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F E A T U R E S
Great Big Bakken By Darrell Stonehouse In North Dakota and eastern Montana, the Bakken oil play is bursting at the seams. Next on tap are tight oil plays in Montana, Colorado and Wyoming.
Pulling hard By Darrell Stonehouse Artificial lift companies prepare for unconventional oil onslaught
8
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N E W S
British Columbia
57
• B.C. government backs LNG industry
31
Northwestern Alberta • Lone Pine grows Evi oil play
35
43
• Don’t raise royalties, says C.D. Howe Institute By Elsie Ross
61
Central Canada • Oliver says major project approvals will be streamlined By Elsie Ross
Northeastern Alberta • Cumulative effects monitoring coming By Lynda Harrison
Saskatchewan
65
International • Husky sanctions Liwan Gas Project
Central Alberta • Penn West eyes cost efficiencies By Elsie Ross
49
Southern Alberta • Alberta land sale revenue passes $3 billion By Richard Macedo
I N
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Statistics at a Glance
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If you want to see what an oil boom looks like, there’s no better time than right now. And there’s no better place to look than North Dakota and Montana. The Bakken tight oil play straddling the international border is producing over 500,000 barrels per day, with 450,000 barrels coming from the U.S. side of the border. And that boom is now spreading as producers expand the Bakken play and develop new tight oil plays, including the Alberta Basin Bakken and the Niobrara in the United States. Including tight oil plays in the southern states, a lot of industry watchers believe the United States could add as much as 1.3 million barrels per day by 2020, if the government gets out of industry’s way. The amount of investment to make that happen is staggering. In the main Bakken play alone, as many as 35,000 wells could be drilled to fully develop the play. The Western Energy Alliance says $58 billion could be spent annually by 2020 developing tight oil in the northwestern United States. And some consider all these numbers to be conservative. While more conservative factions in the U.S. industry believe between four to five billion barrels of oil are recoverable in the Bakken, some of the area’s more optimistic producers say as much as 20 billion barrels are recoverable from only the 167 billion barrels found beneath North Dakota. The Alberta Basin Bakken is still in its early exploratory stages, but already there are estimates saying there could be as much as 2.6 billion barrels of recoverable oil in the play. The Niobrara shale play could produce up to 350,000 barrels per day at its peak, say many analysts. What the U.S. tight oil boom means in the big picture is anyone’s guess. It is already influencing the flow of oil in North America and creating competition to transport growing supplies to market. Bakken crude, along with increased oilsands supplies, has created a bottleneck in the U.S. Midwest, driving down WTI prices to an around $20-per-barrel discount versus international prices. Oil producers are using rail to bypass Cushing, Okla., and to sell their crude into Gulf Coast markets at world prices. There are a number of efforts underway to build more pipeline capacity to new markets, including line reversals, a new Enbridge Inc. proposal for the 800,000-barrel-per-day Wrangler pipeline running from Cushing to Texas, and TransCanada’s Keystone XL pipeline running from Alberta to the Gulf Coast. But the big question in the United States is whether the tight oil boom can impact international oil flows and cut reliance on foreign sources of crude. So far, the results look promising. From 2008 to 2010, domestic oil production climbed by 11 per cent and natural gas liquids production by 12 per cent. Combined, the United States now produces 7.5 million barrels of liquids per day, the most in eight years. Imports are down to 9.4 million barrels per day, the lowest level in 13 years. Analysts credit half of the recent 1.7-million-barrel-per-day decline in imports to increased domestic production. N E X T
I S S U E
December 2011 In the December Oil & Gas Inquirer, we honour the latest and greatest in new oilfield technology in our Tech Stars annual feature. We also look at the Saskatchewan oil boom.
Want to sound off on any content in Oil & Gas Inquirer? Send your emails to dstonehouse@junewarren-nickles.com. Please mark them as "Letter to the Editor" if you want them published.
O I L & G A S I N Q U I R E R • N o v e m be r 2 0 1 1
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Stats
AT A GLANCE Alberta Completions
WCSB Oil & Gas Completions
Source: Daily Oil Bulletin
Source: Daily Oil Bulletin
MONTH
OIL
GAS
T O TA L
MONTH
OIL
GAS
D RY
SERVICE
T O TA L
Sept 2010 Oct 2010 Nov 2010
617 678 868
790 581 989
45 39 75
23 18 165
1,475 1,316 2,097
1,373 453 774
Dec 2010 Jan 2011 Feb 2011
1,061 409 723
559 201 378
78 33 38
238 17 99
1,936 660 1,238
222 112 100
1,846 1,003 433
Mar 2011 Apr 2011 Jun 2011
1,069 618 428
1,081 509 197
64 46 12
164 81 183
2,378 1,254 820
97 93 146
245 728 1,531
Jul 2011 Aug 2011 Sept 2011
298 922 1,448
97 262 445
15 28 24
88 80 155
498 1,292 2,072
Sept 2010 Oct 2010 Nov 2010
357 404 579
638 460 847
59 46 169
1,054 910 1,595
Dec 2010 Jan 2011 Feb 2011
676 226 353
403 145 294
294 82 127
Mar 2011 Apr 2011 Jun 2011
650 419 209
974 472 124
Jul 2011 Aug 2011 Sept 2011
105 452 1,028
43 183 357
Wells Drilled In British Columbia
Saskatchewan Completions
Source: B.C. Oil and Gas Commission
Source: Daily Oil Bulletin
MONTH
WELLS DRILLED
C U M U L AT I V E *
MONTH
OIL
GAS
OTHER
TOTAL
Sept 2010 Oct 2010 Nov 2010
40 42 43
566 608 651
Sept 2010 Oct 2010 Nov 2010
197 201 217
5 12 3
6 11 64
208 224 284
Dec 2010 Jan 2011 Feb 2011
49 62 69
700 62 131
Dec 2010 Jan 2011 Feb 2011
340 136 321
2 4 6
11 3 7
353 143 334
Mar 2011 Apr 2011 Jun 2011
55 41 54
186 172 419
Mar 2011 Apr 2011 Jun 2011
316 183 217
8 11 25
4 11 89
328 205 331
Jul 2011 Aug 2011 Sept 2011
56 40 92
479 519 611
Jul 2011 Aug 2011 Sept 2011
185 413 352
5 2 4
3 13 29
193 428 385
*From year toto date * from year date
12
OTHER
N OVe m be r 2 0 1 1 • O I L & G A S I N Q U I R E R
FAST NUMBERS
4,206
2,993
of August 2011.
of August 2010.
Number of horizontal wells drilled in WCSB to the end
Number of horizontal wells drilled to the end
Drilling Rig Count by Province/Territory
Drilling Activity: Oil & Gas
Western Canada October 14, 2011 Source: Rig Locator
Alberta September 2011 Source: Daily Oil Bulletin
AC T I V E
DOWN
T O TA L
Western Canada
AC T I V E
OIL WELLS
GAS WELLS
(Per cent of total)
Alberta
Sept 11
Sept 10
Sept 11
Sept 10
Alberta
371
199
570
65%
Northwestern Alberta
214
86
176
249
British Columbia
88
47
135
65%
Northeastern Alberta
176
18
34
35
Manitoba
52
27
79
66%
Central Alberta
515
191
57
122
Saskatchewan
19
-
19
100%
Southern Alberta
123
48
117
219
WC Totals
530
273
803
66%
TOTAL
1,028
343
384
625
Service Rig Count by Province/Territory
Drilling Activity: CBM & Bitumen
Western Canada October 14, 2011 Source: Rig Locator
Alberta September 2011 Source: Daily Oil Bulletin
AC T I V E
DOWN
T O TA L
AC T I V E
Western Canada Alberta
398
262
660
60%
British Columbia
150
47
197
76%
Manitoba
16
13
29
55%
Saskatchewan
16
2
18
89%
WC Totals
580
324
904
64%
Northwest Territories
-
1
1
0%
C OA L B E D M E T H A N E
BITUMEN WELLS
Alberta
Sept 11
Sept 10
Sept 11
Sept 10
Northwestern Alberta
0
11
22
4
Northeastern Alberta
0
0
176
34
Central Alberta
12
12
164
53
Southern Alberta
12
20
0
1
TOTAL
24
43
362
92
O I L & G A S I N Q U I R E R • N OVe m be r 2 0 1 1
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Feature
By DarrelL Stonehouse 14
N OV E m be r 2 0 1 1 • O I L & G A S I N Q U I R E R
Feature
In North Dakota and eastern Montana, the Bakken oil play is bursting at the seams. Next on tap are tight oil plays in Montana, Colorado and Wyoming. On the Canadian side of the border, the Bakken tight oil play in southeastern Saskatchewan and western Manitoba has set off an exploration boom. But it is only an echo when compared with the explosion south of the border in North Dakota and eastern Montana. Saskatchewan Bakken production is estimated at around 70,000 barrels per day. In North Dakota, production is estimated at over 425,000 barrels per day, up from 10,000 barrels a day in 2003, when drilling began taking off. And the tight oil boom across the U.S. Plains is just beginning, as explorers are now targeting the Three Forks formation beneath the Bakken, while there is a growing focus on the Alberta Bakken in Montana and the Niobrara play in Colorado. The Bakken play on the U.S. side of the border is huge by any measure. The U.S. Geological Survey says there are over 167 billion original barrels of oil in place in the formation in North Dakota alone. Just how much of that oil can be recovered is up for debate. The Geological Survey puts that number at around 4.6 billion barrels. Many in the industry think this is a gross underestimate, with some putting ultimate recovery as high as 20 billion barrels. Development of the North Dakota play is in its early stages, according to Lynn Helms, director of the North Dakota Department of Mineral Resources. Helms told a September meeting of the Minot Area Chamber of Commerce there are currently around 6,000 producing wells in the Bakken. Helms said he expects industry will drill around 2,000 wells into the play this year. Much of the current drilling is focused on maintaining drilling rights, he added, meaning current volatility in oil prices shouldn’t impact field activity in the near future. Going forward, Helms said, it would likely take another 28,000 wells to fully develop the field. “It will take 14 years with everything going right for 225 rigs to fully develop 28,000 wells,” he noted. Continental Resources, Inc. believes recovery in the Bakken will ultimately reach 20 billion barrels. It is one of the region’s largest players, with 901,370 net acres. Almost three-quarters of its land is in North Dakota, with the remainder in Montana. The company had 23 drilling rigs in the Bakken in the third quarter, with 21 in North Dakota and two in Montana. It also has five fracking crews working the play. Speaking at Continental’s second-quarter conference call, company chairman and chief executive officer Harold Hamm said advances in technology continue to improve production and resource recovery in the Bakken. In the play, Continental is using a multi-well pad drilling technique it calls ECO-Pad, common in western Canada. Continental drills four wells from a single drilling pad. The approach allows it to develop two separate formations on two separate spacing units simultaneously, increasing production efficiency. It completed its first ECO-Pad project in
2010 in Dunn County, N.D., from the Three Forks and Middle Bakken formations of the North Dakota Bakken. The ECO-Pad technique provides an estimated 10 per cent cost savings on the drilling and completion of each well, according to company estimates. It is also continuously increasing the number of fracturing stages along its horizontal wells. The results speak for themselves. “We completed 34 gross (18.2 net) wells as operator in the quarter, and their average initial test period production was 1,188 barrels of oil equivalent per day,” said Hamm. “Our top 12 North Dakota–operated wells in the quarter ranged from 1,400 to 2,240 barrels per day in their initial test periods. These are our great, great wells. So not only are we saving 10 per cent per well on average on our ECO-Pad projects, we’re also seeing outstanding production results with these ECO-Pad wells.” Projected ultimate recovery per well is also climbing as a result of advances in fracturing and well-completion technology, says Hamm. “Based on historical results, we raised our estimated ultimate recovery model to 603,000 barrels oil equivalent per well in North Dakota, compared with the previous EUR [estimated ultimate recovery] model of 518,000 barrels,” he explains. “The key factors contributing to the 16 per cent increase are advances in well-completion technology, including additional frac stages, which have continued to elevate the production curves on our wells. Secondly, as we explore and de-risk new areas of our acreage, we’re seeing the quality of that acreage in our well results. Geology, of course, plays a huge role here.” “Our 518,000-barrel-of-oil-equivalent model was based on a group of wells with an average of just over 20 stages per well,” he adds. “The new model is based on an average of just over 24 stages per well. Today, our standard design is 30 stages and basically, that’s a minimum amount of stages that we’re using.” For comparison, Saskatchewan Bakken wells average initial production rates of around 250 barrels of oil equivalent per day, and ultimate primary recovery is expected to be around 200,000 barrels of oil equivalent. There are a number of Canadian producers working the North Dakota and Montana Bakken. Enerplus Corp. has almost 75,000 acres of rights and is currently running four rigs in the area. Enerplus expects to exit 2011 with over 10,000 barrels of oil equivalent per day of production from the region. The company is using two different well designs. It is drilling 9,000-foot laterals with 24 frac stages and 4,500-foot laterals with 12 frac stages in the play. The long laterals with 24 stages are averaging 1,250-barrel-per-day initial production, while the shorter laterals are averaging around 660 barrels per day. At Fort Berthold in North Dakota, Enerplus drilled one long and three short Bakken horizontal wells during the second quarter, and completed and brought on a short Three Forks well. The company began drilling a long Three Forks lateral well during the quarter and anticipates testing the well during the third quarter. Enerplus currently has four rigs working at Fort Berthold and expects to maintain this rig count through the remainder O I L & G A S I N Q U I R E R • N o v e m be r 2 0 1 1
15
Feature approximately 10 per cent due to the associated natural gas volumes that will be captured once the wells are tied in to the gathering system. The company expects to drill 26 horizontal wells at Fort Berthold during the remainder of Alberta Manitoba Saskatchewan the year, targeting both the Bakken and the Three Forks formations, and plans to complete and tie in 22 wells. Enerplus has permits in place for all of its 2011 wells, and is currently working to secure 2012 and 2013 drilling Bakken Shale permits. Plans for 2011 include testing downspacing to determine optimal well density ND and, as a result, the company expects roughly MT 75 per cent of the wells drilled this year will be short lateral horizontals. Under the full development scenario, approximately 75 per cent of the wells are SD expected to be long horizontals. With four rigs WY working and the company’s frac services agreeID ment in place, drilling and completions activity should accelerate, and management expects to The main Bakken play. Production from the North remain on schedule for the balance of the year, drilling and completing three to four wells per month. Dakota area is now around 425,000 barrels per day. Saskatchewan Bakken producer Crescent Point Energy Corp. of 2011. Infrastructure and gathering system build continues to is also growing south of the border. In September, it announced proceed and the company expects to have a majority of its wells it has acquired approximately 750 barrels of oil equivalent per tied in by the end of the third quarter, reducing the reliance on day of Bakken light oil production and more than 78 net sections trucking. Production volumes are also expected to increase by of land in North Dakota through two strategic acquisitions.
Illustration: Angie Castaldi
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Feature
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Illustration: Angie Castaldi
The company believes the land to be prospective for the Bakken and Three Forks zones. The majority of the land is in a Regina highly prospective area of the Bakken that is adjacent to existing Crescent Point properties, further consolidating the company’s land position in North Dakota. Crescent Point has Bakken identified more than 140 net interShale nally identified low-risk drilling Alberta Basin Bakken locations in the Bakken and Three Bakken Forks zones. Crescent Point now has Bismarck Potential more than 165 net sections of lowerMONTANA risk land within the main productive areas of the North Dakota Bakken. The company has internally identiWilliston fied approximately 260 net low-risk Basin drilling locations on these lands. To date in 2011, Crescent Point has participated in the drilling of 16 (2.2 net) non-operated North Dakota Bakken/Three Forks horizontal oil The Alberta Basin Bakken is in early stage exploration wells and has drilled its first operated North Dakota Bakken horizonon both sides of the border. Much of the drilling done tal oil well, which the company expected to complete in September. in Montana is still confidential. In total, the company now expects to drill 10 net wells in North Dakota in 2011, up from previous plans of three net wells. In August, it announced it had concluded the initial Emerging producer Renegade Petroleum Ltd. is working to production test on the A Trout 6H3-14 well located in Renville County, N.D. The test has established light (43° API) Bakken expand the North Dakota Bakken eastward.
Feature
Bismarck
SOUTH DAKOTA Pierre
WYOMING
Niobrara Shale
North Dakota, Montana, Wyoming, Colorado, New Mexico and Utah have the potential to produce more than 1.3 million barrels of oil daily by 2020.
Rosetta Resources Inc. has 300,000 acres in the Alberta Bakken, with 11 delineation wells and seven horizontals planned for this year. Lincoln Further south, explorers are targeting the Niobrara shale, an emerging unconventional play Denver in the Rocky Mountains. T he Niobr a r a cou ld de ve lop i nto a COLORADO Topeka 350,000-barrel-per-day play, BENTEK Energy, a KANSAS U.S.-based energy consultant, said in September at a conference in Houston, Texas. The Niobrara is currently producing about 112,000 barrels per day. The play straddles the The Niobrara shale could develop into a 350,000Colorado and Wyoming borders and lies within the Denver-Julesburg Basin. Chesapeake Energy Corporation, barrel-per-day field, says BENTEK Energy. EOG Resources, Inc., Noble Energy, Inc. and Anadarko Petroleum oil p roduction approximately 30 miles east of the nearest Corporation are the most active of the 14 operators in the region, Bakken producer. which has 425 wells drilled to date. Drilling results in the play “This well confirms eastward migration from over pressured have been all over the place, with initial production on side-byBakken towards the depositional edge of the Middle Bakken side wells varying from 400 barrels per day to six barrels per day. sand and opens up a potential resource play along the eastern The development of the tight oil plays in the northwestern Williston Basin of North Dakota. The depths of the Bakken in United States has many believing the United States could see its Renville County are similar to the depths of the Bakken in the declining oil production reverse in the coming years. The Western Viewfield pool in southeast Saskatchewan. The initial sevenEnergy Alliance (WEA), a group representing over 400 oil and natural gas producers, says six western states—North Dakota, day test averaged 36 barrels from a 3,100 foot horizontal well,” Montana, Wyoming, Colorado, New Mexico and Utah—have the reported the company. Renegade continues to evaluate, optimize and production potential to produce more than 1.3 million barrels of oil daily by test the well, with further operational and optimization activi2020, 529,000 barrels more than in 2010. ties planned. It predicts in a recent report that the oil and gas industry will “Renegade is very encouraged by the presence of producible spend US$58 billion on drilling and completions by that same year, oil in the middle Bakken sand, and is currently moving forward up from US$28 billion in 2010. But to make that happen, governwith development plans to further de-risk the play in concert with ments need to get out the way and let explorers do their work in a the development of this well,” the company added. timely fashion. Renegade has increased its land position to over 47,350 gross “If we are serious about realizing the full promise of western energy production, regulatory policies must be realigned to sup(23,675 net) acres in the prospective area. With Bakken/Three Forks development in full swing, explorport, not hinder, responsible and timely access to oil and natural gas ers are now targeting what is being dubbed the Alberta Bakken resources on federal lands,” said WEA president Tom Sheffield, who in northern Montana and across the border into Alberta. A recent is vice-president of Pioneer Natural Resources Company’s western report by energy research consultants Wood Mackenzie said the division. “The industry is committed to continued environmental Alberta Bakken could hold as much as 2.6 billion barrels of recovimprovements and balanced use of our federal lands, but...we need a erable reserves. Development of the play is in the early stage. In more efficient and predictable regulatory environment.” northern Montana only 23 wells have been drilled, with eight “Public lands overlap much of the U.S. West,” he said. “The producing. On the Alberta side of the border, 31 wells have been Bureau of Land Management [BLM] controls 236 million acres drilled, with 16 producing. in our region. That’s a majority of the land in Utah, about half of Newfield Exploration Company is a dominant landholder in Wyoming and 30 per cent or more region-wide.” the Montana-Alberta Basin play, with 320,000 exploration acres He said the problem is that it can take up to nine years to receive held in partnership with the Blackfoot Nation. The company has approval to drill on BLM lands. seven well locations either drilled or permitted. It hasn’t released “When a company gets a lease, it’s for 10 years, so they’ve spent nine of that waiting for approval,” he said. any results as of yet.
Cheyenne
Illustration: Angie Castaldi
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Feature
By DarreLl Stonehouse
Artificial lift companies prepare for unconventional oil onslaught With relatively high prices driving drilling towards oil plays, artificial lift companies are positioning themselves for a growth spurt in the next few years. The change to drilling oil wells has been dramatic, with the Canadian Association of Oilwell Drilling Contractors predicting 60 per cent of wells drilled this year will target oil. Texas-based Lufkin Industries, Inc. is one artificial lift player positioning itself
for the coming boom in pumping demand. Lufkin recently took over two western Canadian companies in an effort to consolidate the marketplace and integrate its pumpjacks, well management technology with downhole pumping machinery. In early September, Lufkin announced it was acquiring Red Deer–based Quinn’s Oilfield Supply Ltd. for a little over $300 million. Quinn’s is one of the largest reciprocating rod pump manufacturers in North America and, through its acquisition of GrenCo Industries Ltd. in June 2010, it
also manufactures and distributes progressive cavity pumps and related equipment. Founded in 1965, Quinn’s operations include two manufacturing facilities in Canada, one in the United States, and 51 service locations strategically located in the oil and gas p roducing areas of North America. “The acquisition of Quinn’s continues our strategy of expanding our product portfolio in artificial lift systems, while at the same time extending our sales and service network in the increasingly active oil provinces of the United States and western Canada,” said Jay Glick, president and chief executive officer of Lufkin. “Quinn’s is well positioned to benefit from the large increase in unconventional oil plays, O I L & G A S I N Q U I R E R • N o v e m be r 2 0 1 1
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Photos: Joey Podlubny
Feature
Progressing cavity pump companies are also Heavy oil plays are providing growth for artificial lift suppliers.
benefiting from the greater focus on oil plays.
as oil shale wells generally transition to artificial lift approximately 18–24 months after completion.” Glick said in recent years Lufkin has seen demand from large producers for artificial lift packages that include surface pumps, downhole pumps and well optimization tools. Adding Quinn’s rod pump expertise will position Lufkin to meet that demand. “The integration of Lufkin’s surface beam pump unit with Quinn’s downhole rod pump will enhance Luf kin’s ability to package complementary products and allow us to better optimize the rod lift system to the benefit of our customers,” he explained. “Quinn’s downhole rod pumps and PCPs [progressing cavity pumps] are also a clear fit with our automation strategy of integrating downhole devices and instrumentation to monitor and control production.” The purchase of Quinn’s also allows Luf kin to enter the progressive cavity pump market, with Quinn’s recent purchase of GrenCo. “GrenCo manufactures a proprietary line of PCP equipment and is believed to have the premium wellhead drive offering in the industry,” said Glick. “The PCP market is expected to post strong growth going forward, as PCPs are particularly well-suited to the heav y oil production applications.” Glick said the purchase of Quinn’s will also increase its international market. “Quinn’s has achieved significant market share gains in the U.S. market
ortfolio, avoiding costly start-up and p development costs,” Glick added. “We’re excited to add Pentagon’s industry-leading optimization products, in particular the proprietary ANGEL pump. The ANGEL pump provides a cost-effective method to produce pressure-depleted gas wells and can pump both liquid and gas simultaneously without gas locking. The ANGEL pump has been successfully installed and tested in multiple highly deviated wells with high gas-oil ratios, and is expected to be ready for global commercialization next year.” Lufkin isn’t the only one attempting to consolidate the artificial lift and well optimization market in western Canada. High-tech company Zedi Inc. is growing out from the well-optimization business into the big iron to integrate its product offerings. In June, Zedi purchased the SilverJack hydraulic pump technology from Brooksbased TCB Welding and Construction Ltd. SilverJack has a unique hydraulic pump technology, with patents pending, that has generated significant interest with a number of producers, Zedi said. As an early-stage business, with proven technology, there is significant growth potential domestically and internationally, Zedi believes. SilverJack’s hydraulic pump integrates into Zedi’s current oiloptimization technology, and the company’s oil and gas strategies, it added. Ta r g e t e d a t l o w e r- p r o d u c i n g wells, which represent approximately 80 per cent of the North A merican market, there are currently 29 operating
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over the last few years, and we believe there’s still room for additional growth through Lufkin’s domestic sales and service network,” he noted. “More importantly, Quinn’s has proven its ability to enter new markets, and we expect to leverage Lufkin’s global infrastructure to introduce Quinn’s products and services to Latin America, Eastern Europe, North Africa and the Middle East. Additionally, the acquisition of Quinn’s will instantly give Luf kin a significantly larger footprint in Canada from which to market and service our other products.” The Quinn’s transaction followed a deal in August where Lufkin purchased Red Deer–based Pentagon Optimization Services Inc. Pentagon is a diversified well optimization company serving the oil and gas industry that provides a wide range of products and services, including plunger lift systems and well engineering and testing. Glick said the Pentagon deal was all about adding to Lufkin’s artificial lift offerings. “This acquisition immediately expands our footprint in Canada, the second-largest plunger lift market outside the U.S.,” he explained. “It also improves our existing plunger lift product portfolio and provides entry to the well-optimization, engineering and testing services market, which is highly complementary to our automation strategy.” “The acquisition of Pentagon is also expected to facilitate Lufkin-International Lift Systems with entry into the Canadian market and provide ILS [International Lift Systems] with an upgraded product
Feature
" The field-proven reliability and unique technology were key criteria in our decision to acquire SilverJack." — Matthew Heffernan, president and chief executive officer, Zedi SilverJack pumps in the field, representing both retrofit and new well applications. The reliability of the pumps in the field has resulted in broader adoption and repeat purchases by customers where the technology resolves production problems, Zedi said in a news release. “With the hydraulic pump already fully commercialized, implemented in the field and with a patent pending in Canada and internationally, it contributes to our technology road map with what we expect to be another accretive acquisition. The field-proven reliability and unique technology were key criteria in our decision to acquire SilverJack,” said Matthew Heffernan, president and chief executive officer of Zedi. Customers face an increasing number of wells producing less than 400 barrels of oil equivalent per day that experience high water cuts and sand problems, presenting operational challenges that are difficult to solve. “This technology is uniquely suited to addressing those wells,” said Tokunosuke Ito, chief technology officer of Zedi. In September, Zedi acquired the GlobalEye™ business unit from Global Flow Inc. of Medicine Hat, Alta. With over 500 wells—which are comprised of oil, gas and specialized mon itoring solutions—being monitored, this acquisition represents continued growth in the Canadian market as well as in the overall Zedi oil portfolio, which now includes artificial lift, monitoring and
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Feature
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N OV E m be r 2 0 1 1 • O I L & G A S I N Q U I R E R
production testing on over 5,000 oil wells worldwide, said the company. Zedi will move quickly to transition the customer base, of which almost one-third will be net new customers, to Zedi Access, Zedi’s secure web portal. Zedi will continue to rely on Global Flow to provide field service to the customers, who will now benefit from the excellent service of both Global Flow and Zedi. In addition, Zedi will further enhance its expansion into oil-based solutions with the addition of the WTX portable test software application and Oil Well Test Database, a subscription-based service that supports production test companies and currently contains over 630,000 test records from thousands of oil wells across North America. “ T his acquisition represents yet another accretive deal that involves both technology and a customer base that are a great fit with what we do today at Zedi. It moves us forward on our continuum of increased penetration of the Canadian market and, more importantly, grows our oil portfolio, providing a more appropriate mix of oil and gas revenues in response to current and anticipated market conditions,” said Heffernan.
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British Columbia
B.C. government backs LNG industry
SEP/10
SEP/11
SEP/10
SEP/11
WELLS SPUDDED
36
49
WELLS DRILLED
38
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Photo: Joey Podlubny
to define more effective working relationships. As for training and development, the province has been working with industry partners for some time on the future skills required to support a new LNG industry. The goal is to ensure the post-secondary system is able to deliver the targeted training necessary to grow the oil and gas industry, including LNG. Final details are under consideration with further information to be announced later this fall. The premier has also asked key provincial officials to attract investment by working with industry stakeholders and First Nations to remove the barriers and secure the investment required to establish up to three LNG plants by 2020. As of today, the province is aware of a handful of LNG proposals. Presently, the most advanced project is the Kitimat LNG terminal proposed by
Apache Corporation, EOG Resources, Inc. and Encana Corporation. This terminal is located on Haisla Nation territory. Kitimat LNG and the connecting Pacific Trail Pipeline have received the required environmental approvals. The province continues to work with other levels of government and the project’s proponents to ensure it becomes operational. Once completed, the Pacific Trail Pipeline will connect natural gas from the Western Canadian Sedimentary Basin to the Kitimat LNG facility. Natural gas liquefied at the Kitimat LNG plant would be transported by vessels to markets primarily located in the Asia Pacific region. T hese t wo projec ts a re eac h expected to create approximately 1,500 person-years of work during construction. The export terminal will create 120–140 permanent positions once it is in operation. In addition to these jobs, a successful LNG export operation would keep exploration and production activities at a high level across northeastern British Columbia and keep service sector workers in demand for decades, the province said in a news release. The fourth step is international marketing and trade development. Clark stressed that LNG will be an important focus of her upcoming trade missions to Asia. The goal is to begin the discussions needed to open up markets for B.C. LNG exports. A dec i sion i s pendi ng f rom t he Nat iona l Energ y Boa rd ( N E B) on a 20-year licence for the K itimat LNG pla nt to e x p or t L NG fol low i ng a n oral hearing during t he summer. If approved, it would be Canada’s first export licence for LNG. The NEB is also currently considering an export licence application for t he smaller Douglas Channel B.C. LNG Export Co-operative LLC project.
The B.C. government is creating plans to export surplus gas overseas.
As part of its jobs plan strategy, the B.C. government will take four steps to help create a prosperous liquefied natural gas (LNG) industry and jobs in the province. The four-step plan includes a greater emphasis on the permitting and decision making processes, skills training and development, investment attraction, and international marketing. P r e m ie r C h r i s t y C l a rk s t r e s s e d the first step will be to accelerate the le ng t hy p e r m it t i ng pr o c e s s e s a nd improve the decision making required to bring large-scale production facilities from concept to reality, and that these commitments will be a greater priority for British Columbia on a goforward basis. The province will also continue to st reng t hen collaborat ion w it h First Nations, local communities, industry partners and other levels of government BRITISH COLUMBIA WELL ACTIVITY
SEP/10
SEP/11
WELL LICENCES
69
79
▲
▲
▲
Source: Daily Oil Bulletin
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British Columbia
New water use laws coming Counting on sharply higher water usage in t he prov ince’s nor t heast, Br it ish Columbia’s government is re-tooling its legislation for licensing water, an industry audience in Calgary heard in September. Responsibility for licensing water is currently split between the provincial government and the province’s Oil & Gas Commission (OGC), said a hydrologist working for the commission. “ T he B.C . gove r n me nt i s working on a new water act,” said A llan Chapman. “It would probably be in place within the next five years and include a number of changes, including the licensing of groundwater.” Unlike Alberta, British Columbia does not yet license the use of groundwater. In
changing metrics of horizontal wells are, Chapman said. “One thing we’re seeing is that...laterals are becoming longer, and generally, water use per well has been rising.” At the same time, the province has only a few large sources of water, including surface water and groundwater at various depths. The absence of a provision for licensing groundwater in British Columbia makes the province a bit of an anomaly in Canada, he told the Shale Gas Water Management conference organized by Canadian Business Conferences. “It makes B.C. the only province in Canada—probably the only jurisdiction in North America—that currently doesn’t license groundwater,” he said. When British Columbia’s Water Act is compared
about 10 long-term water licences in use by industr y w it h about anot her 12 in t he applicat ion stage. Ot hers addressing t he con ference said t he province’s application process for longterm—which some have called “permanent”—approvals is more rigorous. “I think there’s much more regulatory robustness in the application process in applying for a longer-term use of water,” said Shad Watts, Nexen’s director of shale gas, who also addressed the conference. “The bar is much higher in terms of what you have to do to get that application. It requires a more sustainable approach.” Watts estimated that applying for a long-ter m water l icence i nvolves roughly a one-year timeline, compared to as little as one month for short-term
“It makes B.C. the only province in Canada—probably the only jurisdiction in North America—that currently doesn’t license groundwater.” — Allan Chapman, hydrologist
the next few years, though, demand for surface and groundwater is expected to rise as shale gas deposits in the Montney Formation and the Horn River Basin are further developed. By far, hydraulic fracturing of horizontal wells represents the largest use of water in British Columbia’s oil and gas operations, Chapman said, with most of it occurring in northeastern British Columbia. Before t he advent of f ract ur ing, the B.C. oil and gas sector’s usage of water was “pretty small,” he said. In a short period, that has changed. In the Montney, for example, he estimated hor i zont a l we l l s now u se 10,0 0 0 – 30,000 cubic metres per well, while Hor n R iver Ba si n wel l s a re t a k i ng 25,000–70,000 cubic metres per well. A mon g t he c omp a n ie s ad v a nc ing shale gas development in northeastern British Columbia are Nexen Inc., Encana Corporation and Apache Canada Ltd. If their ambitious plans were not a sign of things to come, the 28
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to Alberta’s similarly named statute, it becomes clear there are other differences between the two water-licensing regimes. Division of responsibility is one such difference. Under the Water Act, British Columbia empowers the OGC to provide short-term water use approvals to industry. Longer-term water licences, however, are handled by the B.C. government. Industry uses the approvals provided by the OGC, Chapman said. In the last three years, he estimated water volumes represented by approvals were 60 – 80 million cubic metres annually, although the water used by British Columbia’s oil and gas industry was a much smaller amount, totalling bet ween t wo and f ive million cubic metres annually. Yet, with shale gas development in the Montney and the Horn River Basin expected to ramp up, those numbers will only grow. The OGC currently provides from 2 5 0 t o 3 0 0 s h o r t- t e r m w at e r- u s e approvals ever y year. There are only
approvals granted by the OGC. Under British Columbia’s current system, long-term water licences prescribe an allocation of water for the company receiving the licence. However, Nexen is proposing something different for future long-term applications. “Currently, you get an allocation for a volume, which is constant,” said Watts. “You may take that volume or less. What we’re proposing in our application is a variable volume that’s truly dependent on the actual river flow.” Under Nexen’s model, the allocat ion wou ld be predicated on a percentage of water f low from a river, for example, rather than a specific volume of water. A s for whet her or not t he B.C. gover nment is amenable to t he proposal, Watts was hopef ul. “We’re jumping through the regulatory hoops r ig ht now, but heads a re nodd i ng, and they have appetites for the model we’re proposing.” — DAILY OIL BULLETIN
British Columbia
LNG plant essential for Horn River A liquefied natural gas (LNG) plant could help boost future activity at the Horn River Basin, but with a facility still four years away from being operational, the play will continue to face challenges given the weak outlook for natural gas prices. Prices a few years ago averaged around $6.50, but have since dropped to average closer to $4 or less. “What I try to tell folks up in the Northern Rockies Regional Municipality is this: a lot of the activity we’re still seeing was borne out of the $6.50 gas world, so you make plans on gas plants and infrastructure and drilling based on the price at the time,” Rob Spitzer, vice-president, Canada exploration with Apache Canada Ltd. and chair of the Horn River Basin Producers Group, told the Insight Information Northeast B.C. Natural Gas Summit. “That activity won’t just stop, but it will start to decline. That’s what you’re seeing here. There are some economic concerns associated with the lower gas price in the Horn. That’s not trivial. I
don’t want to be alarmist about it, but it’s not trivial.” The disconnect between oil and gas prices, currently at over 20 times, exacerbates the situation, he said. “Not only are you getting less for your product, your cost of service is not going down,” Spitzer added. “Historically... when gas prices go down, your service costs go down. There may be a six-month lag, but they do go down. “But because this horizontal drilling and multistage fracking technology is applicable also to oil reservoirs, you’re not seeing t he price of completions going down.” The dry Horn River gas and its distance from key markets have made it difficult to compete because producers are favouring liquids-rich gas and oil due to the high gas/oil price spread. The light at the end of the tunnel could be the Kitimat LNG plant, which would see the gas exported to Asian markets where prices are higher, and possibly lead to increased activity in the Horn
River. A facility planned by Apache, EOG Resources, Inc. and Encana Corporation awaits a decision on an export licence from the National Energy Board. “ But t h at L NG i s n’t h app e n i n g tomorrow or the next day; it’s going to take a minimum of three years to get the first part off the ground,” Spitzer said. “The question is, what happens in the next two or three years when gas prices are projected to be reasonably low and there is no LNG solution? That is an issue.” Land sales in the Horn River Basin have trailed off significantly, noted Christopher Adams, an oil and gas specialist with the B.C. Ministry of Energy and Mines. “Much of the land has been tenured,” he noted. “For example, in the Horn River, over 75 per cent is tenured now.” After the Horn River play area generated a high of roughly $1.1 billion in land sales in 2008, revenue dropped greatly to $316 million in 2009 and $131 million in 2010. — DAILY OIL BULLETIN
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Lone Pine grows Evi oil play
Lone Pine will be focused on drilling 13 more horizontal wells early this winter before year-end.
Lone Pine Resources Inc. expects thirdquarter average net sales volumes to range from 97 to 100 million cubic feet equivalent per day (105 to 108 million cubic feet equivalent per day working interest), which represents a four per cent increase over levels achieved in the second quarter of 2011 and includes an increase in net liquids weighting from 19 per cent in the second quarter to 22 per cent in the third quarter. The company remains on track to meet its previously announced second half of 2011 net sales volumes guidance of 98–102 million cubic feet equivalent per day (108–112 million cubic feet equivalent per day working interest). Based on field estimates, Lone Pine estimates its current net sales volumes to be 100 million cubic feet equivalent per day (109 million cubic feet per day working interest).
Based on successful Crown land sale purchases at Evi in the third quarter of 2011, Lone Pine has increased its previously announced 2011 exploration and development capital budget to US$237 million –$247 million, which includes the spending of US$130 million– $140 million in the second half of 2011. In an update to third-quarter activity, Lone Pine has drilled 12 horizontal wells to date at its Evi light oil play in the Peace River Arch with a 100 per cent success rate, and completed and brought on stream seven horizontal wells. The company remains encouraged by the initial production rates of the new Evi wells brought on stream as the average initial peak production rates continue to exceed 300 barrels per day. Lone Pine is currently completing six wells and plans to run two rigs to drill an additional 13 horizontal wells prior to year-end.
In the third quarter of 2011, Lone Pine increased its Evi land position by 32 per cent to 65,440 (57,222 net) acres through purchases at Crown land sales. The acquired acreage represents a significant addition to Lone Pine’s existing contiguous land holdings in the Evi field and will extend the company’s future light oil drilling inventory. Meanwhile, to date in the third quarter, Lone Pine has drilled one vertical well, completed three (2.5 net) vertical wells and brought on stream two (1.5 net) vertical wells in the Nikanassin resource play in the Narraway/Ojay area of the Deep Basin. Lone Pine continues to focus its development activities on de-risking its large land base to validate its Deep Basin model. The average performance of the new vertical wells exceeds the program type curve, with an initial 30-day production average rate of 6.2 million cubic feet per day. At Pointed Mountain in the Liard Basin shale play, the company has initiated its first high-impact exploratory test well in the third quarter. The company expects to see preliminar y results from this vertical re-entry of an existing wellbore in the fourth quarter. Lone Pine’s lenders have completed the semi-annual review of the company’s borrowing base available under its fiveyear, syndicated credit facility. The borrowing base has been increased from the previously available $350 million to $425 million. Lone Pine said the increase reflects the successful drilling program the company has completed in the first half of 2011 and the continued advancement of its Evi light oil play. The next scheduled borrowing base review will be completed in the spring of 2012. — DAILY OIL BULLETIN
NORTHWESTERN ALBERTA/FOOTHILLS WELL ACTIVITY
SEP/10
SEP/11
WELL LICENCES
273
294
▲
SEP/10
SEP/11
WELLS SPUDDED
159
290
▲
SEP/10
SEP/11
WELLS DRILLED
177
257
▲
Source: Daily Oil Bulletin
O I L & G A S I N Q U I R E R • N o v e m be r 2 0 1 1
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During its fiscal third quarter, Yoho Resources Inc. continued to move forward with three unconventional resource projects that the company is developing. Yoho’s board has approved the fiscal 2012 capital budget, which has been set at $35 million–$40 million and includes the drilling of six horizontal Duvernay wells at Kaybob, five horizontal Montney wells at Umbach and the construction of a Yohooperated 25-million-cubic-feet-per-day compressor station at Umbach, B.C. Production for fiscal 2012 is budgeted to average between 3,200 and 3,300 barrels of oil equivalent per day with exit production of between 3,700 and 3,800 barrels per day. The company expects to fund the fiscal 2012 capital program with a combination of cash flow and Yoho’s credit facilities. Production for the three months ended June 30 was 2,500 barrels of oil equivalent per day, up from 2,270 over the same period in 2010. Production for the quarter was impacted by the turnaround at the McMahon gas plant in British Columbia, and forest fires and extensive flooding in the Kaybob area of Alberta. The first two successful Duvernay horizontal wells at Kaybob were placed on production during the fiscal third quarter. The high level of associated liquids production from these wells contributed to a $20.16-per-barrel operating netback for the quarter, a 15 per cent increase from $17.56 per barrel in the second quarter of 2011. In particular, the natural gas liquids (NGL) content of both wells exceeds the original expectations for liquid-to-gas ratios, with condensate and pentanes comprising approximately 61 per cent of the NGLs. Yoho currently has working interests in 50.5 (17.7 net) sections of land with Duvernay rights in the Kaybob area along this liquids-rich trend. Near-term development plans include drilling six wells, with ultimate development spacing expected to be six to eight wells per section. During the quarter, Yoho completed its first horizontal well to test the Montney formation at Umbach. The a-A41-A/94H-4 well was flowed (on test) up casing at 6.3 million cubic a day with 30 barrels of liquids per million cubic feet. — DAILY OIL BULLETIN
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Cumulative effects monitoring coming By Lynda Harrison
SEP/10
SEP/11
SEP/10
SEP/11
WELLS SPUDDED
56
96
WELLS DRILLED
69
101
Photo: Joey Podlubny
holders are living within their approvals, said Renner. “The amount of ambient monitoring that we have done has been somewhat hit and miss. We’ve been doing it and there has been a good attempt at finding out what is the ambient collective impact, but we are now going to enter into a stage where we’re spending a significant amount of government resources and, frankly, to a large extent industry resources, to focus on what is the collective impact of all this development on our environment. Because we cannot talk about being sustainable developers of resources unless we can demonstrate that that is true and that is the case.” Renner said he believes his government is entering an exciting phase of reinventing itself as regulators “and frankly, industry [is] reinventing itself as being verifiable, sustainable developers of our resources.” During Renner’s leadership, a new reclamation strategy for oilsands projects was
introduced. It includes an updated reclamation certification process, public reporting on reclamation performance, a new mine reclamation financial security program and a new tailings management framework. The new policy targets oilsands projects, but applies to coal mines and any future mines in the province, he told the conference. Companies will have to commit every year to progressive reclamation and then meet those commitments, and their results will be made public through an online portal. The previous public reporting process was f lawed because it had only three reclamation milestones, he said. It reported the amount of land disturbed, reclaimed and certified, whereas the new system has eight milestones to bet ter ref lect t he ongoing process, said Renner. “I don’t have to remind you, there is a lot of work that goes on between all of those.” T he new cer tif ication process is designed to provide clarity about the roles of each government department, the certificate application and field inquiries, and the criteria and indicators of reclamation success. Implementation began last year and is to be completely operational by 2012. Glenn Scott, senior vice-president, resources division of Imperial Oil Limited and president of Imperial Oil Resources, said his company’s long-term reclamation and mine closure plans are continually being updated and approved by regulators as it seeks to apply new research and technology to its reclamation activities at its Kearl mine site, set to begin production in late 2012. Given the evolving nature of technology and reclamation, Imperial is supportive of the Alberta government’s proposal for progressive certification, said Scott. “It is logical, not just for the Kearl project, but for the industry, to be able
Oilsands operators will soon be facing overall limits on their regional footprint.
A significant amount of government and industry resources are going to be spent on monitoring and managing the cumulative effects of Alberta’s oilsands projects in the next few years, the province’s minister of environment told a mining crowd in late September. Minister Rob Renner told the Sixth International Conference On Mine Closure his ministry is working on the legislation that he hopes will be enacted “in the very near future.” The government will become much more focused on outcomes and that entails putting “overall air limits” throughout the region, he said. “We’ll still expect the same degree of regulation on individual approval owners, but we’ll also be watching from an overall ambient perspective what is the outcome of that.” Monitoring up to now has been largely based on ensuring that various approval NORTHEASTERN ALBERTA WELL ACTIVITY
SEP/10
SEP/11
WELL LICENCES
57
100
▲
▲
▲
Source: Daily Oil Bulletin
O I L & G A S I N Q U I R E R • N o v e m be r 2 0 1 1
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to coordinate certification testing with the various stages of reclamation. As part of Kearl’s long-term vision for reclamation success, we are currently removing, segregating and storing soils from this site so that we can use them as soon as an area becomes available for reclamation.” Imperial has full-time soil monitors on site to ensure the job is done properly, he said. Since project construction began in 2008, enough topsoil and subsoil have
trees that didn’t provide a diverse habitat and were highly susceptible to pests. Our plan includes planting a variety of native species... to better mimic the natural environment and ensure the success of reclamation.” Native species are not widely available commercially, so Imperial has teamed up with local First Nations contractors to start collecting tree and shrub seeds now to ensure it will have sufficient stock available for reclamation. The seeds will be stored
“ We are excited to see natural vegetation, such as raspberry plants, gooseberry and sweet-scented bedstraw returning to our reclaimed areas.” — Glenn Scott, senior vice-president, resources division, Imperial Oil Limited
been removed to fill more than 4,500 Olympic-sized swimming pools (over 13 million cubic metres). In addition, more than 70,000 tonnes of timber have been salvaged to date. “That’s enough to sustain a local pulp mill for approximately two months of production, equal to about 5,000 kilometres of lumber board.” A nother “reclamation currency ” Imperial is “banking” is native seeds, said Scott. “In the past, operators have reclaimed lands with a monoculture of white spruce
until shortly before they are needed, and then they will be sent to a local nursery to be grown into seedlings for planting. Imperial has already begun reclamation, albeit in a small way, he said. The company’s first shrubs grown at the local nursery were planted on the Kearl lease in 2010. Subsequent planting of approximately 22,000 tree and shrub seedlings took place in 2011 at its compensation lake. Six species of trees and 11 species of shrubs were planted.
Planning is also well underway for continued reclamation of the shoreline of a man-made compensation lake on site, as well as revegetation at the River Water Intake site, said Scott. These are two of the first sites to become available for reclamation at Kearl. “We are excited to see natural vegetation, such as raspberry plants, gooseb e r r y a nd s weet- sce nted b ed st r aw returning to our reclaimed areas.” Land will continue to be reclaimed as it becomes available over the entire life of the operation. In the process of mining, Imperial will remove fish habitat in the upper reaches of the Muskeg River, a tributary of the Athabasca River. The federal government requires the company to compensate for this fish h abitat at a two-to-one ratio, so it is replacing double the habitat it will disturb during mining. Imperial has worked with local First Nations people in the region to design and build a fish habitat compensation lake adjacent to the existing Kearl Lake. Once the compensation lake is full, the company will stock the lake with native fish species, based on consultation with local communities. Imperial will ultimately build three lakes that are interconnected.
Oilsands may make Canada energy superpower, says Deloitte Canada has an opportunity to become a world leader in responsible and sustainable hydrocarbon resource development along with technology advances, but first it must obtain access to new markets, says a new report on the oilsands by Deloitte. “Perhaps no other jurisdiction in the world with this magnitude of resource potential has anywhere near Canada’s combi nat ion of pol it ic a l st abi l it y, advanced education, technical prowess and transparency in business dealings,” says the global consulting firm in Gaining Ground in the Sands 2012. “Canada is poised to do for global hydrocarbon-based energy development what Germany has done for the renewable energy R&D [research and development] and manufacturing sectors—lead not only by the numbers but, most especially, by
the example of vision and political will,” says Deloitte. However, “at the end of the day, to have a cohesive strategy, you need a visionary national energy strategy,” Chris Lee, leader of Deloitte Canada’s national energy and resources practice, said in an interview. That will take industry to keep on pushing like it has and government to listen and to be able to get all the various interest groups together into one vision, he said. While Lee acknowledged that isn’t easy, in recent months there has been growing interest in such a strategy from industry and from governments such as at the federal, provincial and territorial ministers’ meeting in July at Kananaskis, Alta. “The dialogue needs to continue, but it can’t be one of those things where there’s
a whole bunch of dialogue and then it gets shelved a year from now.” Lee, though, is optimistic that the combination of a majority government in Ottawa and the increasing importance of the oilsands in the Canadian economy may help to propel to the next level a policy that would deal with issues such as access to markets and renewable resources. A national energy strategy could also play a role in helping to address critical medium-term issues such as transportation infrastructure, said Lee. “Unless greater access to existing and new markets becomes available over the next five to 10 years, the reality is that much of our growth potential will be shut in along with the bitumen itself,” said the report. T he election of a major it y Conservative government earlier this O I L & G A S I N Q U I R E R • N o v e m be r 2 0 1 1
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Northeastern Alberta
“ The urgent, urgent issue is labour. It’s not just the oilsands shortage, but what happens if oilsands carbonates are proven economic or more oilsands upgraders are built, all of which will require more skilled workers.“ — Chris Lee, leader, Deloitte Canada’s national energy and resources practice
year, though, presents an opportunity to encourage pipeline construction in particular that could set the stage for expanded markets across the value chain, the report suggests. As with the case in Germany, technology is the first and critical means to help realize the full potential of Alberta’s energy resources so that money produced from non-renewable energy assets can
be invested in emerging technologies, products and services. “Because it is the major economic driver in Canada today— [marking] a long shift away from the traditional base in auto manufacturing—the oilsands industry is front and centre in terms of influence and long-term energyrelated social policy,” says the report. “The oilsands sector should be looking to parlay its technology development
into a number of enduring values, starting with the technology itself as homegrown intellectual property of potential application and value elsewhere in the world, and also as instrumental in helping to mitigate and/or eliminate ongoing concerns about health and environmental impacts,” it says. “The prize isn’t simply technology itself, but in ensuring we don’t lose the opportunity to develop important secondar y industries and market potential.” Next-generation advances in oilsands technology have the potential to produce more bitumen with less effort, energy and impact, says the report. Some of that technology may also be deployed for use in other resource plays, it notes. A step change this year in tailings consolidation could open the door for further innovations, resulting in significantly smaller and fewer tailings ponds for mining operations as well as less water use overall, it says. Tailings pond reclamation cycles have been sped up through better management of mature fine tailings, and this has provided a faster turnaround for recycling water. The Oil Sands Tailings
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N OV E m be r 2 0 1 1 • O I L & G A S I N Q U I R E R
Northeastern Alberta
Consortium is making good strides in this area, according to the report. Other emerging technologies include the use of solvent-cyclic steam assisted gravity drainage, which could unlock the massive deposits of bitumen in carbonate rocks, and electromagnetic production of bitumen through the electromagnetic stimulation of reservoirs too shallow for steam assisted gravity drainage but too deep for mining. Under the right conditions, the technology is also considered a potential standalone process for mobilizing and even partially upgrading bitumen, eliminating the need for both water and fuel gas. Another new technology is in situ upgrading, in which bitumen is partially upgraded through combustion processes that leave unwanted byproducts underground while capturing carbon, could potentially reduce water use and fuel gas consumption for steam generation by up to 80 per cent while increasing recovery factors by as much as 50 per cent, says the report. The industry needs to continue to engage with the public to continue to
earn its trust by demonstrating that it is investing in technologies to reduce the environmental impact of the oilsands, said Lee. “People are seeing meaningful inroads being made such as Directive 74 [which sets out regulations on oilsands tailings ponds],” he said. The Deloitte report also identifies issues that oilsands operators face in the short term such as the need for cost reductions and increased operational efficiencies, labour logistics and demographic transformation. While companies have been looking at outsourcing or partnering with third parties for housing, transportation or even steam generation, there also are opportunities for collaboration in core areas of the operation, such as safety training and the environment, where all companies must meet minimum standards but vary in approach and procedures, it says. For example, all companies currently have their own training program requirements and contractors are required to be certified for any site on which they will be working, said Lee. Operators could perhaps collaborate in
a program that would certify contractors for multiple company locations. The industry could also borrow contemporary manufacturing approaches to bring about process improvements, increasing efficiency and reducing costs, he said. For example, these are reducing cycle times to first oil or gas by 30–50 per cent, reducing overall operational costs (including fabrication and construction) by 15–20 per cent and eliminating nonproductive activity (recruiting, training, housing and moving people) by more than 50 per cent, according to Deloitte. “The urgent, urgent issue is labour,” said Lee. “It’s not just the oilsands shortage, but what happens if oilsands carbonates are proven economic or more oilsands upgraders are built, all of which will require more skilled workers. Deloitte sees more opportunities to improve the effectiveness of the people supply chain,” he said. “Attracting and retaining talent is key, but it’s also finding ways to leverage technology and processes to actually reduce the number of people you need.” — DAILY OIL BULLETIN
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Northeastern Alberta
Shell’s applications for two more oilsands mines move forward The Canadian Environmental Assessment Agency and the Alberta Energy Resources Conservation Board have agreed to the final terms of reference for Shell Canada Limited’s Jackpine Mine Expansion application. The environmental impact assessment (EIA) for the regulatory applications for the Pierre River Mine and an expansion
aspects of the projects will be reviewed. These two applications are supported by one EIA covering both projects. Shell Canada filed the regulatory applications for both projects in 2007. “We chose to file applications for both mines together following feedback from stakeholders that they would like to see
Obtaining regulator y approval is one of the many steps in front-end project development and a prerequisite prior to taking any investment decision, he added. Expected output from the proposed Pierre River Mine, about 90 kilometres north of Fort McMurray on the west side
“ The single environmental impact assessment covering both projects was intended to provide the broadest, most comprehensive and conservative assessment of Shell’s mineable oilsands development plans.” — Stephen Doolan, spokesman, Shell
to the existing Jackpine Mine is deemed complete and has been referred to a threemember joint review panel. Shell awaits approval of its draft terms of reference for the Pierre River Mine. Following that, the panel will review the applications and later announce a notice of public hearing in which all
Shell’s entire development plan versus frequent, smaller applications,” said Stephen Doolan, Shell spokesman. “The single environmental impact assessment covering both projects was intended to provide the broadest, most comprehensive and conservative assessment of Shell’s mineable oilsands development plans.”
of the Athabasca River, is 200,000 barrels per day. The proposed development includes an open-pit mine, ore handling facility, bitumen extraction facilities, tailings processing facilities, support infrastructure, water and tailings management plans, as well as the construction of a bridge across the Athabasca River.
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Northeastern Alberta
— DAILY OIL BULLETIN
Photo: Joey Podlubny
Anticipated volumes from the Jackpine Mine expansion are 100,000 barrels per day. Current production capacity at the existing Jackpine Mine, which started in late 2010, is 100,000 barrels per day. The expansion would include additional mining areas and associated processing facilities, utilities and infrastructure. The project would be located about 70 kilometres north of Fort McMurray, on the east side of the Athabasca River. In its applications, Shell stated it expects expansion of Jackpine Mine to begin in 2017, and Pierre River Mine in 2018. However, the ultimate timing and development of the projects will depend on a number of factors, including the outcome of the regulatory process, market conditions, final project costs and economics, and consultation with key stakeholders, said Amie Barnes, a Shell spokeswoman. Barnes said it’s too early to say how much the projects will cost, when construction might begin and how many people they might employ. Shell’s mined oilsands output for the second quarter of 2011 was about 205,000 barrels per day.
Shell has filed applications for two oilsands mining expansions.
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Penn West eyes cost efficiencies By Elsie Ross
SEP/10
SEP/11
SEP/10
SEP/11
WELLS SPUDDED
212
350
WELLS DRILLED
213
340
Photo: Aaron Parker
said Foulkes. “We’re all hearing about pre s su re i n t he se r v ice i ndu st r y — labour pressures, labour costs —and there are some ways that you can mitigate those costs that we have already undertaken.” Penn West has been looking at the issue for two years now and finally is in a position to illustrate the value of that kind of procurement and purchasing power associated w it h size and the level of activ it y the company is involved in, analysts heard. “If you are going from five rigs to 36 rigs, the iron that you are going to get when you are pushing into t hat 36 –37 rig count is going to start to get pretty cheap,” she said. “The crews that you get are going to be ver y green.” Working with a green crew, efficiencies go down as does the ability to actually
reduce the number of rig days, Foulkes suggested. “By keeping a sustained level of operation, running 20–25 rigs, we have the privilege of working with the best drilling companies, having the shiniest f leet out there, reducing our drilling costs and days, and actually getting our work done in a more efficient manner,” she said. I f c r ude oi l pr ices c l i mb to t he US$90- to US$95-WTI-per-barrel level, supplies such as sands and acids will be in fierce demand, and Penn West’s ability to secure that supply chain through planning and long-term contracts is in place, said Foulkes. “We are ahead of the game and have some long-term service contracts with the best drilling fleet in the industry.” The company also has reduced its providers of directional drilling tools from 15 companies to two companies. “And they are on speed dial, and they are committed and loyal.” While cost is one of the things that companies are most concerned about, for Penn West that concern has been less on t he rig and equipment side, and more on the labour side, she said. “People are short; you can get trucks, but you can’t get drivers.” “The ability to plan ahead, the abilit y to batch purchase, t he abilit y to sign long-term contracts because we have an inventory that’s going to drive us for years is all part and parcel of the plan,” said Foulkes. Developmentweighted ac t iv it y helps to m it igate some of t he uncer ta i nt ies, a na lysts heard. “When we are drilling 80 wells in the carbonate, we know how much sand we are going to need. We know how m a ny complet ion r ig s we a r e going to need, and we are planning and we have those secured.”
Drilling rig working near Drayton Valley. Good iron and experienced crews are key to cutting drilling costs in the area, says Penn West.
As it shifts its focus to development drilling in tight light oil plays, Penn West Exploration is working on ways to drive down costs and improve capital efficiencies, company executives told a recent meeting with analysts. “The drivers for us to actually get t hose capital ef f iciencies dow n are very simple: cost and efficiencies,” said Hilary Foulkes, executive vice-president and chief operating officer. Penn West will be running between 20 and 25 rigs—which it considers to be the right level of rig activit y—for the latter part of this year and into the early part of 2012, she said. Penn West is one of the most active drillers in western Canada and the top-ranked driller when it comes to service rigs. “ Si z e i s a big e le me nt w he n it comes to actually securing ser vices,” CENTRAL ALBERTA WELL ACTIVITY
SEP/10
SEP/11
WELL LICENCES
247
319
▲
▲
▲
Source: Daily Oil Bulletin
O I L & G A S I N Q U I R E R • N o v e m be r 2 0 1 1
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Central Alberta The lessons learned can reduce an operator’s drilling times and completion costs. Pad drilling in the Cardium, for example, saves nearly $2.5 million on average per pad for four-well pad drilling versus four individual wells. Cost savings and efficiencies come from the construction side, and from reduced rig days (rigging up, rigging down, mobilization and demobilization) and pad facilities. For the Penn West chief operating officer, “the beauty of this situation [development drilling] is that we can look at things with an eye to the two to three to four years out,” enabling the company to begin negotiations and plan for that eventuality, ensuring Penn West will have the capacity to move its products to market when needed. “Eventually, though, the technology will take many of these plays to the point where it will pinch the major
infrastructure in western Canada and, obviously, your relationship with midstreamers and your relationship with pipeliners,” said Murray Nunns, president and chief executive officer. “Those types of things are not going to be an issue today, but [will be] in the three- to five-year range, and you see that in North Dakota with the removal of Bakken oil.” However, in developing resource plays, the company knows where it expects the production to be in two or three years’ time, said Foulkes. “So we are in negotiations with Keyera Corp., with Plains Midstream Canada, with ATCO Pipelines...where in the next two or three years there may be a little bit of competition from a midstream perspective,” she said. “You look at the potential of the Duvernay and the kind of pressure that’s going to bring on the infrastructure in western Canada.”
In the appraisal stage, Penn West has been able to take advantage of existing infrastructure. “There’s no point putting in big infrastructure until you know what the results are going to be,” said Rob Wollmann, senior manager, geosciences. Some wells will be restricted until the company knows what it has and puts in the main trunkline. Now that the company is past the appraisal phase, “we are willing to take greater risks on our facilities buildout, so where we need a group line that joins a whole series of wells, we will prebuild those now rather than wait for results. That tends to allow you to compress your timelines a lot more,” said Nunns. In the Otter Slave Point carbonate play, for example, Penn West has one existing trunkline and is building a second one in anticipation of future production.
Photo: Joey Podlubny
Beaverhill Lake light oil wells work for Second Wave
With wells producing at initial rates as high as 2,000 barrels per day, the Beaverhill Lake play is proving to be a company maker for Second Wave.
S e c on d Wa v e P e t r ole u m I n c . h a s reported continued drilling success in its Judy Creek core area after drilling its first seven Beaverhill Lake horizontal light oil wells, yielding results that meet or exceed the company’s expectations. Five out of the first six wells tested have achieved average gross production rates that are on pace to exceed 700 barrels of oil equivalent per day (90 per cent oil) over the first 30-day production period 44
n o v e m be r 2 0 1 1 • O I L & G A S I N Q U I R E R
versus the company’s internal 30-day initial rate-type curve of 295 barrels per day (90 per cent oil). Four out of the initial five joint venture earning wells have tested with initial f lowback rates exceeding 950 barrels per day (85 per cent oil) over test periods of between eight and 20 days. The 40 per cent working interest 102 /01- 05 - 06 4 - 09W5 a nd 10 0/0 4 06-064-09W5 wells were tested over
a 15-day period at gross rates of 1,200 barrels per day and 2,000 barrels per day (both 85 per cent oil), respectively. Six out of the seven wells drilled were earning wells under the company’s prev iously announced joint venture agreement with Crescent Point Energy Corp. Under the terms of the agreement, Second Wave paid 15 per cent of the drilling and completion costs to retain a 40 per cent working interest in each earning well and its associated earning land block of 3,840 acres. To date, five of the six earning wells have been completed, tested and placed on production. The sixth earning well, at 100/12-16063-09W5, is currently standing awaiting completion. Second Wave’s first development well (40 per cent work ing interest) w it h i n it s joi nt vent u re la nds wa s drilled at 100/04-06-064-09W5, offsetting its previously announced 100/1536-063-10W5 well (40 per cent working interest). The 15-36 well tested at rates of 1,825 barrels per day (86 per cent oil) over its initial 15-day f lowback period and has produced approximately 64,000 barrels (88 per cent oil) over its first five months of production. After 140 days of
Central Alberta production, the well is currently producing at a restricted rate of 260 barrels per day (90 per cent oil). Results f rom the 04 - 06 development well have exceeded Second Wave’s expectations w ith an initial 15-day f lowback rate of 2,000 barrels per day (85 per cent oil). The well has to date produced at rates comparable to the 15-36 location and reinforces the company’s belief in the repeatability of the Beaverhill Lake drilling program on its Judy Creek land block. Under the Beaverhill Lake joint venture agreement, Second Wave incurs its proportionate 40 per cent working interest share on all capital expended on development locations on previously earned joint venture lands in order to retain its interest in such locations. Production f rom t he Judy Creek Beaverhill Lake wells will be restricted to t he i r m a x i mu m r ate l i m it at ion (MR L) of approximately 260 barrels per day after the expiry of their new oil well production period of four months. The MR L restrictions on these wells will remain in effect until the Energy Resources Conservation Board approves g o o d pr o duc t ion pr ac t ic e f or t he Beaverhill Lake formation on Second Wave’s lands. The company anticipates that these limitations could be partially removed in early 2012 upon approval of a waterf lood in the Beaverhill Lake formation. Second Wave currently operates a waterflood in its Judy Creek Pekisko oil pool and has built infrastructure that would accommodate a waterflood in the Beaverhill Lake. Second Wave estimates that successful drilling activities have so far delineated approximately 30 (12 net) sections of Beaverhill Lake mineral rights at Judy Creek, representing an unrisked drill-ready inventory of 120 (48 net) drilling locations on the basis of four wells per section. The company currently has three drilling rigs active in Judy Creek focused on Beaverhill Lake drilling locations. Two (1.4 net) horizontal wells are standing and waiting on completion and three (1.2 net) additional joint venture horizontal wells are in different stages of the drilling process on its joint venture lands. One of the three joint venture wells drilling is a development well. — DAILY OIL BULLETIN
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Central Alberta
PetroBakken focused on Cardium technology Experimentation and innovation are continuing as producers look for the most cost-effective ways to optimize well performance in western Canada’s tight oil plays. Dur ing a presentat ion to an Infocast shale oil conference, Rene L a P r ade, sen ior v ice -pre sident of operations at PetroBakken Energy Ltd., discussed innovation and challenges at a key tight oil play—the Cardium of west-central Alberta. As in many tight oil plays, producers in the Cardium have experimented with more than one completion fluid, and continue to do so. PetroBakken is sy nony mous with tight oil. Through a predecessor company, it launched Canada’s original tight oil play in the Bakken formation of southeastern Saskatchewan, where it has drilled hundreds of horizontal wells. In early 2010, the company decided to leverage its experience in the Cardium,
c ompletion fluid, PetroBakken saved up to $600,000 a well, LaPrade said. Oil production rates were also higher. But the downside is the volume of water required—up to 18,000 barrels per well. Apart from finding water sources, the logistics of handling that much water can be a challenge for a company trying to fracture up to 16 wells a month. On the positive side, frac fluid recovery rates are as high as 50 per cent. “So we were seeing fairly good water recoveries and some higher additional production rates,” said LaPrade. PetroBakken is still experimenting with its Cardium completions. Earlier this year, the company reported lower water cuts and higher initial oil rates in an area of the Bakken by fracking with Cleantech, a low-viscosity fluid. Now it has also tried the new frac fluid in the Cardium. “We’ve been able to have carrying capacity of up to 600 kilograms per cubic metre with Cleantech,” LaPrade said.
64 (48.5 net) by early August of this year. It currently has about six rigs working in the light oil play. At year-end 2010, PetroBakken booked 43 million barrels of Cardium reserves. LaPrade said the company is seeing some strong well results at West Pembina, but the East Pembina results aren’t as good. Discussing the challenges of the play, L a P rade sa id wet spr i ng a nd summer weather has constrained activity there as in several other locations in Alberta and Saskatchewan. “What’s critical to an operation like ours—where you’re running a lot of rigs and a lot of equipment—is continuous field operations,” he said. “It’s critical if we’re going to keep our cost and capital efficiencies in line.” The pace of industry activity remains a challenge for operators trying to secure equipment and services. Along with high well counts in the Cardium, drilling is also ramping up in formations such as
The company has increased the number of frac stages in the horizontal section of its Cardium wells to 30 from 20. It is also experimenting with bigger sand particles so the proppant will maintain bigger paths to the wellbore.
where development is a few years behind the Bakken. Well costs were higher in the Cardium than the Bakken, partly because producers had less experience in the Cardium, but also because in early 2009, gelled oil was the frac f luid of choice in the Cardium. One reason Ba k ken wells were cheaper is they could be fracked with water. Oil-based fracs reduced formation damage, but the big downside was the cost. “It was costing us about $1 million a well in frac fluid,” said LaPrade. Like a number of other Cardium producers, PetroBakken initially experimented with several frac-fluid systems. In late 2010, the company started using a slick water system w ith nitrogen. Using this system instead of an oil-based 46
N OV E m be r 2 0 1 1 • O I L & G A S I N Q U I R E R
O t he r c h a nge s Pet r oB a k ke n i s e xperimenting with in the Cardium include trying to reduce the amount of nitrogen and water used, using clay s tabilizers, testing hybrid frac-f luid s ystems (combining slick water and gelled water to maximize placement) and testing foam water systems. T he company has increased the number of frac stages in the horizontal section of its Cardium wells to 30 from 20. It is also experimenting with bigger sand particles so the proppant will maintain bigger paths to the wellbore. PetroBakken’s Cardium production rose to 12,000 barrels of oil equivalent a day in early August from 7,335 barrels a day last December and none in December 2009, LaPrade said. The company drilled 75 (55 net) wells in the play last year and
the Duvernay and the Swan Hills, which means, for example, that pressure- pumping equipment is at a premium. And even when the hardware is available, often there are no trained workers to run it. “Obv iously, w it h all t his comes increased service costs. It’s going to be difficult this year, but I think if we continue to find some innovative ways to do it, we can at least keep costs flat,” LaPrade said. Another challenge is lack of infrastructure. Although the original highpermeability Pembina field has a large concentration of old vertical wells, the low-permeability “halo,” or fringe area, where PetroBakken is operating, has very few pipelines and batteries in place. “So PetroBakken is constantly building infrastructure,” LaPrade said. — DAILY OIL BULLETIN
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Southern Alberta
Alberta land sale revenue passes $3 billion By Richard Macedo
SEP/10
SEP/11
SEP/10
SEP/11
WELLS SPUDDED
187
138
WELLS DRILLED
184
128
Photo: Joey Podlubny
Standard Land Company Inc. successfully submitted the land sale bonus high bid of $54.85 million for a 6,016-hectare licence. The broker picked up several sections at 39-08W5, 40-08W5, 39-09W5 and 40-09W5 at an average of $9,118 per hectare. “For the parcels west of Red Deer, there are a variety of deep rights posted, including some posted below Mississippian reservoirs [Turner Valley and Shunda], indicating an interest in Devonian rocks,” said Brad Hayes, president of Petrel Robertson Consulting Ltd. “The Duvernay is a likely target, as we are in the southwestern corner of the West Shale Basin where the Duvernay was deposited.” However, these lands are also close to the updip margin of the southern Swan Hills Platform, which hosts the giant Caroline field, and some explorers may also be looking at low permeability carbonates in the Swan Hills formation, he added.
Stomp Energy Ltd. produced the land sale per-hectare high of $10,106 for a 4,608-hectare licence. The company paid a total bonus of $46.57 million and acquired the rights to several sections at 38-08W5. O & G Resource Group Ltd. picked up the other two high-bonus parcels in the area. One went for $42.69 million around 40-07W5, while the other was picked up for $37.62 million at 41-09W5. “In total, producers paid $185 million to acquire 92,040 acres of Duvernay land in the Greater Pembina area at Ferrier/ Strachan,” said Ryan Mooney, senior associate, oil and gas, with Macquarie Securities Group. That amounts to about $2,010 per acre, so he said that it’s in line with the $2,303 per acre paid for Duvernay rights in the Kaybob region at the August 24 Crown land sale. In northern A lberta, meanwhile, Edwards Land picked up a 4,736-hectare licence for $24.99 million at an average price of $5,276 per hectare. The broker acquired the rights to several sections at 91-12W5, 92-12W5 and 92-13W5. “At 91-12W5, the bidder will likely be chasing some sort of carbonate play not dissimilar to the Slave Point at Red Earth/ Otter,” Mooney added. “Obviously, Penn West [Exploration] and Pinecrest Energy Inc. have been very active in the surrounding area to the south of the big bid.” Several other parcels in the area were also acquired in the land sale, but for far less money. “For that entire area, though, only $35.1 million was paid for 101,846 acres, or $344 per acre,” Mooney said. “We are calling that the Sawn Lake area.” Regarding the high-bonus parcel at 91-12W5, Hayes said that these lands lie adjacent to the Peace River Arch, where there are numerous oil pools in Slave Point reefs lapping up against the Arch.
Land sales passed the $3-billion mark in September, thanks to interest in the Duvernay shale play.
For the second time in history, the Alberta government has surpassed the $3-billion mark in total land sale revenue in a calendar year after what appears to be more interest in the Duvernay helped to power September’s land sale, which added another $298.27 million to the provincial treasury. To date in 2011, the province has collected a total of $3.06 billion in bonus bids, the second highest in history with six sales left this year. A total of 3.46 million hectares have exchanged hands at an average price of $884.50 per hectare. Top spot all-time is held by the 2006 tally when the government attracted $3.4 billion thanks to heavy spending for oilsands acreage. In September, Alberta sold 210,642 hectares at an average of $1,416 per hectare. Most of the revenue was generated west of Red Deer in the area around Ferrier/Rocky Mountain House. In particular, four parcels in the region generated combined bids of $181.75 million. SOUTHERN ALBERTA WELL ACTIVITY
SEP/10
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WELL LICENCES
306
181
▼
▼
▼
Source: Daily Oil Bulletin
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Southern Alberta
Tough times to continue for gas producers A Conference Board of Canada report released in late September paints a bleak near- and mid-term picture for natural gas producers as strong supply and muted demand in the United States, increased costs due to ramp up of crude oil and oilsands activity, and continued low prices will weigh down the industry. “The natural gas extraction industry continues to undergo a period of transition. Alberta gas production is projected to fall indefinitely, and barring any unexpected situation that would cause prices to spike, profits are unlikely to return to pre-recession levels until beyond the medium term,” said Conference Board economist Todd Crawford, author of the report. The expected economic weakness in the United States will likely keep prices depressed for the rest of the year. The Conference Board expects the AECO price to continue to hover in its current range, averaging just $3.80 for 2011 as a whole. “Medium-term prospects for natural gas pricing are only slightly more optimistic,” Crawford said in the report. “The threat that more shale gas will flood the market, coupled with only moderate demand growth, means that prices will not surpass $6 per thousand cubic feet until 2015.” With the tempered outlook for prices, the Conference Board projects that drilling activity will remain well below prerecession peaks. “This is particularly true in Alberta, where operating costs tend to be higher because of competition from the oil industry,” the report said. “Production in Alberta is expected to decline severely over the next five years, pulling down total Canadian production.” Even though drilling activity in Alberta is projected to rise moderately over the next five years, the report said it will not be enough to offset the declines expected from existing gas connections in the province. As a result, total marketable production in Alberta will drop to 8.1 billion cubic feet per day by 2015, down 20 per cent from 2010 levels. Strong increases in British Columbia— largely due to shale gas production—and new offshore output from the Deep Panuke field offshore Nova Scotia will help slow the decline in Canadian production, but will not offset declines in Alberta. Other than in British Columbia, the report noted that shale gas remains in the early stages of development across Canada. 50
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Overall, Canadian production has fallen from 25 per cent of the North American total five years ago to less than 20 per cent at present. “After yet another weak drilling year in 2010 that drove total marketable production down 2.1 per cent, Canada currently accounts for just 19.3 per cent of North American production.... Activity in Alberta was particularly weak. For the first time since 1990, the total number of producing gas connections declined,” the report said. Industry representatives contacted by the Daily Oil Bulletin were not in full agreement with the Conference Board’s drilling activity sentiments. “Drilling activity is not weak in my view— all appropriate and available equipment is
trend to drilling liquids-rich gas targets is itself bringing on significant volumes of gas,” he said. The Conference Board said a “trend worth watching” over the medium term will be the rise of Canadian oilsands production as the industry relies heavily on natural gas to generate steam for thermal production, cogeneration and for hydrogen to upgrade bitumen. Natural gas use in this industry totalled 1.27 billion cubic feet per day in 2010 (about 15 per cent of demand), but that is forecast to rise to two billion cubic feet per day in 2015, and to three billion cubic feet per day by 2020. However, the report said that even with the expected increase in demand for natural gas in the oilsands and the probability that strong production gains from the United
Production in Alberta is expected to decline severely over the next five years. working or booked to work and new bigger triple-type rigs are being manufactured to better handle the deeper horizontal wells and lateral sections,” said Mark Salkeld, president of the Petroleum Services Association of Canada (PSAC). “The actual rig release count for 2011 slightly exceeded PSAC drilling activity forecasts three quarters in a row, and when our focus group meets in the very near future to discuss the PSAC annual forecast update for 2012, I am predicting a good degree of optimistic discussion for the upcoming year,” he added. “There is no doubt there’s been a shift toward oil versus natural gas, but gas drilling continues with a focus towards liquids-rich gas, of course.” Salkeld added that while drilling activity as defined by rig release may “remain below pre-recession peaks, one should look at the number of days per well to drill and complete—the overall depth and complexity, not to mention greatly improved initial production rates.” Gary Leach, executive director of the Small Explorers and Producers Association of Canada, said that while he “would agree that the industry is in a transition, to suggest gas production will fall indefinitely” is too pessimistic. “In fact, there are signs that western Canadian gas production is stabilizing. The
States will subside, demand growth will “almost certainly be insufficient” to generate large upward momentum for prices. “Unless North American producers can integrate their markets with regions of the world where demand is strong, the AECO price will rise to just $4.20 in 2012, increasing gradually to $6.14 in 2015,” the Conference Board said. The Conference Board said Canadian natural gas industry revenues are forecast to rise 2.8 per cent in 2011 to $34.7 billion as prices and production increased briefly in the first quarter, driving revenues strongly higher. And even though revenues are expected to trend lower for the rest of the year (as prices have already dropped), the report said that the early-year strength will be just enough for the industry’s revenues to narrowly escape a third consecutive year of contraction. But even though the AECO price is forecast to reach only $6.15 per thousand cubic feet by 2015, that is still considerably higher than where prices are today, and these higher prices will allow industry revenues to climb to $54.6 billion by 2015. Costs will surpass $34 billion this year. Drilling activity remains weak, but competition from the booming oil industry for equipment and materials is up, keeping material and capital costs elevated. The report said that the industry will also continue to add to its payrolls, with more than 500 new jobs
Southern Alberta expected in 2011. As well, wage growth will pick up speed over the next few years. Over the rest of the forecast, the Conference Board expects costs will rise further as total industry costs are forecast to reach $48.5 billion by 2015—four times what they were in 2000. Even though prices remain weak, profits will rise to $744 million this year—a big improvement from earnings of $616 million last year. But starting in 2012, prices will begin to rise again, and that will translate to the bottom line. According the report, revenue growth will outpace rising costs, allowing pre-tax profits to climb to $6.1 billion by 2015. Despite weak price signals and slower domestic demand growth, the report said that U.S. supply continues to rise over the forecast period to 2015. Excluding Alaska and the Gulf of Mexico, U.S. supply of natural gas was up 10 per cent year-over-year in the second quarter of 2011. The Conference Board said this strength will be enough to push total marketable production in the United States up to an average of 61.8 billion cubic feet per day in 2011. “This year will mark the sixth consecutive annual increase in U.S. gas production, which will reach a level 25 per cent higher than its most recent trough in 2005,” the report said. However, the Conference Board expects longer-term increases in U.S. production to slow over the next several years. It noted that Gulf of Mexico production is well down from its peak level, and should continue to decline over the forecast period. As well, gains in onshore production originating in shale deposits may also subside. “Firms have been forced to drill at least one well per section to maintain a long-term lease on their assets. Thus, drilling has been artificially inflated from the true marketdetermined level for several years,” the report said. “As the majority of these agreements will end pre-2013, drilling will begin to react to low prices and subside.” On the demand side, the report said U.S. consumption will remain essentially flat in 2012 and then “accelerate to a moderate pace over the remaining years” of the forecast, in line with the expected economic recovery. However, if the U.S. economy continues to sputter, even modest demand growth is in question. “Should the U.S. tip back into recession or undergo a sustained period of lackluster growth, consumption could easily plateau over the next five years,” the Conference Board said.
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— DAILY OIL BULLETIN O I L & G A S I N Q U I R E R • N o v e m be r 2 0 1 1
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Southern Alberta
Producers’ budgets continue climbing
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A focus on oilsands projects, crude oil development drilling and liquids-rich gas plays has led to several producers hiking their capital-spending budgets for 2011—in some cases multiple times. In outlining their spending plans in late 2010 or earlier this year, producers initially set a budget of $51.27 billion for 2011 spending. As of the end of September, that spendi ng f ig u re had ba l looned by $4.16 billion to a total of $55.43 billion expected for the year. The companies with the largest increases in budgets, in absolute dollar terms, are Canadian Natural Resources Limited (up $1.26 billion), Apache Canada Ltd. (up $380 million), Crescent Point Energy Corp. (an increase of $250 million), Cenovus Energy Inc. (up $200 million) and Devon Canada Corporation (also up $200 million). A recent surge in equity financings has also led to companies hiking their spending plans in 2011. In September, compa n ies suc h a s Tou r ma l i ne Oi l Corp. and Celtic Exploration Ltd. both entered bought-deal equity financings to help boost their spending plans for Deep Basin activities. S o f a r t h i s y e a r, 53 p r o duc e r s have reported plans to increase their c apit a l spend i ng budget s f rom i n itial plans, as oil prices remain strong despite some recent volatility on world crude markets. To date, only three companies have announced decreases in capital spendi n g : Tr i O i l R e s ou r c e s L t d . (dow n $1 2 . 5 0 m i l l i o n), NuV i s t a E n e r g y Ltd. (dow n $10 m i l lion) a nd Hawk Exploration Ltd. (down $500,000). The 103 producers that had released f i na nc ia l resu lt s by press t i me for sister publication Oil & Gas Statistics Quarterly reported cash f low for the second quarter ended June 30, 2011, of $13.09 billion, up from $10.69 billion a year ago. Capital expenditures for the three mont h s ended Ju ne 30 c l i mb ed to $13.84 billion, up $1.21 billion from $12.63 billion in last yea r ’s second quarter. The biggest jump came from Suncor Energ y Inc., which invested
Southern Alberta $1.94 billion f rom April to June, up $423 million from $1.52 billion in the year-prior quarter. Other large increases in year-overyear second-quarter capital spending were booked by WestFire Energy Ltd. (up $357 million), Talisman Energ y
Inc. (up $343 million), Husky Energy Inc. (up $263 million) and Whitecap Resources Inc. (up $186.30 million). In the first half, those companies spending most in excess of cash f low were Talisman (total cash flow of $1.72 billion versus capital expenditures of
$3.26 billion), E nc a na Cor porat ion (c a sh f low of $2 .0 4 bi l l ion ver su s spending of $2.82 billion) and Harvest O p e r a t i o n s C o r p . (c a s h f l o w o f $309.55 million versus spending of $879.06 million). — DAILY OIL BULLETIN
Photo: Joey Podlubny
Horizontal drilling continues at breakneck speed
Horizontal drilling is up 41 per cent year-to-date.
A record 4,206 horizontal wells were d r i l led to t he end of Aug ust, w it h o p e r at o r s a c r o s s w e s t e r n C a n a d a most likely break ing through 2010’s year-end tally for horizontal holes in September. T he 4, 2 0 6 hor i z ont a l we l l s r ig released at the eight-month mark represent a 41 per cent surge from 2,993 wells a year ago. A total of 4,960 horizontal wells were drilled in all of 2010. The horizontal well count is up in all four western provinces, with drillers in Alberta and Saskatchewan leading the charge. Operators rig released 2,401 new horizontal wells in Alberta to the end of August, up 61 per cent from 1,490 wells a year earlier. In Saskatchewan, 1,211 horizontal holes were sunk compared to 941 wells in the first eight months of 2010, an increase of 29 per cent. Producers have rig released 7,801 wells across the country to August, up
10 per cent from 7,069 wells drilled in the January–August period in 2010. In Sask atc hewa n, r ig releases to August climbed 34 per cent to 2,133 wel ls f rom 1,596 wel ls i n t he yea rprior period, while A lberta operators r ig released 4,968 wells, up si x per cent from a year ago. Sa sk atc hewa n’s r ig relea se tot a l i n c lu d e s 2 5 4 o u t p o s t w e l l s , c o m pared to 218 in A lber ta. T here were 169 new pool w i ldc at s r ig relea sed i n A lb e r t a to Aug u s t , ve r s u s 78 i n Saskatchewan. Of the wells drilled across Canada unt i l t he end of Aug ust, 2 ,239 st i l l have no f inal status (oil, gas, dr y or ser v ice). Of t hose w it h a stat us desig nat ion, 3,816 (69 p er cent) were repor ted a s a oi l wel l s. On ly 1,128 were listed as gas wells. A tot a l of 14.01 m i l l ion met r e s w e r e r i g r e l e a s e d t o A u g u s t f r om 12.24 million metres from Januar y to
August last year. Development metres rose to 11.92 million metres from 9.89 million metres a year ago. Alberta operators drilled 8.78 million metres of hole, up from 7.31 million metres in Januar y–August last year, wh i le Sa sk atc he w a n op e r ator s r ig released 3.23 million metres to August, up f rom 2.75 million met res in t he year-prior period. In August, total rig releases increased 18 per cent to 1,386 wells f rom 1,172 wells in the year-earlier period. In Saskatchewan, operators rig released 481 wells, up 73 per cent from 278 wells in August 2010 —that was the largest percentage increase. In Alberta, west of the fifth meridian, 224 wells were rig released in Aug u s t , up f r om 137 a y e a r a go. Meanwhile, in Saskatchewan, 343 wells were drilled west of the third meridian, up from 151 wells in August 2010. — DAILY OIL BULLETIN O I L & G A S I N Q U I R E R • N o v e m be r 2 0 1 1
53
Southern Alberta
Shell targets LNG market at Jumping Pound
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N OV E m be r 2 0 1 1 • O I L & G A S I N Q U I R E R
Royal Dutch Shell plc is pursuing engineering and regulatory permits that would enable its Jumping Pound gas processing facility to produce liquefied natural gas (LNG) for heavy-duty fleet customers by 2013. Pending regulatory approval, it will be the first investment of its kind for Shell globally and will include production facilities and downstream infrastructure. Beg i n n i ng ne x t yea r, L NG f rom third-party supply agreements will be available at select Shell Flying J truck stops in Alberta. “With an abundance of natural gas and a growing need for low-emission transportation fuels, today signals a ver y important step for a significant Nor t h A mer ica n resou rce,” Ma r v i n Odum, president, Shell Oil Company, said. “Our strong portfolio and worldwide LNG leadership puts us in a unique position to grow LNG in key markets. And, to meet growing demand, natural gas for larger f leet vehicles delivers reduced emissions and offers a costcompetitive alternative to other fuels.” With increased global demand for transportation fuels, including LNG, Shell is well positioned to meet this demand, he said. “L NG can prov ide great advantages for our commercial customers as a future energy solution in transportation. LNG will be a welcome addition to Shell’s portfolio of quality transportation fuels,” said Odum. Shell is also actively developing new business opportunities with original equipment manufacturers to substitute LNG for diesel and propane in a number of industrial sectors such as oil and gas drilling, rail, mining, on-road trucking and marine applications. Among these is an agreement with Vancouver-based Westport Innovations Inc. to launch a co-marketing program in North America aimed at providing customers a better economic case when purchasing and operating LNG-powered vehicles by consolidating key value chain components such as fuel supply, customer support and comprehensive maintenance into a single package.
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Southern Alberta
A gas fractionation facility at Redwater, Alta. Some gas producers are focused on liquids-rich gas to overcome low prices. Shell is focused on converting gas to liquid fuel to increase revenues.
Additionally, Shell is actively developing energy solutions that use LNG fuel for the North American mining industry. These solutions will bring fuel cost reductions and emissions improvements to the sector through focused applications in the form of mobile mine haul fleets and other stationary applications. Shell is currently
As part of its efforts to expand the use of LNG as a fuel beyond the heavyduty road transport sector, Shell also announced a joint cooperation agreement with Wärtsilä North America, Inc. to improve further the environmental footprint of the U.S. marine industry, as well as other sectors, by accelerating
E a rl ie r t h i s y e a r, a s ub s id i a r y, Encana Natural Gas Inc., opened its f i r st nat u ra l ga s f leet f uel l i ng station in the Denver-Julesburg Basin of Colorado, northeast of Denver, to serve t he compre ssed nat u ra l ga s (C NG) fuelling needs of the company’s local f leet of field vehicles. In addition to
Pending regulatory approval, it will be the first investment of its kind for Shell globally and will include production facilities and downstream infrastructure. collaborating with technical partners to develop LNG infrastructure solutions for mining customers. Shell also has a cooperation agreement with General Electric Company’s transportation division to jointly develop a total solution for railroads, including associated infrastructure and a locomotive capable of running on both diesel and LNG. This presents a practical alternative fuel source and delivers the benefits of a secure, low-cost and low-emissions fuel for the rail industry, said Shell.
the deployment of larger engines that use LNG as a fuel. To a broad range of Wärtsilä natural gas–powered vessel operators and other customers, Shell will provide the low-cost and low-emissions LNG fuel. Under this agreement, the partners will focus first on the U.S. Gulf Coast and then expand their efforts. As one of the largest North American natural gas producers, Encana Corporation has also been one of the most active gas producers in promoting increased gas demand.
serving local fuelling needs, the station will supply fuel to Anadarko Petroleum Corporation’s and Noble Energy, Inc.’s expanding natural gas vehicle f leets in the basin. Encana also operates a CNG station in Fort Nelson, B.C., for its f leet of bi-fuel (diesel and CNG) trucks in the Horn River Basin and has sought approva l for a CNG stat ion just of f t h e Tr a n s C a n a d a H i g h w a y n e a r Strathmore, Alta. — DAILY OIL BULLETIN O I L & G A S I N Q U I R E R • N o v e m be r 2 0 1 1
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Don’t raise royalties, says C.D. Howe Institute By Elsie Ross
SEP/10
SEP/11
SEP/10
SEP/11
WELLS SPUDDED
244
392
WELLS DRILLED
243
413
Photo: Joey Podlubny
R at her, prov i nc ia l gover n ment s would be better off rely ing more on c omp et it i ve auc t ion s f or r e s ou r c e exploration and development rights, according to the report. “ T he pr oble m w it h t he c u r r e nt heav y rel ia nce on roya lt ies is t hat they impede resource exploration and development, whereas upfront auction revenues would not do so,” said Dahlby. “A shift in emphasis toward auction revenues would have the added benefit of reducing government revenue volatilit y resulting from short-term energ y price shocks,” added report co-author Benjamin Dachis. The authors, Dahlby, Dachis and Colin Busby, compared their estimate of lost bonus revenues from potential f uture production f rom oil and gas projects to the Alberta government’s estimates of total increases in royalty
revenue s f rom e x i st i ng wel l s, a nd found that the 2007 royalty increase led to little total net revenue increase. “Rather, increased royalt y revenues were offset by upfront losses on auction revenues—which for private bidders represent the net present value of profits from a well over and above expenses, royalties and a reasonable rate of return,” says the report. To measure the effect of the change in A lberta’s royalt y rates, the report measured the impact of the increase on bonus bid values by comparing bonus bids within 100 kilometres of Alberta’s borders w it h Br it ish Columbia a nd Saskatchewan, which did not change their royalties. Accounting for differences in bonus bids in the same geologica l zones, t he repor t found t hat w it hin t his region, A lber ta’s royalt y increase reduced t he average bonus bid by 42 per cent i n t he t wo yea rs f o l l o w i n g t h e i n c r e a s e (O c t o b e r 2007– 09) compared to the t wo years preceding it (October 2005– 07). Daily Oil Bulletin records show that in 2007, Alberta took in $1.36 billion in bonuses, down from $3.43 billion in 2006, and in 2008 that number fell even further to $1.23 billion. I n 2 0 0 6 , t h e a v e r a g e v a lu e of a c onve nt ion a l oi l a nd g a s bid i n A lberta within 100 kilometres of the Sask atc hewa n border was $91,0 0 0, while the equivalent value along the B.C. border was $282,000. The average reduction in bonus bids in southeastern A lberta as a result of higher r oy a lt ie s wa s 54 p e r ce nt; i n contrast, royalty bids in western Alberta declined by 32 per cent. Larger companies with operations in multiple provinces likely would have had greater flexibility than smaller companies with more limited operations
Royalties are under discussion as the election heats up.
With the rise in oil prices and a pressure to make royalty payments more responsive to oil and natural gas prices, provincial governments like Saskatchewan’s should t hin k t w ice about t r y ing to increase revenue from non-renewable resources through higher royalties, says a new report by the C.D. Howe Institute. Raising royalties on oil and natural gas production can actually result in lower, rather than higher, tax revenues, the report, Rethinking Royalt y Rates: Why There Is a Better Way to Ta x Oil and Gas Development, found in a study of Alberta’s short-lived effort in 2007 to increase royalties. “The increase in royalties reduced the rewards to companies f rom oil and gas extraction, a nd t herefore reduced t he a mou nt they were willing to pay to explore and develop new resource projects,” said co-author Bev Dahlby. SASKATCHEWAN WELL ACTIVITY
SEP/10
SEP/11
WELL LICENCES
239
417
▲
▲
▲
Source: Daily Oil Bulletin
O I L & G A S I N Q U I R E R • N o v e m be r 2 0 1 1
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Saskatchewan
in other provinces to redeploy capital and workers outside Alberta. Thus, the report found that the larger companies reduced their average bid by 68 per cent, while smaller companies reduced theirs by 35 per cent. The study also found that the average value of an exploration licence in Alberta fell by 59 per cent due to the royalty increase, likely because licences are geared toward finding highly productive oil and gas reserves and the royalty increase was particularly high for these large deposits, which disproportionately
Changes in the number of bids also would have affected total provincial revenues from bonus bids. Because deposits that were marginal at the previous royalt y rate would have been non-economic at the higher rate, it is likely that after the increase, operators reduced the number of projects on which they were prepared to bid, the report suggested. It found that after the royalty increase, the number of bids within one-kilometre-wide concentric bands east and west of the Alberta border declined relative to other wise
The study also found that the average value of an exploration licence in Alberta fell by 59 per cent due to the royalty increase. reduced the expected return from exploring for them. The average value of a lease declined by only 21 per cent. Leases are geared toward relatively low-yielding deposits, for which the royalty increase likely was negligible in many cases, the report noted.
similar bands in adjacent prov inces. Within Alberta, the number of bids was down 27 per cent from the t wo years prior to the increase. To dete r m i ne t he tot a l r e ve nue effect of Alberta’s royalty increase just
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on conventional oil and gas, the report first estimated the new average bonus amount due to the increase using the average bonus bid in 2006 of $175,000 a nd t he est i mated reduced average bonus of $105,000, and the lower bids would have resulted in total annual revenue of $600 million in 2006 in comparison to actual revenue of $1.5 billion that year. In cont rast, i n it s a n nouncement of t he New Roya lt y Fra mework , t he Alberta government estimated that by 2010 —assuming no change in production due to the increase in royalties and at projec ted 2010 pr ices — tota l conventional oil and gas royalties would increase by $930 million. “ T hus, the increase in royalt y rates should have y ielded, at best, a marginal revenue increase if producers did not change their production,” says the report. “But producers likely reduced their production from wells made uneconomical as a result of the higher royalt y, making the net revenue from the royalty increase closer to zero or even negative,” it adds.
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Oliver says major project approvals will be streamlined
Photo: Joey Podlubny
By Elsie Ross
The federal government is making it quicker to get export pipeline approvals in the hopes of keeping oilsands construction moving forward.
The federal Conservative government is committed to modernizing regulatory processes for major projects such as pipelines with the ultimate goal of “one project, one review,” the natural resources minister said in September. “This doesn’t mean undermining the integrity of the regulatory process; it does mean streamlining the regulatory review,” Joe Oliver said in a speech to the Canadian Energy Pipeline Association’s (CEPA’s) annual dinner. He spoke via Skype when his flight from Toronto was delayed. Oliver said his government has heard from the pipeline industry how important it is that regulatory processes be more predictable, more efficient, more timely, more effective and involve less duplication. “Our government recognizes that this is a necessity to capitalize on potential investments and to grow markets,” he said. “That’s why at the Energy and Mines Ministers’ Conference in Alberta this past July, the Government of Canada and all provinces and territories agreed to a collaborative approach to energy, which includes a focus on energy reform.”
While the government established a major projects office three years ago precisely to make its rev iews more timely and predicable, more has to be done, he said. About one-half of the more than 70 projects it has managed are in the energy sector. Among them are TransCanada Corporation’s K e y s t o n e X L a n d E n b r i d g e I n c .’s Northern Gateway projects. Ottawa is working with industr y, governments and other stakeholders on ways to further trim regulatory processes, CEPA members heard. The energy industry will play an increasingly important role in creating jobs and growing the Canadian economy, said Oliver. However, for Canada to ac h ieve its f ul l potent ia l, major i nvest ments i n oi l a nd nat ura l gas infrastructure will be required. In the next 25 years, CEPA members expect to invest more than $50 billion in new and expanded pipelines. “Today, Canada is facing a once-in-a-lifetime opportunity to build essential infrastructure to capture new markets.”
Today, 97 per cent of Canada’s energy exports go to the United States, which effectively means the country has only one customer, said Oliver. “You don’t need an MBA to know that having one customer doesn’t make good business sense.” Fortunately, demand growth is strong in Asia, and China recently surpassed the United States as the world’s largest consumer of energy, he said. “For these reasons, it is strategically important for Canada to diversify.” Diversification would allow Canada to capture new oil market growth that would provide higher netbacks to producers, according to Oliver. It would also allow new competitive sources of crude oil supply to Canadian refineries not currently supported by Canadian oil. The private sector is bringing forward proposals for the projects. Northern Gateway and the expansion of Kinder Morgan’s Trans Mountain system could bring crude oil from Alberta to Canada’s West Coast, where it would be loaded onto tankers for export to Asia. Oliver said he recognized that Northern Gateway is currently under review by a Canadian Environmental Assessment Agency-National Energy Board joint panel. “I respect that process; we await their conclusion,” he said. With the growth of shale gas production in markets once served by Canadian natural gas, equally important is diversifying the Canadian market for natural gas. Two applications to export liquefied natural gas from Kitimat are currently before the National Energy Board. “With the right kind of infrastructure, we know Canada’s economy will see significant benefits as foreign customers of our energy view us as a politically stable, competitive, responsible and reliable producer of energy,” said Oliver. The priorit y, however, is still on safety, Oliver emphasized. “We are fully committed to safety, so we can continue to develop our energy resources in a manner that is environmentally and socially responsible.” The federal government will continue to support CEPA’s efforts to ensure the Canadian pipeline industry maintains O I L & G A S I N Q U I R E R • N o v e m be r 2 0 1 1
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the highest standards of safety, he said. The government’s pipeline research program works on technologies to ensure the reliable performance of existing pipelines, while labs are conducting technology and materials research for pipelines in the north. A good track record in safety and environmental performance also helps to create a distinctive competitive advantage, he suggested. That’s why Ottawa is supporting the industry’s 811 campaign, in which anyone about to excavate would be required to call that number to find out if there was pipeline or cable in the area that should be avoided, CEPA members heard. In his speech, the natural resources minister emphasized his government’s support for the $7-billion Keystone XL pipeline, which he said has the potential to strengthen the North American economy. To maintain its status as a major energy player and to continue to move forward,
Canada needs to “get better and better,” said Oliver. “We need to embrace a culture of constant improvement, and evolution comes through our technology, our processes and our very robust regulatory regime.” The past year has been a challenging one for the pipeline industry, with hardly a day in which one company or another was not in the news, said Ian Anderson, CEPA chair and president of Kinder Morgan Canada. However, “with those challenges, I think it’s been a bit of a rallying cry and a uniting force for our industry,” he said. “We have spent more time together debating the issues and the priorities and the strategies to move forward than I think we ever have.” C E PA me mb e r s, A nde r son sa id, are clearly aligned on what they think are the three major priorities. These i nc lude t he sa fet y a nd i nteg r it y of North American pipeline systems, the market access needed to continue to provide for Canadians and producers
in t his count r y, and ensur ing reg ulator y f ramework s are ef f icient and work ing in t he best interests of t he industry and Canadians. “As far as safety, more effort than ever is being paid to integrity, damage protec t ion a nd t he sha r i ng of best practices,” he said. “I am very proud of industr y and how we have rallied around those three causes.” I n h i s com ment s, Ron L ieper t, Alberta’s energy minister, said Canada needs a national strategy with planned energy development “so the general public can see what we are all trying to achieve.” “I think if we have that plan in place, you can put to rest many of those 15-second sound bytes we are hearing today that have become such a challenge to all of us,” he said. “If we can do that, if we can combat these campaigns, we can get back to serving the globe with the resource that it needs. — DAILY OIL BULLETIN
Shell Canada pushes energy framework Canada risks losing the opportunity to position itself as an energy superpower unless it acts quickly to take advantage of a rapidly changing global energy market, Shell Canada Limited’s president and country chair, Lorraine Mitchelmore, warned in September. In a speech to the annual general meeting of the Canadian Chamber of Commerce in St. John’s, Newfoundland and Labrador, Mitchelmore said every major energy-producing country in the world is going after the growing Asian market—except Canada. “We are the only major oil and gas producer in the world that does not have access to a global market. All our eggs are in one basket—the U.S.,” she said. However, added Mitchelmore, U.S. demand for Canada’s energy products is not growing, and unless Canada diversifies its market, it could be in trouble down the road. “Right now, Asia is setting up its energy supply points, and Canada is not one of them,” she warned. Mitchelmore urged the Chamber to use the influence of the 192,000 businesses represented by its affiliates to
suppor t a more competitive energ y framework for Canada, one that includes a streamlined regulatory system where the rules of engagement are clear. “Canada needs your help,” she told delegates. “This should be a time of great opportunity for Canada, but it’s not—or, at least, not yet. We need to diversify our customer base for energy products and create access to the global growth markets. If we mess this up, Canada will miss an opportunity to sell oil and gas to Asia, which is the world’s fastest-growing energy market.” Mitc hel more sa id t he nex t step towards an energy framework is to build on the action plans identified at the Energy and Mines Ministers’ Conference in Kananaskis, Alta., in July. “You can help by talking to your MPs and to the media. Let them know that you want to see significant progress before the 2012 ministers’ conference on Prince Edward Island,” she urged delegates. There should also be more cooperation between groups that have an interest in energy, based on recognition that Canada’s energ y resources are ver y important to its national future, she said.
Mitchelmore said if anyone asks, “What’s in it for me?”, the answer is simple: Canada’s economic future. “Every Canadian business and every Canadian citizen will be better off if we can sell our oil and gas on the global market. It will generate jobs and create the national wealth we need to continue providing the services and infrastructure that Canadians need to prosper and live well.” She said government revenue generated by the energy industry translates into funding for public services for ordinary Canadians across the country. “Like healthcare, where we spend around $190 billion, and education, which takes another $80 billion every year. I think it is easy to see that energy is the key to Canada’s wealth and well-being.” Quoting energ y economist Peter Tertzakian, Mitchelmore said Canadians are losing about $50 million a day of revenue because Canada does not have access to global energy markets. “It adds up to $18 billion every year, of which $4 billion would be the government’s take. In other words, that’s $4 billion that could be used to provide services for Canadians,” she said. O I L & G A S I N Q U I R E R • N o v e m be r 2 0 1 1
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Husky sanctions Liwan Gas Project
Photo: Joey Podlubny
Encana selling Piceance midstream assets
Husky continues focusing on growing its offshore developments in China.
Husky Energy Inc. has sanctioned the development of the Liwan 3-1 and Liuhua 34-2 fields, the principal fields of the Liwan gas project in the South China Sea. Husky and China National Offshore Oil Corporation (CNOOC) are jointly developing the project, which aims to bring to market at least three natural gas discoveries on Block 29/26, located approximately 300 kilometres southeast of Hong Kong. The overall development plan for Liwan 3-1 has been submitted to Chinese government authorities for regulatory approval and a gas sales agreement for production from the field is in place. “The Liwan gas project will serve as a cornerstone in our plans to establish Southeast Asia as a major growth pillar for the company,” Husky president and chief executive officer Asim Ghosh said. “This is a top-tier project that is expected to deliver strong value to our shareholders. “In addition to the sanction of the Sunrise energy project, Liwan represents the second major action we have taken over the past year to lay the foundations for
our three growth pillars in the oilsands, Southeast Asia and the Atlantic region.” Husky recently announced that a gas sales agreement had been executed with CNOOC Gas & Power Group, Guangdong branch, for volumes from the Liwan 3-1 field. Production will supply the Guangdong province natural gas grid from an onshore gas plant at Gaolan Island, Zhuhai. The project is proceeding on schedule towards planned first gas delivery in 2013–14. Production from the Liwan 3-1 and Liuhua 34-2 fields is expected to ramp up through 2014 towards a rate above 300 million cubic feet per day (gross). Once the Liuhua 29-1 field is approved and developed, the project is expected to reach gross production of about 500 million cubic feet per day in the 2015 time frame. Husky has a 49 per cent ownership interest in production from the block. T he compa ny i s t a rget i ng overall production from Southeast Asia of approximately 50,000 barrels of oil equivalent per day in 2015. — DAILY OIL BULLETIN
Encana Oil & Gas (USA) Inc., a subsidiary of Encana Corporation, has agreed to sell a portion of its Piceance natural gas midstream assets in Colorado to a private midstream company for approximately US$590 million. “Fol low i ng ou r For t Lupton ga s plant divestiture earlier this year, this Piceance divest it ure represents our second successf ul step in capt ur ing significant unrecognized value from ou r m idst rea m a sset s,” sa id Renee Z e m lja k , E nc a n a’s e xe c ut i ve v ic e president of midstream, marketing and fundamentals. The market for midstream assets in the United States and Canada is very competitive as midstream investors are able to realize strong valuations that are not recognized when the same assets are contained inside larger, more diversified energy firms, Zemljak said. “ We have addit iona l divest it ure processes underway as we continue to entertain considerable interest from prospective purchasers of our Cabin Gas Plant in Horn River and Cutbank Ridge midstream assets in Canada. We look forward to completing those divestitures and establishing long-term business relationships with industry-leading midstream companies.” T he P icea nce Ba si n m id s t r ea m assets, built in the past decade, serve Encana’s Mamm Creek, Orchard and South Parachute production in the area around Rif le, Colo., about 180 miles west of Denver. They gather and transport about 500 million cubic feet per day and include about 260 miles of pipeline and 90,000 horsepower of compression facilities. The sale of the Piceance Basin midstream assets is subject to certain regulatory approvals and customary closing O I L & G A S I N Q U I R E R • N o v e m be r 2 0 1 1
65
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conditions, and is expected to close in the fourth quarter of 2011. “ O nc e we h a v e c omple te d t he Piceance midstream asset sale, our 2011 net divestitures will stand at about $6 0 0 m i l l ion . To t a l d i v e s t i t u r e s p roceeds of about $1 billion are offset by about $ 400 million o f a c q u i s i tions,” said Randy Eresman, Encana’s p resident and chief executive officer. Encana has initiated a number of divestiture and joint venture processes to ensure it meets its objective of $1 billion to $2 billion of net divestitures by around year-end. “ T he cur rent highly competitive midstream env ironment is resulting in significant interest in our Canadian midstream assets,” Eresman said. “Due to the strong interest that we have received, we are optimistic that one or more Canadian midstream divestitures will also be forthcoming by around year-end.”
In addition to these well-advanced pr o c e s s e s, E nc a n a h a s pr e v iou sly announced a number of producing property divestitures, including its Barnett shale play in North Texas, portions of the Jean Marie in northeastern British Columbia and its Carrot Creek assets in Alberta’s Deep Basin. Encana has also re-initiated a process to find a joint venture partner for an interest in portions of its Cutbank Ridge undeveloped assets. Ty pica l ly, joi nt ventures of this nature take the form of an up front cash payment and a disproportionate contribution to the future capital program. “Our expectation is that some or all of these transactions, should we choose to proceed with them, will close in the months surrounding year-end. These proceeds will strengthen the company’s balance sheet, providing greater financial strength and flexibility going into 2012,” Eresman said.
Encana said it is also implementing plans to increase natural gas liqu id s recove r y f rom t he compa ny ’s current high-energ y content natural gas streams. “ D e s pite p e r si s te nt ly low Nor t h A merican nat ural gas prices, we have been ac hiev ing some of our best operational per for mance ever,” E r e sm a n sa id. “ We h ave cont i nued to make technological and efficienc y advancements t hat have lowered ou r overa l l cost st r uc t u re s — i n it iatives that help us maintain profitable operations even in a N Y ME X natural gas price env ironment of $4 per mcf [t housa nd c ubic feet]. Sig n i f ica nt ly for t if y ing our capita l and operat ing pla n s is ou r pr ice r isk ma nagement process. Encana has about half of its e x pec ted da i ly nat u ra l ga s product ion hedged f r om now t h r oug h t he end of 2012 at prices averaging more than $5.75 per mcf.”
Enterprise and Enbridge target Gulf Coast Enterprise Products Partners L.P. and Enbridge Inc. announced plans last month to build a new pipeline to transport crude oil from the oversupplied hub at Cushing, Okla., to the Texas Gulf Coast refining complex. I n it ia l ly, t he Wra ngler P ipel i ne will have the capacity to transport up to 800,000 barrels per day of crude oil and accommodate the constrained
Enbridge Cushing Terminal and extend approximately 500 miles (800 k ilomet res) sout hward, closely followi ng ex ist i ng pipel i ne cor r idors, to Enterprise’s ECHO crude oil storage terminal in southeastern Harris County, Texas, providing access to r efineries in Texas Cit y, Pasadena /Deer Park, Baytown and along the Houston Ship Channel. New storage tankage necessary
Initially, the Wrangler Pipeline will have the capacity to transport up to 800,000 barrels per day of crude oil. medium to light cr ude oil currently stranded at Cushing and priced at a substantial discount to the oil imports t hat account for most of t he supply being used by Gulf Coast refiners. The pipeline will also have the capability to handle additional supplies of crude oil arriving at Cushing from other North American producers. T he proposed 36 -inc h dia meter pipeline will originate at the existing
for pipeline operations will be located at the ECHO site and included in the joint venture. The project will also include a new 85-mile (137-k ilometre) pipeline to the Beaumont/Port Arthur refining centre. “The Wrangler Pipeline will offer flexible solutions to shippers seeking to move crude oil out of the Cushing hub, solving the current lack of transportation options following recent changes in supply routes in North America,” said Patrick D. Daniel,
president and chief executive officer of Enbridge. “We’re pleased that Enterprise shares our vision to design this pipeline to meet the needs over the long-term as the Cushing Hub continues to attract both light and heavy production from North American producers.” U.S. midcontinent crude oil supplies are growing rapidly, and that trend is expected to continue as a result of the development of shale plays such as Bone Springs/Avalon, Bakken, Niobrara and Barnett. Additionally, refiners and oil producers are seeking new pipeline routes south of Cushing rather than the historical northerly supply routes out of that crude oil hub. Another important driver of this project is the demand by Gulf Coast refineries for western Canadian crude oil supplies, which have been growing since Alberta oil first accessed the Cushing Hub over the last decade. The Wrangler Pipeline w i l l b e de sig ned to accom modate quality-controlled batches of a variety of grades and sources of crude oil, providing options for economical, efficient and safe transportation of crude oil. O I L & G A S I N Q U I R E R • N o v e m be r 2 0 1 1
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business advice
BUSINESS INTELLIGENCE Making and defending aN SR&ED claim: Five common pitfalls to avoid Ryan P. Mackiewich, CA, SR&ED Practice Leader, MNP
Every year, the federal government awards approximately $4 billion to
RTAs. While this may be the case for companies performing scientific
Canadian companies making scientific research and experimental devel-
research, such as the people in white lab coats working in research labs,
opment (SR&ED) claims. When you consider that companies performing
it is likely not the case for the engineer working in the field developing a
eligible SR&ED work can get up to 68 per cent of their expenditures back
downhole tool to help address a specific problem on a drill string.
in tax credits and cash from the government, making an SR&ED claim is well worth the effort.
The important point here is that the CRA is looking for documentation. Any documentation that is dated and helps support the work you
The current version of the SR&ED program has been around since the
did will help. So it is very important to keep notes and document as you
mid-1980s. In 2008, the federal government announced an increase in
go, such as keeping test results and taking photos or videos. From the
funding for the administration of the program. This additional funding has
CRA’s perspective you have to be able to prove what you said you did. In
led to a myriad of changes in the program, including the addition of many
other words, you must have some sort of evidence to provide to them if
new research and technology advisors (RTAs)—the technical experts who
and when they review your SR&ED claim.
review the SR&ED claims.
We have worked with many companies to assist them in gathering
Other changes include a new claim form limiting the number of words
this evidence through an investigative approach. Ideally, you gather
used to describe a project, the implementation of a new claim review manual
the evidence as you go. Gathering the evidence after the fact is more
(specific guidelines for RTAs to follow when they review the claims) and a
difficult and time consuming, but it can be done. MNP LLP has helped
policy documentation consolidation project. All these initiatives affect the
companies develop systems that work for them and has helped with
companies making the claims and have created some uncertainty. Since uncer-
gathering evidence after the fact.
tainty breeds confusion and confusion leads to mistakes, you could be missing out on significant tax savings with a lower SR&ED claim being awarded.
Pitfall #4—The technical report
There are many common pitfalls companies can avoid in making an
The new SR&ED claim form changed the technical report requirements
SR&ED claim that may help you get your claim processed more quickly and
from a free-form report to a three-question response limited to 1,400
without any significant change by the Canada Revenue Agency (CRA).
words. This change has drastically altered how a company presents its SR&ED projects. The CRA RTAs are not experts in your technology;
Pitfall #1—Filing your claim
you are. You need to be able to describe the project in simple enough
The CRA has a mandate to process an SR&ED claim that is filed with the
terms so that a person with technical knowledge will be able to under-
company’s original tax return by its sixth-month due date within 120 days.
stand you, but not so simply that you miss the point of describing the
Anything else is either 240 days or longer. So, when possible, file the
d ifficulties and challenges. This task is tougher than it sounds and
SR&ED claim together with the original filing of the tax return. This will get
takes a very good technical writer to summarize a complex project into
you your money more quickly and will significantly reduce the likelihood of
1,400 words.
a review of the claim by the CRA. Pitfall #5—Not being prepared Pitfall #2—The owners who
You have only one chance to make a first impression. One of the keys to
perform the SR&ED don’t receive a wage
success in defending an SR&ED claim is to be prepared by having as much
The SR&ED program rewards for expenditures made towards developing
supporting information available for the review as possible. The lead
technologies. So if there are no wages, there is little or no base to calculate
technical person who did the work also needs to be present at the meet-
an input tax credit (ITC). Furthermore, if the company is paying its owners
ing to tell the CRA what they did for the project and why they believe it is
via dividends, this may result in the company not being able to receive
SR&ED. A good advisor will help you prepare for this meeting by organiz-
refundable ITCs. In other words—cash!
ing the information and doing a mock review so you are prepared for the tough questions to challenge your resolve.
Pitfall #3—If a company is performing SR&ED,
The potential savings through SR&ED tax credits can have a measur-
documentation will “naturally” be produced
able impact on your bottom line. If you think you might be eligible, it’s well
Although this is not written in any of the many policy documents of the
worth investigating. To avoid the common pitfalls, it’s worth working with
CRA, it is a phrase we have heard over and over again from many different
an experienced advisor who understands the process.
O I L & G A S I N Q U I R E R • N o v e m be r 2 0 1 1
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