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Energy East pipeline would put waterways at risk, says Council of Canadians

Energy East pipeline would put waterways at risk, says Council of Canadians
By David Howell
Edmonton Journal
August 26, 2014
TransCanada’s proposed 4,500-kilometre Energy East pipeline poses too much risk to waterways to be approved, the Council of Canadians says.
The $12-billion pipeline would carry 1.1 million barrels of crude oil per day from terminals at Hardisty, Alta. and Moosomin, Sask. to refineries in Montreal, the Quebec City region and Saint John, N.B.
Energy East Pipeline
Crude not used in Eastern Canada would be exported to international markets from marine terminals built in Quebec and New Brunswick.
“We believe the proposal should be rejected,” said Andrea Harden-Donahue, a contributing author to a recent Council report on the pipeline titled Energy East: Where Oil Meets Water.
“From what we’ve been hearing from people, water ranks very high, if not at the top of the list of concerns regarding the risks of this particular pipeline.”
The report says the pipeline would cross at least 90 watersheds and 961 waterways, many of them on First Nations land.
“The potential damage from a major Energy East spill is massive,” it says. “What little we know of (diluted bitumen) spills is enough to show that we can — and must — say no to this pipeline to protect the waterways along its path.”
Shawn Howard, a spokesman for TransCanada, said via email that the pipeline will be designed to operate safely. The report “simply repackages the same claims that this opposition group has been making since we announced Energy East …
“It’s very easy to oppose everything, but much harder to be involved in solutions as companies like TransCanada are.”
Harden-Donahue said that in addition to posing threats to water supplies, Energy East would spur further oilsands development and lead to an increase in greenhouse gas emissions.
A social justice group, the Council opposes Energy East and all other pipelines that would transport Alberta bitumen to export markets, including Enbridge’s Northern Gateway and Line 9 Reversal projects, Kinder Morgan’s Trans Mountain Expansion and TransCanada’s Keystone XL.
It argues that instead of approving pipelines and encouraging further oilsands expansion, the Canadian government should develop strong policies to protect the environment and focus on renewable and sustainable energy solutions. It also urges government action on climate change.
TransCanada announced in August 2013 it was going ahead with Energy East. It filed a 108-page project description with the National Energy Board in March and is expected to submit a detailed application later this year. An environmental assessment would be required under the NEB Act and the Canadian Environmental Assessment Act.
“Our application will show that new pipe will be buried deeper and will use thicker walls and have strategically placed shut-off valves to protect water body crossings and other sensitive areas,” TransCanada’s Howard said.
“It will also outline our plans to minimize land disturbances, the advanced equipment we will use to monitor the flow of oil in the pipeline, how we will protect water bodies and other sensitive areas in the event of a leak, and the steps we take to ensure that we maintain the safety and integrity of our energy infrastructure network.”
dhowell@edmontonjournal.com

TIM MCMILLAN STEPPING DOWN AS MINISTER AND MLA – BECOMING CAPP PRESIDENT

TIM MCMILLAN STEPPING DOWN AS MINISTER AND MLA

Released on September 18, 2014

Rural and Remote Health Minister Tim McMillan today announced that he is stepping down from cabinet effective immediately and resigning as the MLA for Lloydminster effective September 30.
McMillan has accepted the position of President of the Canadian Association of Petroleum Producers (CAPP), effective October 1.
McMillan said it has been an honour to serve in the provincial government led by Premier Brad Wall.
“This province has seen such a positive change over the past seven years,” McMillan said.  “I feel extremely fortunate to have been part of the government during this remarkable period of growth and progress.”
Premier Wall said McMillan will be missed and wished him all the best in his new career.
“Tim has been a great MLA and Minister and I will miss his unique perspective at the cabinet table,” Wall said.  “As President of CAPP, I know Tim will continue working hard to develop our resource industry in western Canada, including here in Saskatchewan.”
McMillan noted he will be following all of the provisions of the new Saskatchewan Lobbyists Act which requires that a former minister cannot lobby the provincial government for one year after leaving cabinet.
McMillan was first elected in 2007 and was re-elected in 2011.  He has held several different cabinet portfolios prior to his appointment as Minister of Rural and Remote Health in June of this year.  These include Energy and Resources, Crown Investments Corporation, Saskatchewan Liquor and Gaming Authority and Tourism Saskatchewan.
Wall said for the time being, Health Minister Dustin Duncan will also handle the Rural and Remote Heath duties.  He plans to appoint a new minister shortly.
A byelection must be called by the Premier within six months of the date the seat becomes vacant.
-30-
For more information, contact:
Karen Hill Executive Council Regina Phone: 306-787-2127 Email: karen.hill@gov.sk.ca Cell: 306-5299207

New technology means a fast-pace output response to falling oil prices

New technology means a fast-pace output response to falling oil prices

Peter Tertzakian

Special to The Globe and Mail

Published Wednesday, Sep. 17 2014, 5:00 AM EDT

Last updated Wednesday, Sep. 17 2014, 5:00 AM EDT

 

When the economy slows down, wallets thin out and people have less money to spend. Drivers make fewer trips to the gas pumps. The demand for oil slackens quickly. The price of a barrel goes down. It’s not rocket science.

What about the other side of the oil market? If producers have less money to spend, does production decline swiftly too?

Historically, the output response to lower prices has been slow, much slower than consumer thrift. But that lagging reaction may be history. Because of science and innovation, the character of world oil production has radically changed. Since 2009, oil output has rocketed up in the United States and Canada, and not much elsewhere (see Figure 1). That’s not news. But what may be news is how vulnerable North America’s growth may be to the dropping oil price.

Non OPEC contributions to world oil supply

The price of a barrel of international light crude oil – measured by Brent – has hit its lowest level in more than two years. Discounted North American oil prices are softening sympathetically; inside the continent, crude prices are at least $5 to $10 cheaper than barrels labelled with Saudi, Nigerian and British flags. Some oil price analysts, feeding off slowing demand fundamentals in Europe and China combined with growing Libyan production, suggest that price could weaken more. And while we agree that lower prices are possible in the short term, we do not expect price markdowns to be long-lasting.

Here is why. For oil producers, a crude oil discount translates into less cash flow, less appeal to capital markets and therefore less spending power. Yet not all oil production is affected equally by less investment. The world’s 92 million barrels a day of oil production can be divided into four distinct types of production: Canadian oil sands; age-old onshore conventional wells; increasingly high-tech offshore production; and new-age hydraulically fractured tight oil.

Contrary to popular belief, oil will steadily flow from Canada’s oil sands, even with lower prices. Massive sunk costs, scale, and negligible decline rates mean that most existing operations in the region will keep producing, even if the oil price for West Texas intermediate were to reach $55 a barrel (U.S.) or below. The resilience of oil sands production was proven out during the financial crisis: Oil supply remained steady when the price of oil dropped to under $50 in the last few months of 2008.

Overwhelmingly, the bulk of the world’s output still comes from “conventional” vertically drilled onshore wells, combined with a growing wedge of supply from the larger scale and more technically challenging offshore projects. Historically, these production types have flowed reliably during low price episodes, and there has been a steady string of global megaprojects that have come online to offset legacy production declines.

But this landscape has changed. Producers from outside North America have been plagued with falling output, technical challenges, a lack of investment, outages due to civil war, corruption, sanctions or all of the above. New large megaprojects such as Kashagan or Brazil’s deep-water subsalt have been long delayed. Organization of Petroleum Exporting Countries production is increasingly prone to outages. Even assuming that new international developments come on line, once declines from the existing production base are factored in, the collective capacity expansion from outside North America is flat at best. Or looking through the lens from the other side, the reverse argument is that U.S. and Canadian hydraulically fractured light oil fields will mostly determine the industry’s free-market response to lower oil prices (OPEC may respond at some point, but that’s another story).

North America’s hydraulically-fractured, tight oil production follows a “just-in-time delivery” business model. When prices are robust, production can grow quickly, because each new well delivers very high initial production rates. However, high decline rates in these wells imply that output should fall off quickly when investment (drilling) is reined in. This downside hypothesis has never been tested, but if low prices were sustained, the economic experiment would be on.

Tight oil or shale oil exploitation is heavily dependent on the rapid recycling of cash flow and access to capital markets. Price weakness slashes unhedged cash flow. Price weakness also sours the appetite of capital markets to invest in oil companies. So production growth should moderate, or even retreat, with a low-price cash famine. This would, in effect, set a floor for the oil price. Depending on the rocks and the operator, the break-even price for North American tight oil varies widely. But we would expect that, notionally, the trigger price to start to witness an investment slowdown is about $85 a barrel for the West Texas intermediate benchmark (still about $10 under today’s price).

The just-in-time nature of North American tight oil, combined with the difficulties in adding new supply elsewhere, suggests that the world’s oil supply will quickly adjust to falling demand or surplus production. The lower prices go, the greater the probability they will rocket up again. But that’s not rocket science either.

Peter Tertzakian is chief energy economist at ARC Financial Corp. in Calgary and the author of two best-selling books, A Thousand Barrels a Second and The End of Energy Obesity.

TransCanada sees itself in oil train business regardless of Keystone: CEO

TransCanada sees itself in oil train business regardless of Keystone: CEO
Patrick Rucker
WASHINGTON — Reuters
Published Tuesday, Sep. 16 2014, 4:03 PM EDT
Last updated Tuesday, Sep. 16 2014, 4:07 PM EDT
Pipeline operator TransCanada Corp. is likely to haul Canadian oil sands crude by rail whether or not its embattled Keystone XL pipeline project is finally approved by Washington, the company’s chief executive said on Tuesday.
TransCanada is in its sixth year of waiting for the United States to approve or reject its plan for a 2,700 km cross-border pipeline that could carry at least 730,000 barrels a day of oil sands from Western Canada to Texas refineries.
In those years, Alberta oil sands output has climbed and producers have grown more desperate to find ways to bring fuel to market.
That glut might drive demand for both pipelines and additional oil train capacity, TransCanada Chief Executive Russ Girling said during a visit to Washington.
“I do believe we will have a rail facility,” Girling told reporters. “I don’t know the exact size. But I do think there will be one.”
The company is contemplating a “rail bridge” from the oil sands to a crude oil hub in either Cushing, Oklahoma, or Steele City, Nebraska, where its pipelines can be tapped.
“We have options on land. We have done our engineering on both locations. That work is all done,” Girling said after a meeting with U.S. Senator John Hoeven, Republican of North Dakota.
“My gut feeling would be (we) will probably be in that business,” Girling said.

Canada oil-train boom may thwart winter crude price slump

Canada oil-train boom may thwart winter crude price slump

Nia Williams

CALGARY — Reuters

Published Monday, Sep. 15 2014, 5:08 PM EDT

Last updated Monday, Sep. 15 2014, 5:14 PM EDT

 

Each winter for the past four years, Canadian oil sands producers have watched in dismay as local crude prices slumped.

Limited export pipeline capacity coupled with the end of the U.S. summer driving season led to oil gluts in Alberta, sending prices tumbling and depriving producers of billions in potential revenue.

Not this year, predict industry players.

Revamped U.S. refineries are absorbing heavy Canadian crude and new oil-rail terminals built by companies like Gibson Energy Inc. and Canexus Corp. are loading trains to deliver crude to markets across North America, and potentially abroad, limiting the downturn and keeping prices buoyant compared to the past seasons.

Thanks to the emergence of these “train pipes”, the market is “unlikely to get that deep of a squeeze on the deliver-ability side,” said Bart Melek, head of commodity strategy at TD Securities.

Shipping crude by rail can be up to twice as expensive as by pipeline, roughly $14 to $21 per barrel to the Gulf Coast. But just a small volume of such shipments could help avoid the short-term supply overhangs that have burdened the market for years.

In recent winters, the price of Western Canada Select (WCS) heavy blend crude has fallen to fetch between $33 and $42 per barrel less than the U.S. benchmark WTI crude, far cheaper than the typical discount of around $20 per barrel during the rest of the year.

With oil sands production at just under two million barrels per day, each $1 increase in the discount equates to some $2-million a day in lost revenues for producers like Cenovus Energy and Suncor Energy, and wipes billions of dollars a year off Alberta government revenues.

After U.S. oil tumbled to its lowest prices in nearly two years this month, a sudden slump in prices this winter would be particularly unwelcome. At around $79 per barrel, the absolute price in Canada is getting nearer the break-even cost for major new developments.

Thus far, Canadian crude is holding up well around $13.50 per barrel under WTI, which fetched about $93 a barrel on Monday. That was the narrowest differential since July, 2013.

Some traders say WTI minus $20 per barrel is now a realistic floor for discounts – with the dark days of minus $40 a thing of the past.

A $20 discount would improve the economics of crude-by-rail. In Calgary they say a rule of thumb is WCS should trade around $15 to $20 per barrel below WTI to be worth railing to the U.S. Gulf Coast, where it competes with Maya, a Mexican blend of similar quality.

“There may be periods of lower differentials in which rail is less profitable than pipeline, but there are still benefits to transportation by rail including new market development,” said Cenovus spokeswoman Jessica Wilkinson.

WINTER WOES

Some of the factors behind the winter slump in Canadian crude prices remain: North American refiners still shut down for maintenance in the autumn, diminishing demand for crude. Road construction also tends to ebb, limiting the need for asphalt, a significant by-product of refining heavier oil sands crude.

Seasonal discounts are exacerbated by congestion on Canadian export pipelines that can leave crude bottlenecked in Alberta, sparking wild price swings. TransCanada’s Keystone XL pipeline, which was proposed more than five years ago to help relieve congestion, has been repeatedly delayed by the Obama Administration amid fierce environmental opposition.

Congestion can be worse during cold weather, which makes oil sands bitumen even more viscous than usual and forces producers to blend in a higher proportion per barrel of ultra-light oil known as condensate so the bitumen can be shipped through pipelines, according to traders. This means there are higher volumes of diluted “dilbit” crude squeezing through an export network already pumping flat out.

But several important factors have changed, including the expansion of key North American refiners that have invested billions of dollars in consuming more Canadian heavy crude.

This will be the first full winter for BP Plc’s revamped 405,000 bpd Whiting, Indiana, refinery, which has been upgraded to process 80 per cent Canadian heavy grades.

RAIL TO THE RESCUE

The larger factor is the emergence of the oil-by-rail industry, with a host of operators building new terminals to help mop up barrels that would otherwise be stranded in Alberta.

National Energy Board data shows Canada exported 163,000 bpd of crude by rail in the second quarter of 2014, a 22 per cent rise on the same period a year earlier. That figure does not include shipments to major refineries in eastern Canada.

The Canadian Association of Petroleum Producers estimates current rail loading capacity is much higher at around 800,000 bpd and could hit 1.4 million bpd in 2016.

Certainly, there is a risk that current firm prices will pull back. Supply outages as a result of planned maintenance currently taking place in the oil sands will come to an end, and demand from linefills on Enbridge Inc’s new Flanagan South and reversed Line 9 pipeline is finite.

Jackie Forrest, analyst at ARC Financial, said if there are no big outages on pipelines, WCS differentials should widen to reflect the cost of rail transportation from Alberta to the Gulf Coast. Right now they reflect the cost of moving a barrel by pipeline.

Forrest said if differentials widen to reflect rail economics WCS would trade around $15 per barrel below Maya, or $20 per barrel below WTI.

“With more market options via new pipe connections and rail, we expect large discounts to be less in number and duration than compared to the past,” she added.

Environmental extremism a rising threat to energy sector, RCMP warns

Environmental extremism a rising threat to energy sector, RCMP warns

Shawn McCarthy

OTTAWA — The Globe and Mail

Published Sunday, Sep. 14 2014, 5:08 PM EDT

Last updated Sunday, Sep. 14 2014, 7:29 PM EDT

 

RCMP analysts have warned government and industry that environmental extremists pose a “clear and present criminal threat” to Canada’s energy sector, and are more likely to strike at critical infrastructure than religiously inspired terrorists, according to a report released under Access to Information.

Written by the force’s critical infrastructure intelligence team, the 22-page RCMP document argues there is a “growing criminal phenomenon” associated with environmentalism that aims to interfere with regulatory reviews and force companies to forego development.

“Environmental ideologically motivated individuals including some who are aligned with a radical, criminal extremist ideology pose a clear and present criminal threat to Canada’s energy sector,” said the report, written in March 2011. Since then, the RCMP has held regular meetings with energy companies and federal officials to review potential threats to infrastructure, and faces formal complaints that it conducted surveillance on environmental groups that oppose construction of Enbridge Inc.’s Northern Gateway pipeline.

The paper highlighted Canada’s oil sands sector as one that has attracted considerable opposition because it is a major producer of greenhouse gases that cause climate change. Law enforcement and national security officials worry about a “growing radicalized environmentalist faction” who oppose the oil sands and other energy development, it said.

The oil industry has run into vehement opposition to plans for crude oil pipelines through British Columbia and across the country to the port of Saint John, N.B. But the oil sands sector needs access to new markets – whether in the U.S. Gulf Coast, Asia Pacific, or the Atlantic basin – if it is going to meet ambitious growth plans that would see production doubling to four million barrels per day by 2025.

Some First Nations leaders warned their people may resort to whatever means necessary to block construction of the Northern Gateway pipeline. But neither First Nation leaders nor environmental groups have advocated violence.

Most of Canada’s counter-terrorism effort has been aimed at international jihadis, and there have been a number of high-profile prosecutions against Canadian residents who plotted to conduct attacks either at home or abroad.

“In reality, criminal occurrences attributed to environmentalists have and are more likely to, occur within Canada,” the report said. It added that the Canadian Security Intelligence Agency (CSIS) monitors individuals and organizations that might be involved in domestic terrorism, “including the threat or use of violence by groups advocating for issues such as the environment.”

Carleton University criminologist Jeff Monaghan, who obtained the document, said the RCMP authors constructed a trend from isolated incidents. He worries police and other security agencies are using anti-terrorism legislation to broaden their investigation and monitoring of groups who oppose development.

RCMP spokesman Greg Cox denied the force is targeting protesters or environmental groups in general. “The RCMP does not investigate individuals, groups or movements, but will investigate the criminal activity of any individuals who threaten the safety and security of Canadians.”

Neither Mr. Cox, nor CSIS spokeswoman Tahera Mufti would comment on formal complaints launched by the B.C. Civil Liberties Association that claim the agencies have conducted improper surveillance activities against law-abiding citizens who oppose the gateway project.

Ottawa lawyer Paul Champ filed the complaints with the RCMP’s Commission for Public Complaints and the Security Intelligence Review Committee, backed by numerous documents obtained under Access to Information, which, he said, show the two agencies were actively monitoring and even infiltrating environmental and aboriginal groups involved in Gateway hearings before the federal review panel, which wrapped up last year.

Canadian oil and gas extraction industry: Capital and operating expenditures, 2013

Oil and gas extraction industry: Capital and operating expenditures, 2013

Statistics Canada – September 12, 2014

http://www.statcan.gc.ca/daily-quotidien/140912/dq140912c-eng.htm?cmp=mstatcan

Capital expenditures by the conventional oil and gas extraction industry increased 9.0% from 2012 to $42.8 billion in 2013.

Non-conventional sector capital expenditures rose 12.6% to $31.2 billion.

Operating expenses for the conventional sector increased 15.4% to $30.3 billion.

For the non-conventional sector, operating expenses were up 19.7% to $28.6 billion.

Oil and gas Sept 2014

Crescent Point courts U.S. investors

12 Sep 2014
Calgary Herald
REBECCA PENTY BLOOMBERG
Crescent Point courts U.S. investors
Firm’s assets called ‘No. 1 in North America’
Crescent Point Energy is broadening its push for U.S. shareholders as a $1.7 billion buying spree fails to charm investors at home.
An oil discovery in Saskatchewan and four purchases set Crescent Point up for a potential dividend increase and production growth that some investors aren’t recognizing, says chief executive Scott Saxberg. After listing shares in New York, the company — Canada’s most acquisitive energy player this year — is boosting the number of U.S. investor meetings and seeking bank coverage south of the border.
“We’ve spent more time pushing on the U.S. retail and U.S. shareholder base and our goal for the next year is to focus on that,” Saxberg said in an interview at the company’s Calgary office. “We’re unique to U.S. investors because they don’t see companies hand out a dividend.”
Crescent Point is trying to reverse declining U.S. ownership of its shares as investors chase soaring output growth by shale producers from Texas to North Dakota. While its dividend yield is almost double the average for North American peers, it also isn’t getting as much credit in Canada for its returns as others emulating its model, Saxberg said.
American investment in the company has slumped to 24 per cent from 43 per cent two years ago, data compiled by Bloomberg show.
The seventh most valuable Canadian producer, Crescent Point was among the nation’s top-performing energy stocks from 2004 to 2011. This year, it’s returned 7.4 per cent including dividends, trailing the 19 per cent gain in the Standard & Poor’s/TSX Energy Index and a 40 per cent increase for Calgary-based Whitecap Resources Inc., which has spent $1 billion on purchases this year.
“Canadian investors alone can’t move the stock anymore,” said Ryan Bushell, a portfolio manager at Leon Frazer & Associates Inc. in Toronto. “I look at other companies doing deals and I see how they’re getting rewarded.”
Saxberg, who owns an apartment in Manhattan, has expanded his number of visits to New York for marketing meetings to about eight times a year. Crescent Point’s office in Denver is growing and the company is convincing U.S. banks to follow the stock, he said.
Goldman Sachs Group Inc. and Raymond James Ltd. expanded coverage to include Crescent Point this year. Goldman recommends investors buy the stock and Raymond James, currently restricted, previously recommended the equivalent of a buy since June, according to data compiled by Bloomberg. The stock has 12 buy, two hold and one sell recommendation.
One of Crescent Point’s challenges is explaining why it provides a dividend instead of reinvesting all of its cash into producing more oil, like most U.S. rivals, Saxberg said. He likens the company’s structure to that of a U.S. master limited partnership, or MLP, which producers like Los Angeles-based Breitburn Energy Partners LP have pursued to make distributions to unitholders.
The company’s dividend yield, currently at about 6.5 per cent, compares with 3.4 per cent on average for North American oil and gas producers, data compiled by Bloomberg show.
Its per-share production growth of 3.9 per cent over the past year, compares with a 3.2 per cent median for peers.
Crescent Point may struggle to win over U.S. investors unless it boosts production and dividends without paying for expensive acquisitions with equity, said David Neuhauser, a hedge fund manager at Livermore Partners in Northbrook, Ill.
“The worry for me is they’re not acquiring these companies out of cash flow,” Neuhauser said.
Investors should focus on the long-term growth Crescent Point can recoup from its properties, Saxberg said, calling its assets “No. 1 in North America.” The company has never lowered its dividend and will be able to boost it if oil prices rise next year, he said.
The producer may also win more U.S. shareholders by appealing as an alternative to potentially unsustainable high- growth shale wildcatters financed by junk bonds, said John Stephenson, portfolio manager and chief executive at Stephenson & Co. in Toronto.
Crescent Point will have to deliver higher production growth to compete, he said.
“I own the stock and I’m a little frustrated it hasn’t taken off,” Stephenson said. “I’m looking more for growth than I am for income right now and I think other people are too.”

Putin’s oil deals with Exxon, Shell under threat from sanctions

Putin’s oil deals with Exxon, Shell under threat from sanctions
Indira A.R. Lakshmanan and Joe Carroll
Bloomberg News
Published Wednesday, Sep. 10 2014, 1:02 PM EDT
Last updated Wednesday, Sep. 10 2014, 1:34 PM EDT
The U.S. and European Union are poised to halt billions of dollars in oil exploration in Russia by the world’s largest energy companies in sanctions that would cut deeper than previously disclosed.
The new sanctions over Ukraine would prohibit U.S. and European co-operation in searching Russia’s Arctic, deep seas or shale formations for crude, according to three U.S. officials who spoke on condition of anonymity because the measures haven’t been made public. If implemented, they would affect companies from Dallas to London, including Exxon Mobil Corp. and BP PLC.
The EU is set to decide as soon as Wednesday whether to trigger the sanctions this week or wait longer to see whether a ceasefire holds between Ukraine and pro-Russian separatists and whether Russia backs moves toward a longer-term agreement.
Once the EU implemented the new ban on sharing energy technology and services, the U.S. would follow suit with a similar package, including barring the export of U.S. gear and expertise for the specialized exploration that the Russians are unequipped to pursue on their own, the U.S. officials said.
EU leaders agreed on these oil-related sanctions on Sept. 8 as part of a wider package of measures intended to hobble Russia’s finance, defence and energy industries, pending evaluation of the cease-fire declared in Ukraine last week, according to two European officials who also spoke on condition that they not be named.
‘Very Big Deal’
The added sanctions wouldn’t interfere with drilling and production from conventional land-based wells and those along the shallow edges of inland seas, some of which have been pumping crude for decades. The sanctions target reserves that wouldn’t begin providing crude to global energy markets for five to 10 years.
The move would go beyond previously reported proposals to widen curbs on technologies for the oil industry by banning such co-operation, levying a heavy toll on Russia’s $425-billion-a-year petroleum industry.
No companies outside the U.S. and Europe have the specialized techniques for extracting crude from deep-sea fields and shale formations.
“If true that new sanctions were to ban technology and services for Arctic, deep-sea and shale exploration, that would be a very big deal,” Jason Bordoff, former energy adviser to President Barack Obama and founding director of the Center on Global Energy Policy at Columbia University in New York, said Wednesday in an e-mail. “It would significantly curtail Russia’s future oil production capacity, although it is important to note that it would require close collaboration between Europe and the United States to be effective.”
Russia’s Dependence
While the U.S. doesn’t intend to allow exemptions for existing contracts that would be affected, the American officials said they weren’t certain whether the EU would provide more leeway.
The stakes are high for Russian President Vladimir Putin because of his government’s dependence on the energy industry to drive economic growth, with a growing reliance on U.S. and European technology and services to exploit fields that pump one of every eight barrels of crude produced worldwide every day.
Since Russia’s annexation of Ukraine’s Crimea peninsula six months ago, the U.S. and EU have imposed steadily more painful sanctions on Putin’s inner circle of politicians and billionaires as well as on banks, energy and defence companies close to the Kremlin in an effort to force Putin to abandon efforts to divide and destabilize Ukraine.
Economic Hammer
The U.S. and EU wield a massive economic hammer: Combined, the allies account for 39 per cent of the globe’s economic output, compared with Russia’s 3 per cent. While the economic penalties taken before this week have been significant – including limiting Russian banks’ and energy companies’ ability to raise debt financing – a ban affecting key types of oil exploration would go a significant step further toward choking Russia’s future economic growth.
U.S. and EU explorers operating in Russia would be barred under the new decrees from bringing in experts and rig crews crucial to unlocking billions of barrels of crude locked in offshore Arctic or Siberian shale fields, according to the government officials.
In the Arctic, drill bits that can cost thousands of dollars apiece need to be replaced constantly and some of the world’s best-trained engineers, geophysicists and geologists must be flown in when needed to troubleshoot problems as they arise.
Exxon-Rosneft The ban on co-operation would close gaps in previous rounds of sanctions that left room for a unit of Bermuda-based Seadrill Ltd. to sail the West Alpha floating rig into Russian waters in late July on behalf of Irving, Texas-based Exxon Mobil and Moscow’s state-controlled OAO Rosneft.
The arrival of the rig, as well as the signing of six new Seadrill contracts with Rosneft on July 29, just as the last round of sanctions was imposed, angered U.S. and European officials who said the moves flew in the face of the intention behind the economic restrictions: to freeze Arctic exploration by Russia.
Some of the costliest, most complex drilling forays ever attempted in Russia may be in limbo, including a $700-million well that Exxon and Rosneft began to drill last month in the Kara Sea.
Tillerson’s Stance
For Exxon, Russia represents its biggest exploration prospect outside its home country. Exxon owns drilling rights across 11.4 million acres of Russian land and seafloor, an area twice the size of Massachusetts. Exxon’s $411.3-billion market valuation makes it the world’s largest energy company; its annual sales exceed the economic output of all except 28 nations.
Exxon, which has partnered with Rosneft on Russian oilfields for more than a decade, expanded its relationship with the Moscow-based company in 2011 by signing a $3.2-billion exploration pact. Chairman and Chief Executive Officer Rex Tillerson expressed doubts in May that sanctions on Russia would prove effective. In June, he appeared on stage alongside Rosneft CEO Igor Sechin, a former Soviet spy who is under personal sanctions barring him from traveling to the U.S., at the World Petroleum Congress in Moscow.
Putin called Exxon “an old and reliable partner” during a ceremony last month marking the start of drilling at an offshore Arctic prospect called Universitetskaya that may hold nine billion barrels of crude. At current market prices, that would be a $894-billion bonanza.
“We are assessing the situation,” Alan Jeffers, an Exxon spokesman, said yesterday in a telephone interview when asked about the prospect of further sanctions. “We always follow the law.”
Shell’s Investments
Other vulnerable international operators include Royal Dutch Shell Plc, the world’s second-largest energy company by market value. Multiple investments by The Hague-based company in Russia include ventures to use advanced reservoir-management techniques to revive and increase crude output from Soviet-era fields and to explore some of the nation’s vast, untapped shale formations.
“We are continuing to review the latest sanctions to assess the potential impacts on our business, and engaging with the respective authorities to gain further clarity,” Kayla Macke, a Shell spokeswoman, said in an e-mail. “We are taking action to ensure we comply with all applicable sanctions or related measures. We’re keeping the situation under close review.”
Total, Statoil BP’s 19.75-per-cent ownership stake in Rosneft is the biggest foreign direct investment in Russia.
“We will look at any new sanctions and we will of course comply with all applicable sanctions,” Toby Odone, a spokesman for BP, said by phone.
In addition to Shell and BP, Russia’s deals with marquee European oil companies includes Paris-based Total SA and Stavanger, Norway-based Statoil ASA. Total relies on Russian wells for almost 10 per cent of its global output. A spokeswoman for Total declined to comment.
“This is something we’re monitoring closely,” Statoil Chief Financial Officer Torgrim Reitan said in an interview in Oslo today. “Our positions in Russia have a very long time horizon.”
Last month, Statoil CEO Helge Lund said at a conference in Stavanger, Norway, the existing sanctions regime would delay some of the company’s planned joint-venture projects with Rosneft. Statoil, which is 67 per cent owned by the Norwegian government, was bracing for longer approval processes for exporting equipment and services to Russia, Lund said at the time.

Record capital stoking the oil and gas industry

Record capital stoking the oil and gas industry

Peter Tertzakian

Special to The Globe and Mail

Published Wednesday, Sep. 10 2014, 5:00 AM EDT

Last updated Wednesday, Sep. 10 2014, 10:24 AM EDT

 

Money is being shovelled into the Canadian oil and gas industry like coal into a furnace. Year to date, hot markets have already offered up $19.6-billion to oil and gas producers. By the end of the year, upstream companies are on track to take in $26-billion from banks and equity investors. The dollar volume will stoke a record year, exceeding the $25.5-billion haul in 2007.

Energy capital

Here are five reasons why the money is coming in at a record pace:

Profitability

Over the past year, the Canadian dollar is down a dime, natural gas prices have doubled off 2012 lows, and oil price discounts have narrowed. These top-line fundamentals have helped decompress the industry’s bottom line. Compared to the dark period between 2010 and 2013, average industry profitability at the wellhead is running 30 to 50 per cent higher this year, depending on company type and commodity focus. Savvy producers are making money again and investors have noticed.

Innovation

Nothing instills a sense of urgency more than collapsing margins. Between 2010 and 2013, Canadian producers were realizing the lowest oil and gas prices in the world (they still are, just not as low). Empty pockets sharpened the need to innovate processes and make cost discipline an imperative. Progressive companies became lean and mean by scaling up and using new technology. Lower costs served this group well when the prices rallied. These are the same producers that are attracting a lot of the new capital inflow.

Resource potential

Ten years ago, the oil sands region was recognized as the only multibillion-barrel resource left in the free-market world of oil. Natural gas in the U.S. and Canada was considered “mature.” Then came the shale gas revolution, followed shortly thereafter by tight oil. American plays like the Marcellus, Bakken and Permian Basin demonstrated that billions of barrels of new oil, and trillions of cubic feet of natural gas, could be liberated through new drilling and completion processes. Yet neither geology nor capital recognizes political borders.

Outside investors have been correctly sensing that Saskatchewan, Alberta and northeastern B.C. are ripe for the same innovative extraction techniques that have made Pennsylvania, North Dakota and Texas immature again.

Continentalization

No it’s not a word. But it means that the U.S. and Canadian oil and gas businesses are becoming increasingly integrated, especially on the oil side. The advent of shipping oil by rail began creating many new supplier (producer) and customer (refiner) relationships across the U.S.-Canada border. Savvy investors looked beyond the Keystone XL issue and saw alternatives to one steel pipe. In part, greater market access is why average profitability between the U.S. and Canadian industries has equalized over the past year. During the dark period, U.S. mid- and small-capitalization producers were realizing between $7 to $10 a barrel of oil equivalent more than their Canadian brethren. Not any more. A tighter knit, continental market has led to continental investing.

Risk and return

Canada’s oil and gas industry does have social, political and environmental friction that tends to add to cost. But contrast that kind of rub with civil war, corruption, the threat of expropriation and sanctions found in the rest of the world. Events over the past twelve months have made investment into places like Iraq, North Africa and Russia riskier without any proportional improvement in returns. In fact, the application of new technologies to shorter cycle time projects here is improving the risk-return profile of North America’s industry, while that of the rest of the oil and gas world is deteriorating. This widening risk premium makes it more appealing for foreign capital to come to Canada (and the U.S.); the record inflow of investment capital validates the sentiment.

Canadian investment is set to surpass the 2007 high. Back then the fires of investment were stoked too hot, causing imbalances in the demand for labour and services. Today’s industry has greater capacity to absorb capital, but how much more has yet to be tested. We’ll be watching the gauges carefully.

Peter Tertzakian is chief energy economist at ARC Financial Corp. in Calgary and the author of two best-selling books, A Thousand Barrels a Second and The End of Energy Obesity.

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