Saturday, December 31, 2011

2011 - Year of the Yawn

I had greater expectations for the Alaska Gas Pipeline in 2011. To recap -

  1. The open season process was expected to yield announcements of precedent agreements for long term commitments to ship gas.  The agreements may or may not have been reached, but no public announcement was forthcoming.  Chances are any agreements reached are so heavily conditioned that they represent no commitment to do anything in the here and now. 
  2. In 2011 I expected a viable shipper for a 7 MMTPA Valdez LNG plant to step forward.  What actually happened was that Governor Parnell voiced support for a tidewater LNG project. The Governor's comments had the unintended consequences of delaying submission of resource reports by the Alaska Pipeline Project (TransCanada and ExxonMobil).
  3. 2011 Started with two Alaska Gas Pipeline projects - The APP (TransCanada & Exxon Mobil) working to the scope as defined by the Alaska Gas Inducement Act (AGIA) and The Denali Project (ConocoPhillips & BP).  I had an expectation that the projects would merge in 2011.  Instead Denali folded in May citing "open season efforts have not resulted in the customer commitments necessary to continue work on its Alaska North Slope gas pipeline project".  

What's next? - for starters spot Henry Hub gas closed the year at $2.97/MMBTU (see chart for 2011 natural gas prices).   That's astonishing and sobering to any proponent of an Alaskan Gas Pipeline.  Gas that cheap in December is partially due to a mild lower 48 winter but mainly a function of  the glut of shale gas. The 200 day average price is right at $4/MMBTU - essentially the low profit range to drill and produce a shale gas well.

In 2012 the North American gas markets will have little appetite for Alaskan Gas.  Billions will be spent to build Gulf of Mexico LNG export capacity and preliminary studies will be launched to look into the viability of at least one lower 48 Gas to Liquids (GTL) plant.  Anti-fracking stories will continue with little effect on the continued development of lower 48 shale gas resources. The annual average price of 2012 gas may fall within the $3.50 - $5.00/MMBTU range. No new nuclear power will come on line in 2012, but a few gas fired plants will come on line to replace aging coal plants.

Throughout 2012 Alaskans will come to grips with the increasing unattractiveness of Alaskan Gas.  The best comment this year came from Steve Kirchhoff, Vice President – Americas, ExxonMobil Gas and Power Marketing Company in a presentation to the Resource Development Council of Alaska in this video. In this presentation Kirchoff states that "You can't dabble at LNG"

Saturday, December 17, 2011

Shale Gas Apocalypse* - Ending?

What would it take to end the shale gas apocalypse* ?  Maybe a ton of new laws constraining shale gas development and destroying thousands of good paying jobs, or maybe.....Monetize and export shale gas as LNG, and convert shale gas to liquid fuels.

I favor LNG exports and gas-to-liquids (GTL) for three reasons - Jobs building LNG export plants, Jobs building GTL plants and Jobs building the Alaska Gas Pipeline.

It's one thing for this lonely blog to promote the idea but the industry is beginning to take advantage of abundant, cheap shale gas.

Today we have news that LNG company Cheniere is planning a second LNG export plant  near Corpus Christi Texas (Rigzone Link) (Marketwatch Link) RigZone quote:

Cheniere Energy announced Friday that its wholly owned subsidiary, Corpus Christi Liquefaction is developing a liquefied natural gas (LNG) export terminal at one of Cheniere's existing sites that was previously permitted for a regasification terminal. The LNG export terminal site is located in San Patricio County, Texas , and it is anticipated that the terminal would be primarily supplied by reserves from the Eagle Ford Shale, located approximately sixty miles northwest of Corpus Christi . The proposed liquefaction project ("Corpus Christi Project") is being designed for up to three trains capable of producing in aggregate up to 13.5 million tonnes per annum (mtpa).

The combined export volume of the Cheniere export  projects will equal about 4 BCFD which is about 88% of the capacity of the Alaska Gas Pipeline.  What's great about the LNG export terminals and GTL plants is that they represent new demand.  The scale of these projects is large enough to move markets and increase the gas price, hopefully into a long term stable range that will promote the Alaska Gas Pipeline.

*(my term for super low natural gas prices caused by lower 48 shale gas production)

Friday, December 16, 2011

Rep. Mike Chenault, Comments on Gas Line

No really news or hope from Rep. Mike Chenault, Speaker of the House of Representatives: (LINK to video).

Skip forward to the 13:40 mark for talk about gas lines.  Glimmer of hope: Donlin Creek.  Favorite quote:"Gotta have a buyer, Gotta have a Seller".

Sunday, December 11, 2011

More Gulf Coast LNG Sold

Cheniere Energy Partners has signed another deal to export LNG from Sabine Pass - this time to the Indian utility company Gail, (LINK) and quote:

State-owned gas utility GAIL India today said it has signed an agreement to buy 3.5 million tonnes a year of LNG for 20 years from a US firm to meet India's growing energy needs.
"GAIL has signed a Sales and Purchase Agreement (SPA) for supply of LNG over 20 years with Sabine Pass Liquefaction, LLC, a subsidiary of Cheniere Energy Partners, LP, USA for supply of 3.5 million tonnes per annum of LNG," the company said in a press statement here.  
Supplies may start as early as 2016."Under the SPA, GAIL will pay Sabine Liquefaction as per contractual provisions on a Henry Hub (US gas benchmark) basis after transfer of custody on FOB. LNG will be loaded onto GAIL's vessels," it said.The SPA has a term of 20 years commencing upon the date of first commercial delivery, and an extension option of up to 10 years.
It's interesting to note that the price of LNG under this agreement is indexed to Henry Hub vs. WTI or Brent crude.  That indicates that the buyer believes in long term low Henry Hub prices and sought to de-link their gas price from crude.  For Cheniere, indexing to Henry hub allows them to operate the plant and collect a predictable margin regardless of variations in the crude market.

Of course this is all very interesting for Alaskans.  First - Exporting lower 48 shale gas as LNG is a good thing because it builds support and stabilizes demand for L48 gas.  Second - it shows that long term LNG deals are possible, but the terms of the agreements have to be smart and fair to both parties. Third - I'm interested to see announcements of LNG export deals vs. announcements of new combined cycle power plants.  The export market may beat domestic power producers to the punch.

Friday, December 9, 2011

ConocoPhillips - LNG Makes Sense for Stranded Gas

ConocoPhillips is busy around the world with new LNG projects.  According to this article (LINK) Australia is first in ConocoPhillips mind but they are looking at potential projects in the US and Canada.  Quotes:

ConocoPhillips is studying North America's potential to export natural gas, but it isn't high on its priority list and any rush to build terminals on the U.S. coast could face opposition from Washington, Al Hirshberg, the company's Senior Vice President, Planning and Strategy, said Thursday.
"I just don't see it," Hirshberg said. "Five years from now Queensland will be a major spot on the map, as well as Western Australia in terms of LNG export, and the U.S. Gulf coast won't be, that's my prediction." 
"Canada's a little different," he told Dow Jones Newswires in an interview. "The gas in Canada is stranded, it really doesn't have access to a market so spending the money to liquefy it and get it ready for export is going to make long-term sense."
Similar logic may apply to stranded Alaskan Gas.  Probably not, but exportation of other gas plays helps build price stability which in turn helps the prospects of the Alaska Gas Pipeline.

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.


Tuesday, December 6, 2011

NovaGold - LNG Imports

NovaGold has completed the updated feasibility study for the Donlin Creek project.  It's good reading and looks like a great project if it gets funded.  Alaska Gas angle - The project will build a 300 mile 12" diameter gas line to transport gas from the Anchorage area. The project will depend on gas from IMPORTED LNG. (LINK) and quote:

Natural gas will be delivered to site by a 500-kilometer-long, 12-inch-diameter pipeline. It will serve as the energy source for on-site power generation. This natural gas pipeline is a lower-cost alternative to the previously considered barging of diesel fuel. Operating costs include importing liquefied natural gas ("LNG") by ship to Anchorage and total delivery costs to site which includes ship based regasification of the LNG and delivery from Anchorage to the Donlin Gold project via the pipeline. There may be an opportunity in the future to source natural gas from within Alaska
I read this as LNG gas plus a small pipeline is the baseline cost that doesn't depend on other projects.  They can always switch to Alaskan gas when and if that becomes available.  If the project goes forward it would make a great anchor customer for some of the proposed Alaskan gas pipeline projects.

Friday, December 2, 2011

Gas Off-Take Study Available on line

Gas Off-Take Study by engineering firm Black and Veatch is available on line (LINK).

Additional presentations are available on the Alaska Gas Pipeline Project Office website (LINK)

Tuesday, November 29, 2011

Natural Gas - Growth, Growth, Growth

November 16, 2011  ExxonMobil Presentation Alaska Resource Development Council (LINK)

Quote from page 8:

Alaska North Slope Gas is competing in a growing & increasingly global  marketplace
• Resource development underpins economic growth for State
• Complexity of Alaska gas development dictates need for on-going stakeholder alignment
• Alignment with the State of Alaska
• Establish predictable and durable fiscal terms so an investment of this magnitude can be made
• Build on foundation of the Alaska Pipeline Project and AGIA framework
• Alignment among Producers
• Support from ExxonMobil, ConocoPhillips and BP essential
• ExxonMobil is poised to work with all key stakeholders to shape the next generation of North Slope development
LINK to Video of the presentation.

All true, but no Kumbaya moment yet.

Listening to the presentation I heard a hint of buy in for Alaskan LNG, or at least a pitch that ExxonMobil has what it takes to succeed at an Alaskan LNG project.

Saturday, November 26, 2011

Gulf Of Mexico LNG - Pre-Sold

Cheniere is gearing up to convert its Sabine Pass LNG plant into an export terminal, converting cheap lower 48 gas into LNG.  Here's news (LINK) of Cheniere pre-selling 3.5MTPA of LNG to Gas Natural Aprovisionamientos, a subsidiary of Gas Natural Fenosa.  

The contract runs for 20 years with an option of an additional 10 years.This agreement follows a simlar agreement with BG (LINK) inked in October.

I mention the Cheniere because it has all the ingredients that the  various Alaskan gas projects are missing. 1) Cheap gas at tidewater, 2) some pre-built facilities, and now 3) Customers.

What's next? - I assume the Cheniere business model is a good one and similar import terminals with the right ingredients will follow suit.  See page 38 of the Cheniere presentation (LINK) for plant volumes.  Lake Charles and Golden Pass have high volumes and plenty to gain by adding export capabilities.

As Gulf of Mexico LNG exporters come on line the price of gas will climb - maybe into that $6.00/MMBTU sweet spot that will promote development of Alaska's stranded gas resources.

Wednesday, November 16, 2011

Best use of Shale Gas - Export it

Cheniere project moving forward to export lower 48 shale gas (LINK).

The cost: $5 Billion for two trains producing a total of 9 million tons per year.(LINK2)

You can use the unit rate to estimate the cost of an Alaskan LNG export plant.  The Cheniere volume is roughly 25% of the proposed Alaska gas line volume. Add "Alaska" factors and you find that $25 billion is need to build the plant that could export the full 4.5 BCFD of Alaska gas.  That's on top of the pipeline cost.

Saturday, November 12, 2011

New Gas & New Jobs

The Alaska Dispatch has this article by Amanda Coyne on the release of the Point Thomson EIS (LINK)(Point Thomson EIS Link).

There's no point in developing Point Thomson unless you believe in a future Alaska gas pipeline.

Follow the money - a producer (ExxonMobil) is spending real money with an expectation of a real return on investment.

Real jobs are being created too.  Check out "Careers" at Fluor.  Recent job postings mention Point Thomson by name.

Saturday, October 29, 2011

Alaska LNG - Back in the news

Governor Sean Parnell has taken a position on an Alaska Gas Line option - LNG.  From ADN (LINK):

Parnell, in a speech to an oil and gas industry group in Anchorage, said he wants the major North Slope players - Exxon Mobil Corp., BP and ConocoPhillips - to coalesce behind a project that would allow for liquefied natural gas to be shipped overseas. He wants them to do this under the framework of the Alaska Gasline Inducement Act. If they do, the state can be flexible, including talking tax and royalty terms, he said.
Also see Amanda Coyne's Alaska Dispatch article (LINK)

LNG to tidewater is not a new idea.  It's an option included in the Alaska Gas Inducement Act  (AGIA).  What is news is the the Governor can't envision how Alaska Gas will ever compete with abundant lower 48 shale gas.  Of course the public is not in the loop on the facts and figures but it's believable when you look at the capital cost, the taxes and the low price of lower 48 shale gas.

The big news in his statement is "the state can be flexible, including talking tax and royalty terms". Wow!  This is the one area under the State's control. Getting back to the economics - Lower 48 LNG import facilities are considering conversion to exporting. An Alaskan LNG export facility will need to compete with those projects so the Governor is going to have to be extremely flexible.  Politically this may be the only option with a chance.  The All-Alaska aspect of the plan should resonate with the voters, especially when it supplies affordable fuel to so many along the route.Alaska's competition in the Lower 48 is busy lining up customers and cutting deals (LINK: Cheniere lands customer for LNG export).

Is this just an empty challenge?  Let's hope not.  I'd like to think that the option is thoroughly vetted and in the realm of the possible for the State and the producers.  There's always one element missing from announcements on Alaska's LNG plans - a BUYER.  I'll hold my applause for Governor Parnell until he makes a LNG announcement with a producer CEO and an Asian buyer CEO standing close by.

Sunday, October 23, 2011

Even more LNG for Kitimat

While Alaska continues to jaw about gas lines and LNG (TIM BRADNER LINK) / (BILL WALKER LINK), the Canadians are all in.  For the second week in a row we have news about LNG projects at Kitimat (KITIMAT LINK).

Sunday, October 16, 2011

+1 Canadian LNG, -1 Alaska LNG

This week ConocoPhillips purchased Marathon's share of the Kenai LNG plant (LINK) and the Kitimat B.C. LNG project received an export license (LINK).  The Kenai plant is scheduled to be mothballed and may be converted to and IMPORT terminal 

Neither of these news items are new or shocking, but the stories illustrate Alaska's ongoing failure to compete in gas markets.  One upside, maybe someday Kitimat will export LNG to the Kenai terminal.

Sunday, October 9, 2011

LNG Ice Breakers?

The options for Alaska's gas seem to be getting odder each day.  Now we have a suggestion of LNG ice breakers. (LINK to Dermot Cole article).  According to Pedro Van Meurs:

If there is a dramatic way to improve the economics of North Slope gas, it may be to export it without a pipeline, he writes. Use icebreakers to get to the North Slope and ship LNG by tanker to a place like Dutch Harbor, where it would be transferred to regular tankers.  A project along those terms could start in 2018 and make the gas economical enough to compete with the Yamal project in Russia.  Van Meurs also notes, however, that he is not an expert on icebreakers or North Slope ice conditions, but  he thinks that with the thinning of the summer ice, there will some a time (sic) when this could work
Apparently this is not totally outlandish.  Some firms are already working on Ice Class LNG ships. (LINK) I'll file this under things I won't see before I retire.

Saturday, October 8, 2011

Japan pays $19/MMBTU for LNG

Mega Projects like the Alaska Gas Pipeline don't get funded on the basis of a sky high spot price, but $19/MMBTU LNG vs. $3.48/MMBTU gas in the lower 48 should stimulate a new long term LNG strategy by Japan and Alaska.  (LINK). The LNG price paid vs. lower 48 gas price leads to two conclusions. 1) Alaska gas is stranded indefinitely and 2) Either the Gulf Coast or Alaska have an opportunity to strike long term deals with Japan for LNG sales.

The chart above shows how the Japanese price paid for LNG diverged from other markets in late '08.  Here's a chart of Japan's LNG import volumes:

Japan's current LNG imports equal about two times Alaska's potential gas production.  I've crunched and few numbers and it looks like $10 to $12 per MMBTU for Alaskan LNG would justify a project. 

Mega Projects like this require risk mitigation. Typically LNG prices are indexed to crude oil prices.  Using that pricing mechanism places too much downside risk on Alaska in the event oil prices take a dive as the economy continues to sputter.  What would work is fixed pricing until the project reaches payout, then index to crude.  That would allow the project to reach payout at the soonest possible date.

The "do nothing" option (Alaska's current path) will lead to some incremental development of Gulf Coast LNG export capacity with a marginal impact on lower 48 gas prices.  That impact will not be enough to shove prices back into the $6/MMBTU range needed to justify the Alaska Gas Pipeline.

Saturday, October 1, 2011

Governor Parnell on Huckabee, and more.

Governor Parnell on Huckabee talking about taxes and drilling in Alaska, no mention of the gas pipeline:

Governor Parnell on Huckabee from Office of Governor Sean Parnell on Vimeo.

Also noticed this LNG video this week.

LNG: The Facts from Center for Liquefied Natural Gas on Vimeo.

LOL moment at the 3:58 min mark when the spokesman takes a gulp from a beaker of water cooled by LNG evaporation. Nice video, but imagine OUTBOUND LNG instead of inbound LNG.

In other news: Australia will become the Qatar of LNG. (LINK)  By 2020 Australian LNG exports could top 100 mtpa compared to 77 mtpa from Qatar.  For comparison, the volume of gas available from Alaska equals 35 mtpa in LNG.  A full scale Alaskan LNG export project seems unlikely, but Alaskan gas could supply North American markets if and when shale gas derived LNG is exported from the Gulf Coast.

This week Chevron moved forward with a $28B investment in the Western Australian Wheatstone 8.9 mtpa LNG project (LINK).

Saturday, September 17, 2011

Japan Wants USA LNG

I wonder if LNG hawk Bill Walker is on a plane to sell his idea of Valdez LNG to the Japanese?  From Bloomberg (LINK):

Japan’s senior vice minister of trade and industry, Seishu Makino, asked U.S. Energy Secretary Steven Chu at a meeting yesterday in San Francisco to increase LNG exports, Akinobu Yoshikawa, deputy manager for the Petroleum and Natural Gas Division, told reporters today in Tokyo.
“I believe we gained the U.S.’s understanding to some extent,” said Yoshikawa. “We can’t buy LNG from the U.S. unless the Department of Energy approves LNG plant owners to export. There is one plant that recently won the approval and there are two others in progress.
Japan is a motivated buyer, a long term customer, they can make X120 pipe - where's the photos of the happy Alaskan trade delegation to Japan? Come on guys - time to get your head in the game.

The only good news in the story is that Gulf Coast LNG exports to Japan will sponge up cheap shale gas and improve to overall prospects for any North American gas project.

Friday, September 16, 2011

Larry Persily - "Don't Read the BLOGS!"

LOL Larry! At the 14:45 minute mark of "The Alaska Report September 2011" Federal Coordinator Larry Persily advises Senator Mark Begich "Don't read the blogs"

Come on Larry - I try to keep it factual and on topic.  Aside from that comment I enjoyed the interview.  Thanks Senator Begich, and thanks Larry.

Sasol GTL

Sasol has plans to pursue a Gas to Liquids (GTL) project on the Gulf Coast. (LINK).  Chesapeake has been saying GTL will sponge up the shale gas glut (LINK- see page 10).  Looks like they may be right.

Quote from the DownStream Today article:

Sasol Ltd. (SOL.JO, SSL), a chemical company long known for squeezing motor fuel out of coal, is now turning its sights on the glut of natural gas in the U.S.South Africa-based Sasol on Tuesday announced plans to build a plant, at a cost of as much as $10 billion, that would convert natural gas into diesel.

Sasol's board last week approved an 18-month feasibility study for the project, which would be constructed on land adjacent to Sasol's existing chemical facility in Louisiana.If given the final go-ahead, the plant would be the first in the U.S. to use so-called gas-to-liquids technology. Once seen as far-fetched and futuristic, the technology has gained traction in recent years as the discovery of gas supplies has outpaced that of oil.
 Anything that increases demand for lower 48 gas helps Alaska in the long run.  18 months seems like a long time for a study, but I still look forward to approval for projects like this.

Saturday, September 3, 2011

Alaska Gas Pipeline - PHMSA

The DOT is seeking proposals for work on the Alaska Gas Pipeline (LINK)

The U.S. Department of Transportation (DOT), Pipeline and Hazardous Materials Safety Administration (PHMSA) are seeking proposals from qualified contractors for a program titled "Alaska Gas Pipeline." PHMSA anticipates awarding up to three (3) Indefinite Delivery, Indefinite Quantity (IDIQs) for a period of one (1) base year and three (3) option years with a total maximum shared ceiling of $4.5 million. The purpose of this RFP is to find contractors who can provide assistance in the following program areas:

A. Materials
B. Construction
C. Environmental
The contract is for only $4.5 million, but it is a start.

Sunday, August 28, 2011

Gas to Gasoline?

Petroleum News carried additional details (LINK) on Janus Methanol chairman Deo van Wijk's ideas for un-stranding Alaska's natural gas. The idea is called "MTG" or Methanol to Gasoline. Given the dismal prospects of the umpteen dozen proposed gas lines maybe this idea is worth a second and even a third look.

In a nutshell van Wijk's concept is to convert Alaska's natural gas into valuable liquids and batch the liquids to market via the existing TAPS oil pipeline to Valdez and then on to markets where the material will trade as gasoline.

How it works - Cleaned up natural gas is converted to Syngas (carbon monoxide and hydrogen), Syngas is converted to Methanol (MeOH) and Methanol is converted to liquids, i.e. gasoline via a process owned by Exxon.

Quote from the Petroleum News article:
Using ballpark estimates of development costs on the North Slope, assuming for example a more than doubling of costs compared with a region such as the U.S. Gulf Coast, Van Wijk has estimated a $7.7 billion price tag for an initial two-train plant. Assuming a 20 percent return on investment over a 15-year period and a tax rate of 35 percent, gasoline could viably be sold at a price of $1.583 per gallon at a natural gas price of $2 per thousand cubic feet, Van Wijk said. The viable gasoline price rises with increasing natural gas prices, with the gasoline price reaching $3.458 at a natural gas price of $10 per thousand cubic feet, he said.
Van Wijk estimates the initial two train unit will produce 63,000 bbls per day of low sulfur low benzene gasoline. The economics, as stated look good, although where are North Slope gas producers going to get $10/MMBTU for their gas? (LINK TO VAN WIJK SLIDES)

The price of North Slope gas is really an imaginary number without other viable outlets. I figure that gas input to the facility should be at cost with gas producers compensated and tax assessed on the product stream ex-Valdez.

Van Wijk didn't indicate if the cost of a train includes gas pretreatment so let's tack on some capital cost for other items, say $1.3B for offsite utilities (gas treatment) , tankage at Valdez and assorted items along the pipeline. At $9B per two trains the project should still work.

What's good about this idea:

1) It converts Alaska's gas into revenue.
2) It's incremental, initial cost are more easily financed.
3) It fills the pipeline, extending the life of the pipeline.
4) It puts Exxon in the game as the technology licensing participant.
5) Fewer permits required, fewer jurisdictions.
6) It's an "All Alaska" option.
7) The incremental approach depressurizes the North Slope more gradually than a full size gas pipeline, i.e. it extends some oil field production.
8) There are actual buyers for the product.

Here's what people will hate about this idea:

1) No gas for Alaskans - Better start thinking propane
2) $500 Million for AGIA down the drain, maybe $1.5 Billion if damages are paid to TransCanada. Maybe the viability of MTG will force the discussion of AGIA feasibility.

Conclusion - I say why not - Van Wijk's team should press on and develop a full cost estimate. Clean up the concept and minimize capital installed on the North Slope. Get a proof of concept unit going on the Gulf Coast and iron out the arctic constructability issues.

Saturday, August 20, 2011

Natural Gas and the EPA Train Wreck

The Alaska Gas Pipeline has a few high drag problems, namely State of Alaska - Producer problems (Point Thomson / Fiscal structure) and market problems ($4/MMBTU gas / Shale gas / lack of customers).

Setting aside State of Alaska - Producer problems will the demand side ever tilt in favor of an Alaska Gas Pipeline? One factor of this equation may be new EPA regulations that impact coal fired power plants. The wave of new EPA regulations is known as the "train wreck".

Outfits like TVA are closing old coal plants (LINK) and building more nuclear and more gas fired combined cycle plants.

They say even a blind hog finds nut now and then, maybe an unintended consequence of the EPA Train Wreck will be higher gas prices and firm buyers for more gas.

Friday, August 19, 2011

Plethora of options

Tons of ideas out there, but still no buyers for Alaska gas. Here's links to pipeline related presentations submitted to the Senate Resources Committee this week :

Larry Persily, Federal Coordinator (LINK)
TransCanada (LINK)
Bill "Valdez LNG" Walker (LINK)
Malcolm Roberts (LINK)
Harold Heinze ANGDA (LINK)
David Gottstein (LINK)
AGDC, answers to 54 Wielechowski questions (LINK)
DNR Dan Sullivan, Gasline Update (LINK)
Dan "ASAP" Fauske (LINK)

No Precedent Agreements

That's the word from TransCanada (LINK to slides) in a presentation to Alaska State Legislature Senate Resources Committee on August 16, 2011. Here's a chilling quote from the slides.

"APP has not been able to secure Precedent Agreements with Shippers at this time"
No shippers, no buyers, no project. Tony Palmer, TransCanada VP was unable to show proof of project viability to lawmakers in testimony to the Alaska Senate Resources committee on Tuesday (LINK). Point Thomson is identified as the major sticking point. According to TransCanada:
"Resolution of Pt. Thomson and gas fiscals are essential to commercial success"
A solution to that problem may be in the works (LINK to Alaska Dispatch). Alaska Dispatch ran the Point Thomson story on the 15th however other news outlets have been slow to grasp the significance of an agreement on Point Thomson. The Fairbanks New-Miner has a followup story with no new content (LINK).

We do know that ExxonMobil has drilled a couple of wells (PTU-15 and PTU-16) in recent times and has plans to produce condensate as early as 2014. (USACE EIS LINK). At a minimum Exxon has more data and is in a good position to negotiate with the the Department of Natural Resources. (LINK to a good description of Point Thomson).

Sometimes it seems like this project is all lawyers, politicians, and guys in nice suits. It's good to see at least one outfit (Exxon) is out there, boots on the ground, building, drilling, hiring and making tangible progress. With a little luck maybe their success will get the ball rolling.

Wednesday, August 10, 2011

Exxon X120 Piple Welding

One way to improve the economics of a remote gas pipeline is to use stronger steel.

Here's a press release from Exxon on X12o pipe welding. (LINK).

Because I'm an optimist I read "Alaska Gas Pipeline" into this portion ofthe press release:

X120 ultra high-strength linepipe was jointly developed by ExxonMobil’s Upstream Research Company and Nippon Steel. X120 linepipe is 50 percent stronger than the strongest linepipe steel (X80) commonly used in gas transmission pipelines and is a cost effective and safe method of transporting natural gas from remote regions to urban customers using high-pressure, large-diameter pipelines.

Natural gas demand is forecast to grow 60 percent globally in the next 20 years. Many new gas resources required to meet this demand are in remote areas and will require cost-effective transportation options before they can be commercialized. The use of X120 linepipe could substantially improve the economics of long-distance pipelines used in the development of remote gas resources.

Saturday, August 6, 2011

FERC Notice of Intent for EIS

The Federal Energy Regulatory Commission (FERC) has issued a Notice of Intent to proceed with preparation of the Environmental Impact Statement (EIS). It's difficult to link to the FERC document, but it's available on FERC.GOV, search Docket Number PF09-11-000 or accession number 20110801-3001. I'll send you a copy by email upon request - just leave a comment.

Quote from the Notice of Intent:
Summary of the Planned Project
The APP would involve construction and operation of a new pipeline system to transport up to 4.5 billion cubic feet of natural gas per day (Bcfd). Specifically, the planned project includes the following major components in Alaska:

· About 58 miles of 32 inch diameter pipeline and associated aboveground facilities (the Point Thomson Pipeline) from the processing plant at the Point Thomson Field to a planned gas treatment plant (GTP) near Prudhoe Bay, Alaska;
· A new GTP near Prudhoe Bay capable of producing up to 4.5 Bcfd of pipeline-quality gas;

· About 745 miles of 48 inch diameter pipeline and associated aboveground
ancillary and auxiliary facilities (the Alaska Mainline) from the GTP to the Alaska-Yukon border. The Alaska Mainline would have a maximum allowable operating pressure of 2,500 pounds per square inch;

· Construction of at least five delivery points, eight compressor stations, two meter stations, various mainline block valves, and pig launching/receiving facilities; and

· Associated infrastructure such as access roads, helipads, construction camps, pipe storage areas, contractor yards, borrow sites, and dock modifications and dredging at Prudhoe Bay.
The planned Alaska Mainline would start at the GTP and generally follow the existing Trans-Alaska Pipeline System crude oil pipeline (TAPS) and adjacent highways southeast to Delta Junction, Alaska. From Delta Junction, the mainline would diverge from TAPS and generally follow the Alaska Highway southeast to the Alaska-Yukon border. At the Alaska-Yukon border, the pipeline would interconnect to a new pipeline in Canada to deliver gas to North American markets through the Alberta Hub or other facilities with existing off-take capacity at or near the British Columbia/Alberta border.
One item of special interest for proponents of the Valdez LNG option:
The project proponent is also considering an alternative proposal to build a natural gas pipeline to Valdez, Alaska for delivery into a liquefied natural gas (LNG) plant for liquefaction and export to global LNG markets. Because the Commission has received very little information on the LNG plant and the associated pipeline, the Valdez proposal is not sufficiently developed for the FERC to include in the environmental review at this time
Ouch! That indicates that nothing permit-able has transpired on the LNG option.

Is FERC going through the motions or is this real progress for the project. As always there's too little information and no indication of pending commitments.

EIS Flowchart from the Notice of Intent:

Friday, August 5, 2011

The Future of Natural Gas

The Economist has a new article on the future of natural gas. (LINK). No big surprise the future is shale gas and global trade in LNG. The article also points to a study conducted by the James Baker Institute (LINK).

The take away point of the article and the study is that shale gas has changed the global energy balance. The new global top three gas reserves are, in order, Russia, China and USA. If we combine Canadian and American gas the ranking becomes Russia, North America, and China.

Here's a tabulation of the data showing US Energy Information Agency (EIA) estimates of conventional gas and technically recoverable shale gas by country:

The Baker Institute study estimates American recoverable shale gas at 637 TCF. The Baker Institute also estimates the average break-even pricing of shale gas plays (Table 1). The average break even price works out to $5.42/MMBTU with a standard deviation of $1.00/MMBTU indicating that shale gas producers will drill and develop shale gas when the market price ranges no lower than $4.42 to $6.42 per MMBTU. The low range rings true based on the past year or two of gas prices and the upper range rings true as shale gas developers now tend to target "wet" shale gas to boost the net revenue per well.

What does this mean for Alaskan Gas? First I'm encouraged to see general agreement on the scale of global shale gas. No one can be expected to invest in Alaska if global shale gas was too cheap to meter - but that's not the case. Gas prices have tested the $4/MMBTU support level and producers will shut in wells rather than sell gas below that level. As the uncertainty fades away an Alaskan Gas Pipeline becomes bankable. It won't be wildly profitable, but a gas line can be built - keep in mind that conventional gas from Alaska is loaded with the same natural gas liquids (NGLs) the boost the revenues of "wet" shale gas plays.

Saturday, July 30, 2011

Larry Persily interview

Larry Persily, Federal Gasline Coordinator was interviewed by the Petroleum News. Here's a link to a .PDF of that interview.

From the interview:

Petroleum News: Getting back to the fiscal negotiations with the state, where do you start?

Persily: ....Start with a blank piece of paper and see what you can get done.

...I don’t see any permit problem that can’t be resolved. I think the economics and fiscal terms and the politics are what would stop this project.

Friday, July 29, 2011

New Calls to Dump AGIA

The Alaska Gasline Port Authority (AGPA) has a new press release (LINK) calling for an LNG plant at Valdez (LINK to Report).

In a nutshell the report claims that an LNG plant at Valdez is competitive with other LNG projects for supplying LNG to Asian buyers.

The report does a good job of quantifying the demand side without any actual indication of buyer interest in Alaskan LNG. At this point in time non binding expressions of interest would go the next step to show that buyers are actually interested and armed with baskets of cash. This is important because all Alaskan gas projects are empty promises until buyers step up.

Some other metrics from the report - The LNG plant is estimated to cost $1,200/ton and operate on 9.65% of the gas feed. The reports assumes that pipeline LNG gas plant owner operators will be satisfied with 8% ROE and that natural gas liquids will garner $80/bbl.

The all in cost of delivered LNG is estimated to equal $8.50/MMBTU priced at rates indexed to crude oil prices. This cost well below current and projected LNG cost.

Weak points - 8% ROE won't bank the deal. Think 14% - 15%. Without some indication of buyer or developer interest the report has the empty ring of the early days of project promotion.

Instead we're hearing the Tokyo Gas is looking to Atlantic LNG (LINK).

Recommendation: An Asian LNG buyer should cash in US treasuries and take a large equity position in securing Alaskan LNG. Let's face it who wouldn't rather own MMBTUs instead of USDs if the exchange rate is $8.50/MMBTU.

Monday, July 18, 2011

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?

Wednesday, July 6, 2011

In State Gasline - ASAP, a second look

I'm reviewing the ASAP project plan in more detail and noticed a clever design feature. I like clever and this feature is geared at pumping up project revenue.

Normally the NGL capacity of a project is based on the incoming raw gas composition, but this project exploits a unique opportunity. Since so much North Slope gas is reinjected it's possible to capture some extra NGL from the re-injection stream, and "enrich" the ASAP gas stream. To optimize gas line utilization ethane is stripped from the NGLs to make room for the more marketable NGLs like propane and butanes.

On page 2-11 of the ASAP report you'll see Figure 2.11, a Flow Schematic of ASAP facilities. (top portion shown below):

What this diagram shows is that raw NGLs will get deethanized (ethane removed) and the ethane free NGLs will get re-injected into the gas stream. The text of the report says that the pipeline is "being designed to transport a conditioned natural gas that is highly enriched in non-methane hydrocarbons" (page 2-8 of ASAP Report).

This means that the product gas will be more valuable than straight run conditioned gas. NGLs include ethane, propane, isobutane, and normal butane. Ethane in the gas stream would waste capacity since there is no practical means to ship it at the pipeline terminus. By removing ethane the pipeline has more capacity to move a valuable mixture of propane and butanes (C3 and C4s). Those NGLs may be shipped by barge from the Cook Inlet NGL Extraction Facility.

How much propane/butane NGL could the pipeline carry? The upper limit is controlled by the composition, pressure and temperature. If the gas line composition is very low in ethane, 2,500 psi and 30 degrees F the NGL fraction could be as high as 15%. At total gas volumes of 440 MMCFD (downstream of Fairbanks) the NGL volumes could be as high as 44,000 bbl/day. For comparison, Pt. Thomson is estimated to yield 10,000 initially and 70,000 bbl/day of condensate when completed. Today bulk propane trades for $2/gallon ($84/bbl). This means the NGL gross revenue stream could be as high as $1.35 billion per year. About $1 billion of additional capital expense is required to inject and extract the NGL from the gas stream. (see Report Table 5.5 below):

Update (09 July 11) According to Dan Fauske, AGDC president the NGL figure is closer to 33,000 bbl/day. That figure definitely falls within the range estimated above.

So where will the gas go? It's anybody's guess, only the open season will reveal who will step up and participate. Here's my guess at the potential users. Some are more obvious than others:

  1. Fairbanks. According to the ASAP report Fairbanks may take 60 MMSCFD of utility grade gas.

  2. Donlin Creek Mine. This mine has a proposal to use up to 12 billion SCF/yr which works out to 33 MMSCFD. A lateral from the ASAP line could provide big cost savings to the mine developers.

  3. Kenai LNG Plant - 1.5 MTPA of LNG capacity equals a demand of about 200 MMSCFD.

  4. NGL shipper - The NGLs discussed above could account for up to 66 MMSCFD of pipeline capacity.

  5. Agrium - could use 140 MMSCFD - Scratch that, they're busy tearing down the plant and shipping it to Timbuktu, Nigeria or BFE.
Total quantifiable end user demands = 60+33+200+66 = 359 MMSCFD. That accounts for 72% of the 500 MMSCFD capacity.

That leaves 141 MMSCFD for other utility users including gas for Anchorage and electric power producers.

Is this project do-able? I think so. The NGL design feature monetizes a stranded resource and adds revenues that are in balance with the capital cost. Feeding the Kenai LNG plant keeps Alaska in the LNG export business utilizing an existing capital resource.

Is the project bankable? The report indicates that it is and I don't see any fatal flaws in their reasoning, but I'll continue to crunch the numbers.

Does the ASAP pipeline threaten the AGIA line? I don't think so. In some ways it compliments AGIA by developing more natural gas infrastructure and by leading the way monetizing North Slope gas and NGL.

Conclusion: Take the next step, let's try another open season!

Tuesday, July 5, 2011

In State Gasline - ASAP

ASAP - Alaska Stand Alone Pipeline.

Report from the Alaska Gasline Development Corporation

News release dated 05 July 11

Project Plan dated 01 July 11

From the News-Miner: In-state gas line 'feasible,' report says by Chris Eshleman

First look:

Size: 24",
Pressure: 2,500 PSI
Length: 737 miles
Products: Gas+ NGL
Cost: $7.52 Billion
Capacity: 0.5 BCFD
No gas for Richardson Hwy
First Gas / Mechanically Complete: 2018

Sunday, June 26, 2011

Shale Gas Exposed?

You can't follow the Alaska Gas Pipeline without following the story of shale gas. On one extreme you'll hear tales of plenty, gas too cheap to meter. The average news story on the Alaska Gas Pipeline would have you believe that shale gas killed all hopes of a gasline. On the other extreme you will hear the occasional doubter - they doubt the reserve estimates, the productivity of the wells over time and the over all economics of shale gas wells.

This week the New York Times has a story titled "Documents: Industry Privately Skeptical of Shale Gas" which falls plainly on the side of the doubters. The story contains a lot of insider documents and the investor presentations of shale gas leader Chesapeake.

As the shale gas story develops some facts are bearing out - at $4/MMBTU you'll need plenty of natural gas liquids (NGL) to make a profit. For the past year or so Chesapeake has made it clear that their goal for 2016 is wells with 38% (NGL + oil) and a NGL+oil production of 250,000 BOE (see page 16 of the Chesapeake June Investor Presentation (LINK)).

The trend away from dry gas wells to wet gas wells is a clear indication that $4/MMBTU won't pay cost of drilling and completing a dry shale gas well. Based on Chesapeake's liquid production goal I estimate that $8/MMBTU is needed to justify drilling a dry gas shale well.

I don't think the Times article spells the end for shale gas but it highlights the possibility that every boom precedes a bust. Tough times for shale gas would glean out the dry gas shale production and make room for Alaska gas.

Update - ExxonMobil/XTO responds (LINK) and Chesapeake responds (LINK) the the New York Times article. As you might guess they are not pleased by the Times story.

Friday, June 24, 2011

GTL - News worth noting

Foster Wheeler has been awarded work on a Canadian Gas To Liquids (GTL) plant (LINK). From

Foster Wheeler AG announced Wednesday that a subsidiary of its Global Engineering and Construction Group has been awarded a contract by Sasol to perform the technical portion of a feasibility study for a planned gas-to-liquids facility in Canada, on behalf of the Sasol/Talisman Energy partnership. The technical portion of the feasibility study is expected to be completed during the fourth quarter of 2011.
Recent investor updates from Chesapeake have alluded to GTL plants that will sponge up cheap North American gas for conversion to liquids. This sounds like the first credible North American GLT plant.

Before reading this announcement I would have predicted that the first GTL plants would be sited on the Gulf Coast. Citing a GTL plant in Canada makes a lot of sense too. GTL plants convert gas into hydrocarbon liquids that require further processing into fuel. That processing requires capital investment. In Canada GTL liquids could be added to thick oil sand products as a diluent, thinning the oil sand product. This product would be easy to pump. The GTL cut of the blended product would be co-processed into fuels at the refineries that receive the oil sand oil. It's a great strategy the maximizes return on capital employed.

The press release says shale gas will be used for the GTL project however gas from the Alaska Gas Pipeline and / or the Mackenzie pipeline could contribute to other GTL projects or satisfy other market demand as GTL sponges up shale gas.

Press release did not mention volumes, however I assume the plant will be sized along the lines of the other Sasol GTL plants.

GTL in Canada is good news and it's worth keeping an eye on.

Sunday, June 19, 2011

Qatar GTL Online

Shell reports the first cargo of GTL (gas to liquids) product sold from the Pearl project in Qatar (LINK).

Here's the math - at full production Pearl will produce 1.6 BCFD and produce 120,000 BPD condensate and 140,000 BPD GTL products. The cost was about $19 billion.

The Pearl gas volume is roughly one third of the proposed Alaska Natural Gas Pipeline. Direct comparisons for application to the Alaska gas volumes are difficult. It's fair to say that about 1.3 BCFD went to produce the 140,000 BPD of GTL liquids. If those liquids bring $100 per barrel the simple payout is 3 - 4 years.

Could a GTL plant in Alaska compete with exporting Alaska gas via pipeline? No. At a capital cost of $14/cu ft an Alaska GTL plant would cost $63 billion before adding a 30% "Alaska factor" for Arctic construction. $82 billion is my low side estimate for an Alaska GTL plant capable of processing the full 4.5 BCFD of North Slope gas. That's double or triple the cost of the pipeline.

So can GTL help Alaska? YES. Given Pearl's success, a Pearl sized Lower 48 GTL plant is now bankable. A Lower 48 GTL plant could cost less if less refined products were sold into existing refining infrastructure. If built, GTL plants would sponge up cheap shale gas, making room for Alaska gas.

Overall a large GTL success like Pearl is good news that should be replicated in North America, GTL products directly replace imported crude oil eliminating the need to convert vehicles over to compressed natural gas (CNG). Huge projects like a GTL plant will help put Americans back to work too.

The Txchnologist

Interesting new e-zine, the Txchnologist, info from GE. As builders of combined cycle turbines they support development of natural gas.

The e-zine is somewhat shale gas centric, aside from that there's some good information there.

Thanks to Alaska Dispatch for posting a story about the e-zine.

Sunday, June 12, 2011

Natural Gas Prices - Up?

Lou Kilzer of the Pittsburgh Tribune-Review wrote this story "Natural gas prices set to jump with exports" taking issue with plans to export LNG from the lower 48. In the story he quotes Boone Pickens as saying "we're truly going to go down as the dumbest generation." referring to plans to export LNG.

He also details more LNG export plans, specifically:

Freeport LNG Expansion LP, together with Liquefaction LLC, applied on Dec. 17 to export 1.4 billion cubic feet of natural gas per day from a terminal port near Freeport, Texas. Lake Charles Exports LLC, a subsidiary of British-based BG Group and Houston-based Southern Union Company, applied to DOE on May 6 to export 2.0 billion cubic feet a day from its Lake Charles, La., facility.

If the DOE approves those requests, combined with the Sabine permit, the total 5.2 billion cubic feet a day proposed for export would represent 8.4 percent of U.S. production, a Tribune-Review analysis determined.
The story also bemoans the fact that the US imports 10% of our gas needs. According to the Energy Information Agency (EAI) gas imports in 2010 averaged 10.4 BCFD. For comparison the proposed Alaska Gas Pipeline will export 4.5 BCFD of gas to Canada, offsetting about half of our natural gas imports.

In summary, according to the article, exporting LNG is a bad idea according to the author because:
  1. LNG exports will drive up gas prices
  2. We would export clean energy and import dirty oil
  3. We are dumb
Let's examine these outcomes and fill in the blanks;
  1. Exporting LNG will drive up natural gas prices - GOOD. Current pricing in the $4/MMBTU range will not support job growth in America. $6/MMBTU gas puts Americans to work - building LNG plants, building pipelines, and building petrochem plants. Maybe even building the Alaska Gas Pipeline. I don't see a problem with that. For once we can export a product to Asia and keep the jobs at home.
  2. Importing "dirty" oil sounds just awful doesn't it? The fact is that high sulfur, thick crudes are less expensive and our technological leadership in refining allow us to use the materials. American know how, cheaper products - can't beat that.
  3. Are we dumb? I don't think in those terms. Markets are pretty smart at figuring out how to maximize returns. The Pickens Plan seeks to convert our trucking fleets over to compressed natural gas. I'd call that a pretty good idea, it would be even better if Boone was spending his money instead of reaching out for my tax dollars to fund the plan. Of course increased domestic use of gas for transportation will drive up price which is OK with me since that will spur development and build domestic employment.
I can offer a few ideas, and I think these will build a better America:
  1. Support the conversion of LNG import terminals into export terminals. Conversion of these facilities is the most cost effective way to get into the LNG export market.
  2. Let's get serious about Gas To Liquids. Our cheap natural gas and coal can be used to make clean liquid hydrocarbon fuels. Fuels that will burn in our existing cars trucks and trains without all the taxpayer funded investment required by the Picken's Plan. Domestic GTL will help protect us from overseas supply disruptions.
  3. Let's build facilities in this country instead of building overseas. Let's build LNG export terminals, new petrochem plants, and new pipelines including the Alaska Gas Pipeline. Building here equals jobs here.

Saturday, June 11, 2011

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.

Gas Pipeline History

I have a policy to avoid mention of Sarah Palin if possible. From a gas pipeline perspective she's in the past, the damage is done and I keep focus on the market realities that shape the current and future pipeline design, economics and schedule.

Having said that, Palin's emails are posted here (LINK). Enjoy

Sunday, June 5, 2011

Link of the week: Moving the Gas

Here's a good run down of North American gas pipeline routes and capacities from the Office of the Federal Coordinator (LINK to Bill White article).

Monday, May 30, 2011

Shale to the rescue?

I'm always in the market for some good news, maybe this is it.

Great Bear Petroleum is on the hunt for oil and natural gas liquids in Alaskan shale deposits. (Graphic - Map of Great Bear lease, from the AOGA website)

This isn't new news (Alaska Dispatch and Petroleum News ran the story back in March) but the irony just sunk in. With all the hub hub going on in the Eagle Ford shale what if Alaskan Shale was the next big thing? I like ideas that have the potential to help two Alaska pipelines - TAPS and the gas line.

Good luck Great Bear - provide some updates when you get a chance.

Sunday, May 29, 2011

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?

Friday, May 27, 2011

Boone Pickens on CNBC

I follow T. Boone Pickens because his plan will boost gas sales, increase demand and by extension boost gas prices back to a range that will support development of the Alaska Gas Pipeline.

Today Pickens ranted a bit on CNBC (LINK) today. Aside from his remarks about OPEC funding the Taliban and disparaging remarks about the Koch brothers he also attacked the idea of exporting LNG from the U.S., specifically from Cheniere.

By his logic we are importing dirty oil and exporting clean LNG.

I take issue with this - First we import oil, refine it and use it, but we also export refined products (about 450,000 bbls/day) - good lets build our export economy. Secondly we import a lot of high sulfur "dirty crudes". Many of our refineries are designed and tuned to run on these less expensive feedstocks - another good thing let's use technology to exploit the full range of available feeds. Third - I'm all for exporting U.S.A LNG - it will sponge up excess lower 48 shale gas, boost our economy and help build price support for the Alaska Pipeline.

Speaking of sponging up cheap shale gas - I think the free market is catching on to the idea of converting to cheap gas. Follow this link to see all the CNG fueling stations. It's still early days, but CNG may be the breakout alternative fuel.

Wednesday, May 25, 2011

Agrium - Moving to Nigeria

Agrium is shipping out, literally to Nigeria (link). Free markets have a way of voting with their feet. If market conditions, raw materials, or government policies don't work for a business they up and leave. I had wondered if closing the LNG plant would free up enough Cook Inlet gas to restart Agrium - boy was that bad idea.

Coming to a plant near you?

Years ago I worked on a job that packed up a chemical plant and shipped it overseas. I've seen industries pack up and go. Nobody is hanging around waiting for a pipeline. If Alaska wants a gas pipeline I suggest a 10 year tax holiday starting in 2020 and a guaranteed rational rate for the first 10 years after that.

Saturday, May 21, 2011

AGIA, Denali, Exxon, Shale Gas, and all that

The announcement this week that the ConocoPhillips / BP Denali project is over (link) has the pundits punditizing. The alternative plans are rampant: terminate AGIA, built a LNG plant in Valdez, build a small line to _______fill in the blank, make petrochemicals, make methanol, make ethanol and so on.

Concerning AGIA. It's all about unintended consequences and timing. Amanda Coyne of the Alaska Dispatch assembled a good timeline of recent efforts to build an Alaska Gas Pipeline (LINK). Let's add price data to the pivotal points in the timeline:

March 2007, Sarah Palin rolls out AGIA, well head gas price = $6.65/mmbtu.

January '08 AGIA has five bidders, gas at $7.38/mmbtu

April '08 ConocoPhillips & BP form Denali, gas at $8.87/mmbtu

June '09 ExxonMobil joins the TransCanada AGIA licensed project, gas price $3.38/mmbtu

December '09 Exxon announces acquisition of shale gas producer XTO, gas price $4.66/mmbtu.
What this data shows is that AGIA imposed a delay of about 4 years at the precise time that gas prices and support for a pipeline surged. It also shows that Exxon joined the TransCanada project near the lowest point in the gas price cycle. It also shows that Exxon made it's big move in natural gas about the same time and also at low gas prices - Exxon clearly picked a shale gas winner (XTO) and bought in at a cyclic low, and built a foundation for a future Alaska gas pipeline. In May '09 Exxon was drilling in the gas-rich Point Thomson field, gas price $3.23/mmbtu.

I'm going to go with the premise that Exxon got it right and that the State of Alaska got it wrong. Got it wrong in several ways, but mainly via AGIA and oil and gas taxes.

So what's next? Denali's collapse shows that a couple of well financed oil and gas firms can't fund an Alaska gas pipeline any time soon. At least they can't get it done without Exxon. AGIA may get chased out of town by villagers with pitch forks sometime soon, but I think we can judge Exxon's intentions by their actions, specifically why are they drilling at Point Thomson unless they believe in a pipeline? I don't like the 2020 date proposed for Alaska Gas flowing, but that's probably what we can expect. We're probably 3 years and 150 hopeful blog posting away from kicking off the project.

Exxon and other producers, and maybe TransCanada will move forward because natural gas will become a bigger part of the power generation mix, and because the lower 48 will begin to export LNG (LINK: Cheniere Unit Wins US Approval To Export LNG From Louisiana). The potential Cheniere export volume (2.2 BCFD) equals roughly half of the proposed Alaska gas pipeline volume (4.5 BCFD). Moves like this will be the game changer, this time back in the favor of Alaska.

Keep in mind any optional use of natural gas is less expensive to execute in the lower 48. LNG export plants, petrochem plants, gas to liquids (GTL) plants, methanol, plastics you name it - I can build it cheaper on the Gulf Coast and feed it with cheap shale gas from Texas and Louisiana.

LNG export and the Fukushima effect will sponge up $4/mmbtu shale gas and prices will move back to $6/mmbtu by the end of this decade. $100/bbl oil will drive heavy oil production in Canada and that will drive gas demand.