Western Canadian gas exports to the United States could be completely displaced into Northern California by

1.      Abundant, low cost US natural gas production, and

2.      By several new gas pipelines in the US…

Says a new market study by Bentek, a US energy analysis company.

Overall, Canadian gas exports to the US will drop 2 bcf/d over the next few years – almost 30% – and this impending loss of the northern California market builds upon the loss that western Canadian gas has in lower exports to the US northeast.

Increased Canadian demand and declining Canadian supply will pick up some of the slack, but it won’t be enough to offset a significant loss of exports to the US market in the near term, they add.

Bentek’s report, titled “The Big Squeeze,” is a report that also outlines how fast growing production from the Marcellus shale in Pennsylvania is displacing Canadian gas to the lucrative Northeast US market, and how new pipeline capacity carrying low cost gas out of the Rocky Mountains is now set to displace much of Canadian gas to the US Midwest and lucrative California markets.

“What we outlined in our study was complete displacement of Canadian gas into Northern California by the summer of 2014,” says Jack Weixel, Director of Energy Analysis for Bentek.

Last summer I wrote about how the new $6 billion Rockies Express pipeline, or REX, going from Colorado to Ohio, was displacing western Canadian gas production by almost 10%.  Lately, US natural gas production from the Marcellus shale has also been displacing Canadian gas to the US Northeast.  Canadian suppliers have been able to send more natural gas into the Midwest and Western US to help make up for that drop.

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But Bentek says even that market is at risk – and Canadians could see this market get curtailed within the next two weeks, in early December 2010.

That’s when low cost Rockies gas supply will start flowing east on the newly installed Bison Pipeline.  This will give Rockies producers an additional 0.5 Bcf/d (billion cubic feet per day) of capacity out of the Powder River basin in Wyoming.  The Bison connects into the Northern Border Pipeline, which moves mostly western Canadian supply.

Weixel expects the Bison Pipeline to create stiff competition for Canadian gas.  He says Canadian gas has to get cheaper to stay competitive.

“They (Canadian gas producers) need to drop 14 cents (an mcf).  Let’s say Rockies gas is $3.50/mcf – that means that AECO (the Canadian natural gas benchmark price out of Edmonton) needs to be priced $3.36 to be competitive in northern California,” says Weixel, adding that the breakeven price for certain Rockies gas producers in the Pinedale and Jonah tight sands plays is “well below $3 per mcf.”

Weixel expects net Canadian exports to drop 2 bcf/d through 2015 – out of a total of 6.9 bcf/d now.  But it’s not all gloomy for producers – and their shareholde“At the same time exports are declining, you’ve got Canadian demand growing, primarily from oilsands in the west and coal retirements in the east,” he says. “You’ve also got production slipping  from conventional gas plays in Alberta.  So there is a tightening supply-demand balance.

“Traditionally that would lend itself to gas prices getting stronger.  But we believe that due to the drop in exports, that there will be just as much gas on hand in Canada as there is now.  So if production drops 1.5 bcf/d but exports drop 2 bcf/d, they’re up half a “b” a day.

Canadian gas production is actually going up because of the unconventional plays in BC (read: MONTNEY), but Weixel says the gas rig count in Alberta dropped off a cliff this September, and is about half the number it was last year and about one quarter what it was in 2008.

What’s surprising to me is how little both the industry and investors appear to be concerned about this issue.  The Calgary Herald ran a small story on this, and The Daily Oil Bulletin, which is ready by the industry only, ran a story (masthead, or lead story).  There are thousands of high paying jobs at stake – mostly in Alberta but also in northern B.C.

NEXT STORY – HOW DOES THIS AFFECT THE PIPELINE COMPANIES?

– Keith

Publisher’s Note:  Many of my readers have emailed me to ask what my # 1 energy trade is.  That’s an easy one to answer at the moment.  It’s a little-known Canadian company with an extraordinary new technology… one that will shape the oil & gas hydraulic fracturing (fracking) market for decades to come. This company’s proprietary process is proven to increase production in wells by 40% or more — while it literally “pays for itself.”  I’ve put together a video that details this trade in full. Watch it by following this link.

The Junior Players in this “Unconventional” Natural Gas Formation

Large land prices for natural gas parcels in Alberta are continuing to drive higher – despite some of the lowest gas prices in the last seven years in western Canada.

Alberta has made over $2 billion on land sales so far in 2010, at an average price of $629.57/hectare, vs. a total of $280 million at the same time last year, at an average price of $189.91/ha. And at the most recent sale, where $151 million was raised, much of that was for natural gas.

While that may not make sense, the answer can be found in one word – Montney.

This formation is turning into exactly what producers in western Canada need to stay competitive in a time of low gas prices in North America – big, thick and rich in higher value add natural gas liquids, or NGLs.

“The Montney is becoming increasingly attractive because it is recognized as a thick, highly pressurized formation with a lot of recoverable reserves of natural gas and with a high “NGL” content,” says Malcolm Todd, President of Donnybrook Energy (DEI-TSXv), which has 34 gross sections in the Montney.

The Montney is a NW-SE trending, football shaped formation that straddles the border between British Columbia and Alberta. Much of the merger and acquisition activity in the upstream Canadian gas industry has been here – and at high valuations.

Buyouts this year included ARC Energy buying Storm Exploration for $69,000 per flowing barrel – which at the time was roughly the average valuation price for junior/intermediate oil producers.    When Monterey Exploration was bought out by Pengrowth in July, they paid $200,000 per flowing barrel (but some other production behind pipe).

“Those were really strong sales, and it shows the long term money knows this is a good place to be,” says Ben Jones, CEO of Canada Energy (CE-TSXv), which has 42 sections in the Montney.

He added “our observation has been that critical mass and pipeline access drive the acquisition costs; i.e. large tracts bring higher prices than small, isolated tracts.  That’s somewhat counterintuitive – whatever happened to ‘volume discounts’?”

Jones listed off a number of geological factors that are making the Montney an industry focus:

1.      broad expanse-companies can assemble or buy a BIG land package

2.      intermediate depth

3.      sweet gas (vs Haynesville shale in Louisiana which has carbon dioxide)

4.      very fracable rock (“brittleness”),

5.      high amounts of natural gas liquids through much of the trend

6.      flat declines relative to other shale plays (VERY important for valuations…)

7.      The Barnett Shale appears to be the closest analogue in the US, although he says the Estimated Ultimate Recoveries (EUR) are higher in the Montney.

Donneybrook’s Todd adds that though the Montney is an “unconventional” play, it’s not a true shale play – it’s better.  It’s more like a sandstone, which means it’s more porous than a shale, and so the fracks should move farther into the formation – making Point #7 – higher recoveries – come true.

Jones could have added “multiple zones” – there is the upper, middle and lower Montney, and two zones called the Doig Phosphate and Doig Siltstone.  There is also the Duvernay zone at the very bottom of all the formations which has garnered a lot of attention recently – the Deep Basin it’s called.

Natural gas producers in the Montney have been getting 25-40 barrels of natural gas liquids per million cubic feet of dry gas produced, though sometimes higher.  The basket of NGLs trade roughly at 80% of oil prices, which greatly increase the economics for these wells.

Several other factors are also in play – the Alberta government reduced royalty rates in April, and that sparked a renewed interest in gas in the province.  Plus, there is a sense in the industry that gas prices will not stay low forever.

“Companies with the ability to fund land will continue to do so if they think it is quality,” says Doug Bartole, President of Vero Energy (VRO-TSX), a gas-weighted producer in Calgary.  “They don’t think in short term gas prices – and new crown land has long tenure. They will run their economics accordingly.  Current and near term price forecasts are not sustainable.”

There are several junior Montney gas players, including – in alphabetical order – Advantage Energy, Birchcliff Energy, Canada Energy, Celtic Exploration, Cequence Energy, Cinch Energy, Crew Energy, Crocotta Energy, Delphi Energy, Donnybrook Energy, Insignia Energy, Orleans Energy, Painted Pony Explorations, Progress Energy, Rock Energy, Seaview Energy and Terra Energy and Trilogy and Yoho Resources.

PS – A good map to the British Columbia Montney land sales in 2010 is here – http://www.empr.gov.bc.ca/OG/oilandgas/petroleumgeology/UnconventionalOilAndGas/Documents/2010_August_Montney.pdf

by +Keith Schaefer

Taking Their Chances in the Spot Market… Later

Natural gas prices in Canada are so low that end users are now trying to seduce producers to hedge, so they can lock in longer term low prices.  But few producers are keen to lock in long term losses.

RBC, Canada’s largest brokerage firm, suggested in a weekly comment that producers still have many reasons to hedge at $3.27 a gigajoule (GJ) now, and $4.11/GJ in April 2011.  For context, the full-cycle cost for new gas in North America is $5.60/mmcf and in Canada is $6.85/mmcf, according to independent analysts Ziff Energy.  So producers would be selling at a significant loss.

But some quick calls to the energy desks of the major Canadian firms showed that few producers are biting, and even one of my contacts at RBC said these “hedging strategies are geared more towards the end-user market; the end users are trying to lock in really good prices. But nobody’s hedging.”

RBC lists several potential reasons for hedging, which often mirror the Ziff Energy white paper from June 2010 on the state of Canadian natural gas (a GREAT read – not too technical – www.ziffenergy.com/download/papers/cdn_gas_crossroads.pdf.)

1.     Strengthening Canadian Dollar

2.     US Production Growth

3.     Reduced Canadian Imports

4.     Heightened Pipeline Delivery Competition in the US

5.     Abundance of Canadian Storage

6.     Material Expansion of Canadian Shale Gas Production

7.     Growth in Marcellus Shale Gas Production – Production has increased by over 1 bcf/d since January 2010

That’s a big list! And it’s not good news for producers or their investors – especially the junior ones who either have high gas weightings or are close to their debt limit.

But despite producers losing money on every mmcf out of the ground, some may be inclined to hedge, says Ralph Glass of AJM Consultants.

“The bigger producers are still drilling and they can afford to (hedge); it’s part of their long term plan and their economics of scale allow it.  The only advantage I can see is that if you’re making positive cash flow at $3.50/mmcf, this gives you stability to hang in for one more year.  But it’s not an investment strategy.”

He added even small producers may consider it: “A small producer that has limited cash flow cannot afford to pay for capacity costs without actually producing the volumes.”  This means they may have “take or pay” like provisions, where the producer must pay the pipeline companies their transportation tolls even if they don’t produce the gas.

For producers, it comes down to the same issue it always does – are prices going lower or higher?  By not hedging, major producers are saying that despite all the gloomy market data, they see prices stable or higher.

Long term dated future gas prices are now below $5/mmcf for a full two years out now.  With such a low, and flat futures pricing curve, producers are saying they would rather take their chances in the spot market then, rather than lock in losses now.

P.S. One of the most-asked questions I get from my readers is, “When should I invest in natural gas?”  Follow the link to read my response.

Natural gas companies are now trying to market themselves as “liquid rich” or “wet gas” producers whenever possible.That’s because these “wet gases,” or NGLs (natural gas liquids), are worth a lot more money than straight-up dry gas – which is methane.

Angle Energy (NGL-TSX) has what I call a “freak of nature” gas field just northeast of Calgary. The field contains a whopping 193 barrels of NGLs for every thousand cubic metres of gas produced. The industry expresses this as “xx bbl/xx Mmcf.”For a gas to be considered “liquids-rich” it must yield greater than 10 bbls NGLs for every MMcf sales gas when processed through a plant.  Many producers who speak of “liquids-rich” gas will have average yields of 15-40 bbl/MMcf.

So, how does something like 193 bbls/MMcf happen?

The first reason is that Angle’s Mannville gas pool is located in the “oil window” in Alberta.  What this means is that the pool is buried at a depth where the temperature is not too hot and not too cold.(If it was too hot, it would have turned to just gas, and if it was too cold it would never even have turned into hydrocarbons).The other thing that had to happen was MULTIPLE geologic events, which created the full spectrum of petroleum fluids to remain in deposits – and still kept all the hydrocarbons under the same pressure and temperature.

Petroleum fluids (which are oil, gas and condensate) are made up of many different hydrocarbons.  There are  five general types:

1. black oil

2. volatile oi

3. retrograde gas-condensate

4. wet gas

5. dry gas

A “volatile oil” generally has a higher amount of natural gas in it than a “black oil” does.  A volatile oil produces both oil and gas, and the gas helps to lift the oil, making production easier.  Imagine a bottle of pop that’s flat, and one that has just been opened.  Which one will flow out more easily when shaken? – you get the idea.  Think of natural gas & NGL’s as the carbonation and oil as the Coca Cola.

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Angle’s freak of nature Mannville pool is a “retrograde gas-condensate”.  The retrograde gas-condensate has much higher total NGLs than a simple “wet gas.”   It produces readily (which means it doesn’t need to be stimulated by a process such as fracking), as a volatile oil would, because it has both natural gas and natural gas liquids.

Also, the natural gas liquids will start to separate from the gas and produce both condensate and dry gas at surface.

Now, these retrograde gas deposits occur from Calgary all along the foothills up to the Montney gas play 1000 km north-north-west.

So why don’t I see other companies with similar NGL counts?

That just appears to be luck of the draw.  (The 2^nd largest NGL count I’ve seen is the 100 barrels of condensate per day in Second Wave’s new Gilwood discovery three hours northwest of Edmonton.)

But technology does play a small role. As production of this exceptionally rich gas continues, and the pressure in the pool becomes lower, the condensate (the most valuable NGL) “drops out” in the reservoir itself.

Recovery of all that condensate is difficult.  The problem gets tougher when the reservoir is being produced using only vertical wells.  With 14 vertical wells in the Mannville pool, Angle is only seeing an effective 15-20% recovery of all the hydrocarbons in place.

Horizontal wells help solve this issue and produce the natural gas liquids more efficiently along with the gas.  Possible recovery factors with a horizontal well development are 60-70% of the hydrocarbons in place.  This is obviously a huge difference.

The other technology issue is having the right gas plant.  The capabilities of the hundreds of gas plants around western Canada vary widely.  Some are able to get out all the various NGLs, and some aren’t.  Obviously, the ones that can cost a lot more money and it’s not always worth it, or the operator can’t afford it.

DISCLOSURE: Keith Schaefer owns Angle Energy.