Data Dump and Walker Talk

This week the Alaska LNG project submitted a series of draft environmental and socioeconomic reports to the Federal Energy Regulatory Commission (FERC).  FERC is responsible for conducting the environmental review of the project.

You can find the files at the FERC elibrary site (FERC LINK) and search docket number PF14-21:

 

I'm still downloading and sorting through the documents - so far I don't see anything shocking or new but I'll post any snippets of interest.

Other project news of interest: Gov. Bill Walker  and his team are in New York explaining how they will manage through the current dip in oil revenues. (LINK to Alaska Journal of Commerce).  Whatever misgivings Gov. Walker may have about the project it is now his job to promote the project and represent the project as a source of future revenue.  We should all wish him good luck on his mission to protect the State's bond ratings.  Those ratings play a huge role in the cost of capital to build the project.  At today's low interest rates no one talks much about financing the project, but stay tuned - the day will come when interest rates matter a lot and the date of first revenue matters a lot. 

Speaking of Gov. Walker's misgivings, this week the Governor spoke to lawmakers and indicated in a conditional sort of way that he would drop his Point Thomson lawsuit  (Alaska Dispatch Link) and quote from Alaska Dispatch story: 

Walker said he will move to dismiss his lawsuit after introducing legislation Friday intended to address his concerns.

We'll see what he expects to get out of this legislation but the story in Juneau should flange up with the story in New York. (LINK TO GOV. WALKERS COMMENTS) 

Finally here's a link to an editorial from my favorite Okie Boone Pickens (FORBES LINK) "To Kill A Pipeline...Or Two: The Sad Reality Of Obama's Energy Thinking"  Boone may be an Okie but understands that Obama's Alaska wilderness plans can will kill Alaska oil.  It's off topic for this Alaska LNG project blog, but what's bad for TAPs is bad for LNG too. 

SB 21 Link

Link to the Oil and Gas Tax Bill SB-21

Almost There

After years of nattering nonsense we are starting to hear the right kind of stories about the Alaska Gasline project - stories about customers. All those cliches about "the customer is always right" are true.   LNG is not a commodity (yet) so Alaska must have a long term buyer lined up and participating in the LNG project.

The good news includes a piece in the Alaska Dispatch by Amada Coyne. Apparently a Japanese group called Resources Energy Inc is in Alaska with boots on the ground exploring a gas project.

The next bit of good news comes from the Asia Pacific Energy Research Centre LNG Producer - Consumer Conference recently held in Tokyo.  All of the presentation slides are worth reading, but its great to see Alaska Department of Resources Commissioner Dan Sullivan making the case for Alaska gas to a group of buyers (Dan's Slides).

A smart LNG buyer would negotiate to buy Alaskan gas at a tidewater and be a major equity partner in an LNG facility.  The good news is that there are some smart buyers out there and the stars may start aligning soon.

Golden Pass LNG

North Slope producer ExxonMobil holds a 30% position in Golden Pass Products LLC.  This week GPP announced their intent to move forward with a $10 billion LNG project at the Sabine Pass location.  The project will export an average of 2.0 BCFD of gas.

Obviously it's cheaper to build on the Gulf Coast rather than Alaska, but the cost and capacity data provide an insight into LNG project economics.

In Alaska producers have stranded gas.  Stranded gas has value as an energy source and as a means to maintain reservoir pressure.  At Golden Pass the problem is non producing stranded hardware.  The Golden Pass facility was built to receive imported LNG and sell that gas to the American market.  The shale gas revolution made import facilities like Golden Pass obsolete.  Gas from imported LNG can't compete with cheap domestically produced shale gas.

The Golden Pass export project investment equals about $14/MMBTU/yr export capacity.  ($10 Billion @2 BCFD capacity).  In comparison the Alaska Gas Pipeline Project plus LNG will cost about $40 Billion and export about 3 BCFD which equals about $37/MMBTU/yr export capacity.  By this measure the Alaskan project is over two and half times more expensive than a Gulf Coast stranded equipment project.

The big disadvantage to an Alaskan project is the pipeline required to move the gas to tidewater.  If the pipeline cost is eliminated from the calculation the Alaska Project would only cost 1.33 times the Golden Pass Project - a reflection of the cost of building in Alaska and the value of sunk assets at Sabine Pass.

Of course an Alaskan gas project has other benefits including affordable energy for (some) Alaskans and proximity to Asian LNG buyers.  At the end of the day these benefits will not tip the balance in favor of the Alaskan project.

The value of co-produced natural gas liquids (NGL) will promote Alaska project economics to a small degree, but not a significant amount, perhaps as little as $5 Billion discounted back to the project start date.  Helpful, but not a game changer.

Assuming a relative free market we can expect the low hanging fruit of Gulf Coast import terminals to be converted to export terminals fueled by cheap shale gas.  As more export facilities come on line the domestic price of gas can be expected to increase while abundance of supply puts downward pressure on the asking price of LNG.  The increased cost of feed stock and reduced revenue for products will tend to pinch out projects that move forward later rather than sooner.  Stir in a helping of anti free market regulation and the number of stranded equipment conversions may stay in the single digits.

Still standing by for good news in September, but I don't see a home team bounce in the project economics yet.

This Weeks Items of Note

No real news on the Alaska Gas Line, so here are some gas industry related tidbits:

• Shell expands LNG option for 18-wheelers.  Good, gas displaces lower 48 oil imports it also creates a new demand for lower 48 shale gas.
• TransCanada to build pipeline for Shell LNG plant.  Money well spent.  One third the capacity of the Alaska Gas Line at one fifth the price (LNG plant cost excluded). Another Link
• Gas Line Options
• Lower 48 Gas will displace coal for power generation. Combined cycle gas fired plants are the wave of the future.
• A reminder that all LNG investments are risky, things may turn sour in Australia.
• Dragging their heals on LNG exports.  The feds aren't about to move on energy projects until the elections are over.

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.

One Message: Alaskan LNG

At long last Alaskan leadership is on message with the same story: LNG.  Lower 48 shale gas killed the gas pipeline to Canada.  The pipeline is headed to a tidewater LNG plant.  We can still argue about the route, taxes, branch lines, straddle plants and natural gas liquids, but consider the main project objective settled.

On Wednesday Dept of Natural Resources Commissioner Dan Sullivan and Dept. of Revenue Commissioner Bryan Butcher approved TransCanada's Project Plan Amendment (PPA) which switches the gasline focus to commercialization of Alaskan gas a LNG for export (LINK to approval letter).

Meanwhile Senator Lisa Murkowski is in Japan talking Alaskan LNG (LINK).  DNR Commissioner Dan Sullivan also pitches Alaskan LNG in Asia (Slides).  Of course Governor Parnell is on message with his support of the LNG project (LINK). Finally the North Slope producers are aligned (LINK).

Looks like the end of the beginning.

Northern Pipelines - On Hold

Low gas prices can't support Arctic gas pipelines:

First the Mackenzie Pipeline (Calgary Herald link) and quote:

CALGARY - Partners in the proposed Mackenzie Valley pipeline have put the $16.2-billion project on hold, slashing budgets and eliminating staff in response to continued poor price outlooks and lack of commercial support.
Imperial Oil, the lead producer in the project with a 34 per cent interest, will close offices in Norman Wells and Fort Simpson, Northwest Territories, this year, and has reduced the size of its office in Inuvik, N.W.T., spokesman Jon Harding said Thursday.
Cheap shale gas that pulled down prices, and cost escalations played into the partners' decision to cut capital on the pipeline project, he said

Back in Alaska pipeline company TransCanada has asked permission to curtail work on the eastern part of the Alaska Gas Pipeline (LINK) and quote:

TransCanada has asked the commissioners of Natural Resources and Revenue to allow it to "curtail" its work on a line that would run from Alaska's North Slope into Alberta, Canada, to focus on a liquefied natural gas project, said Tony Palmer, the company's vice president for major projects development. TransCanada's piece of that project would be the pipeline.

So now there is one project with two probable phases. Alaska LNG pipeline Phase 1 (condensate to TAPS and gas Prudhoe Bay) then Phase 2 (Gas to tidewater + LNG plant).  Lots of permutations and iterations along the way, but many options are now off the table.  Expect LNG for Japan, Korea and China in about a decade.

Reaction to Point Thomson Settlement

Maybe it's a case of what was said doesn't equal what people heard.  Fairbanks News Miner columnist Dermot Cole heard the part about no commitments (LINK).  The Anchorage Daily News heard (correctly) that Alaska has a deal to develop Point Thomson Gas (LINK) . The Wall Street Journal heard that "Alaska, Gas Firms Clear Way For Pipeline" And many media outletS proclaimed that Alaska and Exxon have agreed to build an LNG plant "Exxon seals deal with Alaska to develop $26b LNG plant".

If you want to know that facts I suggest you look at the documents on the Alaska DNR website (LINK).

What you will find is that one of three alternative or combinations of alternatives will play out over time:

Alternative A - Major Gas Sale : Gas to a pipeline and liquids to TAPS.  The clock is ticking to get this alternative sanctioned by 2016.  The window closes in 2019 when the producers must choose Alternative B or Alternative C.

Alternative B: Increase cycling and produce more liquids for TAPS.  Producers must do this or start losing leases.

Alternative C: Gas to Prudhoe Bay, Condensate to TAPS.   The gas flow to TAPS "Significantly increases TAPS throughput" This alternative also provides gas for in-state use.

None of these options involve a guarantee from the producers. The stated goal of the agreement is "A primary goal of this settlement is to incentivize commercialization of North Slope gas/Major Gas Sale (MGS)"

Looking at these options you can see it's a bit over the top to claim a LNG plant is in the works anytime soon. Possible - maybe, probable no. On the other hand the State and the Producers have covered all the bases, and they have done so in away that allows development of Point Thomson in a way that can boost Prudhoe Bay production in the short term and develop a gas export solution later (i.e. Alternative C first followed by Alternative A).  Alternative B looks like the worst case scenario unless you count Alternative "D" Point Thomson abandoned.

Those are the facts, but what about perceptions?  The markets are focused on the potential of Alaskan LNG entering the global mix.  Alaska's competitors will need to pencil that volume into the mix.  Alaska's potential customers can now step up and start negotiating deals.

Any of these outcomes equal revenue and jobs - Good things for Alaska.

Point Thomsom Settlement Agreement

The full text of the Settlement Agreement is at the DNR website (LINK).  Notice the EOR role of Point Thomson gas.  That seems to be the one of the sure things of the agreement.   EOR helps fill TAPS which is always a good thing.  The agreement also leads to commercialization of gas for sale or a large scale cycling project - either way Point Thomson starts cranking out revenue.  I'm still reading the whole thing, but so far it looks like Alaska is on the road to some large projects.

Here are some key parts:


1.6 This Agreement sets forth the WIOs’ commitment to produce natural gas condensate liquids (“condensate”) from the Point Thomson Reservoir for delivery into theTransAlaska Pipeline System (“TAPS”). The WIOs have committed to construct anInitial Production System (“IPS”) which is to be completed by the end of the 2015-2016 winter season. The IPS facility is being designed to produce and re-inject (cycle) 200 million cubic feet per day of gas and to produce approximately 10,000 barrels per day of condensate. In addition, a liquid hydrocarbon pipeline is being designed that can transport approximately 70,000 barrels per day from Point Thomson to an existing pipeline interconnection at the Badami field, which will provide for final delivery of Point Thomson liquid hydrocarbons into TAPS. Operation and production from the IPS will provide data and information to assist in evaluation of additional development plans, including potential increased gas and condensate production from Point Thomson, and plans for the delivery of Point Thomson gas into a Major Gas Sale pipeline project.

1.7 In parallel with the work on the IPS, Parties and/or their affiliates to this Agreement will, upon execution of this Agreement, undertake work for commercialization of North Slope gas. This work will build on ongoing gas commercialization efforts. If a Major Gas Sale is Sanctioned prior to year-end 2016, the WIOs will begin work on a Point Thomson project associated with that Major Gas Sale. However, if a Major Gas Sale has not been Sanctioned by June of 2016, the WIOs have committed to begin engineering of a Point Thomson Expansion Project. An expanded cycling project would result in additional condensate production, totaling approximately 20,000 to 30,000 barrels per day into TAPS, depending on the level of expansion. Alternatively, a project to deliver Point Thomson gas to Prudhoe Bay for injection would significantly increase the rate of condensate production at Point Thomson, serve as a pre-investment for a Major Gas Sale project, and essentially complete installation of the Point Thomson wells and facilities required for a Major Gas Sale. In addition, this option would materially increase production at Prudhoe Bay, and result in enhanced recovery at Prudhoe Bay.

1.8 The Agreement further establishes terms and conditions to facilitate development and provide benefits to the State of Alaska. Certain acreage within the Point Thomson Unit is secured when specified work activities are completed (e.g., the IPS is completed and producing) and key commitments or decisions are made (e.g., a Major Gas Sale is Sanctioned or WIOs Commit to a Point Thomson gas development / Prudhoe Bay enhanced oil recovery project or an IPS gas cycling expansion project). Likewise, the Agreement provides for the automatic release of certain acreage to the State if the IPS is not completed or if certain key commitments or decisions are not made (e.g., a Major Gas Sale is not Sanctioned or WIOs do not Commit to a Point Thomson gas development / Prudhoe Bay enhanced oil recovery project or an IPS gas cycling
expansion project). Depending upon the work activities that occur, the Point Thomson Unit will remain in effect or may terminate.

2.13 “Initial Production System” or “IPS” means the gas cycling facilities designed with capacity to produce and re-inject (cycle) 200 million cubic feet of gas per day utilizing reciprocal compression and with the objective of a minimum of 10,000 barrels per day of condensate for delivery into the TransAlaska Pipeline System (“TAPS”).

2.16 “Major Gas Sale” or “MGS” means a large-scale pipeline project having a design throughput of more than 500 million cubic feet of gas per day that results in delivery of gas off the North Slope of Alaska.

2.21 “Point Thomson Gas Development / Prudhoe Bay Enhanced Recovery Project” means a project to deliver Point Thomson gas to Prudhoe Bay for injection that would significantly increase the rate of condensate production at Point Thomson into TAPS, serve as a pre-investment for a Major Gas Sale, essentially complete installation of the Point Thomson wells and facilities required for a Major Gas Sale, and allow for continued efforts towards, and positions Point Thomson gas for, a Major Gas Sale. In addition, this project would materially increase oil production at Prudhoe Bay into TAPS and result in substantial enhanced recovery at Prudhoe Bay. A Point Thomson Gas Development / Prudhoe Bay Enhanced Recovery Project would result in
production and recovery of liquids from Point Thomson and Prudhoe Bay that would be greater than production and recovery of liquids from Point Thomson from an IPS Gas Cycling Expansion Project of a minimum of an additional 20,000 barrels per day. Before Project Start-up required approvals from the Alaska Oil and Gas Conservation Commission must be obtained.
The project would consist of:
(i) a newly constructed gas pipeline from Point Thomson to Prudhoe Bay with the capacity to transport significant volumes of Point Thomson gas in an amount that would position Point Thomson gas for a Major Gas Sale, for injection for:
(a) use in repressuring, stimulation of production, and increasing ultimate
recovery of Prudhoe Bay oil; and (b) for ultimate availability for a Major Gas Sale; and
(ii) additional wells and facilities at Point Thomson to produce and process significant condensate production for delivery into TAPS through existing liquid hydrocarbon pipelines and pipelines constructed as part of the IPS Project. These facilities would also be used for a Major Gas Sale

New Focus On LNG "We Have Aligned"

Nothing to bank on but it sounds like the gas line project is morphing into an All Alaska line that will feed a tidewater LNG plant.  The first element of the plan is the Point Thomson settlement (LINK), and quote:

(Reuters) - The U.S. state of Alaska has reached a settlement with Exxon Mobil Corp and its partners to develop a huge, long-fallow oil and gas field, possibly paving the way for a $26 billion pipeline and an export plant for liquefied natural gas.
The settlement, which resolves a long-running lease dispute over the Point Thomson field about 60 miles (95 km) east of Prudhoe Bay, could allow for exports of liquefied natural gas via tanker to Asia and may boost Alaskan oil production after decades of decline.
In exchange for continued lease control, operator Exxon and partners BP and ConocoPhillips have agreed to build a pipeline from the field to deliver 70,000 barrels per day of liquids into the Trans Alaska Pipeline System.
The settlement also calls for the companies to produce 10,000 barrels per day of natural-gas condensates by the winter of 2015-16, state officials said.

That's a lot of condensate, I'm not sure where that flow will go but I'm looking forward to the project awards and jobs that will flow from this settlement.

The second element of this good news story is the possibility of an LNG export terminal (CEOs Letter to Gov. Sean Parnell). Quote from the letter:

Serious discussions between our  companies have taken place over  the past several months,
along wi th the Alaska Pipeline Project (APP) parties who are supporting the AGIA License.  We have aligned on a structured, stewardable and transparent approach wi th the aim to
commercialize Nor th Slope natural gas resources within an AGIA framework.  As a result of  the rapidly evolving global market, large-scale liquefied natural gas (LNG) exports f rom southcentral Alaska will be assessed as an alternative to gas line exports through Alberta.  In addition to broadening market access, a south-central Alaska LNG approach could more closely align wi th in-state energy demand and needs.  We are now working together on the gas commercialization project concept selection, which would include an associated timeline and an assessment of  major  project  components including in-state pipeline routes and capacities, global LNG trends, and LNG tidewater  site locations, among others. 

This isn't the slam dunk project sanction announcement, but it's close to the Kumbaya moment many of us have looked for.  The language is parsed, but you would like to think that the CEOs of the North Slope producers are at least 80% certain of a project before they signed up to "assess" an Alaskan LNG project.

The current trend in lower 48 shale gas prices lead me to believe that Alaskan LNG export is the last hope of developing Alaska's natural gas.  Full development of Point Thomson makes little sense without a viable outlet for the gas.

One certain take away is that all three producers are on Team AGIA now with the "We have aligned" statement.  Nice job Governor, don't stop now.

Additional LINKS

(Washington Post/Bloomberg Link)
(Gov. Parnell Website Press Release - Pt. Thomson Resolved, Aligment on Gasline)
(Alaska DNR Point Thomson website)

Team Alaska - Missing

Japan continues to lobby American officials on the topic of LNG exports (Platt's Link).  Quote:

Japanese officials will meet with a US delegation headed by Deputy Energy Secretary Daniel Poneman later Tuesday to ask that Washington allow exports of LNG to Japan, the world's biggest importer of liquefied natural gas, a Japanese delegate said. 

Platts assessed its Japan/Korea marker Monday at $15.45/MMBtu for April, while its Northwest and Southwest European markers were assessed at $10.95 and $11.35, respectively, for April. In contrast, the NYMEX April gas futures contract settled at $2.269 Monday.

Where's all the Alaskan leadership?  Senators Murkowski and Begich, Governor Parnell, Representative Don Young  - where are you when LNG customers come knocking?  You would think a project to sell Alaskan LNG priced at $12 -$15 would motivate these elected leaders to weigh in and lend a hand, a photo op, a trade mission, something.  Instead they are missing and silent.  The LNG for Japan opportunity may be the last chance for decades.

Alaska LNG for Japan?

ALASKA LNG For

This week the Alaska Dispatch ran a story about a Japanese delegation visiting Anchorage to discuss LNG from the North Slope (LINK). First comment - Hooray! It's about time.  I'm glad the Japanese include Alaska on their list of energy solutions.  I've always wondered why Alaskan leaders don't push Alaskan gas sales to Japan more vigorously.  Without customers for Alaskan gas no gas project will ever be built. Now that introductions are out of the way maybe Alaskan leaders can man up and get engaged with a paying customer who may be motivated to partially fund the project.

Having said that what would a Japanese-Alaskan LNG project look like? Japan needs long term politically stable supplies of LNG.  I can see Japan funding and building the LNG plant and terminal in Valdez that would equal about half the project cost.  The producers and the State of Alaska would build the North Slope gas treatment facility, various natural gas liquids (NGL) projects, and assorted sub-pipelines.  The Japanese will be focused on guaranteed delivery of specific gas volumes and the producers will seek take or pay options for delivery of the gas.Fairbanks, Anchorage, Delta Junction and lots of points in between can execute sub projects along the way.   Remote Alaskans may even benefit from propane extracted from North Slope gas.

Could this really happen?  Yes because a Japan-Alaska-LNG project ticks all the right boxes.

First and foremost is project economics.  A million BTUs (MMBTU) of energy from crude oil cost more than $18.75 today (WTI basis, $22/MMBTU Brent basis) and could exceed $20 in the near future as crude prices edge upward. Henry Hub gas prices may have found bottom in the $2.50/MMBTU range this winter.  At least that's the price that shuts down dry shale gas drilling rigs.  Converting gas to LNG cost about $2/MMBTU.  The resulting low end cost of delivered LNG could be less than $10/MMBTU (Henry Hub indexed) and over $20/MMBTU (crude indexed).

LNG is not a true commodity yet so we can expect a unique price for any North Slope Alaskan LNG sold to Japan.  I expect that the unit cost of Alaskan LNG will be higher than Gulf Coast LNG.  This price difference will enable the project and cover the higher construction cost in Alaska.

But what would drive Japan to sign up for an expensive project? The answer is that Alaskan LNG  is a long term, reliable, dedicated source of supply for Japan completely decoupled from the lower 48 market and lower 48 hazards. A bad lower 48 winter or a bad Gulf hurricane season will not disrupt the flow Alaskan LNG.Additionally Alaskan LNG is closer to Japan than Mid East or Gulf Coast LNG.  Alaskan LNG can be shipped in the largest most efficient tankers unlike Gulf Coast LNG tankers that must transit the Panama Canal. Alaskan LNG is also more reliable than LNG shipped through the Strait of Hormuz.

Japan and the North Slope producers share one vital common interest,  Both sides need a long term deal that works for decades.  To quote Steve Kirchhoff, Vice President – Americas, ExxonMobil Gas and Power Marketing Company "You can't dabble at LNG"

Of course the State of Alaska is behind the curve on LNG exports to Japan, or Asia in general. It's easy to imagine Canadian LNG projects shipping product before Alaskan leaders get their heads around the idea. On one hand I'd like to know what transpired when the Japanese met with Alaskan State government officials. On the other hand I'm afraid the Japanese may have heard very little encouraging news.

Go Pedro

The Alaska Dispatch has a good letter from Pedro van Meurs (LINK).  Pedro has replied to the Concerned's invitation to run for Governor.  Both the invitation and the reply are humorous and point to the root cause of Alaska's ongoing failure to build a gas pipeline.  Pedro says:

Alaska has not lifted a finger to attract new investment from a fiscal perspective. In fact, Alaska does not even have useable fiscal terms for heavy oil, shale oil and natural gas that can be published in a simple investor brochure. How can Alaska attract investors in this way when other nations (Canada, Lower 48, Australia, Brazil, et al.) offer attractive well defined terms?

And

Unless substantial policy and fiscal changes are introduced that encourage large scale investment in heavy oil, shale oil and natural gas in Alaska, as is being done in competing jurisdictions, the future of oil and gas production in Alaska is bleak.

Sadly I agree fully with the last paragraph.  At today's gas prices I can't understand why Alaska doesn't take bold action to get things rolling. I know the Alaska constitution says "The legislature shall provide for the utilization, development, and conservation of all natural resources belonging to the State, including land and waters, for the maximum benefit of its people" but too many Alaskans focus on the "maximum benefit" rather than the whole sentence including  "utilization, development".  No gas will ever be utilized or developed unless Alaskans accept what Pedro is telling them.

My idea of a good incentive program is a combination of tax holidays and flat taxes. Pick a flat tax rate for new oil and gas and declare a tax holiday for new oil and gas sales.  Imagine the effort that would go into a gas  pipeline if there was a potential payoff for early completion, otherwise sit back and watch the rest the world trade LNG, develop shale gas resources and build the big pipelines.  Alaskans can cling "maximum benefit"but its really about competing. Pedro tried to warn you.

AGIA Spending Report

The Alaska Department of Revenue and Department of Natural Resources submitted a report on expenditures on the Alaska Gasline Inducement Act (AGIA) (LINK).  The report includes details of spending to date and forecast of future spending.

Here's the simplified version:

What's absent from the report (1) The report indicates that no money has been spent to date on the LNG option, but tosses in $35,696,000 for LNG and other contingencies, and (2) There no real substance in terms of results. (3) There's no breakdown of spending East of Delta Junction, i.e. if the LNG option goes through how much AGIA spending was wasted?

The report does break out percentages spent in Alaska and Canada.  I estimate the Delta Junction to Canadian border spending equals about 8% so that 40% of AGIA spending can be tacked on to the cost of any LNG option.

More Lower 48 LNG Exports

The idea of lower 48 LNG exports is becoming a reality. A few months back Cheniere start the trend. I made this prediction last November:

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. 

This week the Department of Energy authorized Sempra to export LNG from the Cameron Parish Site (LINK), and quote:

HOUSTON -(MarketWatch)- The U.S. Department of Energy said Friday it has authorized Cameron LNG to export liquefied natural gas, opening the door wider for U.S. natural gas companies to send their bounty overseas.
The export permit is only the third awarded in the U.S. It allows Cameron, a wholly-owned subsidiary of California-based natural gas distributor and marketer Sempra Energy, to ship up to 1.7 billion cubic feet a day of LNG from its in Cameron Parish, La., facility to countries possessing free-trade agreements with the U.S. 

Here's a list of existing North American LNG import terminals with my analysis of proximity to shale gas (including the pipeline infrastructure to move the shale gas) Note, this table does not include the 2.8 BCFD proposed Gulf Coast LNG Terminal, Brownsville Texas:

The plan to convert LNG import terminals into an export terminals make sense for terminals located near shale gas fields and adequate pipelines. By this analysis there's good potential for four more new export terminals.  Two of those potential sites are controlled in part by Alaskan North Slope producers. I say this to illustrate the business decision before the producers: Build liquefaction  units at existing lower 48 import facilities -or- build a North Slope gas treatment plant, a $20 billion pipeline to Valdez, and a liquefaction at Valdez.  Obviously the Alaska LNG option is pointless unless North Slope gas is priced at a deep discount to Henry Hub.  How deep?  To defer the cost of $20 billion gas line to Valdez North Slope gas needs to sale for $1.50/MMBTU less than Henry Hub (based on a discount cash flow over 20 years at 5%).  

Now this isn't all bad news.  In the best case scenario the four import terminal near shale gas listed above are all converted to LNG export pushing the Henry Hub price of gas up into the $5 or $6/MMBTU range.  At that point in time Alaskan gas will not need to compete with the low capital cost of import facility conversion and the deep discount will not be a factor.  In the mean time it's important to remember the North Slope producers can sell LNG from lower 48 import terminals for less cost compared to building an pipeline to Valdez. 

Prediction - expect more announcements of lower 48 LNG import facility conversion to export.

For more information on the effects of LNG export see the  EIA report (LINK), and

Brookings Institution study on exporting LNG from the United States (LINK)

Nova Gold Donlin Feasibility Study Complete - Includes Gas Line

Another milestone for gold mine developer Nova Gold.  The Donlin feasibility study is complete (LINK).  According to the new release NovaGold will power the mine with gas (LINK). Quote:

The capital cost of $6.7 billion, which was approximately $300 million lower than the guidance provided in September 2011, now includes the construction of a 500-kilometer natural gas pipeline that, at a cost of approximately $1 billion, which would deliver natural gas from the Cook Inlet to the mine site, and $984 million of contingencies. The change to utilizing natural gas was previously described as an upside case for the updated feasibility study. Its confirmation of viability is indeed an important modification that is believed to improve numerous project parameters including lowering operating costs; improving environmental management and social
infrastructure; providing flexibility for future operational modifications; and facilitating potential increases in the scale of operations in this geologically prospective district. The Company believes that the long-life nature of the Donlin Gold Project offers the potential to lower the capital expenditures through long-term off-take with third-party providers, including supply of natural gas. The Company now anticipates the Project permitting to commence in the first half of 2012.

From the NovaGold website this nugget (LINK), 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.

Maybe this gas line is GO.  I'm still hunting a link to the actual study, I'll post a link when I find it. (UPDATE - Found the file.  Go to LINK then click on "View this company's public documents" and search for "Technical Report (NI 43-101)" dated Jan 12 2012). (Better link on the company website LINK).

Sounds like the NovaGold study is based on $13.33/MMBTU LNG from outside Alaska with the possibility of obtaining gas from within Alaska at some point in the future.  Their approach is a good one - Project cost are independent of the outcome of the larger Alaska Gas Pipeline debate / projects.

Good luck NovaGold - Best wishes for a safe and productive project.

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.

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.