Shell Canada LNG Export License Application

Since the Alaska Gas Pipeline and LNG plant plans are in yawn mode, take a look at the Export License Application filed by LNG Canada Development Inc., (Shell Canada, Korea Gas, Mitsubishi, and PetroChina) (LINK).

The annual maximum stated in the application is 1180 BCF, or 3.2 BCF/D which is about the same as the various pipeline options proposed for Alaska.

Section 4.4 of Appendix D (Ziff Energy) addresses Alaska Gas projects in very uncertain terms:

The LNG Option is being explored more thoroughly at time of writing. Project estimates for a 3 Bcf/d pipeline to Valdez are in the order of $20-26 Billion. Costs and economics of transporting and liquefying Alaska production will be dependent on many factors including final size and nature of facility and related pipeline, and are unknown at time of writing.

Section 6.3 foresees the possibility of future "Northern Gas"

Northern Gas (Alaska/Mackenzie Delta): could flow beginning in 2025 at the earliest and, assuming favourable economic conditions, could expand up to 7% of North American supply in
2045. Although discussions for a liquefaction facility and pipeline to Valdez, Alaska are at a preliminary stage, these could impact the supply of Northern gas to North America, if economics were favourable to LNG exports. If Northern Gas is transported to Western Canada, the pipelines would be the costliest component of each project, while another $8 Billion would be needed for Mackenzie field development. Once they are built, the pipelines will have a low variable cost and will continue to flow. Expansion projects (compression) will have low incremental cost and will be likely economic.

 Once again we are in hold mode waiting for 30 July Alaska LNG progress report.

Canada LNG

Shell / KOGAS / Mitsubishi / PetroChina have announced a 12 MTPA LNG plant on Canada's west coast (LINK).  That's about half the size of the possible Alaskan LNG project.  The LNG Canada plant will be located in Kitimat B.C. home of another LNG project Kitimat LNG (LINK).  At 5 MTPA the total of the two plants is less than the possible Alaskan LNG project.

I say "possible" Alaskan LNG project for two reasons 1) LNG isn't crude oil, the potential margins and profits are much less,  and 2) Competition is heating up and Alaska is way behind Australia, the U.S. Gulf Coast and now Canada.

Maybe economies of scale will tip the balance, but remember "You can't dabble at LNG"  Alaska continues to lack the key ingredient of buyer participation.  Until a Japanese, Korean, or Chinese LNG buyer signs up for a portion of Alaskan LNG project we're all just dabbling at LNG.

Shell, Shale, and GTL

Cheap shale gas in the lower 48 is attracting the attention of LNG exporters (LINK) and now Shell is looking at building a large Gas-to-Liquids (GTL) plant in the United States. (LINK). Quote (link and highlights added):

By JAMES HERRON  Royal Dutch Shell is in the early stages of planning projects to turn natural gas into fuels like diesel in the US, of similar scale to its huge project in Qatar, Andy Brown, executive vice president of Shell, said in Qatar Monday.  "We are looking for places where gas is cheap and [oil] products are expensive," he said at a press briefing at the World Petroleum Congress in Doha, Qatar. "Clearly the US is something we're looking at."  Shell is only interested in large-scale projects similar to the $18 billion Pearl gas-to-liquids plant it has developed in Qatar, Brown said. The first phase of Pearl GTL is now producing at close to full capacity and the second phase started over the weekend, he said.

 What can an $18 billion investment yield?  According to the Shell website Pearl converts 320,000 BOE of gas into:

• - 140 kboe/d of gas-to-liquids products (2 trains)
• - 120 kboe/d of natural gas liquids and ethane

At today's prices I estimate that's equal to about $8.5 billion in gross annual product revenue.  The 1.8 BCFD of gas feed stock  would cost about $2.5 Billion leaving a gross margin of  $6 Billion.  Assume operation, maintenance and utility cost of $1 Billion and a Pearl type GTL plant will yield $5 billion annually EBIT.  After taxes the rate of return is in the attractive range.  I assume the capital cost in the lower 48 will be higher than Qatar, so the rate of return is probably in the 12% to 15% range.

How does this relate to an Alaskan Gas Pipeline?  First don't get your hopes up for Shell to build a world scale GTL plant in Alaska - construction cost are much higher than the lower 48 and the pipeline infrastructure is already in place on the Gulf Coast.  A lower 48 GTL plant of this scale does help Alaska - it soaks up 1.8 BCFD of gas, roughly 40% of the 4.5 BCFD capacity of the Alaskan Gas Pipeline.  Keep in mind GTL is expensive, but outfits like Shell can buy gas at $3.5/MMBTU and sell liquid products at $16/MMBTU.  There's also the possibility that more lower 48 GTL plants will be built and the gas demand could easily exceed the volume of the Alaska Gas Pipeline.

Ultimately sponging up cheap lower 48 shale gas with GTL plants and LNG export plants will help create demand for Alaska's gas.

 

Shell Out of Mackenzie Pipeline Project

Just once I'd like to hear some positve news about a North American Arctic gas pipeline.

Today we learn that Shell is pulling out of the Mackenzie gas pipeline (News LINK).

Shell is (was) an 11% player in the pipeline project. The project go / no-go date is December 2013.

Keep an eye on who picks up the Shell share - predictions?

Shale Gas Liquids & Shell Gas Liquids

Larry Persily, the head of the office of the Federal Coordinator for Alaska Natural Gas Transportation Projects has an article in the Alaska Dispatch about shale gas economics (article link). The article focuses on the value stream from shale gas ethane and touches on the possibility of Gas-to-Liquids (GTL) projects in North America.

He quotes Harold York of Wood Mackenzie:

To illustrate just how important the revenue from gas liquids can be for a shale gas producer, York ran through some numbers:

A typical shale well needs $5 to $6 per thousand cubic feet (mcf) of output to make money.

Methane has been priced at about $4 most of the past year.

But the added value of the liquids makes the entire flow from the well worth about $7 to $8 per mcf.

"The natural gas liquids contribution is carrying the well," York said.

The same theme runs through the Chesapeake investor presentation. Page 16 of this presentation (LINK) Quoting:

Many reasons to be bullish on intermediate and long-term natural gas prices:

• U.S. natural gas producers are rapidly moving to an oilier production base. Once producers convert to drilling wells that produce $10-17/mcfe units and finish natural gas drilling to HBP land, why would they go back to drilling natural gas wells if prices increase from $4/mcf to $5/mcf to $6/mcf to $7/mcf? CHK believes this is the single biggest misunderstood aspect of the future bull case for U.S. natural gas...
  

• Conversion of U.S. liquefaction import facilities to LNG export facilities U.S. will be exporting gas via LNG by 2015, when this becomes obvious in 2012, out year strip prices will go up as clear pathway develops for U.S. to receive world natural gas prices
  

• Growing industrial demand U.S. natural gas prices are lowest in the industrialized world and well below oil-based naphtha prices
  

• Quickening momentum for CNG vehicles $4+ gasoline and diesel prices will cause the market to force policy changes
  

• Continuing and accelerating shift from coal to natural gas for U.S. electrical generationElectrical generation natural gas demand could increase 10-15 bcf/d over the next decade
  

• Construction of U.S. GTL plants. Several will be built in U.S. by 2015-16, when this becomes obvious in 2012, out year strip prices will go up as clear pathway develops for U.S. natural gas to receive world oil prices

Both Persily, and Chesapeake discuss future GTL plants. I'm interested to see if a North American GTL plant materializes. If it does I'll bet on a lower 48 plant location. Either way all the factors listed support higher gas prices and improved economics for an Alaska Gas Pipeline.

So what about ethane? This week I learned that Shell is looking at a lower 48 ethane cracker to take advantage of shale ethane (LINK), quote:"

Building an ethane-fed cracker in Appalachia would unlock significant gas production in the Marcellus region by providing a local outlet for the ethane," said Ben van Beurden, Shell Executive Vice President Chemicals. "This fits well with our strategy to strengthen our chemicals feedstock advantage and would be another step in growing our chemicals business to meet the increasing demand for petrochemicals."

I expect this plant to be sited somewhere in West Virgina or Ohio. In the odd math of the natural gas world the shale gas glut causes a ethane glut, ethane prices plummet hurting the economics of shale gas wells, less shale gas is produced and the price of natural gas rebounds.

Long story short - markets are re-normalizing to the available volumes of shale gas and shale gas liquids. New opportunities abound including the Alaska Gas Pipeline.

More LNG exports considered

This time Shell is considering LNG exports to Asia from B.C. From the Vancouver Sun:

In Canada, Shell Canada paid $5.9 billion in 2008 to buy Duvernay Oil Co., a major player in B.C.’s Montney shale gas deposit near Dawson Creek.

Petroleum Intelligence Weekly reported shortly after the Japanese tsunami in March that, as a result of the destruction of two nuclear reactors there, “Shell and its Asian partners could scale their proposed Prince Rupert plant in British Columbia toward the top end of its mooted 8.5 million-14.0 million tonnes/year range.”

Those volumes equal 25% to 40% of the capacity of the Alaska Gas Pipeline (4.5 BCFD). A pipeline from Dawson Creek to Prince Rupert would be about 400+ miles long as the raven fly vs. 800+ miles for a North Slope to Valdez line. Based on flow rates the line would be 24" to 30" vs. 48" for the proposed Alaska Gas Pipeline.

I have mixed feelings about this story - First it's good to see North American shale gas sponged up for export, however my "something is not right here" alarm is going off. If an Alaska LNG plant at Valdez is not feasible, exporting LNG to Asia at $12/MMBTU - how can a smaller plant be justified in Canada? In Alaska, the wells are drilled, in Canada (shale gas) wells are yet to be drilled, and shale gas completions are not cheap.

Update: More from Petroleum News (Link). Perhaps the "Floating Technology" will play a role enabling plant owners the chance to drag up and move the plant if and when the return on capital employed drops below other opportunities.

Economy of scale should work in favor of Alaska - double the length of the pipeline for more than double the amount of gas. Of course economy of scale drop for smaller Valdez LNG plant options (LINK to AGIA Findings LNG Chapter).

Something to keep an eye on. And by the way - where's the Asian interest in Alaska gas?