International: Canadian Outlook

A record-setting year for oil prices was not enough to offset a precipitous drop in activity in 2007, and the outlook for 2008 remains uncertain.

Robert Curran, Contributing Writer, Calgary

At the outset of 2007, there was wariness about the future throughout the Canadian oilpatch that now seems prophetic. And as if the seemingly incongruous combination of booming oil markets and slumping natural gas prices was not enough, industry faced a skyrocketing Canadian dollar and political uncertainty, with mounting calls for the federal government to consider a carbon tax. And in Alberta, the provincial government announced reforms to its royalty structure late in the year.

It is well known that oil prices topped the US$100 mark in late 2007, but slumping natural gas prices have been more of a story in Canada, particularly with the strength of the Canadian dollar as compared to the US greenback. But recent cold weather across North America has boosted continental natural gas markets and given producers hope that the slump may be over, although no one is predicting a dramatic increase.

At the outset of 2007, the Canadian dollar was trading at 85 cents US. It rose to 94 cents by midyear, was on par with the US dollar in September, and topped out at US$1.10 in November-reaching levels not seen since the 1950s, and establishing a modern-day record. Since then, it has hovered around par, or slightly below.

In recent years, the dollar has traded much lower, which resulted in more vulnerability for Canadian companies to foreign takeovers, but also meant that crude oil and natural gas export sales also resulted in higher revenues, as most transactions were conducted in US dollars.

On the political front, speculation continues that the federal government is looking for means to reduce the country’s massive per-capita emissions, without causing undue harm to the booming economy and, in particular, Alberta’s massive oil sands deposits. Recovering the gooey, tar-like substance, largely contained in the Athabasca region in Alberta’s northeast, is an energy-intensive endeavor that contributes substantially to Canadian greenhouse gas emissions.

Balancing the country’s energy future-the oil sands contain enough oil to satisfy Canadian demand for more than 400 years-against a growing public will to reduce the country’s carbon footprint is proving difficult for Prime Minister Stephen Harper (who hails from Calgary) and his minority Conservative government.

At this point, Harper’s government has consistently rejected calls for a carbon tax. Bolstering the feds’ reticence, polls consistently show that Canadians support the idea of a carbon tax, but balk at the notion of paying substantially more for gasoline or other products that would necessarily see a tax-induced price increase.

Some environmental activists suggest that to eliminate emissions from Alberta’s oil sands mines would cost at least $50 per metric ton of carbon dioxide. To date, Harper’s administration has suggested that they would consider nothing higher than $20/mt, while the opposition has proposed a tax of $30/mt.

In Alberta, royalty changes-promised by provincial Premier Ed Stelmach in his successful bid to become the leader of the ruling Conservative party-came after the government commissioned a report from an independent panel to assess the province’s take from the production of its energy resources. The report drew harsh criticism from industry, which claimed that the authors had failed to accurately consider the inherent costs of exploring for and producing oil and gas in Alberta.

Adding to the debate were accusations by Alberta’s auditor general that staff within the provincial Energy Department had raised the possibility that C$1 billion to $3 billion more could have been collected over the past three years without undue impact on industry.

Industry warned that adopting the report’s recommendations, as is, would lead to a massive decrease in spending, a corresponding drop in activity and, ultimately, a reduction in the province’s royalty take. Calgary-based Tristone Capital predicted that up to C$3 billion worth of spending would leave Alberta due to the new regime. Others predicted the money would flow to neighboring Saskatchewan and British Columbia.

The issue proved divisive in the province, as politicians and special interest groups weighed in on both sides of the debate. There was even a protest at the Alberta legislature, attended by more than 500 oilpatch workers concerned about the negative impact the new regime might have on their livelihood.

After reviewing the report, the government announced that it would implement a new royalty structure-largely based on the report-as of January 1, 2009. Premier Stelmach called the revisions a “framework for a new century,” adding that it provides balance, will add $1.4 billion to Alberta coffers, and gives industry time to adjust to the new system. Although the government had softened the recommendations of the original report, industry reaction was predominantly negative.

Concerns focused on a number of factors:

• The greatest short-term impact will be to conventional oil producers.
• Deep oil and gas production will be unduly impacted because high production costs were not considered.
• Existing agreements for oil sands producers will not be grandfathered, and the government is asking Suncor and Syncrude to voluntarily adopt the new structure before 2016, when the agreements expire.
• The introduction of shallow-rights reversion may benefit some producers, but others predict any attempt by the government to take back rights that were legally acquired will likely end up in court.
• The report lacks details as to how the government will implement many of the changes.

However, Stelmach raised the possibility that further modifications to the new royalty framework will be considered for those sectors that were hit hardest by “unintended consequences.” Alberta Energy Minister Mel Knight has publicly stated that the province will not consider any further increases to royalties for at least another decade.

What 16 Canadian drillers plan for 20081

The combination of the new royalty structure, Canada’s high-cost environment, the high Canadian dollar, and low natural gas prices has resulted in predictable reductions in profits and spending plans for many Canadian companies.

Through the third quarter of 2007, industry profits fell by more than 32% compared with 2006 results, a decrease of C$2.6 billion, according to a survey conducted by Calgary’s Daily Oil Bulletin. Cash flow was virtually flat in the same period. And the news was even worse for the Canadian service sector, as profits fell over 50% through the third quarter.

To date, several producers have announced reductions in their 2008 capital budgets. Among them were EnCana, which announced an increase in its overall budget, up 13% to US$6.5 billion, but will decrease Alberta spending by $500 million. Petro-Canada plans to boost spending to C$5.3 billion, although $125 million in planned natural gas dollars will be shifted out of Western Canada due to the changes to Alberta’s royalty structure. Canadian Natural Resources Ltd. announced it would reduce spending to C$4.9 billion, largely due to a 33% decrease in conventional oil and gas expenditures, most of which the company attributed to Alberta’s new royalty regime. Talisman Energy announced spending would stay essentially flat at C$4.4 billion this year; it did not attribute the decision to Alberta’s royalty changes. And Nexen Inc. said it would cut spending by a third, to C$2.4 billion, also citing the new royalty framework as a primary factor.

The strange conditions evident in 2007 also produced some strange results for Canadian markets, as integrated and senior firms held their own, but the indices for service companies, royalty trusts and junior producers fell dramatically. According to Calgary-based Peters & Co., the market value of integrated companies increased 18%, large producers rose 13%, service companies fell 6%, energy trusts dropped 7%, natural gas producers declined 23%, and juniors plummeted 25%. The poor results for the junior, natural gas and trust companies are drawing predictable speculation that those sectors will see more action on the merger and acquisition front in 2008.

The market instability led to increased mergers and acquisitions in 2007. In fact, through the first three quarters of the year, just under C$40 billion worth of deals had been announced, exceeding every annual total since 2001, according to Calgary-based Sayer Securities. Combined with the value of the deals announced in the fourth quarter, 2007 may set a record for M&A activity.

Second-half deals included:

• In September, Abu Dhabi National Energy Co. announced it would acquire PrimeWest Energy Trust for C$5 billion, its third acquisition in Canada of 2007.
• In October, Penn West Energy Trust announced that it would become the largest conventional oil and gas trust in North America (with an enterprise value of over $15 billion) by acquiring Canetic Resource Trusts for C$3.6 billion in cash and paper.
• In November, EnCana Corp. acquired Houston-based Leor Energy’s 50% interest in Amoruso Field’s Deep Bossier gas play for US$2.55 billion. The deal boosts EnCana’s stake to 100% in the 215-MMcfd field.
• In December, Enerplus Resources Fund announced plans to merge with Focus Energy Trust. The C$1.38 million deal will create the third-largest trust in Canada.
• In November, AltaGas Income Trust announced that it would acquire Taylor NGL Ltd Partnership for C$590 million, making AltaGas Canada’s most diversified energy infrastructure trust.
• In November, Petrobank Energy and Resources Ltd. announced the acquisition of Peerless Energy Inc. for C$334 million in a cash and paper deal that increases Petrobank’s stake in Saskatchewan’s light-oil Bakken play.

Meanwhile, the federal government raised the possibility that it may consider implementing a national security test for foreign investment, particularly as it pertains to acquisitions of Canadian firms by state-owned oil companies. The announcement was sparked, in part, by Abu Dhabi’s acquisition of PrimeWest.

On the drilling side, the continued slump in natural gas pricing and the soaring Canadian dollar were enough to reduce drilling below the 20,000 mark for the first time since 2003. Daily Oil Bulletin records show drilling fell to 19,272 wells in 2007, down more than 13% from the 22,171 wells drilled in 2006, but still the fifth-highest total in Canadian history. Gas completions fell to 12,621, compared with 15,317 in 2006, representing more than 65% of total wells drilled. Oil completions reached 5,429 last year, second only to the 5,609 drilled in 2006. Only 20% of the wells drilled last year were exploratory, the lowest number since 1997.

Continued uncertainty does not bode well for Canadian drilling in 2008, as most forecasts are extremely bearish. Both the drilling and service associations have predicted substantially lower totals, citing of continued low gas prices, high costs, Alberta’s new royalty structure and the strong Canadian dollar.

The Canadian Association of Oilwell Drilling Contractors (CAODC) is the most bearish in its outlook, predicting a total of 13,735 wells drilled in 2008. The CAODC based its forecast on an average WTI price of US$80/bbl and an average NYMEX spot gas price of C$6.50/Mcf. The CAODC is also predicting that rig utilization will average 34% in 2008, compared with 40% in 2007. A utilization rate of 50% is normally required for the drilling industry to remain profitable.

The Petroleum Services Association of Canada (PSAC) is more optimistic than CAODC, but it is still forecasting that 14,500 wells will be drilled in 2008. PSAC believes that the decrease will once again be seen primarily in shallow gas drilling. PSAC’s forecast is based on a WTI average of US$75/bbl, and C$6.50/Mcf at Alberta’s AECO storage hub. The Canadian Association of Petroleum Producers has a forecast of 15,000 wells in 2008.

Meanwhile, World Oil’s annual survey of Canadian producers indicates a similar, but slightly more bullish trend, with participants indicating they will drill 4,690 wells in 2008 (19.6% less than the 5,837 drilled in 2007), which translates to a projection of about 15,500 wells drilled this year.

Most optimistic of all, a total of the data from individual provinces shows 20,431 wells drilled in 2007, with a forecast for 19,829 wells this year.

The survey of producers indicates operators plan to drill 27% fewer gas wells in the year ahead (3,417), although that amount still represents 59% of total drilling for the year. Surprisingly, survey participants also indicated they will be drilling more than 40% more wildcats in 2008 (488).

Activity is expected to plummet 28.2% in Alberta, primarily as a result of lower gas drilling, stay flat in British Columbia, and increase 54.5% in Saskatchewan, which is most likely indicative of the high oil-price environment and uncertainty in Alberta.

But despite all the uncertainty and concerns about royalties and spiraling costs, Alberta remains bolstered by activity dedicated to its enormous oil sands deposits. Total E&P Canada, a wholly owned subsidiary of Total SA, is hopeful that its North Mine project applications will be reviewed at public hearings this year, and has indicated that plans remain in place to spend from C$10 billion to $15 billion over the next decade on mines and an upgrader in the Edmonton area. Total is forecasting that production out of the Athabasca region will reach 250,000 bpd by 2015.

Meanwhile, Shell Canada submitted applications to regulators in late December to increase bitumen production from its Jackpine Phase 1 project to 100,000 bpd, bringing the plant’s capacity up to 300,000 bpd. Shell also applied for the Pierre River mine, located north of Jackpine, which will produce 200,000 bpd bitumen. And Husky Energy Inc. has partnered with BP plc to create an integrated North American oil sands business, comprised of two 50/50 partnerships. Husky will operate the Canadian oil sands partnership, and BP will operate the American refining business. The transaction is expected to close in the first quarter.

On Canada’s East Coast, EnCana’s proposed Deep Panuke offshore natural gas project in Nova Scotia received regulatory approval in October, following federal approval to construct a pipeline to ship the Deep Panuke gas to markets in eastern Canada and the northeastern US. In November, Newfoundland celebrated its tenth year as an oil-producing province. First oil flowed from the Hibernia offshore project in November 1997. Since then, almost 900 million bbl of oil have been produced from Hibernia, Terra Nova and White Rose. White Rose was also in the news in December, as the province’s energy corporation signed an agreement with Husky and Petro-Canada to expand the offshore oil play. First oil is expected in late 2009.

Finally, land sales were erratic in 2007, with Alberta’s provincial take plummeting 60% to C$1.36 billion, its lowest total since 2003, and well off the record $3.4 billion collected in 2006. Nonetheless, it was still the province’s third-highest total on record. But as Alberta fell, British Columbia surged, bringing in just over $1 billion, an increase of 66.7% over 2006’s $630 million, shattering the province’s previous record of $643 million, set in 2003. Saskatchewan also set a record in 2007, garnering over $250 million. The previous record of slightly less than $200 million was set in 1994. 

Mr. Curran is a Calgary-based freelance writer.