
|
Productivity |
Monthly Average |
Total Crown |
Crown Royalty Volume |
Crown Royalty Volume |
Crown Gross |
Crown Gross |
Gross Royalty |
|
0.0-17.7 |
45,222 |
55.3 |
17.5 |
8.0 |
31.7% |
14.4% |
$71.3 |
|
17.7- 35.3 |
23,119 |
113.6 |
35.8 |
12.4 |
31.6% |
10.9% |
$108.4 |
|
35.3-53.0 |
13,367 |
114.5 |
36.1 |
13.4 |
31.5% |
11.7% |
$116.1 |
|
53.0-70.6 |
8,150 |
99.2 |
31.1 |
12.7 |
31.4% |
12.8% |
$110.3 |
|
70.6-176.6 |
18,652 |
434.2 |
133.4 |
70.3 |
30.7% |
16.2% |
$617.9 |
|
176.7-282.5 |
6,997 |
342.7 |
104.0 |
73.9 |
30.3% |
21.6% |
$654.1 |
|
282.5-600 |
8,447 |
790.3 |
239.9 |
219.5 |
30.4% |
27.8% |
$1,957.8 |
|
600-1765.7 |
4,759 |
1,033.6 |
313.7 |
312.5 |
30.4% |
30.2% |
$2,794.4 |
|
1765.7-3531.5 |
796 |
427.6 |
129.9 |
129.7 |
30.4% |
30.3% |
$1,152.0 |
|
>3531.5 |
448 |
580.7 |
175.2 |
175.1 |
30.2% |
30.2% |
$1,517.6 |
LPWA: Low Productivity Well Allowance
Crown Natural Gas Royalty Volume and Royalty Rate by Productivity Range - 2006
|
Productivity |
Monthly Average |
Total Crown |
Crown |
Crown |
Crown |
Crown |
Gross |
|
0.0-17.7 |
50,333 |
62.7 |
19.8 |
8.4 |
31.5% |
13.5% |
$59.4 |
|
17.7- 35.3 |
26,874 |
129.6 |
40.8 |
13.6 |
31.5% |
10.5% |
$92.9 |
|
35.3-53.0 |
15,015 |
128.2 |
40.2 |
14.6 |
31.4% |
11.4% |
$99.0 |
|
53.0-70.6 |
9,100 |
113.0 |
35.3 |
14.2 |
31.2% |
12.6% |
$95.9 |
|
70.6-176.6 |
20,861 |
494.0 |
151.2 |
78.7 |
30.6% |
15.9% |
$541.1 |
|
176.7-282.5 |
7,494 |
382.6 |
116.0 |
81.9 |
30.3% |
21.4% |
$568.1 |
|
282.5-600 |
8,495 |
817.7 |
248.1 |
226.2 |
30.3% |
27.7% |
$1,581.5 |
|
600-1765.7 |
3,149 |
577.3 |
175.0 |
174.0 |
30.3% |
30.1% |
$1,227.6 |
|
1765.7-3531.5 |
1,336 |
423.1 |
128.3 |
128.0 |
30.3% |
30.3% |
$904.9 |
|
>3531.5 |
1,136 |
915.5 |
276.7 |
276.5 |
30.2% |
30.2% |
$1,932.3 |
LPWA: Low Productivity Well Allowance
Crown Royalty and Royalty Rate by Productivity Range - 2007
|
Productivity |
Monthly Average |
Total |
Crown |
Crown |
Crown |
Crown |
Gross |
|
0.0-17.7 |
55,514 |
69.8 |
22.0 |
8.8 |
31.5% |
12.5% |
$58 |
|
17.7-35.3 |
29,901 |
142.9 |
44.9 |
14.6 |
31.4% |
10.2% |
$94 |
|
35.3-53.0 |
15,788 |
135.8 |
42.5 |
15.2 |
31.3% |
11.2% |
$97 |
|
53.0-70.6 |
9,413 |
116.8 |
36.3 |
14.6 |
31.1% |
12.5% |
$93 |
|
70.6-176.6 |
21,881 |
523.7 |
160.0 |
82.7 |
30.5% |
15.8% |
$529 |
|
176.7-282.5 |
7,727 |
403.6 |
122.2 |
86.0 |
30.3% |
21.3% |
$548 |
|
282.5-600 |
8,257 |
801.3 |
242.8 |
221.0 |
30.3% |
27.6% |
$1,406 |
|
600-1765.7 |
4,186 |
948.8 |
287.6 |
286.4 |
30.3% |
30.2% |
$1,792 |
|
1765.7- 3531.5 |
687 |
379.3 |
114.8 |
114.7 |
30.3% |
30.2% |
$716 |
|
>3531.5 |
376 |
440.4 |
132.8 |
132.8 |
30.2% |
30.2% |
$823 |
LPWA: Low Productivity Well Allowance
Crown Natural Gas Royalty Volume and Royalty Rate by Productivity Range - 2008
|
Productivity |
Monthly Average |
Total Crown |
Crown Royalty Volume |
Crown Royalty Volume |
Crown Gross |
Crown Gross |
Gross Royalty |
|
0.0-17.7 |
62,104 |
79.5 |
25.0 |
9.6 |
31.4% |
12.0% |
$81 |
|
17.7-35.3 |
32,398 |
155.8 |
48.9 |
15.6 |
31.4% |
10.0% |
$128 |
|
35.3-53.0 |
16,066 |
136.1 |
42.5 |
15.3 |
31.2% |
11.3% |
$125 |
|
53.0-70.6 |
9,637 |
118.7 |
36.8 |
14.8 |
31.0% |
12.4% |
$121 |
|
70.6-176.6 |
21,917 |
532.8 |
162.2 |
83.7 |
30.4% |
15.7% |
$699 |
|
176.7-282.5 |
7,675 |
405.2 |
122.6 |
86.1 |
30.3% |
21.3% |
$725 |
|
282.5-600 |
7,940 |
772.1 |
233.8 |
212.5 |
30.3% |
27.5% |
$1,799 |
|
600-1765.7 |
3,808 |
865.0 |
262.0 |
260.8 |
30.3% |
30.2% |
$2,218 |
|
1765.7-3531.5 |
627 |
362.8 |
109.7 |
109.6 |
30.2% |
30.2% |
$934 |
|
>3531.5 |
308 |
364.7 |
109.8 |
109.8 |
30.1% |
30.1% |
$908 |
LPWA: Low Productivity Well Allowance
Analysis of Gas Wells by Depth, Production and Gross Royalty
Note:
Well depth is an important factor in determining gas royalty rates under the Alberta Royalty framework (ARF). The depth analysis is based on the total depth of the producing well events (finish drill date) which are paying royalties including wells spud and produced to 2008. There are several well depth ranges; however, under the current ARF regime there is a special focus on wells in three categories: Wells greater than 2000 meters depth, wells greater than 2500 meters and wells greater than 4000 meters depth. Wells greater than 2000 meters depth will receive a royalty adjustment through the depth factor; the wells greater than 2500 meters will receive a deep drilling program royalty adjustment and wells greater than or equal to 4000 meters will receive a supplemental benefit of $875,000 per well. In addition the transition royalty rate is applicable to well events between 1000 metres and 3500 metres depth. Gross royalties are related to Alberta par price, average daily production (ADP) rate, acid gas factor and well depth.
Number of Well Events Producing Natural Gas1 by Depth Range in 2008
|
Depth Range |
CBM |
Gas |
Oil |
Others2 |
Grand Total |
Cumulative Number |
Cum % of Total |
|
0<Depth<=500 |
1,203 |
16,285 |
0 |
145 |
17,633 |
17,633 |
11% |
|
500<Depth<=1000 |
8,064 |
63,443 |
5,877 |
804 |
78,188 |
95,821 |
60% |
|
1000<Depth<=1500 |
1,554 |
14,538 |
7,768 |
142 |
24,002 |
119,823 |
75% |
|
1500<Depth<=2000 |
228 |
6,352 |
8,067 |
228 |
14,875 |
134,698 |
84% |
|
2000<Depth<=2500 |
135 |
7,280 |
3,773 |
543 |
11,731 |
146,429 |
92% |
|
2500<Depth<=3000 |
146 |
5,431 |
2,051 |
691 |
8,319 |
154,748 |
97% |
|
3000<Depth<=3500 |
16 |
2,992 |
427 |
141 |
3,576 |
158,324 |
99% |
|
3500<Depth<=4000 |
1 |
803 |
88 |
7 |
899 |
159,223 |
100% |
|
4000<Depth<=4500 |
|
324 |
13 |
1 |
338 |
159,561 |
100% |
|
4500<Depth<=5000 |
|
153 |
3 |
|
156 |
159,717 |
100% |
|
5000<Depth<=5500 |
|
47 |
1 |
|
48 |
159,765 |
100% |
|
5500<Depth<=6000 |
|
6 |
|
|
6 |
159,771 |
100% |
|
6000<Depth<=6500 |
|
7 |
|
|
7 |
159,778 |
100% |
|
6500<Depth<=7000 |
|
6 |
|
|
6 |
159,784 |
100% |
|
Depth>7000 |
|
|
|
|
|
159,784 |
100% |
|
Total |
11,347 |
117,667 |
28,068 |
2,702 |
159,784 |
Source: Alberta Department of Energy
Notes:
1. Number of wells are those well Events which paid royalties during the year
2. Include crude bitumen, shale gas only, CBM & shale gas combined etc.
Number of Well Events Producing Natural Gas1 by Depth Range in 2009
| Depth Range | CBM Well Events |
Gas Well Events |
Oil Well Events |
Others2 Well Events |
Grand Total Well Events |
Cumulative Number of Well Events |
Cum % |
|
0<Depth<=500 |
1,381 | 16,123 | 0 | 146 | 17,650 | 17,650 | 11% |
|
500<Depth<=1000 |
9,648 | 63,380 | 5,976 | 964 | 79,968 | 97,618 | 60% |
|
1000<Depth<=1500 |
1,891 | 14,147 | 7,457 | 130 | 23,625 | 121,243 | 75% |
|
1500<Depth<=2000 |
289 | 6,243 | 8,058 | 240 | 14,830 | 136,073 | 84% |
|
2000<Depth<=2500 |
148 | 7,262 | 3,773 | 564 | 11,747 | 147,820 | 91% |
|
2500<Depth<=3000 |
166 | 5,520 | 2,054 | 690 | 8,430 | 156,250 | 97% |
|
3000<Depth<=3500 |
19 | 3,178 | 445 | 140 | 3,782 | 160,032 | 99% |
|
3500<Depth<=4000 |
3 | 877 | 94 | 10 | 984 | 161,016 | 100% |
|
4000<Depth<=4500 |
- | 393 | 12 | 2 | 407 | 161,423 | 100% |
|
4500<Depth<=5000 |
- | 166 | 3 | 1 | 170 | 161,593 | 100% |
|
5000<Depth<=5500 |
- | 46 | - | - | 46 | 161,639 | 100% |
|
5500<Depth<=6000 |
- | 7 | - | - | 7 | 161,646 | 100% |
|
6000<Depth<=6500 |
- | 7 | - | - | 7 | 161,653 | 100% |
|
6500<Depth<=7000 |
- | 8 | - | - | 8 | 161,661 | 100% |
| Total | 13,545 | 117,357 | 27,872 | 2,887 | 161,661 |
Source: Alberta Department of Energy
Notes:
1. Number of wells are those well Events which paid royalties during the year
2. Include crude bitumen, shale gas only, CBM & shale gas combined etc.
Natural Gas Royalty Wellhead Production by Depth Range in 2008
|
Depth Range |
Gas - Bcf |
Solution gas- Bcf |
CBM - Bcf |
Others1 Bcf |
Total - Bcf |
|
0<Depth<=500 |
256.75 |
- |
30.54 |
1.23 |
289 |
|
500<Depth<=1000 |
989.95 |
14.59 |
174.00 |
5.13 |
1,184 |
|
1000<Depth<=1500 |
456.07 |
59.70 |
27.78 |
0.51 |
544 |
|
1500<Depth<=2000 |
398.97 |
144.42 |
5.59 |
0.91 |
550 |
|
2000<Depth<=2500 |
692.53 |
105.66 |
17.22 |
3.13 |
819 |
|
2500<Depth<=3000 |
667.15 |
103.30 |
17.58 |
5.06 |
793 |
|
3000<Depth<=3500 |
521.67 |
29.75 |
2.90 |
2.04 |
556 |
|
3500<Depth<=4000 |
268.66 |
5.32 |
0.77 |
0.01 |
275 |
|
4000<Depth<=4500 |
142.65 |
2.20 |
|
0.00 |
145 |
|
4500<Depth<=5000 |
131.27 |
0.33 |
|
|
132 |
|
5000<Depth<=5500 |
58.92 |
|
|
|
59 |
|
5500<Depth<=6000 |
4.86 |
|
|
|
5 |
|
6000<Depth<=6500 |
10.51 |
|
|
|
11 |
|
6500<Depth<=7000 |
6.52 |
|
|
|
7 |
|
Depth>7000 |
- |
|
|
|
|
|
Total |
4,606.48 |
465.27 |
276.39 |
18.03 |
5,366 |
Source: Alberta department of Energy
Notes: Others include solvent, crude bitumen, shale gas, CBM & shale and other sources
Total Crown and Freehold Natural Gas Production by Depth Range
|
|
Total Wellhead Volume (Bcf) |
Crown Volume (Bcf) |
||||
|
Depth Range |
Total Gas |
Cumulative |
Cumulative |
Total |
Cumulative |
Cumulative |
|
0<D<=500 |
289 |
289 |
5% |
236 |
236 |
5.88% |
|
500<D<=1000 |
1,184 |
1,472 |
27% |
752 |
988 |
24.63% |
|
1000<D<=1500 |
544 |
2,016 |
38% |
293 |
1,281 |
31.93% |
|
1500<D<=2000 |
550 |
2,566 |
48% |
393 |
1,674 |
41.72% |
|
2000<D<=2500 |
819 |
3,385 |
63% |
680 |
2,354 |
58.66% |
|
2500<D<=3000 |
793 |
4,178 |
78% |
652 |
3,006 |
74.92% |
|
3000<D<=3500 |
556 |
4,734 |
88% |
486 |
3,492 |
87.04% |
|
3500<D<=4000 |
275 |
5,009 |
93% |
215 |
3,707 |
92.39% |
|
4000<D<=4500 |
145 |
5,154 |
96% |
123 |
3,830 |
95.46% |
|
4500<D<=5000 |
132 |
5,285 |
98% |
113 |
3,944 |
98.29% |
|
5000<D<=5500 |
59 |
5,344 |
100% |
51 |
3,994 |
99.56% |
|
5500<D<=6000 |
5 |
5,349 |
100% |
4 |
3,999 |
99.67% |
|
6000<D<=6500 |
11 |
5,360 |
100% |
8 |
4,007 |
99.86% |
|
6500<D<=7000 |
7 |
5,366 |
100% |
5 |
4,012 |
100.00% |
|
Depth >7000 |
- |
5,366 |
100% |
- |
4,012 |
100.00% |
|
Total (Bcf) |
5,366 |
|
|
4,012 |
|
|
Note: Total production is wellhead production, Crown volume is royalty liable volume (includes liquids) in gas equivalent volume.
Natural Gas and Natural Gas By-Products Gross Royalty
|
Depth Range |
Gross |
Cumulative |
Cumulative |
|
D = Depth |
Royalty ($Million) |
Gross Royalty ($Million) |
Gross Royalty Percentage |
|
0<D<=500 |
$299 |
$299 |
3% |
|
500<D<=1000 |
$979 |
$1,278 |
13% |
|
1000<D<=1500 |
$596 |
$1,875 |
19% |
|
1500<D<=2000 |
$1,113 |
$2,988 |
30% |
|
2000<D<=2500 |
$2,030 |
$5,018 |
51% |
|
2500<D<=3000 |
$1,970 |
$6,988 |
71% |
|
3000<D<=3500 |
$1,449 |
$8,437 |
85% |
|
3500<D<=4000 |
$642 |
$9,079 |
92% |
|
4000<D<=4500 |
$344 |
$9,423 |
95% |
|
4500<D<=5000 |
$285 |
$9,708 |
98% |
|
5000<D<=5500 |
$117 |
$9,825 |
100% |
|
5500<D<=6000 |
$11 |
$9,836 |
100% |
|
6000<D<=6500 |
$19 |
$9,855 |
100% |
|
6500<D<=7000 |
$13 |
$9,868 |
100% |
|
Depth>7000 |
$0 |
$9,868 |
100% |
|
Total |
|
$9,868 |
|
Costs
Gas Cost Allowance (GCA) – An allowance Crown pays to process Crown share of Natural gas
Annual Natural Gas Crown Gas Cost Allowance (GCA)1
|
Year |
Operating |
Capital |
Custom |
Total |
UOCR |
UOCR |
GCA per |
|
1994 |
$306 |
$300 |
$28 |
$633 |
1,098 |
$0.28 |
$0.58 |
|
1995 |
$209 |
$296 |
$32 |
$535 |
1,936 |
$0.11 |
$0.28 |
|
1996 |
$260 |
$355 |
$36 |
$650 |
1,023 |
$0.25 |
$0.64 |
|
1997 |
$274 |
$430 |
$41 |
$744 |
1,149 |
$0.24 |
$0.65 |
|
1998 |
$266 |
$455 |
$49 |
$768 |
1,149 |
$0.23 |
$0.67 |
|
1999 |
$316 |
$514 |
$57 |
$888 |
1,261 |
$0.25 |
$0.70 |
|
2000 |
$365 |
$603 |
$58 |
$1,025 |
1,321 |
$0.28 |
$0.78 |
|
2001 |
$437 |
$682 |
$45 |
$1,164 |
1,309 |
$0.33 |
$0.89 |
|
2002 |
$459 |
$709 |
$49 |
$1,215 |
1,257 |
$0.37 |
$0.97 |
|
2003 |
$493 |
$754 |
$42 |
$1,288 |
1,198 |
$0.41 |
$1.08 |
|
2004 |
$589 |
$820 |
$39 |
$1,447 |
1,180 |
$0.50 |
$1.23 |
|
2005 |
$686 |
$892 |
$34 |
$1,612 |
1,149 |
$0.60 |
$1.40 |
|
2006 |
$793 |
$1,053 |
$26 |
$1,869 |
1,143 |
$0.69 |
$1.63 |
|
2007 |
$834 |
$1,176 |
$16 |
$2,023 |
1,102 |
$0.76 |
$1.84 |
|
2008 |
$890 |
$1,253 |
$-3 |
$2,139 |
1,035 |
$0.86 |
$2.07 |
| 2009 | $618 | $869 | $230 | $1,593 | 662 | $0.93 | $2.41 |
Bold indicates numbers updated in 2010.
1. GCA includes gathering, compression and processing at the plant.
2. Total GCA is the sum of operating, capital and custom fees adjusted by cost restrictions (that is, GCA cannot
exceed Crown royalty payable)
3. EAGEV stands for energy adjusted gas equivalent volume.
4. UOCR per Mcf = Operating Cost Allowance/UOCR Volume, where UOCR stands for Unit Operating Cost Rate
5. GCA per Mcf = Total GCA Costs/UOCR Volume
*: Effective January 1, 2009 the operating costs paid by the crown are based on a facility by facility percentage of the actual operating costs of that facility. The percentage is the ratio of the value of the royalty volume compared to the total value of the volume processed at the particular facility.
* The data is subject to prior period adjustments, statute barred after four years, for example, 2005 production year was statute barred at December 31, 2009.
Alberta Natural Gas Production and Royalty Revenues*
Royalty Rates Before Gas Cost Allowance (GCA)1
|
Natural Gas |
Gross Gas |
Crown |
Crown Gross |
Low Productivity |
Holiday |
Royalty |
Royalty Rates |
|
2001 |
$30,027 |
$24,696 |
$7,469 |
$668 |
$86 |
$6,715 |
27.19% |
|
2002 |
$20,427 |
$16,784 |
$5,104 |
$534 |
$109 |
$4,462 |
26.58% |
|
2003 |
$32,030 |
$26,193 |
$8,004 |
$942 |
$155 |
$6,908 |
26.37% |
|
2004 |
$33,413 |
$27,039 |
$8,252 |
$1,076 |
$150 |
$7,025 |
25.98% |
|
2005 |
$43,852 |
$35,391 |
$10,790 |
$1,628 |
$323 |
$8,839 |
24.98% |
|
2006 |
$34,846 |
$28,226 |
$8,598 |
$1,436 |
$271 |
$6,891 |
24.41% |
|
2007 |
$32,250 |
$26,264 |
$7,995 |
$1,464 |
$324 |
$6,207 |
23.63% |
|
2008 |
$39,092 |
$31,878 |
$9,696 |
$1,918 |
$339 |
$7,439 |
23.34% |
| 2009 | $18,773 | $15,185 | $2,376 | $0 | $74 | $2,302 | 15.16% |
|
Liquids |
Gross Liquids |
Crown Liquids |
Crown Gross |
LPWA |
Holiday |
Royalty |
R% |
|
2001 |
$3,746 |
$3,119 |
$1,016 |
$0.4 |
$8 |
$1,008 |
32.33% |
|
2002 |
$3,099 |
$2,609 |
$849 |
$0.3 |
$13 |
$836 |
32.05% |
|
2003 |
$3,850 |
$3,194 |
$1,034 |
$0.4 |
$14 |
$1,020 |
31.93% |
|
2004 |
$4,441 |
$3,657 |
$1,193 |
$0.5 |
$17 |
$1,176 |
32.16% |
|
2005 |
$5,683 |
$4,720 |
$1,552 |
$1.5 |
$37 |
$1,514 |
32.07% |
|
2006 |
$5,880 |
$5,001 |
$1,640 |
$3.3 |
$44 |
$1,593 |
31.86% |
|
2007 |
$5,968 |
$5,104 |
$1,672 |
$4.2 |
$55 |
$1,613 |
31.60% |
|
2008 |
$7,378 |
$6,452 |
$2,123 |
$5.7 |
$62 |
$2,055 |
31.86% |
| 2009 | $4,359 | $3,818 | $1,335 | $0.0 | $36 | $1,299 | 34.02% |
|
Total |
$Million ($MM) |
Revenue |
Gross |
LPWA |
Holidays |
Net Roy |
R% |
|
2001 |
$33,773 |
$27,815 |
$8,486 |
$669 |
$93 |
$7,724 |
27.77% |
|
2002 |
$23,526 |
$19,393 |
$5,953 |
$534 |
$121 |
$5,298 |
27.32% |
|
2003 |
$35,881 |
$29,388 |
$9,039 |
$942 |
$169 |
$7,927 |
26.98% |
|
2004 |
$37,854 |
$30,696 |
$9,445 |
$1,077 |
$167 |
$8,201 |
26.72% |
|
2005 |
$49,535 |
$40,111 |
$12,343 |
$1,630 |
$360 |
$10,353 |
25.81% |
|
2006 |
$40,726 |
$33,227 |
$10,239 |
$1,439 |
$315 |
$8,485 |
25.54% |
|
2007 |
$38,219 |
$31,367 |
$9,667 |
$1,468 |
$379 |
$7,820 |
24.93% |
|
2008 |
$46,470 |
$38,330 |
$11,820 |
$1,924 |
$401 |
$9,494 |
24.77% |
| 2009 | $23,132 | $19,002 | $3,711 | $0 | $110 | $3,600 | 19.95% |
Bold indicates numbers updated in 2010.
Adjustments for the prior period continue up to the end of the year. No further adjustments after that.
Notes
1. The information in this section is based on monthly charges data where all changes in the past months
are included in the present month and as of May 2009 production month.
2. Crown gross royalty before any deduction and excludes sulphur production
3. Deep Gas Royalty Holiday Program terminated December 31, 2008.
Alberta Combined Natural Gas and NGL Net Royalty
|
Year |
Total |
LPWA |
GCA |
Other Deductions1 |
Net Royalty2 |
|
2001 |
$8,486 |
$669 |
$1,243 |
$534 |
$6,040 |
|
2002 |
$5,953 |
$534 |
$1,274 |
$444 |
$3,702 |
|
2003 |
$9,039 |
$942 |
$1,335 |
$544 |
$6,217 |
|
2004 |
$9,445 |
$1,077 |
$1,458 |
$524 |
$6,387 |
|
2005 |
$12,343 |
$1,630 |
$1,618 |
$813 |
$8,282 |
|
2006 |
$10,239 |
$1,439 |
$1,744 |
$680 |
$6,375 |
|
2007 |
$9,667 |
$1,468 |
$1,934 |
$704 |
$5,560 |
|
2008 |
$11,820 |
$1,924 |
$2,053 |
$851 |
$6,992 |
| 2009 | $3,711 | $0 | $1,444 | $284 | $1,873 |
Bold indicates numbers updated in 2010.
Adjustments for the prior period continue up to the end of the year. No further adjustments after that.
Notes:
1. Other Deductions include injection credit, DGRHP, transportation, fractionation, raw gas adjustments etc.
2. Excludes sulphur revenues
Net Royalty and Deductible Items as Percent of Gross Royalty
|
Year |
Net Royalty |
LPWA |
GCA |
Other Deductions1 |
|
2001 |
71.2% |
7.9% |
14.7% |
6.3% |
|
2002 |
62.2% |
9.0% |
21.4% |
7.5% |
|
2003 |
68.8% |
10.4% |
14.8% |
6.0% |
|
2004 |
67.6% |
11.4% |
15.4% |
5.5% |
|
2005 |
67.1% |
13.2% |
13.1% |
6.6% |
|
2006 |
62.3% |
14.1% |
17.0% |
6.6% |
|
2007 |
57.5% |
15.2% |
20.0% |
7.3% |
|
2008 |
59.2% |
16.3% |
17.4% |
7.2% |
| 2009 | 50% | 0% | 39% | 8% |
Notes:
1. Other deductions include injection credit, DGRHP, transportation, fractionation, raw gas adjustments etc.
Holiday, Injection Credits, Raw Gas Adjustments and Other Misc. Deductions from Royalty
|
Year |
Holidays |
Injection Credits |
Raw Gas Adj. |
Others |
Total |
|
2001 |
$93 |
348 |
10.9 |
82 |
$534 |
|
2002 |
$121 |
239 |
6.7 |
76 |
$444 |
|
2003 |
$169 |
278 |
5.2 |
36 |
$489 |
|
2004 |
$167 |
245 |
8.0 |
103 |
$524 |
|
2005 |
$360 |
297 |
9.3 |
147 |
$813 |
|
2006 |
$315 |
231 |
6.4 |
127 |
$680 |
|
2007 |
$379 |
211 |
6.2 |
108 |
$704 |
|
2008 |
$401 |
241 |
6.7 |
209 |
$858 |
| 2009 | $110 | 94 | 2.0 | 187 | $393 |
|
|
% of Total |
% of Total |
% of Total |
% of Total |
Total |
|
2001 |
17.5% |
65.2% |
2.0% |
15.3% |
100% |
|
2002 |
27.4% |
53.9% |
1.5% |
17.2% |
100% |
|
2003 |
34.6% |
57.0% |
1.1% |
7.4% |
100% |
|
2004 |
31.9% |
46.9% |
1.5% |
19.7% |
100% |
|
2005 |
44.2% |
36.6% |
1.1% |
18.1% |
100% |
|
2006 |
46.3% |
34.0% |
0.9% |
18.7% |
100% |
|
2007 |
53.8% |
30.0% |
0.9% |
15.3% |
100% |
|
2008 |
46.8% |
28.0% |
0.8% |
24.4% |
100% |
| 2009 | 28.1% | 23.9% | 0.5% | 47.5% | 100% |
Bold indicates numbers updated in 2010.
Alberta Natural Gas Royalty Rate Without Liquids Royalty
|
Year |
Gross Royalty |
Royalty Rate |
Royalty Rate |
Effective Royalty Rate |
|
2001 |
30.25% |
27.54% |
27.19% |
21.21% |
|
2002 |
30.41% |
27.23% |
26.58% |
18.25% |
|
2003 |
30.56% |
26.96% |
26.37% |
20.65% |
|
2004 |
30.52% |
26.54% |
25.98% |
20.12% |
|
2005 |
30.49% |
25.89% |
24.98% |
19.92% |
|
2006 |
30.46% |
25.38% |
24.41% |
17.96% |
|
2007 |
30.44% |
24.87% |
23.63% |
16.18% |
|
2008 |
30.42% |
24.40% |
23.34% |
16.79% |
| 2009 | 15.65% | 15.65% | 15.16% | 5.51% |
Note: The percentage calculation is based on data in the previous table.
Bold indicates numbers updated in 2010.
Alberta Natural Gas Royalty Rate With Liquids
|
Year |
Gross Royalty |
Royalty Rate |
Royalty Rate |
Effective Royalty Rate |
|
2001 |
30.51% |
28.10% |
27.77% |
21.71% |
|
2002 |
30.70% |
27.95% |
27.32% |
19.09% |
|
2003 |
30.76% |
27.55% |
26.98% |
21.16% |
|
2004 |
30.77% |
27.26% |
26.72% |
20.81% |
|
2005 |
30.77% |
26.71% |
25.81% |
20.65% |
|
2006 |
30.81% |
26.48% |
25.54% |
19.19% |
|
2007 |
30.82% |
26.14% |
24.93% |
17.73% |
|
2008 |
30.84% |
25.82% |
24.77% |
18.22% |
| 2009 | 19.53% | 19.53% | 18.95% | 9.86% |
Note: The percentage calculation is based on data in the previous table.
Bold indicates numbers updated in 2010.
Natural Gas Royalty Programs
Deep Gas Royalty Holiday Program (DGRHP) Information1 Expired December 2009
|
Year |
Number of |
Gross |
Gross |
Gross |
|
1994 |
136 |
49 |
87 |
56.33% |
|
1995 |
86 |
27 |
95 |
28.73% |
|
1996 |
93 |
39 |
159 |
24.72% |
|
1997 |
132 |
58 |
219 |
26.36% |
|
1998 |
174 |
70 |
211 |
33.25% |
|
1999 |
176 |
106 |
345 |
30.82% |
|
2000 |
250 |
167 |
645 |
25.85% |
|
2001 |
378 |
171 |
848 |
20.11% |
|
2002 |
386 |
207 |
767 |
27.05% |
|
2003 |
475 |
247 |
1,345 |
18.40% |
|
2004 |
650 |
314 |
1,589 |
19.76% |
|
2005 |
850 |
445 |
2,177 |
20.45% |
|
2006 |
952 |
385 |
1,945 |
19.80% |
|
2007 |
746 |
427 |
1,985 |
21.51% |
|
2008 |
289 |
404 |
2,428 |
16.63% |
|
Total |
5773 |
$3,117 |
$14,846 |
|
Run Date: February 2009 invoice, as of December 2008 Production Month.
2004 to 2008 numbers are subject to reporting amendments (until Statute Barred).
Notes:
1. The program terminated effective 31 December 2008.
2. Based on effective start date – the number of new wells added to the program.
Otherwise Flared Solution Gas (OFSG) - OFSG Credits1 by Production Year
|
Production year |
OFSG Credit $ Million |
|
1999 |
$0.66 |
|
2000 |
$4.50 |
|
2001 |
$8.10 |
|
2002 |
$7.68 |
|
2003 |
$12.72 |
|
2004 |
$12.65 |
|
2005 |
$15.57 |
|
2006 |
$11.39 |
|
2007 |
$10.94 |
| 2008 | $13.69 |
| 2009 | $0.71 |
Bold indicates numbers updated in 2010.
Notes:
1. The OFSG program was announced in December 2, 1998 and was implemented in mid 1999 with royalty waiver made retroactive to January 1, 1999 production. The waiver would last for ten years from the first day in the month in which the application was received. The OFSG program was introduced to encourage the reduction of solution gas flaring in Alberta. For wells approved under this program, royalty is waved on solution gas and gas by-products that are uneconomic to conserve.
Sulphur Emission Control Assistance Program (SECAP) Credits1
|
Production Year |
SECAP Credits ($Million)2 |
|
1995 |
$0.43 |
|
1996 |
$2.19 |
|
1997 |
$3.15 |
|
1998 |
$2.28 |
|
1999 |
$3.82 |
|
2000 |
$1.13 |
|
2001 |
$0.61 |
|
2002 |
$0.00 |
|
2003 |
$9.26 |
|
2004 |
$5.47 |
|
2005 |
$7.72 |
|
2006 |
$0.00 |
|
2007 |
$35.18 |
|
2008 |
$2.05 |
Notes:
1. This program expired on November 30, 2008.
2. The SECAP program was intended to provide financial assistance to operators of small sour gas plants
in meeting the sulphur emission standards. The program extended later to include some large sour gas plants identified in ERCB Interim Directive 2001-3 which were required to meet updated sulphur recovery
guidelines.
