John Alexander

250-793-4934
 

We are at a time now when the slump in oil prices have stopped drilling in this Oil/Gas rich part of the province. But now with multibillions in investments looming with the Shell Kitimat LNG and the Petronas led LNG terminal at Lelu Island in Prince Rupert, there has never been a better time to invest in this area. We are at the low end of the cycle for property values and about to hit the biggest energy boom in Canada since the Tar Sands. Petronas estimates 17 Trillion cubic feet of Gas in the Montney Shale alone.

Above: Streetview shot of a well kept older home  4 bedroom 2 bath with new roof and oak floors with motivated seller. Easy to rent this beauty out for a good ROI and especially when factoring in growth.

 

 

I can find you up to 13% Gross Caps on older, remodelled duplex's with tenants in place. I know your accountant is telling your always to account for a vacancy rate, but in Fort St. John the rents have also taken a pounding so by the time your tenants move on, in this recovering market, so will the rents.

If you are shopping for newer construction, there is a host of eager, cash strapped builders that need to make a deal and a good selection of home owners needing to relocate. The rental market is starting to return with Surerus holding a Job Fair last week at the Pomeroy and the Site C Dam poised to increase hiring for the 8+ Billion Dollar dam.

Call me for more information 250-793-4934.

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Comparing 2008-9 with today using MLS Stats
 
I thought it would be a good idea to compare our present state with 2008-9 just to give you a better idea of some market trends and what to expect around the corner.
 
 2016 is very comparable to 2008-9.  I wanted to let you know why statistically speaking:
 
For those of you in the Fort St. John, BC real estate business in 2009, you might remember that July - 08 things looked quite rosey with 81 sales in FSJ, well last July we had 68 only 13 off , but still pretty good.
 
From there the comparison gets tighter, Aug 08- with 61 Sales and Aug 15 with 50 Sales, 11 off.
 
It tightens up even more with Sep 08 at 54 Sales and Sep 15 at 48 Sales only 8 off.
 
But look at this, October 08 with 46 Sales compared to Oct 15 with 46 Sales Dead Heat.
 
Nov 08 compared to Nov 15 was 33 to 22 respectively
 
Dec 08 compared to Dec 15 was 15 to 31 respectively (Nov and Dec 08 average to 24 ea month and Nov and Dec 15 average out to 26.5 each month)
 
Jan 08 rang in 14 Sales and Jan 15 rang in 12 thats only 2 off and the pattern is developing
February 08 is 27 Sales February 15 is 26 Sales.
 
 
 
 
Averaged out its pretty darn close.
 
When I look back and compare all the years since 2000 it's extremely interested to see the highs and lows that we tend to blend altogether.
 
On the positive side May, June and July were good sale months in 2009 as I think we will find a similar pattern this year with buyer taking advantage of opportunities present in our market that haven't been for 6 or 7 years.
 
Our highest sales year ever was 2014 which was the only year to beat 2006 .. 
 
 
The media is grim as it was in 2009, oil was valued similar to it is now, the US had entered its second year of recession in 2009, there was no LNG at the federal level in 2009 like now, and site C was just starting the discussions with communities in 2009, not hiring like now.
 
Here we find ourselves in this position again of negative media, job cuts and losses as we did then ... But we have more things to be positive about than ever.... And things will showing signs of recovery are here already, in fact oil has a hell of a lot more room to go up than it has to go down.
 
So from here on in, things are going to get better, and I just had to break the good news.
 
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It's been amost a year since I attended Industry Outlook 2015, sponsored by Prospera Credit Union ( I sponsored Refreshments). 

I thought that a recap of some of the highlights from Brad Magnasson's portion of the seminar would be interesting to read. Brad is a Consultant that specializes in Oil and Gas.

  • Oil is expected to rise toward 70/bbl by 2016
  • Africa has an emerging supply
  • Russia needs Crimean Ports to sell oil.
  • Russia would like to see 55-62 bbl minimum
  • WTI spot price runs parralell to the Canadian Dollar
  • Brad thinks 51/bbl is close to the bottom 
  • Wages are the leading indicator of a recovering economy
  • Oil & Gas employees making 300-350K US anually  in the oil feild would  indicate good growth
  • OPEC has not been able to control it's memebers
  • ISIS is selling oil from 28-40/bbl US
  • Saudi Arabia break even point for oil production is $106/bbl
  • Alberta break even point for oil production is $65/bb/
  • Brazil has huge unknown reserve with no infrastructure
  • We might see $82/bbl by the end of 2016 but Iran is a huge wild card.
  • US debt level is going down
  • US can stand on it's own now for oil and gas
  • Most countries have their economies tied to oil and gas
  • Power generation with LNG will continue to grow
Of course these bullets represent highlights of a well discussed industry, but I find it very interesting because you just have to recall recent fundamental developments in the last year and know which way the pendulum will swing according to markets.
I was shocked to hear $106/bbl for Saudi Arabia, and went and confirmed that figure with outside sources.
This is all good news for Fort St. John, eventually.

 

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Coal is driving China's hydro electric plants and it  is the dirtiest of all fossil fuels, it creates more pollution than oil, natural gas and gasoline when burned. That is why Bejing is one of the most dirtiest places on earth.

 

Liquid natural gas (LNG) is the cleanest fossil fuel, and Canada has an abundance of natural gas.

 

“That’s another significant piece that people miss on this whole LNG story in B.C – that we’re actually helping large economics that are continuing to grow to create new transition fuels to get out of older fuels into cleaner-burning fuels,” said Greg D’Avignon, CEO of the Business Council of BC.

 

Northeastern BC is home to the Montney Formation and Horn River Basin, the third largest hydrocarbon fields in North America.

 

Between the drilling, piping, and exporting of the natural gas in British Columbia, there is over $100 billion of proposed capital investment. Each project has one key component, all of the natural gas comes from Northeast BC.

 

A few of these massive capital projects proposed:

  • LNG Canada led by Royal Dutch Shell - $40,000,000,000 [source]
  • Pacific NorthWest LNG led by Petronas - $36,000,000,000 [source]
  • West Coast Canada LNG led by Exxon Mobil - $25,000,000,000 [source]
 
 
Here are some recent developments pointing to one of the biggest upcoming booms in Canadian history.

 
 
$715-million natural gas processing plant gets go-ahead
 

Construction of the $715-million Tower natural gas processing plant, which would be south of Fort St. John, has received the go-ahead from the Cutbank Ridge partnership formed by Encana and Mitsubishi.

 

The Tower complex includes a processing plant as well as storage and other facilities.

 

The decision to build the Tower complex follows the announcement of a $860-million natural gas plant near Dawson Creek, for Cutbank Ridge.

 

Both processing plants are expected to start operating in 2017, and would handle natural gas from the Montney Formation. [source]

 
 
Site preparations underway at LNG Canada site in Kitimat
 

It's not a final investment decision but LNG Canada is embarking on early site preparation at their proposed liquefaction plant site which will pave the way towards a smoother construction phase.

 

As of right now there are currently 120 people working on site. 

 

If a positive FID is made in 2016 the company would then shift to construction of permanent facilities on the property. [source]

 

Another item leading up to their FID, is the decision to lease a parking lot at Northwest Regional Airport in Terrace. 

 

“LNG Canada has made provisions for parking at the Northwest Regional Airport in Terrace to function as a “park-and-ride” facility for LNG Canada staff and contractors who live in Terrace and the surrounding areas,” [source]

 

 

 

 
 
Petronas LNG terminal 'not likely' to harm Flora Bank

 

Pacific NorthWest LNG, led by Malaysia’s state-owned Petronas, wants to build an $11.4-billion export terminal on Lelu Island, which is located next to Flora Bank.

 

“The technical work completed to date indicates that the project is not likely to cause significant adverse environmental effects on fish and fish habitat,” according to the consortium’s 36-page summary of its findings. [source]

 

Recent news about an global glut of LNG under production has cast a shadow over BC's prospects to develop the industry, but as late as mid November Petronas CEO Datuk Wan Zulkiflee Wan Airffin said, "the company will proceed, pending federal approval." [source] 


Construction on the massive Site C Dam is underway, the Civil Contractors have been announced and construction to house the workers has begun.


Between the $8.9 billion BC Hydro Site C Dam, and the over $100 billion of proposed capital for BC LNG, the population in Northeastern BC is expected to double by 2020.
 
These massive capital projects create high paying jobs, and people move to the region to fill these jobs. The average age in Fort St. John is 29 years old with an average income of $108,000.

 

Let me find you investment opportunities that will pay huge dividends to you and your family for years to come.

 
Find out how through well selected properties in Fort St John our investors are achieving annualized returns up to 26%.
 

Call me today to find out what properties can acheive your short term and long term investment goals.
 
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The following article is a repost of Cynthia Aeson's article 120 days into Site C Dam

Site C Dam
 
At $8.9 billion, BC Hydro's Site C Dam is Canada’s largest infrastructure project and the largest capital project in British Columbia’s history. Site C Dam is located only 7 km from Fort St. John, British Columbia. 

 

Today marks the 120th day of construction, into a decade long project. BC Hyrdo allows contractors to work 24 hours a day, seven days a week, 365 days a year, meaning the work could be literally non-stop.

 

In the first 120 days of construction, work crews have been undertaking site preparation activities, including:

  • clearing trees and vegetation at the dam site
  • upgrading public roads
  • building access roads at the dam site
  • constructing a 1,600-person worker accommodation facility
  • excavation and slope stabilization and starting work on a temporary construction bridge across the Peace River
 
 
Interesting Image
 
 
Things to know:
  • As of the end of September, there were approximately 600 people working on the project, including approximately 450 workers from B.C.
  • An estimated 10,000 jobs will be created during the decade of construction.
  • More than 1,000 people and over 200 businesses participated in jobs fairs and business-to-business networking sessions in October in Tumbler Ridge, Chetwynd and Fort St. John.
  • $3.2 billion will be added to the provincial economy from the purchase of goods and services during Site C construction, including $130 million to the regional economy.
  • $40 million in tax revenues will be provided to local governments during construction.
  • Site C construction activities will contribute $179 million in provincial revenues and $270 million in federal revenues during the construction period.
  • A temporary 300-person work camp has been set up on site to house workers while the 1,600-person lodge is constructed.
 
 
Interesting Image
 
 
A concern we are presented with frequently is, "as a real estate investor, isn't the construction of a 1,600 man camp bad news?"
 
First, you must understand the nature of a man camp. Man camps are used to house workers from outlying cities, for example: Kamloops, Nanaimo, Edmonton, and Abbotsford. 
 
Their schedule is 2 weeks in the camp, 1 week off. During this week off, they pack up their duffle bags and another worker takes their place in the man camp, leaving them no place to store any personal belongings. 
 
After a few months of spending 2 of their 7 days off commuting back home, "it is estimated that up to 60% of workers will either rent or own in the nearby city."  
 
Secondly, according to the economic development office, the population of Northeast BC is expected to almost double over the next 5 years. If this growth happens, there are simply not enough housing units to accommodate this massive growth in population.
 
The North Peace Economic Development Commission estimates that Northeast BC currently needs at least 5,500 new housing units. The demand is broken down by the following:
  • 3,516 - Single Family Homes
  • 1,200 - Townhomes, Duplexes, Row-Homes
  • 1,151 - Apartments 
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Petronas Still Committed to Building LNG Terminal in BC 

"Petronas would like to reaffirm its commitment to deliver long-term LNG supply to its customers through the Pacific NorthWest LNG project in Canada, despite the current market volatility for oil and gas," said Petronas executive vice-president Wee Yiaw Hin. 

 

B.C. Natural Gas Development Minister Rich Coleman spoke with Petronas officials and said, "I have a lot of confidence that these guys are still focused with regards to an LNG plant." [read more]

 

Lax Kw'alaams First Nation Divided Over Decision On Petronas LNG Project

In June, the First Nation's band Lax Kw'alaams rejected a natural gas benefit agreement worth over $1 billion. Today, there is a disagreement among members on whether Lelu Island should be rejected outright as the site of a $11.4 billion export terminal.

 

Prominent members of the band are open to having an export terminal on Lelu Island, saying they want to examine efforts by Petronas to protect the fish habitat. [read more]

 

BC Will Be Transformed When LNG Takes Hold

There is substantial revenue flow, employment opportunities, contracting opportunities and business opportunitiesaccording to LNG Canada CEO Calitz. LNG Canada - one of the 19 projects proposed for the West Coast - expects 7,500 workers will be employed during peak construction and an estimated $8 billion will be spent on goods and services within Canada, including $3 billion in B.C.

 

 

"B.C., through the LNG industry, will be linked to China, Japan, Taiwan, India, and Korea with an umbilical cord with $50 to $100 million worth of product leaving B.C. and travelling for 10 days to one of the port cities of Asia. That new umbilical cord creates a whole new connectedness across the Pacific." added Calitz. [read more]

 

 

 

$860 Million Sunrise Gas Plant Near Dawson Creek Gets Approved

 

Versen Inc. announced that construction has begun on the $860 million Sunrise gas plant. This is the largest gas plant to be commissioned in western Canada in the last 30 years.  Sunrise is the first of three gas plants that are expected to reach a final investment decision between now and the end of Q1 in 2016.

 

During construction the three plants shouldproduce 3,000 jobs, including 1,100 at Sunrise. The plant, which has been approved for 400 million cubic feet per day, is expected to be running in the last quarter of 2017. The estimated cost between the three plants is $1.8 billion. [read more]

 

Waterless Fracking Company Sets Sights On Northeast BC

Millennium Stimulation Services has developed a process using energized natural gas to replace or eliminate water from the frackingprocess. Millenium CEO Mike Heier hopes the company will be operating in Northeast BC in the near future.

 

Heier said his company is planning to build its own network of LNG plants. "The volumes are very large and the infrastructure is non-existent.Our primary mandate is to build, own, and operate LNG plants." [read more]

 

 

 

What Does This All Mean to Real Estate Prices in NE BC?

 

Call me to find out . 250-793-4934

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What would happen it the US Repealed it Ban on Oil Export? Now that we are seeing that there never was an "Energy Crisis" and instead a Glut of Oil on the markets. If the US repeals the ban on exports, will we see releif in price at the pumps?
Here is a repost of Oil Pro by Gabriel Collins to give us a little more insight of what we might see.
 
 
 
 
 
 

 

 

 

 

 

Gabriel Collins

Attorney at Baker and Hostetler, LLP

Followers7
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Will Congress Repeal The Crude Oil Export Ban In Fall 2015?

Rising congressional support signals real promise that the ban on U.S. crude oil exports could be repealed within the next six months. The U.S. now exports more than 550 thousand barrels per day (kbd) of crude oil and another 120 to 140 kbd of condensate as of May 2015.1 Yet continuing restrictions mean producers can only access a handful of markets. Meanwhile, U.S. oil refiners are sourcing stranded domestic oil at cut-rate prices, processing it, and then turning around and freely exporting more than 2.5 million bpd of gasoline, diesel, and other refined products at premium global prices.

Low oil prices have emboldened Congress to seriously consider lifting the crude oil export ban. By my count at this time last year, nine lonely members of Congress publicly supported a repeal; now there are at least 150 (128 representatives and 22 senators). Exhibit 1 provides a cumulative summary of congressmen and -women who have publicly endorsed repealing the ban. These numbers will likely rise once representatives and senators return to Washington after the August recess.

Exhibit 1: Crude Oil Exports Are Rapidly Gaining Support in Congressenter image description here

WTI Spot Price (USD/bbl) and Number of Representatives and Senators Supporting Repeal of Export Ban; Source: Assorted Media Outlets, Draft Bill Texts from House of Representatives and Senate

Isn’t there a simpler way to repeal the ban? Yes, but it is not politically feasible at present. President Obama could rescind the ban by executive order and would simply need to show that doing so is in the “national interest.” In 1996, President Clinton justified a blanket approval of Alaskan North Slope crude oil exports to Asia on the basis that the export decision was in the national interest and (1) would not “diminish the total quantity or quality of petroleum available to the United States,” (2) would not “pose significant risks to the environment,” and (3) would not likely “cause sustained material oil supply shortages or sustained oil price increases above world market levels” that would injure consumers in the U.S. and its territories.2 These three national interest standards could be easily met today, but the administration’s political priorities in the energy and environment space likely preclude executive action to lift the ban. Hence the rising support in Congress for legislatively repealing it.

House and Senate advocates of repeal must contend with a mixed map of support that holds promise, but needs significant shoring up in order to amass a veto-proof two-thirds majority (Exhibit 2 and Exhibit 3). On the House side, the 128 supporters to date are clustered in the Rockies and Plains states, as well as Texas, Arizona, Tennessee, and North Carolina.

Exhibit 2: Levels of Support for Repeal of Crude Oil Export Ban in House Delegations, 19 August 2015

enter image description here

California and New York will likely remain bastions of opposition. Likewise for Pennsylvania, home to large independent refiners that benefit from discount-priced U.S. crude supplies stranded by the export ban. These populous states—with 98 House seats between them—will be key “battleground states” where House leaders must try to corral support from at least one-third of each state’s delegation. Expect supportive House Democrats such as Henry Cuellar of Texas to push their colleagues hard to try to garner votes in support. Opponents of crude oil exports will likely pressure President Obama to veto any legislation repealing the ban, so getting at least two-thirds support in the House will be an important priority.

On the Senate side, the politics are a bit different. The top oil-producing states, which other than Texas have smaller populations, wield higher influence than they do in the House since all states have two votes regardless of population. At least 22 senators currently support lifting the ban. Thus, if the Senate leadership can persuade the uncommitted senators in the Rocky Mountains, Heartland, and Gulf Coast and a few coastal Democrats to support repealing the ban, they will be well-positioned to pass the legislation. Achieving the two-thirds majority needed to override a presidential veto will be tougher, as Senator Murkowski and her colleagues would need to garner 11 more Democratic votes as well as ensure that all 54 Republican senators support the bill.

Exhibit 3: State-by-State Senate Support for Repealing the Crude Oil Export Ban, 19 August 2015

enter image description here

Many elected representatives’ primary point of hesitation when presented with the idea of repealing the crude oil export ban is simple: they fear voters will hold them responsible if gasoline prices increase. This visceral fear endures despite multiple credible studies showing that repealing the U.S. crude oil export ban is in fact much more likely to actually decrease—or at a minimum, stabilize—gasoline prices.3

Survey data from the University of Texas Energy Poll covering the period between September 2011 and March 2015 paint an interesting—and somewhat contradictory—picture of how consumers view gasoline price issues.4 On one hand, respondents consistently attributed the primary responsibility for gasoline prices to oil companies and market forces. Yet of a sample of more than 2,100 people surveyed by the UT Energy Poll before the November 2014 election cycle, 63 percent said they would be more likely to vote for the candidate who “promises to make gasoline less expensive.” From data points like these, many politicians are likely to infer that voters will punish them at the ballot box if gasoline prices rise in the wake of legislation to repeal the crude export ban.

Yet crude oil exports do not equal higher gasoline prices. Because gasoline is freely exportable, its price is already set globally regardless of how crude oil exports from the U.S. may or may not be restricted. Restricting exports and trapping surplus light, sweet crude within U.S. borders simply shifts rents to the refining industry.

The “crack spread,” which measures refiners’ profit margin from processing various crude oils, tells a clear story here. Prior to the shale boom, Brent crude was generally more profitable to process than WTI. Yet beginning in 2011, the profits from refining WTI crude at the U.S. Gulf Coast (and by extension, the shale crudes whose prices closely relate to WTI) rose dramatically relative to the Brent crude crack spread as domestic production increased (Exhibit 4). Refined product exports absorbed the initial wave of shale crude production, but by late 2013, continuing production growth in the shale plays and slower demand growth in key U.S. oil product export markets exacerbated the domestic crude supply glut.

Exhibit 4: U.S. Refiners Profit, Not Oil Producers and Consumers

enter image description here

Refined product and crude oil exports from U.S. (kbd), left axis, Spot WTI 3-2-1 crack spread minus Spot Brent 3-2-1 crack spread, USD/bbl, right axis; Source: EIA, Author’s Analysis

Furthermore, despite refiners’ access to large amounts of virtually captive shale crude supplies, gasoline prices can still spike and hit consumers’ wallets hard. For instance, between August 7 and August 14, 2015, a major refinery outage triggered a more than 50 percent upswing in Chicago-area retail gasoline prices, reaching approximately $3.23 per gallon—a level last seen when WTI crude was selling for twice its current price.5

The market case for exports of light, sweet is clear. The U.S. refining system is saturated with the light, low-sulfur shale crudes responsible for virtually all incremental U.S. crude oil supply growth in the past three to four years. Once U.S. refiners’ use of domestic crude rose into a consistent 50 percent to 55 percent range, crude oil exports trended sharply upwards, and domestic crude’s share of supply only fleetingly exceeded the 55 percent threshold (Exhibit 5). Moreover, there appears to be little room for additional shale barrels in the U.S. refining system. Refiners are running flat out, with capacity utilization rates exceeding 95 percent for the past seven weeks and counting, according to the EIA.

Exhibit 5: Refineries Are Saturated With Domestic Crude, Exports Can Help Rebalance the Market

enter image description here

Source: EIA, Author’s Analysis

Refined product exports cannot compensate for the existing glut of shale crudes, not to mention any future production growth. Likewise, new refinery capacity investments for processing light, sweet crudes will likely only make a marginal dent in the current shale crude glut. And if oil prices creep back up and producers become more efficient, even a few hundred thousand additional bpd will swamp expansions and put the market right back in its current state of light, sweet super-saturation.

There is a clear and compelling case for lifting the crude oil export ban and giving U.S. oil producers full access to global markets. Now is the time to harness these arguments and redouble efforts to persuade undecided members of Congress to back a repeal. Based on the rising congressional support analyzed in this article, the odds of the ban being repealed in the next six months are better than 50/50.

 

 
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AltaGas has advanced its plan to be the first to export liquefied propane from the British Columbia coast, announcing Thursday it has struck a deal on an unspecified site and that it will build a new gas fractionating plant in northeastern British Columbia. AltaGas reported a net loss of $22 million in the second quarter versus a profit of $29 million a year earlier as revenue fell to $416 million from $471 million.

 

“On the growth front, we are well on our way to provide producers with a solution to weak liquids prices,” said chairman and chief executive David Cornhill on a conference call to discuss second-quarter results.

He said the Calgary-based company could invest over $1 billion over the next two years in B.C., including the liquefied petroleum gas (LPG) plant on the coast, the new fractionation facility worth about $100 million at Fort St. John and its previously announced $350-million Townsend gas plant in northeastern B.C., along with associated pipelines.

“The site will initially be able to handle 25,000 barrels per day with significant expansion opportunities,” said Cornhill. “We expect to finalize agreements by the end of the year and we expect to be the first to export LPG off Canada’s West Coast.”

AltaGas said it will make a final investment decision on the B.C. LPG facility next year. It is expected to buoy propane prices by giving Canadian producers awash in the fuel an alternative to domestic or U.S. sales. The propane would be delivered by rail.

Executives wouldn’t say whether part ownership would be extended to AltaGas’s partner, private Calgary-based Petrogas, or local native communities.

Meanwhile, AltaGas reported the Ferndale LPG export facility in Washington State operated by Petrogas is expected to ramp up exports to 25,000 bpd by the end of the year.

 

The Ferndale terminal acquisition in March 2014 provides a strong fit for AltaGas Ltd. and Idemitsu Kosan Co. Ltd., which recently acquired interests in Petrogas. The facility gives AltaGas direct offtake for its production and for Idemitsu to acquire North American LP gas for its sales and distribution infrastructure in Japan as well as its other interests in southeast Asia, the press release also notes.

The LP gas terminal has the capability to handle exports and imports of up to 30,000 barrels a day and has facilities to handle and supply propane to the regional market for U.S. domestic consumption. The terminal has rail, truck and pipeline capability and is connected to the two local refineries offering LP gas balancing services

 

AltaGas missed analyst expectations on earnings and cash flow for the three months ended June 30 mainly because it did not receive a dividend from Petrogas, in which it holds a 33 per cent stake.

Chief financial officer Deborah Stein said Petrogas, which diverted the money to invest in building storage facilities in the second quarter, is expected to pay $30 million to $40 million per year in future.

Cornhill said AltaGas is negotiating to receive more regular dividends from Petrogas in return for a pledge from AltaGas to support capital projects separately.

AltaGas reported a net loss of $22 million in the second quarter versus a profit of $29 million a year earlier as revenue fell to $416 million from $471 million.

FirstEnergy Capital analyst Steven I. Paget said second-quarter adjusted earnings of $107 million fell below his expectation of $128 million and consensus of $115 million, while adjusted cash flow per share was 50 cents, below FirstEnergy’s 69 cents and consensus of 62 cents.

AltaGas also confirmed Thursday it and its three international partners in Douglas Channel LNG plan to make a final investment decision in the fourth quarter of this year on their liquefied natural gas export facility.

They propose a barge-based facility near Kitimat to supercool and liquefy gas for export.

The project site is secured by a long-term lease with the Haisla Nation and initial capacity is to be 550,000 tonnes per year, making it one of the smallest of B.C.’s 18 or so proposals.

 

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Wednesday, Jul. 29, 2015

The following article was written by Gary Marr and published by the Financial Post.;

Under the new rules, CMHC will consider up to 100% of gross rental income from a two-unit owner-occupied property that is the subject of a loan application submitted for insurance. FOTOLIA

Canada Mortgage and Housing Corp. is going to make it easier for homeowners renting out apartments in their principal residences to borrow money, a move that could further heat up markets in Toronto and Vancouver.

The Crown corporation, which controls a majority of the mortgage default insurance market in Canada, announced changes to its rules Monday and effective Sept. 28 which are aimed at boosting affordable housing.

A background document sent to lenders and obtained by the Financial Post suggests the change is aimed at what CMHC sees as a significant part of the housing market.

“Many municipalities across the country now formally recognize secondary rental suites as a source of affordable housing,” CMHC wrote in its document intended for industry partners. “Rents in secondary rental suites are often lower than those for apartments in purpose-built rental buildings.”

FP0623_Affordability_C_JR

The Crown corporation has said Vancouver has 26,600 secondary units which comprise almost 20 per cent of the rental stock in the city.

The changes from CMHC would allow homeowners to count the income from their secondary units when qualifying for a loan, something that would seemingly bring more people into the housing market.

The Crown corporation has suggested this would target two unit owner-occupied homes and would likely include basement rental units, in-law apartments and garden suites known as laneway homes. It suggested, in its document to industry players, secondary apartments usually are self-contained with separate kitchen, sleeping and bathroom facilities.

One key issue will be whether the units are legal. CMHC only recognizes units that are legal or conform to local municipal standards. The Crown corporation says that it’s up to lenders to exercise judgment, when it comes to borrowers proving the units are legal.

Homeowners with less than a 20 per cent down payment and borrowing from a regulated financial institution must get government backed mortgage default insurance. Even financial institutions not regulated by Ottawa, like credit unions, must abide by CMHC rules to be covered by the government backing.

Under the new rules, CMHC will consider up to 100 per cent of gross rental income from a two-unit owner-occupied property that is the subject of a loan application submitted for insurance. The annual principal, interest, municipal tax and heat for the property including the secondary suite must be used when calculating the debt service ratios.

Rob McLister, founder of ratespy.com, said homeowners with legal units can now only count 50 per cent of the income from legal rentals for calculating their household income which determines how much they can borrow. “It will be marginally inflationary for single family homes,” said McLister.

The change comes on a day when one economist predicted prices in the Toronto and Vancouver markets could drop by as much as 30 per cent. “Lower mortgage rates have enabled Canada’s key housing markets to defy gravity for the past few years. But with prices rising dangerously high relative to household incomes, there is the potential for a large correction down the road,” wrote David Madani, of Capital Economics, in a note out Tuesday.

Doug Porter, chief economist with Bank of Montreal, said it might encourage some people to jump into the housing market who might have been on the fence.

“I think first and foremost this tries to address the lack of affordable housing. Whether it will be effective is another issue,” said Porter, who thinks it will help on the margins.

Elton Ash, region executive vice-president of Re/Max of Western Canada, said the changes will make a difference in Toronto and Vancouver. “It could have a very strong positive effect on qualifying for a mortgage,” he said, adding there’s strong interest from consumers in renting out part of their primary residences.

FP0611_Price_Range_of_Houses_620_AB

Tags: Mortgages & Real Estate, Canada Mortgage And Housing Corporation

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Hydro releases new poll on Site C ahead of planned construction start

 The controversy at times has been heated and in the north most people have heard both sides of the story but according to BC Hydro the majority is in favour.

BC Hydro is touting results of a new poll this morning saying support of the Site C project has gained momentum across the province, but BC residents don’t appear to side one way or the other on how to meet future hydro needs.

The telephone survey of 1,038 people by Abacus Data released Tuesday found that 59 per cent of British Columbians support the construction of the $8+billion dam, with only 17 % of those surveyed opposed.

An additional 22 % said they would “accept” construction under certain circumstances, according to the results, though those circumstances were not clearly defined.

Looking at it regionally, the survey included 303 people from the north and northeastern portion of the British Columbia.

 Abacus claims the regional support for the dam’s construction is much of the same — just 51 per cent support building the Site C Dam, with 26 per cent opposed to building the Site C Dam.  Another 22 per cent said they would accept the dam’s construction conditionally providing it met certain criteria, which was not clearly defined.

The telephone survey was conducted between June 10 and 19, and has a margin of the error of 3.9 per cent.

The Polls results also suggests that 92 per cent of people surveyed agreed demand for electricity in the province will increase in the coming years but they were unclear on how much that increase would be.

According to the poll, 75 per cent supported adding a new hydro dam and generating station to meet those needs.

However, another 75 per cent supported buying more power from independent power producers operating smaller wind and run-of-river hydro projects.

Another 64 per cent supported building more natural gas power plants.

So the popularity according to the Poll has increased and it could be said that the majority of BC Residents are in favour of it.

 
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History keeps repeating itself my friend, and as George Bernard Shaw points out , the unexpected always happens, this article by Martin Tidbury posted in Oil Pro gives a good aspect on those families that have been in limbo waiting for the Oil Biz to start up again;

 

History Repeating Itself?

enter image description here

In good times and bad, the challenge of finding and retaining skilled and experienced workers in the Oil & Gas industry remains high.

When the Oil price slumped to below $10 a barrel by mid-1986, the industry reacted by delaying or dropping projects, cutting exploration and capital spending along with major job losses across the sector. The impact of this drop in training and recruitment was felt for many years later and by 2013/2014, when record spending pushed up activity levels in the North Sea, there was an acute shortage of workers with 10-15 years experience.

With the oil price dropping to below $50 a barrel over the last year, the industry has again reacted by delaying or dropping projects and cutting spending, along with job losses across the sector. But with this reaction do we risk being in the same boat as 2013/2014 in 2030?

Oil and gas producer BG Group has become the first to explain recently in detail how it intends to make its offshore platforms more efficient. By simply reducing "dead time" on installations and empowering the offshore workforce to carry out its own logistics and planning.

Thousands of staff and contractor posts have already been lost or had their rates significantly slashed, and we don't seem to be at the end yet. There are a lot of savings to be made by what BG is doing and engaging with the workforce is key.

You don't deliver efficiency by just cutting jobs.

Perhaps we can look at what Dave Brailsford did with British cycling in 2008 when he was head of performance at British cycling, marginal gains.

The concept of marginal gains is that you break down all the individual elements involved and improve each of them by just 1% to realise a significant increase when all were combined. In these lean times it is one that should be considered as a means of transforming companies so they are streamlined, efficient and ready to handle challenges of the future.

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It's starting to look like the Perfect Storm is shaping up in Fort St. John, BC. If oil prices come back as stated below, together with the Site C Dam and an unprecedented Boom in the LNG Business, this little town of FSJ is about to go off the charts.

The article below is printed courtesy of Oil and Gas Pro;

Mid-Year OCTG Playbook: Looking For The Silver Lining

Photo Courtesy Hunting Energy Services Inc.

Every June we assess the mid-year market sentiment throughout the OCTG supply chain. It is interesting to note how the weather in Texas and much of the country’s midsection seemed in sync with so many of the observations; a somber affirmation of the expression “when it rains it pours.” Most of those with whom we spoke wondered how or for how long they will have to weather the storm that looms large over the oil patch. While optimism seemed in short supply, the fact is there are a few rays of hope on the horizon. 

While one month does not make a trend, it was encouraging to see that Texas permitting tipped up in the most recently released May report. The rig count, despite a ripple here and there, seems to signal that we’re closing in on a trough. Moreover, the combination of deep domestic OCTG production cuts together with declining import tonnages appears to be keeping a lid on inventories, a development that we will determine conclusively in our inventory quarterly survey next month. Clearly, every advancement made in the current ‘upstream’ battle has been hard-won. This confluence of catalysts is critical to bringing much needed stability to the market. 

In terms of prospective tailwinds insofar as domestic OCTG producers are concerned, the U.S. House of Representatives voted in favor of an improved trade remedy bill on June 12. The American Trade Enforcement Effectiveness Act modernizes the “injury” standard used in antidumping trade cases and includes provisions to strengthen our trade laws significantly – a decided win for the domestic steel industry. We will also remind readers that the first administrative review of the imposed duties on the affirmatively named countries in the OCTG trade case can be requested this September by either importers or domestic petitioners. 

Meanwhile, nobody needs to be reminded that oil prices are running one-third below the five-year average and the fate of OCTG for 2015 is balanced on a fragile ecosystem. While definite improvements have been seen in oil pricing of recent, much hinges on the production response if oil prices recover upwards toward $65 - $70/barrel. Domestic OCTG mills are proceeding with great caution eyeing “lean” order books and rising costs of raw materials. OCTG demand is expected to “inch up” by the end of the year while prices remain down or flat until inventory levels can be restored. If oil prices take another turn for the worst all bets are off. Distributors primary concern is reducing inventories/months of supply. Some are worried about the impact of the demand fallout on their already thin margins. 

So what will it take to turn the OCTG industry around and what will the oil patch look like five years hence? “Restraint from oil companies, OCTG producers and importers,” was the answer frequently given for the former. And in five years’ time we can expect to see “the outcome of a lot of consolidation”; suggesting for all but the leanest and most efficient of organizations the well will likely run dry as excess supply, weaker demand and uneven economic growth catch up with the oil patch. Be that as it may, don’t let this forecast rain on your parade. After all, how many folks predicted the “U.S. Shale Revolution” prior to 2007? 

Photo Courtesy Hunting Energy Services Inc.

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I thought it would be interesting now to re read this article from Wendy Stueck from the Globe and Mail on just what to expect on development moving forward on the Site C Dam. Published October 15, 2014 it has argueable insights of how this baby is going to roll.

First Nations challenge to Site C approval could make dam a test case

 

BC Hydro has cleared major environmental hurdles for its Site C megaproject, but opposition from First Nations is almost certain to result in new court action. And that could make the dam a test case for the thorny legal question of when and how public interest can trump aboriginal claims.

“It will be one of probably dozens of projects where that question comes up,” Gordon Christie, an associate professor with University of British Columbia’s Faculty of Law, said on Wednesday, adding that, “I have a hard time seeing how this won’t end up in court.”

A model of the proposed Site C Dam at the Community Consultation Office in Fort St. John, B.C.
First Nations in the Peace River and BC Hydro's Site C dam

In a conference call Tuesday, B.C. Environment Minister Mary Polak said First Nations do not have a veto on Site C and emphasized the mitigation and accommodation measures included in the province’s environmental assessment certificate for the project.

“Our understanding of our obligation is meaningful consultation, accommodation where it is appropriate – we don’t believe that constitutionally there exists such a thing as a veto,” Ms. Polak said.

But some First Nations leaders questioned whether the province is heeding the latest legal developments, including a landmark Supreme Court of Canada decision in June that granted the first declaration of aboriginal title in Canada to B.C.’s Tsilhqot’in Nation. That landmark case, often referred to as the William case after plaintiff Roger William, found government incursions on aboriginal title must be justified on the basis of a “compelling and substantial public interest” and is widely seen as having strengthened First Nations’ role in land-use decisions.

Grand Chief Stewart Phillip, head of the Union of B.C. Indian Chiefs, on Tuesday accused the province of denying First Nations’ constitutional rights by pushing ahead with a “grandiose energy plan.”

Both the provincial and federal governments this week issued environmental approvals for Site C, a $7.9-billion hydroelectric project that would become the third dam on the Peace River and generate enough electricity to power about 450,000 homes a year.

The approvals come with dozens of conditions designed to mitigate impacts on First Nations whose lands would be affected by the project, which would flood 83 kilometres of the Peace Valley to create a reservoir.

The project would have the greatest impact on seven B.C. aboriginal groups that are signatories to Treaty 8, an 1899 pact that also includes signatories in Alberta and the Northwest Territories. BC Hydro is negotiating with five of those seven groups and has made offers to the two others.

Treaty rights in B.C. are broad and typically include the rights to hunt, trap and fish, said Drew Mildon, a partner with Woodward and Company, a Victoria law firm that represented the Tsilhqot’in Nation in its recent court case.

If the Site C debate winds up in court, the province could find it challenging to argue the project is in the public interest, Mr. Mildon said.

“To justify that infringement, it seems to me, is going to be a very difficult step. Because you have to essentially know that there is going to be enough undisturbed natural habitat for there to be a harvestable surplus of species.”

Treaty rights would be a key element in any court case, Dr. Christie agreed.

“That’s the thing they [plaintiffs] will hinge their arguments on, the extent to which the flooding of this territory will make hunting and fishing problematic,” he said.

Those issues are already playing out in Alberta, where some First Nations have challenged oil sands expansion in court, Dr. Christie said.

The Site C debate also involves the question of cumulative impact of resource developments, he said, adding that the oil and gas industry has already had a major impact in the form of roads, wells and pipelines in northeastern B.C.

At a press conference in Vancouver Wednesday, Energy Minister Bill Bennett said he hopes First Nations will recognize the economic opportunities that could come along with the dam if it is built.

“Government needs to make sure that enough engagement is happening with Treaty 8 First Nations so we can get to a point where even if the First Nations are not comfortable supporting the project, then at least they have recognized the opportunities that are there if we decide to build the project,” Mr. Bennett said.

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A US$70 billion takeover of BG Group Plc by Royal Dutch Shell Plc could bode well for Shell’s liquefied natural gas project in Kitimat, but not so well for BG’s own LNG proposal for Prince Rupert, say industry analysts.

Shell confirmed the takeover pf BG Group PLC April 8.

Of the 19 LNG proposals in B.C., the $40 billion LNG Canada project proposed by Shell and PetroChina is considered one of the ones more likely to be built.

Analysts say the merger does not bode well for BG Group’s own Prince Rupert LNG project.

“I certainly agree that the deal casts a lot of doubt on the BG project proposal, and I had heard that it was probably not one of the more likely ones to go ahead anyway,” said Brad Hayes, president of the petroleum consulting firm Petral Robertson Consulting Ltd.

“Shell will focus on what they’ve already got there.”

Some analysts have speculated the company will be occupied with the merger for months to come, which could push back the LNG Canada project. There were also concerns that that might happen anyway, given current energy prices.

Earlier this year, Shell and PetroChina walked away from the Arrow LNG project in Australia.

But Hayes said Shell has already made significant investment in the LNG Canada project and Canada in general, and in making the announcement, Shell’s CEO confirmed that LNG will be an important part of the company’s business going forward.

“Shell is a very long-term and committed player in Canada,” Hayes said. “They’ve been in Canada since the 40s and they’re going to stay here for the long-term.”

“I think that it’s highly unlikely that it will be cancelled. I think it would be shuffled up and down the priority list a little bit, but the fundamentals of there being a long-term big demand for LNG are there.”

Christopher Goncalves, the LNG, natural gas and power group leader for Berkeley Research Group’s, said Shell and BG Group each have substantial global footprints, shipping capabilities and marketing networks in the LNG sector.  He characterized the merger as “a doubling down” on Shell’s LNG business.

He said a rationalization of some of the companies’ projects and activities is to be expected. If one of the projects that cut through rationalization is one of the LNG projects in B.C, it leaves the other in a stronger position.

“There may be one project instead of two, but the strength behind that project will be much more substantial,” he said.

nbennett@biv.com

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What E&P M&A Means For Oil Service & Drilling... Spoiler Alert, It's Not Good

Following the Shell/BG deal announcement yesterday morning, we've fielded some incoming questions from Oilpro readers asking what this transaction means for the rest of the oil and gas industry.

For starters, it is confirmation that M&A is heating up during this phase of the downcycle. In a presentation we gave last week, we conveyed the notion that M&A deals are about to become much more frequent across the O&G value chain.

Our channel checks suggest a burgeoning deal pipeline. While few transactions may come close to the size of Shell for BG ($70bn), we do expect smaller scale consolidation to add up to a meaningful trend this year and next.

Consolidation in E&P is not great for the service industry and vice versa. The reasoning is best explained by Porter's Five Forces. 2 of the 5 tenets of Porter's philosophy are i) bargaining power of suppliers and ii) bargaining power of customers.

When E&Ps consolidate, they have more leverage over their suppliers (i.e. the oil service and drilling contractors). When contractors merge, they are able to push prices higher for E&P operators and sometimes quality can be adversely impacted. A rising concentration of players in any one sub-segment of the industry generally hurts the other side.

And in the E&P industry in particular, scale achieved via consolidation can lead to overall capex reductions, reduced exploration activity, and deferrals of some projects that once were high priorities requiring service / drilling contractor support. For example, if two operators exploring offshore West Africa merged, they might reduce the size of their contracted deepwater rig portfolio - via combination they can deploy assets across the play more efficiently. And in larger portfolios, return profile variation can create shifts in the timing of investment decisions for specific projects. Takeout premiums are often rationalized by the development pipeline of the target, which can curtail the future exploration activity of the buyer.

Shell & BG Will Reduce Oil Service & Drilling Spend Post-Deal

So turning to the Shell/BG combination in particular, here are three points from the companies' management team that are relevant to the oil service and drilling industry outlook:

  • 1. Capex Falling. The combined entity will moderate organic capital investment, and management is looking at deferrals, cancellations, and divestments. The company will also examine its supply chain and procurement processes on a combined basis looking for efficiencies (read less opportunities for contractors).
    • 2. Cutting The Fat. Priorities in 2015 and beyond include acheiving $2.5bn in synergies, accelerating the reset of the supply chain, and looking at new options for capital efficiency. While the elimination of redundant internal resources will play the leading role in achieving synergies, external savings via enhanced bargaining power will have a cameo appearance in the synergy drama.  
    enter image description here
  • 3. Less Exploration Activity. Following the deal, Shell will reduce exploration activity and exploration spending to focus on BG's development pipeline. This impacts the entire front end of the oil service/drilling spectrum from seismic arrays to core analytics to drilling rigs and stim crews.  
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FACTSHEET: LNG project proposals in British Columbia

Wednesday, February 11, 2015 9:00 AM

These are the export projects in various stages of development as of February 11, 2015:

 

Aurora LNG
Website: http://www.cnoocltd.com
Proponent: CNOOC Limited's wholly-owned subsidiary Nexen Energy ULC/ INPEX Corporation/JGC Corporation
Location: Digby Island

Cedar LNG
Website: http://haisla.ca
Proponent: Cedar LNG Export Development Ltd.
Location: Douglas Channel, Haisla project lands

Discovery LNG
Website: www.discoverylng.com
Proponent: Quicksilver Resources Canada
Location: Campbell River

Douglas Channel Energy project
Proponent: AIJVLP, a limited partnership between AltaGas Ltd. and Idemitsu Kosan Co., Ltd., EDFT Trading and EXMAR
Location: Kitimat (floating facility)

Grassy Point LNG
Website: http://www.woodside.com.au
Proponent: Woodside Energy
Location: Grassy Point, north of Prince Rupert

Kitimat LNG
Website: http://www.kitimatlngfacility.com/
Proponent: Chevron Canada and Woodside Petroleum Limited
Location: Kitimat

Kitsault Energy project
Website: www.kitsaultenergy.com/
Proponents: Kitsault Energy Ltd.
Location: Kitsault

LNG Canada
Website: http://lngcanada.ca/
Proponent: Shell Canada and their co-venture partners - KOGAS, Mitsubishi, and PetroChina
Location: Kitimat

NewTimes Energy
Proponent: NewTimes Energy Ltd.
Location: Prince Rupert area

Orca LNG
Website: http://orcalng.com/
Proponent: Orca LNG Ltd.
Location: Prince Rupert

Pacific Northwest LNG
Website: http://pacificnorthwestlng.com/
Proponent: PETRONAS/Progress Energy/JAPEX
Location: Prince Rupert

Prince Rupert LNG
Website: http://www.princerupertlng.ca/
Proponent: BG Group
Location: Prince Rupert

Steelhead LNG
Website: www.steelheadlng.com
Proponent: Steelhead LNG Corp. and the Huu‐ay‐aht First Nations
Location: Sarita Bay, Vancouver Island

Stewart Energy LNG
Website: www.stewartenergy.ca/en/
Proponent: Canada Stewart Energy Group Ltd.
Location: near Stewart, British Columbia

Triton LNG Limited Partnership

Website: www.altagas.ca/ or www.idemitsu.com/
Proponents: AltaGas Ltd. and Idemitsu Canada Corporation
Location: No site has been chosen, but Kitimat and Prince Rupert are under consideration.

WCC LNG Ltd.
Website: www.exxonmobil.com/ or www.imperialoil.ca/
Proponents: ExxonMobil Canada Ltd. and Imperial Oil Resources Limited
Location: Tuck Inlet, Prince Rupert

Watson Island LNG
Website: http://princerupert.ca
Proponent: Watson Island LNG Corporation
Location: Watson Island near Prince Rupert

WesPac LNG
Website: http://wespac.com/
Proponent: WesPac Midstream - Vancouver LLC
Location: Delta

Woodfibre LNG Project

Website: http://www.woodfibrelngproject.ca/
Proponent: Woodfibre Natural Gas Limited
Location: Squamish

In addition to the export projects above, these domestic LNG facilities are operating or proposed in the province:

AltaGas
Website: www.altagas.ca/
Proponent: AltaGas Ltd.
Location: proposal to build small LNG facilities throughout northern B.C.

Mt. Hayes Natural Gas Storage Facility
Website: www.fortisbc.com/
Operator: FortisBC
Location: Ladysmith

Tilbury LNG facility
Website: www.fortisbc.com/
Operator: FortisBC
Location: Tilbury Island in Delta
*Note: This facility is undergoing an expansion. WesPac LNG is proposing to export supply from the facility following the expansion project.

Contact:

Sandra Steilo
Media Relations
Ministry of Natural Gas Development
250 952-0617 

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Strong Growth Expected for Commercial Real Estate Sector in 2015

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BCREA <bcrea@bcrea.bc.ca>

6:00 AM (2 hours ago)
 
to me

For the complete news release, including detailed statistics, click: here.

For immediate release

Strong Growth Expected for Commercial Real Estate Sector in 2015

Vancouver, BC – March 5, 2015.  The BCREA Commercial Leading Indicator (CLI) rose 0.8 index points to 119.8, the fourth consecutive quarterly increase. The continued advance in the CLI trend points to optimism surrounding the economic environment underlying the commercial real estate market.

“Rising consumer confidence combined with a lower value of the loonie and a strengthening US economy helped to push the economic activity component of the CLI higher in the fourth quarter,” said BCREA Economist Brendon Ogmundson. “A stronger provincial economy in 2015 will support increased commercial real estate activity this year.”

The rising trend in the CLI generally points to growth in investment, leasing and other commercial real estate activity two to four quarters ahead. Therefore, the positive increase in the trend component of the CLI for the fourth quarter of 2014 signals positive growth for much of 2015.

- 30 -

To view the full BCREA Commercial Leading Indicator index, click here.

For more information, please contact:

Brendon Ogmundson Damian Stathonikos
Economist Director of Communications and Public Affairs
Direct: 604.742.2796 Direct: 604.742.2793
Mobile: 604.505.6793 Mobile: 778.990.1320

The British Columbia Real Estate Association (BCREA) is the professional association for more than 18,500 REALTORS® in BC, focusing on provincial issues that impact real estate. Working with the province’s 11 real estate boards, BCREA provides continuing professional education, advocacy, economic research and standard forms to help REALTORS® provide value for their clients.

To demonstrate the profession's commitment to improving Quality of Life in BC communities, BCREA supports policies that help ensure economic vitality, provide housing opportunities, preserve the environment, protect property owners and build better communities with good schools and safe neighbourhoods.

For detailed statistical information, contact your local real estate board. MLS® is a cooperative marketing system used only by Canada's real estate boards to ensure maximum exposure of properties listed for sale.

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Ottawa grants tax breaks for LNG sector in B.C.

 

 
 
 
 

Ottawa has agreed to grant tax relief to proposed B.C. liquefied natural gas terminals, hoping the incentive will help persuade LNG backers to make final investment decisions.

Prime Minister Stephen Harper announced the federal tax breaks for B.C.’s fledgling LNG sector during a visit to Surrey on Thursday, saying lower taxes on industry players will spur economic activity.

While there are 19 LNG proposals, none of the proponents have made the decision yet to forge ahead with investing billions of dollars needed to export natural gas in liquid form to customers in Asia.

The pending changes to capital cost allowance rules mean that B.C. LNG projects will be able to take advantage of breaks pegged to asset depreciation rates.

“This will create investment that would obviously not occur,” Mr. Harper said. He added that while the tax changes will be crucial for LNG projects, “the actual cost in our fiscal framework is quite modest” – perhaps an initial impact of less than $50-million in revenue to federal corporate tax coffers until 2020.

The B.C. LNG Alliance and the provincial government have been advocating for better fiscal rules federally for planned export terminals, saying the manufacturing sector already enjoys favourable tax treatment.

Pacific NorthWest LNG, a joint venture led by Malaysia’s state-owned Petronas, praised Ottawa for the tax relief that will be in effect for nearly 10 years.

“The government of Canada is delivering on its goal to diversify and grow Canada’s energy exports,” Pacific NorthWest LNG president Michael Culbert said in a statement. “Pacific NorthWest LNG has the potential to generate over $1-billion in tax revenues to all levels of government each year.”

Ron Loborec, an energy expert at Deloitte & Touche LLP, said the tax deductions are important. “I see this as a valuable shot in the arm and incentive that makes B.C. more competitive,” he said.

Premier Christy Clark welcomed the new depreciation formula for equipment and buildings at B.C. LNG terminals.

“The change the federal government has made is going to be a big help in making sure LNG companies get to that final investment decision,” she said. “We were really persistent. The federal government was curious. You have to make your case.”

The B.C. government, which unveiled its provincial LNG tax structure last October, is counting on three LNG projects operating by 2020, with hopes that one of those will be a major exporter.

“To the extent this makes it an easier environment for investment, that’s really good,” Ms. Clark said.

Industry analysts caution that there is only room for four B.C. LNG export terminals at most due to fierce global competition from rivals such as Australia.

B.C. LNG proponents are conducting further studies before making their final investment decisions.

“We view this as a positive step by the government of Canada and this will help increase the fiscal certainty that we’ve been looking for,” said David Keane, president of the seven-member B.C. LNG Alliance.

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French Major Total Gives Traders Long-Term Insight On Global LNG Markets

TotalLogoThe global LNG industry is in flux. Australia is close to replacing Qatar as the world’s number one supplier with the US also on the way to becoming a major exporter. This greater competition between suppliers has wiped out – at least for now – the premium spot supplies can command in key East Asian markets. But the 50% fall in crude prices over the past six months means that many proposed LNG export projects will be delayed – if not cancelled – as companies struggle to keep healthy balance sheets.

In a wide-ranging interview Total’s Senior LNG Advisor Guy Broggi tells MEES about the challenges and opportunities faced by the French major and its peers in the current market environment.

The global energy industry has witnessed a fall in crude oil prices of more than 50% since mid-June. International oil companies have all announced significant Capex cuts. How is this influencing Total’s LNG global strategy?

Our LNG strategy is to increase our portfolio of LNG. This has not changed, despite the fact that LNG and crude oil prices have been declining very steeply. Because the LNG business is a long-term business, we are still active in the projects we started, including Russia’s Yamal LNG and Cheniere’s Sabine Pass in the US.

What matters for the big names in this business is to have projects sanctioned, as well as projects on the drawing board to be able to offer buyers the necessary LNG when they need it. If you have access to gas reserves, it takes 5-10 years before first LNG production. You have to get prepared in advance to attract markets, be it in Asia, or in Europe. But we are more cautious about the next projects to be sanctioned. These will be under greater scrutiny because of prices.

Which projects are you talking about?

We are evaluating the exploration potential in our block in Papua New Guinea. We first need to confirm the reserves and then make up our mind on exporting LNG eventually. These things take time. And the current situation on energy prices will not divert us from making a decision in the future.

The Yamal LNG project is under construction [but] we are still looking for financing solutions following sanctions imposed by the West on Russia. Each shareholder is financing [their share of] the project so it’s a question of patience until the resolution of the political and military crisis between Ukraine and Russia – we hope that this geopolitical context will change sooner rather than later. We are still hoping for a start-up in 2017-18.

We have already incorporated Yamal LNG output in our portfolio, and we are expecting good news from the US on the Sabine Pass export project, which is expected to start in 2016 and in which we have already committed to take some quantities. In other words, our portfolio will be increased by these two projects.

For the next phase, we still have reserves in Nigeria. Expansion at Nigeria LNG (Train 7) and a grassroots Brass LNG project have been under consideration for several years. A decision on how to proceed may be taken at some point in the near future.

Projects led by competitors have been shelved. When you have been working on a project for years, even if you already found potential buyers and signed MoUs, you still work on the project but you don’t rush to take a decision. The [Chevron-operated] Kitimat LNG project in British Columbia for example and Arrow LNG in Australia [Shell], have just said that time is not right to take a decision. In other words, they appear to be either delayed or cancelled.

Prices for spot LNG – mostly uncommitted LNG – have fallen considerably since last summer, before the fall in oil prices. How is this affecting Total?

The decline in crude oil price is affecting the entire company’s finances. We will start by cutting the Capex and trying to reduce Opex, as previously announced by our new CEO, Mr Pouyanné. Big companies are used to such things. They can weather a short-term reduction in the crude oil price.

As far as LNG prices are concerned, they had been declining even before the oil price fall and for different reasons. The fall in LNG prices was mainly due to an increase in global supply from existing and new projects – like PNG LNG – and slower demand growth. And of course, because long-term LNG contracts are indexed to crude oil, you are witnessing further mechanical declines.

More than 50% of our production is natural gas so of course our finances are impacted. For us, the problem is how to survive in an environment where prices may stay at this level, for a couple of months... or years, who knows. However, it will not change the way we see Total as an energy provider in the future.

So we have to be selective and aim for the best projects in terms of security and location. You can’t go today into countries like Syria and Libya for obvious security reasons. Then you have to consider the quality of reserves you own and how you can adapt to market conditions, by reducing your costs because you know pretty well that your revenues are reduced in such an environment. One potential opportunity for LNG is the transportation and bunkering sector where crude oil products are replaced by natural gas. Our long-term strategy has not changed yet. It may change, if it looked like $50/B were here to stay. This would be a general change for the energy market, not just for Total.

So with an uncertain oil price outlook, what are the main factors driving new LNG projects?

Natural gas is experiencing the same glut as oil. Supply is greater than demand. The culprit is partly the US, which is becoming a big oil and gas producer. In terms of reserves, there is far more natural gas than crude oil accessible on the planet. The race will be between the best technologically available sources of production. The winners will be the less costly, well located projects in terms of security and distance to the final markets.

Having said that, we are in a world where the geo-strategy of hydrocarbons prevails over economic reasoning. Today the war within Iraq and dynamics with Iran are based on who is going to control the energy of the future. North America, Russia and the Middle East are competing for a greater role in supplying the whole world and the best place for “security of supply”.

If you start to threaten people with supply shortage, they walk away and try to find other solutions such as renewable energy, coal, or traditional energy from countries with greater security of supply.

How do you see the role of the Middle East in the global supply picture?

For the time being we are just reacting to political developments in the Middle East. We shut down operations in Libya [see p4], we are no longer in Syria. We have become very concerned in Yemen [see p16]. Qatar remains a big LNG producer, we hope it will remain so because of our involvement there with Qatargas. But the current moratorium means there will be no new LNG from the Middle East in the foreseeable future. It doesn’t mean that the Qataris will stay put. They will do what we do: find better places to do business. The Qataris, with ExxonMobil, will launch the Golden Pass project in the US which will serve their clients especially in Europe.

Aren’t Golden Pass and other projects in the US and Asia Pacific facing uncertainty due to current oil and gas prices?

For me, Golden Pass is not entirely based on pure economics. This project has a strategic importance and Qatar and ExxonMobil will go for it: short-term prices have no relevance when you talk strategy. They have spent billions of dollars on a white elephant in Golden Pass and the best way to use it is to transform it into an export plant. This future LNG could easily go to the UK and the west coast of Europe, while new markets like Pakistan, Bangladesh, Egypt and Jordan will be supplied by quantities diverted from the current UK or European contracts.

New buyers are not where you think they would be: they are in the Middle East and South Asia. Take Egypt, Pakistan and India, they all can be supplied by Qatar LNG.

After the wave of costly LNG projects, like Australia’s Gorgon LNG, Ichthys and Queensland LNG, all the reserves owners waiting for a market will be ready to contract additional trains at somewhat lower prices. Because people will need to work, we may well find ourselves in a low price environment for new projects.

Look at ExxonMobil, they have announced a third train in Papua New Guinea: it will not be low cost but marginal cost; it is well located; the Asian markets will love it.

Alaska LNG will go ahead for geopolitical reasons and sound economics after 2025. In Canada, one or two projects may be sanctioned by the end of next year. Look at who is promoting the project: if you have plenty of buyers owning the gas as well as the project, they may decide to go ahead and take the LNG for themselves, hedging their risks all along the LNG chain.

What minimum oil price would allow these projects to go ahead?

Again, you can’t just look at the price; there are projects which are meant to bring energy into countries like China and Japan where people actually need energy. I don’t want to say that the price doesn’t matter, but it’s about finding a price in line with the entire economics of producing the gas, transporting and liquefying it under conditions that allow their inclusion into existing end-users’ markets.

When it comes to Australia, it’s ‘wait and see’. People will be trying to regroup, try to find the best reserves they have, try to find the best projects for their buyers, and start talking to them.

In Mozambique, Eni, Anadarko and their partners have almost finalized the marketing phase so they may ask themselves twice on whether to go ahead or not. It’s a question of buyers and sellers talking together and agreeing on a time schedule, costs and prices.

Current spot LNG prices are currently around $7/mn BTU for Asian delivery in Asia, down from around $15/mn BTU a year ago and below the UK’s NBP price for the first time since 2010. What pricing trends do you expect in the coming months?

The situation is very simple on the spot market: we have the same price everywhere, from Japan to Brazil. Arbitrage opportunities are very limited. Atlantic basin LNG will be for Atlantic buyers while Pacific Basin for Pacific buyers for the time being.

We know what kind of surplus would be diverted to Europe if Asian buyers don’t take this extra LNG – there is a surplus of LNG coming from many places for different reasons (extra cargos, uncommitted quantities from new projects, quantities released after contract termination, etc...) therefore this situation may last more than six months.

How is your trading business affected?

It is not affected at all because we have hedged our position for the next three years. Our deals for this period are already cashed in and hedged. At present, we are working on deals from 2018 onwards.

What do you do beyond that period?

This is the beauty of a portfolio – if we have some more LNG from Yamal, or US LNG – because we have already some end-users contracts, priced where they were priced, so we will arrange the best supply for these buyers.

Compared with oil-indexed long-term contracts, how much do you expect spot LNG prices to fall and by when?

In Asia, if you assume a price of 14% to 15% of Brent value plus 1, we will have some prices between $7-8/mn BTU if we stay at $50/B. If it comes to $70-80/B, the LNG price will be proportionally higher. LNG contracted on long-term basis will still follow the same formula. But then, on top of that long-term LNG, you have so many offers for flexible LNG, with buyers trying to complement the long-term contract through these spot sales.

Oil indexed long-term contracts give buyers the confidence that they will receive their own base-load quantities and at a price which they know, because the price of oil is factored in the formula with a time lag of three to five months. So the price of April deliveries under a long-term contract is already known by now.

Do you think LNG producers will start wanting to renegotiate their oil-indexed long term contracts with buyers if low oil prices were to persist?

One has to abide by contractual terms. There are times when it is allowed to open the price again via “price reviews”, usually every five years, so some clients in Japan, Korea and Taiwan are always in price reviews. So if they start new renegotiations today for the next five years, of course today’s context will have an influence. There may be a return of the S-curve within contractual formulas. But, remember, in a negotiation both parties have to agree to new pricing.

So what kind of opportunities do current market conditions present?

Now is the time for traders and participants with geostrategic purposes. IOCs are just monitoring the situation, trying to see where their reserves are best located for the best markets. For them, strategy has nothing to do with short-term market considerations.

Because it’s a time for trading, the likes of Vitol and Trafigura are taking big risks, in supplying Egypt [see p6], Argentina, countries where the money supply is not guaranteed.

New LNG candidates say they want LNG, so you have to believe them. If Abu Dhabi says it will build an import terminal in Fujairah, I hope that they mean it! The same applies to Bangladesh and Pakistan. Everybody needs LNG! But are they ready to pay for the necessary infrastructure to receive it? The current conditions might be an opportunity for such candidates.

But there is plenty of LNG around, and there’s even talk of some Asian buyers committing to take too much LNG between now and the end of the decade?

I don’t think Asian buyers have committed too much. Among currently operating LNG plants, some were targeting the US and Europe at their FID time, some years ago. The aftermath of the Fukashima nuclear disaster in 2011 witnessed a shift between the Atlantic Basin and the Pacific region, especially due to an increase in Japanese imports (with a plateau at 88mn tons/year).

A new wave of LNG was contracted and is under finalization in Papua New Guinea and Australia. From these new plants a certain amount of uncontracted LNG will have to find a home at buyers’ terminals. If not in Asia, this extra LNG will have to come back to Europe.

As far as new LNG projects are concerned, they have now to look for 2020+ buyers’ needs, which may come from termination of former contracts and start-up of brand new buyers like Pakistan, Bangladesh and the Middle East.

How much can Middle East countries absorb?

Some Middle East countries have already started importing LNG: Kuwait and Dubai; others have taken the decision to do the same, like Egypt, Jordan and Fujairah (UAE). These imports are starting to become substantial and will absorb quantities initially intended for the US or European markets. Don’t forget, however, that a well-designed pipeline policy could also supply these countries from huge producers like Iran, Iraq, Qatar and to a lesser extent Israel.

What does this mean for the market and potential competition?

Competition now is between suppliers. In Europe, buyers can relax because they don’t need LNG anyway. And in Asia, the traditional buyers have plenty, they have covered their long-term needs [until around 2020 after which some buyers will have to renew some existing contracts]. So now there are opportunistic buyers and they take what is available on the market. They are contracting with suppliers: Aqaba LNG (Jordan) is talking to Shell; Pakistan and Bangladesh to Qatar, and Egypt to Sonatrach, Gazprom and Trafigura, even Vitol for short term supplies. The result of exploration in Egypt shows there is potential for natural gas production in Egypt, but timing is not good for huge investment in Egypt today. So the only thing they can do is import, start building an industry which is reliable and go back to domestic production when times are better. One serious issue here is security: the region is not right for business today.

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In early 2013, we interviewed Daniel Lacalle, a London-based energy analyst. Lacalle has also been active in the media in the last few years, airing his views about the markets and the economy on his website and for El Confidencial. He has been a regular guest on most of the major financial media outlets. Since our previous interview, Lacalle has published three books in Spanish and one in English (a translation and update of his first work Life in the Financial Markets) and will publish his second book in English, The Energy World Is Flat, in the next couple months.

Given the latest developments in the price of oil and their implications for the broader market, we at Enterprising Investor thought it was time for a second round with Lacalle. We spoke with him last month, in the midst of the plunge in oil prices — a trend that has only continued in recent weeks, rendering some of the figures mentioned out of date.

Gustavo Teruel, CFA: Daniel, you have been quite bearish about the fundamentals driving the oil price in the long term, I guess you must be feeling vindicated these days?

Daniel Lacalle: Evidence was mounting and very few wanted to acknowledge it. While the “peak oil” conspiracy theory continued to be proven wrong, its message remained in the public consciousness, and the oversupply in the oil market grew. I received a lot of criticism, particularly about the resilience and strength of the non-OPEC supply growth as well as the slowdown in Chinese demand. Today, no one questions it — I hope.

The last time you wrote about the moves in the price of oil was 30 November 2014. Do you think there has been a downward overshooting?

It is not overshooting. Oil prices have been rising on the back of a pro-cyclical cost curve. That is, service costs and development costs tend to rise as oil prices go up and investments increase well above the market’s needs. The industry has gone from underspending in the late 1990s to overspending — close to $1 trillion a year — on the back of an elusive growth of demand that has been proven incorrect. Efficiency and a less industrial model have proven that the correlation between real GDP growth and energy demand is broken. We do more with less, and the unit of energy needed to create a unit of GDP is lower today than 30 years ago. Now we find that many of those investments made in the 2004–2013 period have created overcapacity in the system.

What happens is that oil prices, when OPEC refuses to be the balancer of the market, test the marginal cost of production — and costs fall. High-spec sixth-generation rigs, pressure pumping, seismic, completion — all these costs have fallen between 20% and 45% in the space of two months as overcapacity becomes evident and excess capex [capital expenditure] is revised.

OPEC’s decision not to balance the market through cuts makes total sense. It was not OPEC who increased production well above demand in the first place, and they are also the lowest marginal cost of the curve. Why should OPEC countries cut production to let non-OPEC countries grow even further and erode their market share year by year?

Conventional wisdom credits the conspiracy theory that says the decisions made by Saudi Arabia with regard to output have the sole purpose of hindering Russia, for geopolitical reasons, or, at a minimum, the least-efficient producers. Do you believe that is the case or do you think the cartel’s influence goes only so far?

I think those conspiracy theories tend to flood the energy market because they make the analysis look simple. And by accepting the conspiracy, it stops us from really understanding the issues. There is no desire to harm anyone. Saudi Arabia does not need to balance the market for non-OPEC countries to grow their production when the kingdom’s production costs are the lowest. It is like thinking that an efficient and low-cost producer has to reduce output to let the higher-cost producers thrive. Saudi Arabia and the rest of OPEC are simply showing the world and their clients that they are the low-cost, efficient producers and that they can sustain a period of oversupply. It is up to the other producers to see whether they can be more efficient or not. It is not “harming Russia.” Many countries, including Saudi Arabia, lose excess oil revenues, but they will adapt. Saudi Arabia loses $100 billion of revenues from these oil prices, but like many OPEC countries, they have no debt, strong currency reserves, and a low cost base.

Saudi Arabia is defending its market share and proving it is low cost. But more importantly, OPEC knows that cutting would be damaging for them and ineffective. The world has about 2.5 million barrels per day of excess supply. Would OPEC cut almost 10% of its production to keep prices higher and support the rise of non-OPEC production, which is growing around 3% per annum? This makes no sense. A cut would only extend the overcapacity and just erode OPEC’s market share.

Some market strategists, pointing to historical precedent, are now saying that the price of oil is going to remain low for years. Don´t you think we have reached a point in oil prices where market dynamics — the rise in fuel consumption, the shutdown of projects, the cuts in capital expenditures — can only add upward pressures?

Oil can go lower. Maybe to $50/bbl [barrel] [Editor’s note: this interview was conducted before oil fell below $50/bbl in early January.] Al-Naimi [the Saudi Arabian Minister of Petroleum and Mineral Resources] mentioned it could go to $40 or even $20. It was only eight years ago when it was at $45–$50/bbl in real terms (we always speak of oil in nominal terms, which infuriates me). Oil is at 1978 prices in real terms today — that is, counting the impact of inflation. Neither demand nor supply dynamics have tightened the market dramatically. Excess capacity has only grown from 1–1.5 mbpd [million barrels per day] to about 2.5–3 mbpd. I do not know if there will be spikes due to one-off events, but I know that oil is at $60/bbl today, despite the fact that Libya’s exports have been slashed [in December] by 400,000 bpd and that non-OPEC growth estimates have been revised down by around 700,000 bpd. This tells you how well supplied the market is. Despite ISIL [Islamic State of Iraq and the Levant] and Iraq, Libya, the Russian crisis, and Brazil’s scandal — all of which could affect production — the supply-demand balance remains ample. One thing is for sure: the period of disinflation in oil prices can last longer than what many predict.

It seems that the smart money is entering the industry. They claim that the rationale of this move is that there has been indiscriminate selling of asset classes and sectors of the market due to the way exchange-traded funds (ETFs) work, which has left the market rife with opportunity. I guess the second point of the rationale is that they believe the stickiness of capex in the industry, hedging, and the upward trend of prices from this point will keep the companies they are investing in afloat. Do you share that view?

[Laughing] If the market moves against your thesis, blame the speculators, not the wrong thesis. I love it. Again, it is simplistic — and wrong. The poor speculators — they are to blame when prices go up and when they go down as well [laughs]. According to data from the CFTC [US Commodity Futures Trading Commission], net length in oil increased [in] December and oil fell. ETFs and speculators do not make the price. They buy financial products referenced to the physical price, not the opposite. CFTC data show that speculators are still net long oil futures by 300,000 contracts, a very large margin compared to a few years ago.

Anyway, we have some investors in the market who want to believe this is a temporary glitch and want oil to go higher to justify investments in stocks and debt. That is fine, but is nothing more than a desire. I remember when natural gas prices collapsed from $12/mmbtu [million British thermal units] to $6/mmbtu, many said the same — and they fell further, to $3.6/mmbtu [Henry Hub]. This is because their view of the fundamentals is flawed due to a number of misconceptions about the industry:

  • Forgetting that spare capacity becomes a sunk cost and many producers just run for cash, not for 10% or 20% IRRs. Remember refining — a business that has been delivering below the cost of capital returns for many years, or seismic, or shipping.
  • Ignoring efficiency and substitution. Just by improving light-duty vehicle motors in the United States from 24 to 34 miles per gallon reduces oil demand by 4 mbpd, almost four years of growth. Just a 6% penetration of hybrids in the United Kingdom and United States would reduce demand by 3.5 mbpd.
  • The industry is not self-adjusting, as many want to believe, but pro-cyclical. As such, megacap major oil companies tend to acquire low-hanging fruit not to tighten the market, but to grow and expand. The large acquisitions in shale gas in 2009–2013 did not reduce oversupply in the United States — they prolonged it. The industry becomes more efficient and adapts to lower prices, it doesn’t shrink to tighten.

To summarize, be careful about buying ex-growth sectors on the promise of internal adjustment. As in utilities, coal, gold, or refining, it can be a deadly mistake.

How do you see the situation with the vast amounts of high-yield debt used to fund shale oil ventures? Do you think, as some pundits argue, that there will be a wave of defaults that could trigger a severe downturn in the United States, as happened with the burst of the housing bubble?

This is ridiculous. They talk about the shale bubble when energy is less than 5% of the commercial loan book of banks, and less than 14% of the entire high-yield spectrum. And, they compare that to housing, which was multiple times those figures!

These people see shale, with the high end at 2.5-times net debt to EBITDA, as a bubble but do not see renewables, which have 4.5-times to 6-times EBITDA debt, as a bubble?

Just think of the following figure: if there were 13% NPLs [non-performing loans] in energy (to use the NPLs of housing from the Spanish banks, for example) in the entire United States, the total figure would be around 0.1% of the banks’ loan book and less than the NPLs in solar of peripheral Europe today!

These fearmongers forget that the oil industry is less indebted today than it was years ago, that 90% of shale production is profitable at $60/bbl, and that out of the hundreds of companies, very few breach their covenants at $60/bbl. They forget the example of shale companies, which successfully navigated the collapse in US gas prices. They forget that the equity market and M&A [merger and acquisition] ramp up with these opportunities. More importantly, they forget that more than 80% of shale production comes from monster-large companies like Exxon, Shell, Statoil, Continental, Anadarko, Occidental, Hess, Devon, Apache — with some of the strongest balance sheets in the world — who have successfully survived low and high prices and many geopolitical crises and events. Will there be some bankruptcies in the small names? Maybe, but those companies and licenses will be acquired by larger, more efficient players.

I find it ironic that the doomsayers focus on shale, when in 2014, with high subsidies and low interest rates, we saw a record number of solar bankruptcies — the list of carcasses between 2009 and 2014 is staggering. But hey, shale is a bubble [laughs].

One final question about the oil industry: Do you foresee consolidation of the industry? Is there a lot of money to be made betting on which companies will be acquired?

There will be consolidation, but before that happens we have to see excess-capex adjusting, dividend cuts, and really cheap opportunities. We are easily one or two years away from M&A. Remember not to buy based on the greater fool theory, and that M&A does not happen on a mass scale. Learn from the shale gas example or the West Africa upstream example. Those who bet on acquisitions found that valuations went much lower before it actually happened. M&A might be at rock-bottom prices, asset driven, or not happen at all at the levels or premiums that investors desire. Buyers will look for scale, quality, and opportunity to improve efficiency.

A quick question about utilities: How do you think all this is going to affect green energy? Is it easy to pick winners and losers among utilities, given a scenario of cheap oil? What characteristics do winners and losers have?

The impact is already evident. Virtually none of the solar and wind projects are competitive at the $100/bbl equivalent, let alone at $60/bbl. Solar PV [photovoltaic] system installation estimates in China have been reduced for 2014, 2015, and 2016 by 2 GW [gigawatts], 2.5 GW, and 3 GW, respectively. Germany will also install 2 GW less than last year. Wind installations are expected to stall globally by 2016. In essence, lower oil prices mean subsidized energy suffers, so it will have to adapt.

Losers bet on cheap debt and on the promise of rising prices or subsidies. Those will inevitably be the low-hanging fruit, as in oil, and will be absorbed.

Winners adapt, become more efficient, learn from the mistakes of the past, and focus on cash-flow generation, a diversified mix, and a good portfolio. The winners will be the diversified, low-leveraged players.

Finally, I would like to ask you about your books. In our previous interview, I asked you whether you thought it was feasible to publish your first book — Nostros, los mercados — in English. You have finally done that, and you have another book in English in the pipeline. I read the Spanish version of Life in the Financial Markets when it was released. Are there many changes in the English version?

Life in the Financial Markets has been updated to reflect the end of QE [quantitative easing], the new era of rising market exuberance after the crisis, the European recovery, the role of the ECB [European Central Bank], and Abenomics. It also covers new elements like bitcoin and high-frequency trading, as well as being more focused on international markets. A reader told me it is almost like a new book — revised, more international, and focused on the issues that matter today.

Your next book, The Energy World Is Flat, is solely about energy. Tell us about the insights this book can offer readers of Enterprising Investor.

I believe it is a detailed guide to the new era of competition between technologies, the battle for market share, the end of oil as transport king, and the war driven by efficiency. The book has been a great success in Spain — it sold two editions in less than two months — and shows, in layman’s terms, the 10 forces that are flattening the energy world and that will generate opportunities in energy globally. It is not a book about oil. It covers natural gas, LNG [liquefied natural gas], biofuels, coal, hybrid and electric vehicles, and renewables at a detailed level, but is oriented to all readers, both experts and non-experts. It also gives advice about investing, avoiding value traps and risks, and opportunities in commodities in the new era after the end of peak oil. I hope you like it.

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All posts are the opinion of the author. As such, they should not be construed as investment advice, nor do the opinions expressed necessarily reflect the views of CFA Institute or the author’s employer.

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