OPEC and non-OPEC members have pledged to cut their combined oil production by an average of just over 1.7 million barrels per day (bpd) in the first six months of 2017.

Saudi Arabia and its Gulf allies are expected to implement most of their cuts immediately, but other producers both within and outside the Organization of the Petroleum Exporting Countries are likely to phase in the reductions gradually.

The collective cut should increase progressively over the first half of 2017 and have its biggest impact on the supply-demand balance from the second quarter onwards.

Market tightening should be felt at the start of summer as output cuts are fully phased in, U.S. refineries ramp up for the driving season, and crude combustion in Saudi Arabia and Iraq starts to rise.

Compounding this effect, continued underlying growth in oil consumption in both OECD and non-OECD economies during the first six months should also help progressively tighten the supply-demand balance.

OPEC and non-OPEC members also have given themselves the option to extend the cuts for a further six months depending on prevailing market conditions.

If they decide on an extension, the supply-demand balance could tighten even more quickly in the second half of 2017.

CONTANGO VANISHES

Most traders expect market rebalancing to be backloaded, with futures prices trading in contango in the first half of 2017 but then moving to level or backwardation in the second half.

The structure of prices is consistent with a gradual phase-in of cuts during the first semester and their extension into the second (“Brent curve signals oil tanks will start emptying in second half of 2017”, Reuters, Dec. 21).

But the different pace of production cuts for different countries increases the risk of non-compliance, especially toward the end of the first half and in the second half of 2017.

If the agreement succeeds in raising prices and drawing down excess inventories, some countries may not deliver all the cuts they have promised.

Compliance is likely to be greatest by Saudi Arabia and its allies at the start of the period, and least by countries such as Russia toward the end.

PRODUCTION OPTIONS

In most cases, a new well will produce its highest daily output in the first days, weeks and months after completion, when the natural pressure in the reservoir is greatest.

Daily production tends to decline progressively thereafter as pressure falls (“Petroleum geology, exploration, drilling and production”, Hyne, 2001).

Production rates can be described by a decline curve (“The decline and ultimate production of oil wells”, Beal, 1919).

Oil producers employ several methods to offset production declines from existing wells and maintain field output.

New wells can be drilled to replace declining production from existing holes (either within the same reservoir or from a new one).

Surface pumps or downhole pumps can be employed to raise more oil from old wells by providing artificial lift to replace natural field pressure.

And production from old wells can be stimulated by injecting water, gas and chemicals into the producing formation to sweep more of the remaining oil toward the well bores and help it flow more easily.

Most producing countries have a mix of old and new wells, of varying vintages and at various stages of decline, some on artificial lift or being stimulated by secondary and tertiary recovery techniques.

Producers therefore have a menu of options for cutting output by shutting in or choking back existing wells, discontinuing artificial lift, ceasing to drill new holes, or scaling back secondary and tertiary recovery.

Hinting at the importance of these options, non-OPEC countries have committed “to reduce their respective oil production, voluntarily or through managed decline, in accordance with an accelerated schedule”, OPEC said.

HOW TO CUT OUTPUT

Saudi Arabia and its allies are likely to cut production by shutting in or possibly choking back output from older wells in older fields.

Saudi Arabia shut in more than 1,000 wells during the last round of OPEC cuts in 2008/9, according to an analysis of well data (“Annual Statistical Bulletin”, OPEC, 2016).

Most of those were less productive (and presumably older) because the number of wells still in production dropped much more than the decline in actual output.

Production per active well rose sharply, indicating older and less productive wells were shut while newer and more productive ones continued to flow.

Much of Saudi Arabia’s famed output flexibility comes from the kingdom’s ability to shut in or reopen hundreds of older wells in older fields.

Shutting old fields and wells makes economic sense because it can extend their lives and increase the amount of oil ultimately recovered from them.

Conversely, Saudi Arabia can boost output by bringing old wells back into production, but at the cost of lower ultimate recovery (“Cost of pump-at-will oil policy spurred Saudi OPEC U-turn”, Reuters, Dec. 15).

So this time around Saudi Arabia is likely to meet most of its output-cutting commitment by resting older wells and older fields, which can be implemented fairly quickly.

Kuwait and the United Arab Emirates are likely to employ a similar strategy that will deliver production cuts quickly.

Saudi Arabia has already implemented its cuts fully, a Gulf source familiar with Saudi oil policy said on Thursday (“Saudi Arabia cut oil output in Jan to 10.058 million bpd”, Reuters, Jan. 5).

ARCTIC AND SUB-ARCTIC

Onshore and shallow offshore wells in Saudi Arabia and its Gulf allies are relatively straightforward to close, but shutting in wells in other countries will be more difficult.

Russia, in particular, has warned it cannot close some existing wells in Arctic and sub-Arctic regions without risking irreversible damage.

Oil comes up from deep underground at high temperatures and helps prevent damage to wells and field equipment in the frozen north.

The problem of shutting in existing wells is obviously greatest during the northern winter, when it affects the maximum number of wells.

Russia is therefore relying on natural decline and a reduction in new well drilling to meet its commitments under the deal.

Relying on field declines rather than shutting existing wells also makes it easier for Russia to secure the assent of its myriad private producers.

BACKLOADED CUTS

In recognition of these problems, Russia and other non-OPEC producers secured the right to phase in cuts and average them over the entire six-month period.

Officials in Moscow have repeatedly said cuts will be phased in gradually, meaning Russia is likely to deliver its deepest reductions only at the end of the six months.

Backloading creates a temptation to cheat, however, since the full extent of any non-compliance will become evident only in the second half of 2017.

If the supply-demand balance has started to tighten by that stage, the market may be able to absorb a level of non-compliance without so much impact on prices.

However, if OPEC and non-OPEC deliver their promised cuts, including backloading, and extend them into the second half of the year, oil inventories could shrink rapidly later in 2017.

http://www.reuters.com/article/us-opec-production-kemp-idUSKBN14Q1DQ

IRAN OIL HELD ON TANKERS FALLS TO 16.4 MLN BARRELS VS 29.6 MLN IN OCT 2016 AND 29.7 MLN BARRELS IN JAN 2016 – DATA. RTRS.

@Lee_Saks

A Nigerian militant group, which has claimed a wave of attacks on oil pipelines in the Niger Delta, said on Friday that it had asked its fighters to prepare to fight the "enemy" as authorities were not ready for dialogue.

The Niger Delta Avengers had declared a ceasefire last year after staging major attacks on oil facilities crippling the OPEC member's oil output in a fight for more oil revenues to give dialogue with authorities a chance.

The government has been holding talks for more than six months with Niger Delta leaders to address grievances of poverty and oil pollution in the southern region but former militants have complained that no progress has been made.

"It has been evidently clear that the Nigerian state is not ready for any form of dialogue and negotiation," the Niger Delta Avengers said in a statement posted on their website.

"All fighters and commands are hereby placed on high readiness in your webs of operations to hit and knock the enemy very hard," the group said.

It declared the start of an "Operations Walls of Jericho and Hurricane Joshua ... to reclaim our motherland" but did not say whether this meant an end of the ceasefire or gave any details.

The Avengers, like other militant groups, has split into different factions, which struggle to control their fighters, unemployed young men who work for anybody who pays them.

Another former militant group, the Movement for the Emancipation of the Niger Delta (MEND), which had agreed to lay down arms in 2009, had said a week ago it had lost trust in the government to bring peace to the region.

Those behind the pipeline attacks, which began in early 2016, say they want a greater share of Nigeria's energy wealth to go to the southern region. The frequency of attacks has diminished since President Muhammadu Buhari held talks with community leaders but there are sporadic attacks, most recently in late November.

The attacks cut Nigeria's oil production, which stood at 2.1 million barrels per day (bpd) at the start of 2016, by more than a third in the summer although the oil minister said in December pipeline repairs lifted output to nearly 1.8 million bpd.

http://www.reuters.com/article/us-nigeria-oil-militants-idUSKBN14Q2HN

With 2016 behind us, energy intelligence groups have begun dishing out their takes on the energy sector for 2017.

One of them, S&P Global Platts, an independent provider of information and benchmark prices for the commodities and energy markets, has shared its view on what to watch this year when it comes to oil market.

In its forecast on Friday, Platts says that the recent OPEC-led global production cut – first in 15 years -underpins an emerging but fragile recovery, with 2017 set to see a huge stock overhang disappear by the third quarter and the oil market move from over-supply to a more balanced supply/demand situation.

Great deal of optimism

With Saudi Arabia and Russia joining forces to cut production by almost 800,000 barrels a day in the first half of 2017, and other oil producers under pressure to comply with their share of cuts to bring the total close to 1.8 million b/d, there remains a great deal of optimism in some quarters that the pace of rebalancing will be accelerated; in others there is skepticism that OPEC and its non-OPEC associates can really deliver, the intelligence group added.

However, Platts has pointed out that the pace of the rebalancing of the oil market will also depend on the discipline to enforce and maintain the cuts across “a disparate group” of oil producers, especially with “crisis-ravaged” OPEC members Libya and Nigeria exempted from the agreement, but with the potential to see large additions in output.

Opec=Floor/Shale=Ceiling

Moreover, Platts said, the speed of return by US shale producers could ultimately keep a lid on prices. Most oil companies appear generally optimistic that prices will rise to a more sustainable level in 2017, but spending is likely to stay modest for now and production growth moderate. Caution is likely to dominate the North Sea oil industry, with a mini-revival in production in the last two years juxtaposed against years of decline since production peaked in 1999, Platts said.

Paul Hickin, Oil Editorial Director, S&P Global Platts: “The next few years will be shaped by the relationship between US shale and OPEC, Russia and other key oil producers. This landmark agreement between OPEC and non-OPEC is providing a floor to oil prices and US shale is providing the ceiling. Compliance to the deal until the stock overhang disappears, most likely by the third quarter of 2017, according to Platts estimates, will be pivotal to ensuring the price floor holds, while the speed of return of US shale will determine how low the ceiling becomes.”

Marked increase for U.S. exports

Reflecting large production cost reductions and productivity gains, Platts Well Economics Analyzer estimates that if US crude benchmark West Texas Intermediate reaches $65/b, leading US production areas have an internal rate of return of between 35 and 40%. The Permian Basin could be the biggest beneficiary of expected double-digit increases in capital budgets in 2017. Platts Analytics forecasts that production in the West Texas/New Mexico basin will reach 2.226 million b/d in 2017 up from slightly below 2 million b/d in 2016.

“An increase in US crude production and a wider WTI-Brent spread since the end of 2016 are raising hopes that 2017 will be the year when US crude exports see a marked increase.” Platts said.

Also, the energy intelligence group forecasts that, for the third year in a row, India’s oil demand growth will outpace China’s. Platts Analytics is forecasting a 7% rise to 4.13 million b/d in Indian oil demand in 2017, compared with a 3% rise in Chinese oil demand to 11.50 million b/d.

http://www.offshoreenergytoday.com/platts-oil-stock-overhang-could-disappear-by-3q-2017/

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Attached Files

BP has today renewed its commitment to the North Sea – by announcing the creation of more than 500 jobs.

It comes as the oil giant completed a “once in a lifetime” double win for the region, with the installation of all the major modules for its Clair Ridge platform and the imminent arrival of Glen Lyon FPSO to the west of Shetland.

In his first sit-down interview since being named BP’s North Sea president, Mark Thomas said: “This is our home. This is where BP has matured and we feel this is our backyard.”

This week, BP will have completed the installation of the modules for Clair Ridge and its Glen Lyon FPSO will arrive in the west of Shetland, unlocking a combined one billion barrels of oil over the next 40 years.

Speaking exclusively to Energy Voice, Mr Thomas said: “It’s not very often in an oil and gas basin that in the course of five days you have two major projects basically sailing to the field.

“It should never be taken for granted.

“The north-east is a mature basin but we are looking towards the future, particularly in the west of Shetland, and we see that as a growth opportunity.

“When was the last time you ever heard someone talk about the North Sea as a growth opportunity? And that’s what we’re looking at. West of Shetland is a place we want to invest and be in for the next three or four decades.

“In this environment people say, ‘Really can you look that far ahead?’

“And in this environment, absolutely we can.”

The 534 jobs are linked to the hook-up and commissioning of the two projects. The work is expected to last 18 months. The jobs, which are being sourced by Amec, need to be filled by July 4.

“It is nice to give a little bit of economic stimulation to the north-east,” Mr Thomas added.

“The region could use it right now. And there are some very high-quality resources available, so we’re getting top-notch people to come out to do the construction for us.”

The jobs boost comes after BP was forced to shed 600 of its 3,000-strong North Sea workforce earlier this year.

Mr Thomas, who had only been in his post for a few weeks when the cuts were made, said: “We wanted to make sure we could do this once if at all possible. So while our numbers have been quite big – we’ve probably had the biggest announcement of any of the companies – we wanted to make sure when we were through we could take the company to a different level of performance.

“We wanted to be prepared and well placed for the future as we saw it, and do right for the company. And at the same time do right for the people who remain in the organisation as well as those exiting the company.”

Despite the job losses, BP continues to invest. Last month, it doubled its stake in the North Sea’s Culzean development. Over the last five years it has invested $10billion in the North Sea. Last year, it invested a $1billion into its aging ETAP field, securing its future through 2030.

The North Sea president said it was exciting that the Glen Lyon project was finally coming to fruition, and said it would be “magnificent” when it was finally online.

“Glen Lyon is a project that was years and years in the making and all of sudden it’s there,” Mr Thomas said.

“It’s going to be in the field this weekend and start hook-up. It will be online towards the end of the this year or early 2017.

“To have that happen in itself is magnificent.

“And then over course of five days, to have five big modules together weighing 30,000 tonnes sail-out into the Shetlands and be installed into the jacket flawlessly – I mean that’s a once in a lifetime opportunity. For most project engineers that is the one opportunity in their whole career to see that, and here we’ve seen that twice in the matter of one week.

“There’s not many other oil and gas basins in the world today that can say they’ve seen that type of activity in such a short time.”

https://www.energyvoice.com/oilandgas/north-sea/111250/exclusive-bp-creates-500-north-sea-jobs/

Russia's Gazprom said on Saturday its daily supplies of natural gas to countries outside of the former Soviet Union have reached a record high due to cold weather in Europe.

Gazprom pumped 615.5 million cubic meters of gas to countries outside the former USSR borders on Jan. 6, beating its previous record hit on Jan. 5 by nearly 1 million cubic meters.

"We have reached a totally new level of gas exports in conditions of a cold snap, lower extraction volumes in Europe and higher demand for gas on the energy market," Gazprom's CEO Alexei Miller said in a statement.

Gazprom delivers around a third of EU's gas, and the recent spike in European demand boosted Gazprom's supplies through Nord Stream pipeline to an all-time high of 165.2 million cubic meters in the past few days, up from 160.75 million cubic meters on Jan. 1., Gazprom said.

The current volumes of gas supply, if extrapolated throughout the year, exceed the Nord Stream's projected volumes by 10 percent, Miller said.

http://www.reuters.com/article/us-gazprom-exports-record-idUSKBN14R0DD

Libya's UN-backed government will declare force majeure on two ports to stop fuel smuggling from them, a statement from its presidential council said on Saturday.

The statement gave no details on when the measure would come into effect, but it comes after officials accused a local armed group of fuel smuggling from Zawiya port. The measure will cover Zawiya and Zuwara ports.

The armed faction guarding Zawiya port peacefully withdrew from the terminal earlier this week.

Libya expects its oil production to rise to around 900,000 barrels per day after a series of agreements to reopen major oil ports and oilfields which had been closed for two years by armed factions, fighting and strikes.

http://www.reuters.com/article/libya-security-energy-idUSL5N1EX0G2

Demand for LNG and thermal coal for power generation in North Asia has risen on the back of low winter temperatures.

Colder-than-usual temperatures in the midst of the heating season push the demand for electricity up which subsequently tightens the market and supports high LNG prices.

Citing a Tokyo-based analyst, Reuters reports that lower than usual temperatures expected in the next 45 days will push the demand for energy up.

It is expected that temperatures in Tokyo, Japan, Beijing, China, and Seoul, South Korea, where city gas is used for heating, will drop up to 3 degrees Celsius lower than normal.

It is expected that consumption of liquefied natural gas in Japan, the world’s largest LNG importer, will reach 10.73 billion cubic meters during January, the highest it has been in a year.

LNG imports in China have already risen from November to December and the trend is expected to continue, with consumption in South Korea expected to reach 5.23 bcm in January 2017, the highest level since January 2015.

Reuters further reports that the Asian spot LNG prices were at US$9.5 per mmBtu at the end of December, also the highest it has been since early 2015.

http://www.lngworldnews.com/asian-winter-temperature-drops-boost-lng-demand/

US to sell 8 million barrels of sweet crude from three SPR sites

The US government plans to sell up to 8 million barrels of light, sweet crude from three of the Strategic Petroleum Reserve's four sites later in January, with first deliveries planned for as early as February, a Department of Energy official said Friday.

DOE plans to sell 3 million barrels from its Bryan Mound SPR site and 3 million barrels from its Big Hill site, both in Texas, and 2 million barrels from its West Hackberry site in Louisiana, according to the official, who spoke on the condition of anonymity.

The crude will be sold at multiple delivery points throughout the SPR system.

"Companies could make offers for oil coming out of one site only, for all three sites, for pipeline deliveries only for marine vessels or combinations of both," the official said.

The agency plans to issue a notice of sale by mid-January, according to the official, beginning the process for what is expected to be the first of 18 expected SPR sales through fiscal 2026 that would put nearly 200 million barrels of government-owned crude up for auction.

The US SPR, the largest government stockpile of crude in the world, currently holds 695.1 million barrels of crude, including 266.1 million barrels of sweet crude.

The estimated 8 million barrels to be sold this month are part of an appropriation by Congress to sell up to $375.4 million of SPR crude to partially fund an effort to modernize the SPR and add marine terminal capacity.

Once the notice of sale is issued, companies will have eight days to submit bids. In order to bid, companies need to be registered in the SPR's Crude Oil Sales Offer Program and must submit an offer guarantee of $10 million or 5% of maximum potential contract amount, whichever is less.

"That's what prevents just anybody from throwing a bid out there," the DOE official said.

DOE, which can reject any offer made, will notify companies with successful bids 11 days after the notice of sale is released, expected to be by late January, and contracts are expected to be awarded by early February.

The official said regular deliveries of the crude, once contracted, will be made between March 1 and April 30, but said February deliveries will be accommodated.

"Purchasers must make their own transportation arrangements and make sure that terminal and pipeline availability is sufficient for its volumes," the official said.

The official said additional sales could be held in the future if the agency does not receive the $375.4 million it was authorized to sell from the SPR.

"If we don't get enough good bids in this sale cycle, we will go out with a second sale cycle," the official said.

In addition to the $2 billion Congress has authorized for paying for the SPR modernization and new marine capacity, Congress over the past year has approved a biomedical research bill, federal budget and transportation bill that are all partially funded by sales of a combined 149 million SPR barrels.

On Thursday, in his cabinet exit memo, Secretary Ernest Moniz called the SPR a "critical federal energy security asset," and indicated it was being endangered by many of the crude sales approved by Congress.

Moniz wrote that through these sales, the SPR was "being used by Congress to cover costs of programs not related to energy security, a shortsighted use of long-term security assets to meet short-term budget goals."

http://www.platts.com/latest-news/oil/washington/us-to-sell-8-million-barrels-of-sweet-crude-from-21532668

West Texas’ Permian Basin again led the growth of the nation’s drilling rig activity, with Texas and New Mexico each adding three more rigs to oil fields. The Permian extends into southeastern New Mexico.

The total rig count started 2017 by tacking on seven more rigs nationwide — four primarily seeking oil and three drilling for gas — with oil prices now hovering near $54 a barrel in the U.S. The growing Permian activity accounts for more than half of all the nation’s active oil rigs with 267 rigs drilling in the basin, according to weekly data collected by the Houston-based Baker Hughes oilfield services firm.

However, the Granite Wash basin in the Texas Panhandle and Oklahoma lost five rigs, keeping the total rig count from growing more.

The Gulf of Mexico added one offshore rig, while Louisiana represented two of the three gas rigs brought on thanks to more activity in the Haynesville Shale.

The total rig count is now at 665 rigs, up from an all-time low of 404 rigs in May, according to Baker Hughes. Of the total tally, 529 of them are primarily drilling for oil.

After the Permian, the next most active area is Texas’ Eagle Ford shale with just 47 rigs.

http://fuelfix.com/blog/2017/01/06/permian-basin-again-drives-rig-count-growth/

The US Army Corps of Engineers will not remove oil pipelines from the next five-year authorization of its streamlined permitting program, despite opponents of the Dakota Access Pipeline and historic preservation groups calling for more scrutiny in order to prevent spills.

The agency released a final rule Thursday authorizing the program through March 2022.

More than 53,000 of the 54,000 comments the Corps received about the wide-ranging program dealt with Nationwide Permit 12, or NWP 12, a provision that allows oil pipelines to avoid much of the federal scrutiny that interstate natural gas pipelines undergo.

NWP 12 includes oil pipelines in its definition of utility lines that are eligible for streamlined federal permitting authorizing construction, maintenance and repair work in federally regulated waters. Some projects can begin work without prior approval from the Corps.

Other projects with certain characteristics -- including those that cross a navigable river or run more than 500 feet in a single water body and those that may affect sensitive cultural resources or endangered species -- must get pre-construction authorization from the Corps' regional office that oversees that area of the pipeline and comply with a number of general conditions.

The Corps decided not to make any major changes to the provision.

Dakota Access Pipeline opponents like the Standing Rock Sioux Tribe in North Dakota amplified calls to modify or eliminate NWP 12, which would have made it more difficult for companies to site oil pipelines.

Standing Rock Chairman Dave Archambault said NWP 12 was intended for projects with minimal effect on the environment.

"However, as events across the country have shown, spills from oil pipelines occur with great frequency, often with devastating environmental effects, particularly when they occur in the aquatic environment," Archambault said in comments on the rulemaking.

"The Corps should address this fundamental disconnect by expressly recognizing that oil pipelines in waters of the United States require individual permits and are not properly deemed to be utility lines within the meaning of NWP 12," he added.

Interstate gas pipelines must get permission from the US Federal Energy Regulatory Commission for construction and operation. During the review, FERC looks at environmental impacts, safety standards, market conditions and other factors. The process averages about 12 months for projects that begin a pre-filing process at least seven months before filing for a certificate application, according to a January study by the nonpartisan Congressional Research Service.

The Corps responded to some of the comments in the final rule, saying it does not regulate oil and gas pipelines per se. Rather its legal authority is limited to regulating discharges of dredged or fill material into federal waters and work done in navigable waters.

The Corps used the example of Enbridge's 600,000 b/d Flanagan South crude pipeline from Flanagan, Illinois, to Cushing, Oklahoma. It said the segments subject to the Corps' jurisdiction under NWP 12 amounted to just 2.3% of the total pipeline route.

The Corps said other agencies like the Department of Transportation's Pipeline and Hazardous Materials Safety Administration, the Environmental Protection Agency and the Coast Guard address pipeline operations and spills.

"We do not have the authority to regulate the operation of oil and gas pipelines, and we do not have the authority to address spills or leaks from oil and gas pipelines," the Corps said.

http://www.platts.com/latest-news/oil/washington/us-army-corps-keeps-oil-pipelines-in-streamlined-21517802

Pipelines will lead the charge in Canadian energy companies in debt issuance this year amid signs the recovery in the industry is solidifying.

Bank of Montreal sees C$5.5 billion ($4.2 billion) in issuance from oil and gas pipeline companies like TransCanada Corp. in 2017, up from C$3.8 billion last year, as they fund ongoing projects. With oil below $60 a barrel, it’s still too early for companies most closely tied to commodity prices to start spending again. Exploration and production companies are expected to issue about C$1 billion to C$2 billion, largely to refinance existing maturities.

“A lot of the issuance does come from the pipeline names because of the type of infrastructure they’re building,” Manmit Pandori, an analyst who covers energy companies for Bank of Montreal’s BMO Capital Markets unit, said by phone from Toronto. The explorers and producers are “more in maintenance mode than they are in a broad growth in capital spending.”

The Canadian energy industry is stabilizing after being roiled by a plummet in oil prices from more than $100 a barrel in New York in June 2014 to $26 in February. Crude is now trading around $52, with forecasters in a Bloomberg survey seeing it holding between $55 to $60 through 2019. As oil rose, the cost of borrowing for Canadian energy companies dropped relative to government debt. Investors now accept a yield spread of around 160 basis points, or 1.6 percentage points, compared with more than 270 in February.

Best Performance

That improving picture helped drive highly rated Canadian energy companies to the best performance on the Bank of America Merrill Lynch Canada Corporate Index last year, returning 6.5 percent to investors. The index average was 3.6 percent.

Infrastructure companies are expected to tap the debt markets this year whereas last year they may have issued more equity, relied on credit facilities, or delayed a project or investment, Pandori said. Enbridge Inc.’s Line 3 pipeline replacement, TransCanada’s NGTL gas-pipeline system, and North West Redwater’s refinery construction are some of the projects with big spending, he said.

“It’s obviously a sigh of relief when you’re seeing some of the bigger guys with the balance sheets starting to spend again,” said Chris Kresic, portfolio manager in Toronto at Jarislowsky Fraser Ltd., which has C$6.5 billion in fixed-income assets. “That’s obviously a sign of confidence in the industry.”

Taking Steps

Some high-grade producers did tap the bond markets in the second half of last year, but those were for maintenance and refinancing, as opposed to new growth, Pandori said. Select Canadian large energy companies began announcing expansion projects at the end of last year.

“They’ve taken a lot of steps, to the industry’s credit, to make sure that their balance sheets are in order, they’re not getting downgraded below investment grade,” he said. Producers were taking advance of borrowing costs that had narrowed significantly since February.

TransCanada spokesman Mark Cooper declined by e-mail to comment.

Enbridge spokeswoman Suzanne Wilton declined by e-mail to speak specifically to Line 3, but noted that the project was part of a growth program that still had outstanding capital requirements that will be funded with debt and equity. Cost of capital is a “significant determinant” in when and where Enbridge chooses to fund from, she said.

Doug Bertsch, North West Redwater’s vice president of regulatory and stakeholder affairs, confirmed through a spokeswoman that the partnership expects to issue Canadian-dollar debt this year, and monitors for market conditions that may affect timing and amount issued.

‘Cheap Overall’

Surer signs of health in the energy industry would see explorers and producers ramping up along with the infrastructure companies, which will need to fill their pipes with something. It’s still too early to see much spending beyond the healthy, investment-grade producers, Jarislowsky Fraser’s Kresic said.

“Even if the price goes back to $60 a barrel, it’ll be tough for the amount of financing that was done before to reach those levels again any time soon,” he said.

Energy companies have also seen stock prices stage a dramatic recovery through 2016, leading the S&P/TSX Composite Index to the best performance among 24 developed markets. Given the recent jump in interest rates, companies are more likely to head to the equity market this year for financing, according to Rafi Tahmazian at Canoe Financial LP.

“My inclination would be that debt’s a tougher game to play now,” Tahmazian, senior portfolio manager in Calgary for Canoe, which has C$1 billion in energy assets, said by phone.

With the oil recovery, a better U.S. economic outlook and a need pipeline capacity in Canada, Kresic sees a window for infrastructure companies looking to finish projects started years ago.

“They’ll still be coming to market,” he said. “Debt is cheap overall."

https://www.bloomberg.com/news/articles/2017-01-06/pipeline-debt-rolls-on-for-canada-energy-as-producers-bide-time