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.

The Next Alaska Movie

The Alaska Dispatch ran a story on five worst Alaska themed movies (LINK).  I'm sure you'll be excited to learn another great tale of the North is in development.....

I don't want to give too much away, but it's the gripping tale of one state's struggle to bring natural gas to market.  There's excitement: An earthquake, a tsunami, snow, more snow, explosions and the daring rescue of sea mammals.There's a tender love story as stakeholders tearfully embrace mountains of cash.  There's drama when greedy markets confront their addiction to cheap shale gas.  Coming to the bargain DVD bin soon!

Rigging Down on Low Gas Prices

This week shale gas champion Chesapeake Energy announced that they are backing off dry gas drilling and production. Quote:

 Chesapeake Plans to Reduce its Operated Dry Gas Drilling Rig Count to 24 Rigs, a Decline of Approximately 50 Dry Gas Rigs from its 2011 Average Operated Dry Gas Rig Count. 

Chesapeake Plans to Curtail its Gross Operated Gas Production by up to 1.0 Bcf per Day and Plans to Defer New Dry Gas Well Completions and Pipeline Connections Wherever Possible 

 This isn't anything new. Chesapeake has "deferred" production before when the price dips below $4/MMBTU.  The graphic below shows the gas price over time with a sales volume bars on the left.  You'll note the actual volume of transactions is in the $4.00 to $4.40 / MMBTU range.  There's virtually no incentive to drill for dry gas at today's insanely low prices.

I view the Chesapeake action as further validation the $4/MMBTU is the long term support level for lower 48 natural gas. Overall gas rig rates are down 14% from a year ago (791 now vs. 906 last year). We'll soon learn if $4/MMBTU less transportation cost of $1.5/MMBTU can support an LNG plant in Alaska.

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.

Alaska Pipeline Project - FERC Filing

LINK to Alaska Pipeline Project draft resource report:

Suggested Reading

The reality of the lower 48 shale gas glut may have finally sunk into Alaskan policy makers (see previous entry).  Here's a good paper on the dynamics of the shale gas business. (Musings From the Oil Patch LINK) Turns out $3/MMBTU is an insane price for shale gas drilling.  The data indicates at current prices sane people stop drilling for dry gas, i.e. gas not loaded with higher value liquids.

Impacts to Alaskan gas projects: Less drilling leads to higher prices. At $6/MMBTU the rigs switch back to gas.  A gas market oscillating between $3 and $6/MMBTU is unlikely to justify a $40 billion gas line.

IF, and that's a big if, Alaska and the oil companies can align their common interest and build an in state line and LNG export plant then it's possible that the state and the producers will benefit from higher lower 48 gas prices.

Three & One

Yesterday Alaska's Governor Sean Parnell met with the CEO's of ExxonMobil, BP, and ConocoPhillips to talk about commercialization of North Slope gas, boosting Alaskan oil output and Point Thomson.(LINK to Governors press release), and the agenda:

It's not a kumbaya moment yet, but I'll give the Governor and the CEOs credit  for manning up and doing the adult thing, i.e. start talking about the issues that are stalling development of oil and gas in Alaska.  This group should talk more often.  Quote from the Governor:

“I appreciate the willingness of the chief executives to come to Alaska to discuss the important topic of commercializing North Slope gas,” Governor Parnell said. “For a gas project to advance, all three companies need to be aligned behind it. This meeting is an important step, but much work remains.”

Nice work Governor, don't let up.