Aside from dwindling oil production (that we discussed last week) the State of Alaska is also home to 35 Tcf of proven conventional natural gas reserves. These could be consumed domestically or exported as liquefied natural gas (LNG). Alaska is closer to Asian markets than the 20 LNG export projects currently sitting in the Department of Energy approval queue. But the massive infrastructure investment required to get Alaskan gas from north of the Arctic Circle to market requires complex alignment of competing producer, shipper and government interests. Today we review efforts by the 49th State to find markets for its natural gas.
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A number of presentations at the Infocast Alaska Oil & Gas Infrastructure & Development Summit that RBN spoke at last week (June 4, 2013) covered the topic of competing liquefied natural gas (LNG) project proposals in Alaska. Hearing about those proposals reminded us that we have not provided a blog update on the progress of various US and Canadian LNG export projects since December 2012 (see Prices Shaky as DOE Approvals Get NERA).
Before we get into the nitty gritty here’s a quick refresher on the basics of LNG (skip to the next paragraph if you know your way around the frozen gas industry). The process of liquefaction lowers the temperature of dry natural gas to -2630 Fahrenheit causing it to liquefy. In its liquid state 600 standard cubic feet of natural gas take up only 1 cubic foot of space, making it economical to transport between continents in specially designed ocean tanker ships. Known as “trains”, large-scale liquefaction plants are seriously huge investments costing anywhere from $2-$8 Billion (MIT estimate). In previous RBN Energy blogs we looked at the project economics of the 20 United States LNG export projects awaiting DOE approval (see Export Boom or Import Echo) as well as 3 proposed Canadian West Coast projects (see Lonely Gas Surplus Seeks Long Term Overseas Relationship).
The big news since December 2012 came last month when the Department of Energy (DOE) approved the application at the top of its project queue - the Freeport LNG Expansion Liquefaction plant - to export to countries without a free trade agreement with the U.S. (i.e. most of the countries that actually import LNG). Subject to environmental review and final approval, Freeport LNG has been authorized to export up to 1.4 Bcf/d of natural gas for the next 20 years from the Texas Gulf Coast. Based on current project schedules the Freeport LNG plant would come into operation in 2017. The only previously approved project for export to non-free trade agreement countries is Cheniere’s Sabine Pass - authorized to export 2.2Bcf/d back in 2011 and due online in 1Q 2016. The complete list of pending DOE applications as well as proposed projects in Canada and the US can be seen here on the FERC website).
The US LNG export terminal project list has been the subject of considerable politicking in Washington DC as industry lobbyists fight off a campaign by Dow Chemical Company (Dow Inc). to limit LNG exports. Most observers seem to believe that Dow’s strategy is intended to keep the domestic price of natural gas low (and with it feedstocks to their production facilities). The natural gas industry maintains that exports through LNG terminals are the best way to balance booming shale gas production with US demand and continue the incentive for producers to drill. The DOE is navigating the issue by slowing its decision making process to a crawl and ordering up impact studies by the truckload. So far the only consensus about these projects is that there’s no way all 20 are going to get approved, let alone built in the next 5 years. Needless to say, RBN Energy is not stepping into the political debate – our job is to look at the economics and tell you whether these projects make sense in the market.
Which brings us back to Alaska and progress or rather lack thereof on numerous schemes to commercialize huge natural gas resources in the 49th State. Last week we updated an earlier blog on prospects for production investment in Alaska’s North Slope oil industry (see Anchored Down in Anchorage). A combination of growing oil production in the lower 48 because of the shale revolution and Federal regulations requiring crude oil transportation in Jones Act vessels make continued new oil company investment to reverse a decline in Alaska’s production seem less likely. But at least Alaska’s remote oil fields have a pipeline in place to ship oil from the inhospitable Prudhoe Bay production fields to the southern coast at Valdez, AK. At the moment there is no such infrastructure to transport natural gas to market. As a result the associated gas produced with crude oil in Prudhoe Bay is simply re-injected into wells to enhance oil recovery in older fields.
That’s not to say that there isn’t plenty of natural gas available in Prudhoe Bay. The Alaska Department of Natural Resources estimates there are 200 Tcf of unproven and 35 Tcf of proven conventional gas reserves onshore and offshore on the North Slope and in outer continental waters off the north coast of Alaska. Prudhoe Bay producers already re-inject 8 Bcf/d of gas into oil wells that could theoretically be rapidly delivered to a gas project instead. The Point Thompson gas field is currently being developed with 8 Tcf of natural gas reserves. And apart from the need to process that gas to remove impurities and meet pipeline specifications (that requires a gas processing facility) and the little matter of an 800-mile pipeline to reach tidewater in South Alaska for liquefaction and transport to market, there is plenty of demand for Alaska’s natural gas. We will get to the infrastructure issues in a moment but there are two sources of demand for North Slope natural gas. The first is in State – providing residential and commercial supplies for Alaskans estimated at 300-350 MMcf/d depending on the season. Limited supplies of gas from the Cook Inlet field in south central Alaska are currently available for domestic consumption in Anchorage but these are declining. Many Alaskans in central cities such as Fairbanks use expensive locally refined fuel oil for heating. Using abundant North Slope natural gas is cheaper for Alaska. The State can use gas taken in lieu of royalty payments for local sale and distribution.
The export market for Alaska LNG is all about Asia and in particular Japan since the Fukushima nuclear disaster in March 2011 left that country short of natural gas for power generation. The map below shows the journey length between Alaska and Japan is shorter than that for any other major potential and actual export competitor except Australia. The shipping distances from Alaska are certainly lower than from any other proposed North American export terminal on the Gulf Coast or the West Coast. A recently completed feasibility study by Japanese company Resources Energy, Inc that is looking to partner with the State of Alaska and producers to contract for a 20 year LNG supply, estimated shipping costs to Japan at $1/MMBtu.
Source: Alaska Department of Natural Resources (Click to Enlarge)
But as we have noted before with these giant LNG projects, adequate supplies and market demand do not build infrastructure on their own. The scale of Alaska’s LNG infrastructure requirements is bigger than any competing proposal in the lower 48. Not surprising then that deciding who should build (and pay for) that infrastructure is an ongoing stumbling block for Alaska LNG projects. Take the 800-mile pipeline from Prudhoe to the south coast. The Federal government in the midst of the 1970’s oil crisis underwrote construction of the oil pipeline equivalent. Two years ago in 2011 competing plans for gas pipelines from Alaska to the Lower 48 through Canada were being touted. But both the TransCanada-ExxonMobil Alaska Pipeline project and the BP-Conoco Denali project were abandoned in March 2012 and May 2011 respectively in the face of rising production of cheaper Lower 48 shale gas.
On the table at the moment are two different pipeline projects to deliver gas from Prudhoe Bay to South Central Alaska. The first of these is a joint venture between TransCanada (a pipeline company) and the big three North Slope producers - ExxonMobil, Conoco and BP. Their pipeline would ship as much as 3.5 Bcf/d of treated gas from Prudhoe to the South Coast of Alaska. After subtracting the gas consumed along the way at pipeline compressor stations, gas withdrawn along the way for Alaska's needs, and gas burned up at the liquefaction plant to power the process, the companies expect to have 2 bcf/d to 2.4 bcf/d of natural gas ready to ship out as LNG. By the time the project estimates are added up for the gas pipeline from Port Thompson to Prudhoe, a gas treatment plant in Prudhoe, the pipeline to South Alaska tidewater and the huge liquefaction plant, there will not be much change out of $50 Billion to build this infrastructure. Under an exclusive agreement in 2007 with the State of Alaska, the producers have until 2014 to submit this plan to the US Federal Energy Regulatory Commission (FERC) in order to get State funding towards the pipeline.
But partly in frustration that the producers (who have the lease rights to the Prudhoe Bay gas) are dragging their feet, the State of Alaska set up another project in 2010 under the Alaska Gas Development Company (AGDC) with the primary aim of meeting local Alaskan demand. Trouble is that pipeline is not allowed to carry more than 0.5 Bcf/d of gas from Prudhoe Bay to Anchorage without paying a $500Million fine to the producer backed project. That means there would not be much gas left for export after meeting local demand.
The message from State and commercial presentations at the conference last week was that the two competing pipeline projects need to work out a compromise solution that meets Alaskan and export needs and then decide how to pay the massive infrastructure costs. Getting that agreement and bringing together producers, shippers and State is proving complex. The Japanese company Resources Energy has expressed willingness to pay for the liquefaction plant and shipping to Japan as part of a 20 year deal but the producers have yet to agree to sell their gas and speed up their infrastructure plans to meet that company’s timeline to get export supplies online by 2020. Alaska has a massive accumulated State fund from previous oil taxes and royalties that could be used to underwrite project financing. But the State needs the producers to sign onto any infrastructure plan and they are sticking to their own proprietary plan.
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