Hawaii LNG Shipping Options

by Michael Hansen, President, Hawaii Shippers Council

The Hawaiian Electric Company Inc. (HECO)’s formal plans state that they are seeking to transition from liquid petroleum fuels to lower cost fossil fuels such as Liquefied Natural Gas (LNG), which will also reduce power plant emissions to comply with U.S. Environmental Protection Agency (EPA) regulations that will come in to effect in January 2016.

HECO relies on liquid petroleum fuels to generate approximately 70% of the electricity they currently produce; this is a very high reliance on petroleum fuels in comparison to both national and international norms. In comparison, nationwide less than 1% (actually 0.3%) of U.S. electricity is produced from petroleum fuels, and worldwide it’s approximately 5.5%, primarily in third world countries and stranded markets (such as in island situations).

Hawaii electricity rates are extraordinarily high as compared to the U.S. as a whole: The average current residential rate in Hawaii is approximately 38¢ per kilowatt hour (KWH) while the equivalent national U.S. rate is about 13¢ per KWH. The Hawaii rate is effectively three times the nationwide average.

HECO’s plans state they are looking to LNG as a solution to both the rising cost of petroleum fuels and to comply with the impending EPA regulations, as natural gas is significantly cleaner burning than petroleum fuels and will appreciably reduce emissions.

From the point of view of shipping, there are several issues which will impinge on HECO’s planning to transition from liquid petroleum fuels to LNG, which we shall elaborate herein.

Hawaii Gas

The Gas Company LLC. d.b.a. Hawaii Gas (HI Gas) is the State’s only franchised public gas utility. They are currently shipping very limited quantities of LNG to Hawaii under a Hawaii State Public Utilities Commission (PUC) approved program known as “Backup Enhancement Project” (Docket 2013-0184). These efforts are often confused with HECO’s LNG supply plans.

HI Gas began shipments of LNG in April 2014 from a small liquefaction plant in Boron, California (Clean Energy’s Pickens Plant) to Honolulu utilizing three 40’ ISO (International Organization for Standardization) shipping containers transported by the existing domestic containership services operated by Matson Inc. Ocean shipment is via the Port of Los Angeles.

These are highly specialized cryogenic tank containers designed for the carriage of LNG at minus 260°F. The LNG containers are discharged from the interstate containerships at the Sand Island container yards (Honolulu Piers 51A – 53), trucked to HI Gas’ Pier 38 facility in Honolulu Harbor, un-loaded using a mobile re-gasification unit and the resulting natural gas is injected into HI Gas’ existing utility pipeline system.

Containerized LNG is well suited to HI Gas’ current and estimated future gas sales volume. The very small quantities of LNG now being shipped by HI Gas and possible larger future volumes would not support bulk shipments of LNG in dedicated tanker ships known as LNG carriers.

HI Gas is using the LNG to supplement local production of synthetic natural gas (SNG) at their Kapolei plant from naphtha feed stock.  HI Gas anticipates that they will increase shipments of containerized LNG over time, perhaps completely displacing their SNG production. (SNG and LNG are compatible and can be safely combined in the HI Gas utility pipeline system.)

On the basis of HI Gas’ current sales of SNG, it would appear that they would be able to efficiently cover all their requirements with containerized LNG and perhaps completely replace SNG at sometime in the future providing the economics remain favorable. It is unlikely that HI Gas’ sales volume alone would ever support bulk LNG shipments, at least given today’s market.

HI Gas provides SNG by utility pipeline to customers from Kapolei to Hawaii Kai along the South Coast of Oahu Island. In other areas in the State, HI Gas supplies petroleum gas (a mixture of propane and butanes) by pipeline in Central and Windward Oahu, Hilo (Hawaii Island), Kahului/Wailuku (Maui Island) and Lihue (Kauai Island). Outside of those areas petroleum gas is supplied by tank.

Hawaiian Electric Company Inc.

HECO’s situation is very different from HI Gas. HECO’s requirements for LNG to replace liquid petroleum fuels for the generation of electrical power would be on a far larger scale.

The immediate reason for HECO to pursue LNG and other alternatives is they are facing new EPA emission regulations known as the Mercury and Air Toxic Standards (MATS) that were adopted on December 16, 2011 and will become effective for HECO in January 2016.

HECO’s alternatives other than LNG to reduce emissions and comply with MATS are:

• Fit their fleet of generating plants (on Oahu, Molokai, Maui, Lanai, and Hawaii Islands) with emission control facilities commonly known as scrubbers. This would allow HECO to continue burning lower-cost petroleum-derived Low Sulfur Fuel Oil (LSFO). HECO’s capital cost for scrubbers is roughly estimated to be around $1 billion.
• Switch their steam boilers from LSFO to more expensive Ultra Low Sulfur Diesel (ULSD), which would reduce emissions to allowable levels without scrubbers. Switching from LSFO to ULSD in the steam boilers (and to ULSD in the diesel and turbine plants) would substantially increase the cost of generation and appear in the fuel adjustment portion of the ratepayers’ bill. (ULSD currently costs about $26.00 to $27.00 per million British Thermal Units (MM BTU)s versus LSFO at around $21.00 per MM BTU.)

On September 4, 2014, HECO filed form 8-K with the Securities Exchange Commission (SEC) informing investors that they will not renew their LSFO contract with Par Petroleum Corp.’s Hawaiian Independent Energy Inc. (HIE), and amended their LSFO fuel contract with Chevron Products Company (“Chevron”) to begin supply of “ULSD as soon as January 2016 to help HECO meet more stringent federal EPA air emission requirements known as MATS.”

HECO’s Power Supply Improvement Plans (PSIP)

HECO filed with the PUC its Power Supply Improvement Plans (PSIP) and Distributed Generation Interconnection Plan (GDIP Book 1 & Book 2)) on August 26, 2014 for their group of companies including Maui Electric Company Ltd. (MECO PSIP) and Hawaii Electric Light Company Inc. (HELCO PISP).

The HECO PSIPs and DGIP were filed with the PUC in response to the Commission’s four orders of April 29, 2014, which directed HECO as follows:

The Hawaii Public Utilities Commission (PUC) announced four major decisions and orders that collectively provide key policy, resource planning, and operational directives to the Hawaiian Electric Companies (HECO Companies). The orders require the HECO Companies to develop and implement major improvement action plans to aggressively pursue energy cost reductions, proactively respond to emerging renewable energy integration challenges, improve the interconnection process for customer-sited solar photovoltaic (PV) systems, and embrace customer demand response programs.

The HECO PSIPs among other items addressed the issue of delivering LNG to Hawaii (See HECO PSIP pages I-1 through I-3) in both bulk and containerized modes and discussed the possibility of transitioning from containerized LNG to bulk LNG and the requirements to do so.

LNG in Bulk

Importing LNG in bulk on LNG carriers, would be the most efficient way to transport and handle LNG and result in the lowest fuel cost offered by the various alternatives.  However, transporting and handling LNG in bulk requires extensive and expensive infrastructure and long lead (planning) times.

Among the needed infrastructure is a main LNG import terminal on Oahu Island, which would be required to receive and store bulk LNG at -260°F and re-gasify the LNG to send out the natural gas by pipeline to the power plants and potentially other customers. 

It is generally agreed the probable location of a shore-side LNG terminal would be at Kalaeloa Barbers Point Harbor in West Oahu. The likely site would be the undeveloped harbor area shown as “future expansion area” and sometimes called “Pier 8.” It is estimated the shore-side LNG terminal and pipelines to the power generation plants on Oahu and other potential customers would together cost around $1 billion. 

Another bulk LNG terminal option, which HECO seriously pursued for a time and indicate in their PSIP is still under consideraion, is a Floating Storage and Re-gasification Unit (FSRU) to be moored in Middle Loch, Pearl Harbor.  FSRUs are highly-specialized purpose-designed and built ships to act as an LNG terminal in lieu of a permanent shore-side terminal. Typically, FSRUs are time chartered (akin to leasing) from a highly experienced operator and installed while a shore-side terminal is being designed, permitted and built.

There are indications HECO’s FSRU Pearl Harbor proposal has encountered problems including Navy resistance to some of the necessary aspects of a FSRU installation, and can no longer be considered their primary solution at least for the medium term.  There are significant capital costs associated with constructing an FSRU mooring and associated pipelines, albeit they should be lower than for a shore-side terminal. However, a floating terminal would incur higher operating costs primarily from chartering a FSRU, which is a very large operating expense.

Neither a floating nor shore-side LNG receiving terminal on Oahu Island would address the delivery of LNG to the neighbor islands where HECO also has plants and also needs to transition away from petroleum fuels for cost and regulatory compliance reasons.

It would be possible to operate a small interisland LNG carrier (small self-propelled ship or tug and barge unit), which would load from the main terminal at Kalaeloa Barbers Point Harbor or floating in Pearl Harbor and transport LNG to Neighbor Island ports.  However smaller bulk deliveries to the neighbor islands would require small LNG receiving terminals with storage and re-gasification facilities at each port that would significantly increase infrastructure costs.

HECO addressed development of a bulk LNG receiving terminal in their PSIP and said it could be available in approximately 8 years by 2022 based on advice from the U.S. Federal Energy Regulatory Commission (FERC) as follows:

The development of a bulk receiving terminal will be subject to FERC review and approval and therefore cannot be realistically achieved by 2017. Siting of such a terminal, whether floating or land-based, will require substantial engineering analysis and stakeholder socialization. After consulting with FERC, a realistic schedule to develop a bulk LNG terminal is approximately 6 to 8 years.

We agree that the permitting process for a bulk LNG terminal would be lengthy, but would estimate design, permitting and construction is likely to require ten or more years.

Potential Bulk LNG Sources

HECO is facing several problems arranging for a supply of bulk LNG.

The most efficient points of LNG supply to Hawaii would be on the West Coast of North America where several LNG export terminals are being proposed as follows:

• U.S. West Coast -- primarily on the Oregon Coast and lower Columbia River
• Canadian West Coast -- Ports of Kitimat and Prince Rupert, British Columbia
• Alaska -- A new terminal to be built at Nikiski, Cook Inlet.

However, most of these projects are unlikely to be completed within the next ten years and offer HECO a convenient source of bulk LNG at their planning time horizon of 2022.

In addition, HECO’s potential LNG requirements are very small by world standards and could not justify development of a bulk liquefaction export terminal alone. Therefore to arrange a bulk LNG supply, HECO must piggyback on the requirements of the major Asian buyers who will induce development of LNG export terminals on the West Coast of North America and Alaska. At the end of the day, HECO’s volume may not be large enough and they may not be able to make the long term commitment to seriously interest bulk LNG export terminal operators.

The several proposed LNG export terminal projects planned for the Canadian West Coast are stalled today because the developers have not been able to conclude long term (typically a minimum of 20 years) take-or-pay contracts with the major natural gas importers in their intended markets of Japan, South Korea, Taiwan and China. The developers are seeking higher LNG prices indexed to the price of crude petroleum oil, while the Asian gas buyers are demanding the price be decoupled from oil and pegged to a gas industry pricing standard such as Henry Hub.

The proposed new terminal at Nikiski, Alaska, must await development of a Trans-Alaska gas pipeline from the North Slope to the tidewater in Cook Inlet, which is estimated to require substantially more than a decade to develop.

The one proposed North American LNG export terminal on the Pacific Ocean that currently appears to be making significant progress towards actual construction is the Jordan Cove project at Coos Bay, Oregon. The Jordan Cove project, which is not anticipated to be online before 2019, will be a tolling facility meaning that the terminal owners and operators will not be the owners of the natural gas and exporters of the LNG; rather, they will assess a toll on the natural gas passing through and processed into and stored as LNG at their facility for ocean shipment. 

To take advantage of Jordan Cove, HECO would either have to become a natural gas owner and arrange pipeline capacity to deliver their gas to Jordan Cove, or turn to a gas merchant to make these arrangements. Not only are these undertakings are outside HECO’s usual purview of contracting for the supply of fuel to plant gate, Jordan Cove may choose not to accommodate HECO’s smaller requirements as they need to target large customers who can make long term commitments to finance their project.

Jones Act

In order to take advantage of Jordon Cove or any U.S. bulk LNG supply location (including Alaska), HECO would also need to address the Jones Act which requires the use of U.S.-built, U.S.-flag, U.S.-owned and U.S.-crewed vessels to carry cargo between two domestic points.

There are no LNG carriers in the Jones Act fleet and none have been built in the U.S. since the late 1970’s.

The most straightforward way to deal with the Jones Act problem, if HECO was to obtain bulk LNG supplies via Jordan Cove or any other U.S. source, would be to seek an exemption allowing use of foreign built, U.S. registered LNG Carriers in the Hawaii trade.

As the Jones Act is a federal law, an exemption would require an act of Congress signed by the president.

Containerized LNG

Because of all the problems facing bulk LNG for Hawaii, HECO is now seeking to bring in LNG by container in a similar fashion to HI Gas except on a vastly larger scale.

In March 2014, HECO issued a request for proposals (RFP) to supply up to 800,000 metric tons (hereinafter, “MT”) per annum of LNG by container.  There have been reports that HECO is attempting to finalize their container LNG contracts by October 2014, but that deadline would seem optimistic at this time. 

We believe transporting 0.8 million MT of LNG by container annually will present many logistical challenges, is unlikely to result in significant cost savings due the high handling costs associated with the proposed shipping method in containers; and, as a result, containerized LNG could potentially end up costing more than the petroleum fuels currently being used.

HECO also addressed containerized LNG in their PSIP Section I in part as follows:

Based on confidential information received via the Containerized LNG RFP process, we believe that an LNG delivery commencement date in the latter part of 2017 remains viable if the following five key milestones are realized by their noted deadlines.

Upon achievement of these milestones, we will make the investments necessary to construct, assemble and aggregate the various pieces of the supply chain needed to deliver LNG to Hawai‘i in 2017. It nevertheless must be recognized that these milestones are challenging, some of which are beyond our control and they will only be realized if no significant legal, environmental, or social obstacles encumber the process.

If HECO can solve the supply chain challenges, which by their own description seems problematic, containerized LNG could solve their emissions problem and allow them to comply with the new EPA MATS regulations coming into force in January 2016 albeit approximately 2 years late. The higher fuel costs likely to result from containerized LNG would be paid for by the ratepayers, again through the fuel adjustment portion on their bill.

HECO states in respect of their prospective liquefaction contractor for their containerized LNG – Fortis BC of Canada which operates a facility in the Vancouver area -- the following:

In addition, because FortisBC is in British Columbia, Canada, they are not subject to the Jones Act and, therefore, can provide substantial marine transport savings to Hawaiian Electric through the use of international shipping assets.

While it is true the Jones Act does not apply to the movement of cargo directly between Canada and Hawaii, to accommodate the regular movement of ISO containers loaded with LNG a dedicated containership or ship with container capability would be required. Presently there is no containership service between Vancouver and Honolulu, and HECO would have to induce service, which could substantially increase unit freight costs. Alternatively, HECO’s LNG containers could be routed via Seattle, Washington, but that would necessitate use of a Jones Act carrier. Matson offers weekly service from Seattle to Honolulu.

Conclusion

It doesn’t appear HECO can implement bulk LNG and lower energy costs for Hawaii State rate payers in the near to medium term because of: infrastructure requirements in Hawaii; the development of efficient LNG supply sources on the West Coast of North America and Alaska; the Jones Act; and, other issues. The development of an efficient bulk LNG supply for Hawaii is probably more than ten years away, providing the process is currently underway and will continue to be pursued in a serious way.

HECO’s container LNG alternative would seem to incur high handling costs and not offer any real savings in comparison to the current use of low sulfur fuel oil, diesel and naphtha for power generation, and may well cost ratepayers more. This alternative is not estimated by HECO to be available until two years after the EPA MATS regulations go in to effect for HECO, requiring interim measures. There are many issues regarding the containerized LNG supply chain that need to be sorted out, and in our opinion, this option is likely to face major logistical bottlenecks possibly making it unfeasible in the final analysis.

The recent amendment to HECO’s contract with Chevron to supply ULSD beginning in January 2016 indicates this will be HECO’s near term solution to meet the EPA’s MATS regulations, which come in to effect in January 2016. This ULSD alternative would seem to solve HECO’s MATS emissions compliance issues in a timely fashion. However, it would also pass the higher cost of ULSD to the rate payers through the fuel adjustment rate mechanism.

Furthermore, it would seem that ULSD could easily become HECO’s longer term solution in view of the issues facing implementation of LNG in either the bulk or containerized mode. If USLD in fact becomes HECO’s longer term solution to the EPA’s MATS regulations, HECO will have failed to capitalize on the low cost of natural gas in North America and continue to expose their ratepayers to the volatility of petroleum on international commodity markets and strategic risks of serious disruptions in this market place.

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