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:

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.

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.

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.

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?

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!

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