About The Author:
Joseph P. Mathew is the President of Hybrid Energy Advisors, Inc. Hybrid Energy Advisors, Inc., based in Houston, TX, provides independent business advisory services to the natural gas industry and related markets. Their advisory services include business development, risk management, asset and corporate valuation and optimization analysis, corporate, project and public finance, general industry research and analysis, and corporate credit risk analysis.
Liquified Natural Gas:
Hybrid Energy Advisors, Inc.
(originally published by PMA OnLine Magazine: 2003/01)
The natural gas industry is in constant evolution. A few general observations in the current market are:
Given the confluence of the above observations, the United States is going to feel increasing upward gas price pressure, all other things being equal.
So what can mitigate this effect? The answer is new natural gas supply and its reliable transportation to consuming markets. Although the answer appears simple, the process of getting to a viable solution requires intensive study of supply alternatives. One source is liquefied natural gas, or LNG.
It sounds fluid, but usually is not quite as simple. Raw natural gas can be “heavy” (also called “wet” or “hot” gas) with various higher carbon molecules. These heavier particles create a higher heat content (ranging from 1,090-1,320 btu/cf) than permissible by many pipeline distribution standards. Although this heavier form of gas can be frozen, stored and shipped, the extra heat content may have to be “stripped off” prior to entering another distribution system to conform to the gas heat standards of the pipeline network.
In the United States, state public utility commissions (PUCs) oversee gas pipeline heat content standards. It is estimated that the average heat content of current distributable gas in the United States is approximately 1030-1060 btu/cf.
Any gas disseminated into a system that does not conform to these independent standards will not be permitted into the inherent system without the heavier particles being stripped (through a process called “fractionation”) or diluted with inert gas. This process adds an additional cost to the overall project. Fractionation can occur either upstream or downstream, but is usually contingent upon which location is most cost effective, politically sound, environmental-friendly or where there may be access to a viable purchasing market for the fractionated heavier gas. Fractionated gas products can either be marketed or injected back into the ground. Any marketing and sales of this heavier gas can serve as a revenue enhancement of or a contra-expense item to the total project.
The LNG Opportunity
In the 1970’s and 1980’s, physical gas prices had spiked in the United States, feeding fears of gas shortage. This phenomenon inspired the construction of four major LNG import re-gasification terminals, all on the United States East Coast (Everett, MA, Elba Island, GA, Cove Point, MD, and Lake Charles, LA in total constituting approximately 3 bcf/day of installed capacity).
However, deregulation led producers of gas to become motivated to explore and develop newer, easy access gas reserves in the mountain states and the Gulf Coast, flooding the market with excess gas inventory. This was exacerbated by Canadian policy changes that allowed increased gas exports, in effect emigrating additional low-cost gas from the Western Canadian Sedimentary Basin to compete for demand in the United States. The result was a gas supply “bubble” which kept prices very low for quite some time. How times have changed.
Last year, the Department of Energy’s Energy Information Administration (EIA) anticipated medium-term Henry Hub gas prices to range from $3.25/mmbtu to $3.50/mmbtu, and long-term gas prices to be close to $4.00/mmbtu.
In analytically forecasting natural gas prices, one can label the expected gas price a “dependent” variable and the underlying fundamentals as “independent” variables that influence the dependent variable. Using quantitative techniques, Hybrid Energy Advisors, Inc. (HEAI) predicted in the spring of 2002 that Henry Hub financial prices, the dependent variable, would range between $3.35 and $4.10 through the winter months of 2002/2003. They also calculated ten-year price forecasts of $2.25-$2.80/mmbtu during the summer months and $3.70-$4.25/mmbtu during the winter months. HEAI believes that ten-year city gate prices of gas on the West Coast and Midwest United States will trade approximately equivalent (“flat”) to Henry Hub prices, and upper East Coast prices to trade at approximately 45-65 basis points (cents/mmbtu) above Henry Hub prices. These forecasts include a greater gas import as a percentage of total domestic gas. HEAI believes that by the year 2010, approximately 6-8% of the total US gas supply will come from LNG produced from foreign stranded gas reserves.
Today the total cost of LNG production has been quite streamlined and reduced to approximately $2.00/mmbtu due to competition and improvements in technology. Much of the technology pertaining to lower-cost land-based terminals and offshore and ship-board re-gasification units are still relatively unproven. However, major energy industry players and engineering firms do not foresee problems with the design and implementation of these methods.
Therefore, assuming a netback of $1.00/mmbtu, the total delivered price of approximately $3.00/mmbtu can now be theoretically achieved. This LNG price is almost $1.00/mmbtu less than a decade ago. When comparing this new price to industry average price forecasts for Henry Hub and East and West coast city gates, LNG can certainly be considered an economical source of natural gas supply.
Major supply and major
The gas supply to meet expected growth in LNG demand is from stranded gas reserves associated with crude oil production that historically did not have much hope of coming to market. These reserves are typically owned and operated by many major worldwide energy companies. Longstanding production zones include Algeria, Libya, Nigeria, Qatar, Malaysia, Australia, Brunei, Indonesia and the United States (Alaska, Cook Inlet). Many proposed new areas of liquefaction include Norway, Trinidad & Tobago, Venezuela, Bolivia and various countries of the Middle East.
The ideal economic scenario when evaluating which terminal projects make sense are contingent upon studies related to where and how much gas demand is going to be, where the supply will come from, and how much gas to produce.
Not so Fast
In any energy infrastructure project, due diligence on regulatory, permitting, and environmental factors is quite important. A hiccup in procuring the necessary political approvals, permits and rights-of-way can be devastating to the economics and viability of a project. Projects have been known to come to a dead halt, much to the chagrin and expense of the lead project developer and production consortium, over matters such as residential noise or particulate pollution, wildlife endangerment, political vacillation, or just plain general nuisance.
LNG re-gasification terminals are viewed as large, obstructive and generally displeasing to the eye for local residents and businesses. Although designs to bury such large facilities underground have been forthcoming, general apprehension related to the “don’t build in my backyard” philosophy still emphatically exists. One mitigant to that problem is sighting the terminal off-shore or aboard the LNG transport ship itself, far from residential or commercial areas. Although such new technologies regarding offshore and ship-board re-gasification is being studied and developed by a variety of industry players, the educating process required with political parties is an ongoing and sometimes frustrating process.
Guidelines regarding the oversight, regulatory standards and environmental compliance of on-shore or off-shore terminals are still in debate. In the United States, three of the four import terminals are overseen by the FERC. Regulatory oversight can be an issue to contend with as most merchant energy firms and pipeline companies vie for ownership, control, and equity interest. For such market participants, FERC jurisdiction impedes profitability and ease of management control of the owners and its merchant gas off-take counterparties. Many of the industry participants building and sighting these terminals contend to the FERC that if they have the burden of finding, constructing, funding, and permitting a terminal, they should not be subject to losing the economic potential to sell such re-gasified gas into open market by subjecting the capacity to a FERC-controlled “open-season”. After all, if one firm does all of the work, why would that firm surrender the market opportunity to profit from the off-take gas sales to another firm who has not incurred the same “finders” costs? For many of these project leaders, equity ownership of a FERC-jurisdiction terminal at a regulated rate of return is not enough. They want the most facile way to attain the real “juice”. That is, they prefer the sole ability to sell their upstream LNG into the interstate domestic markets as gaseous gas and take merchant positions in key locations.
Two other LNG-related non-operational risks that are worth mentioning at this time are terrorism and/or accident risk and sovereign government risk.
Firstly, the events of September 11, 2001 will forever be marked in American and world history as an indelible reminder that impedances to economies can come in a variety of forms. Terrorism has been shown to be a more significant influence on energy endeavors than ever before. With the threat of oil tanker, nuclear reactor and LNG ship sabotage, political risk to sighting an on- or off-shore re-gasification unit is high. Man-made or accidental explosion of such a tanker can be catastrophic in the mind of the common person, and although studies have shown that LNG volatility is much lower in its liquid cooled form, the image of a giant vapor cloud can have devastating effects on the human psyche and at the very least create an apocalyptic image that few are willing to internalize.
Secondly, since much of the gas that is being liquefied comes from foreign and third-world countries, sovereign risk can be quite disenchanting as compared to reliable, high-credit, highly-liquid United States gas. Changing governments, political coups, local customs, and draconian regimes can portend inconsistent supply. Due to this factor, price concessions are usually made in relation to United States-priced gas supply, however, the sovereign risk inherent in such supply must to be evaluated concomitantly with the discounted pricing.
It is becoming more apparent that the energy companies, United States government, FERC, and state public utility commissions (PUCs) need to ally interests in figuring a pragmatic goal in satisfying such projected United States gas demand growth. The figures and analysis tell a convincing story of what is required to mitigate impending natural gas shortfalls, but the real solutions need to be prudently pursued by private enterprise and supported by rational local, state and federal government legislation.