With TAPS, questions arose as to whether market prices would support such large-scale energy infrastructure projects, and would those expected prices make it feasible to build such a mammoth pipeline to get crude oil from stranded reserves closer to market?
The questions were asked, and the questions were answered. Yes. But who would have known this project would work? Who could afford the costs? Who took the risk? Simply, the answer is some very big energy companies. Equipped with large balance sheets, large-scale research and development efforts, fluid access to capital, experience, and risk appetite, these behemoth companies launched an unprecedented effort in energy history.
Like any major energy infrastructure development project, much analysis, estimations and calculations had to be ascertained regarding:
- exploration (supply),
- development, processing and gathering of reserves,
- pipeline asset construction and engineering costs,
- regulatory costs and risks,
- political costs and risks,
- accounting methods,
- tax implications,
- market risk and demand expectations,
- overall project valuation (cost-benefit),
- expected market prices, and
- a plethora of other parameters.
This was no different for TAPS, as this project was analyzed for almost a decade. After exhaustive study, the producers, financiers, governments, engineering firms et al decided it was worth the effort. They were not disappointed.
The success of TAPS proved that energy commodities can be explored, processed and taken to market if the price is right and the returns exceed the relative risk, despite the titanic size of such a project. The bottom line is that the fundamental expectations of crude oil prices were higher than expected costs. Can the same be said about the stranded gas that accompanies the crude oil extracting, currently being re-injected back into the ground? Can a huge natural gas project also be economical? That is one of the most prevalent questions today regarding new sources of domestic natural gas and one of great debate.
Current State of Domestic Gas Supply and Prices
United States gas supply is of key relevance in a market that is exhibiting continued upward natural gas price pressure. In the 1990’s, natural gas supply was abundant, coming predominantly from areas such as the Gulf Coast and the importation of Canadian gas from the Western Canadian Sedimentary Basin (“WCSB”). Prices averaged approximately $2.00/mmbtu for the decade. However, notwithstanding the alleged corporate malfeasance that led to certain exaggerated regional gas price spikes in 2000-2001, supply constraints, diminishing exploration returns and changing weather patterns are leading to an ever increasing price trend.
Hybrid Energy Advisors, Inc. (“HEAI”) expects gas prices to increase further until more abundant sources are brought to market, with the marginal cost of these sources dictating future gas price “floors” and competitive fuel sources providing theoretical “ceilings”.
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, 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 assumption, most imports coming from liquefied natural gas and Canadian gas.
United States gas demand is approximately 65 bcf/day and growing. Current economic slowdown, demand side management, and efficiency programs have led to slight declines in demand, but HEAI feels that such declines related to the buy-side in the long term are economically unhealthy and unrealistic.
While natural gas consumption growth rates are expected to increase over the next twenty years by 50% as compared to current levels (most growth coming from electricity generation), the solution to providing the supply to mitigate that growth is not quite as transparent as just evaluating the face-value economics of alternative sources, whether it is from deeper United States Gulf Coast drilling, United States East and West Coastal exploration, Canadian production, Alaskan production, or liquefied natural gas (“LNG”) imports.
Reserves that contribute or can contribute to the United States natural gas supply stack are predominantly from the WCSB, Mackenzie Delta, Mid-continent and Gulf Coast, deep-water Gulf Coast, the Rockies, western coal-bed, Alaska and abroad in the form of LNG. Below is a table that exhibits the amount of proven natural gas in each region and its approximate percentage contribution to the natural gas supply stack (LNG and other sources, such as San Juan, Williston, and Permian Basins and East Canada are excluded at this time).
Brief History of the Alaskan Natural Gas Topic
Alaskan natural gas has been a market consideration for quite some time now, even during the construction of TAPS. What to do with the abundance of natural gas reserves that coincided with the massive oil recovery has been debated stridently. To date, almost all of the gas has been re-injected back into the oil wells. Heavier liquids have been stripped out of the gas and shipped down via TAPS to oil tankers in Valdez that carry such heavier particles mixed with crude oil to the United States West Coast market for refining and product sales. However, the stripping and shipping of the heavier liquids is limited to the amount of capacity available via TAPS (taking into consideration ambient temperatures, specific gravity and such).
Alaskan producers are injecting over 9 bcf/day of gas back into the reserves (albeit much of it is recycled gas already recovered coincidentally with oil in the past). This gas to date has been used to maintain compression and oil extracting levels (similar to the effect of an aerosol spray can). Generally speaking, the higher the gas pressure, the more efficient the oil extraction process, to a limit.
However, with natural gas making up the majority of volume component in many of the main oil reserves in the Alaskan North Slope concurrent with the growing United States natural gas needs, its extraction and release is becoming a more prevalent consideration.
In the early 1980’s, a variety of natural gas producers formed consortiums to explore these possibilities after the enactment of the Alaska Natural Gas Transportation Act (“ANGTA”). ANGTA was enacted in 1976 for the express purpose of providing an expedited procedural vehicle for governmental approval and construction of a transportation system to bring newly discovered Alaska natural gas supplies to the lower 48 states. At the time, the nation was in the throes of an energy shortage and existing gas supplies, as well as reserves, in the lower 48 states were expected to decline (much like the scenarios today) in the coming years. The Federal Power Commission (“FPC”, the precursor to the Federal Energy Regulatory Commission, or “FERC”) required hearings under the Natural Gas Act (“NGA”) prevailing under NGA Section 7. Congress decided to act as a result of the delays associated with competitive gas hearing processes. This action was a result of prior observations in the TAPS procedures, such as delays, roundabouts, and cost overruns. Canada’s National Energy Board (“NEB”) worked with the FPC in creating a joint policy.
Thus, ANGTA was enacted to provide a facile, direct method to make competitive offerings on gas projects from Alaska to the lower 48 states a reality, and would award such projects the necessary federal permits and rights-of-way. This Act was structured on the assumption that a single approved transportation system would be selected by the President of the United States, such as the Alaska-Canada (“ALCAN”) Highway project (to be discussed later), and ratified. Upon ratification, ANGTA would become law. Since the projected pipeline was to transverse Canada on its way to the lower 48 states, Canadian producers and transporters were entitled to certain benefits and assurances as well as the commensurate project cost allocations. FERC later issued certificates for a ‘pre-build’ for an Eastern and Western leg facilities, but due to the fact that ANGTA never legally disqualified other competing proposals for a multiple-line build scenario, much debate eventually followed as to cost-recovery on work-in-process and compulsory award rights.
The Alaska Natural Gas Transportation System (“ANGTS”) consortium (who proposed and researched the ALCAN project) has regularly maintained that federal agencies have an obligation to ensure the completion of the ANGTS project superceding any other project due to ANGTA language, the history of ANGTA and foreign policy implications of the Agreement.
One other main project consideration that competed in terms of viability and economics was the Trans-Alaska Gasline System (“TAGS”). This project was predominantly supported by a company called Yukon Pacific Corporation (“YPC”). Instead of delivering gas from Alaska to the lower 48 states via a large pipeline system like ANGTS, this project was to use the North Slope gas to create LNG to be shipped cryogenically to ports in Asia, including but not limited to Japan, Taiwan and Korea. These countries historically have consumed approximately 70% of the world’s LNG market (TAGS will also be discussed later).
Although this competing project has been evaluated for about 20 years and its sponsors have attained certain federal, state and local approvals and permits, no real progress had ever been made on the market viability of LNG. The economics of the entire project, while shown to have been cheaper from a cost perspective than the ANGTS route (ALCAN Highway route), has still yet to be proven when taking into consideration delivered prices.
Needless to say, with the 39 Tcf of proven reserves in the Prudhoe Bay region alone, and an expected 65 Tcf more along the Beaufort and Chukchi Sea shores, Alaska gas as a compelling and economic alternative as compared to other traditional sources of gas for the lower 48 states has yet to be shown. However, with gas price economics and forecasts ever increasing, all Alaska gas projects are becoming a more prevalent subject of considerable debate.
Major Proposed Projects & Routes to Market
There are many projects and sponsors that provide independent and consortium studies on the validity of Alaskan gas and its ability to be delivered to a viable market. Some projects have been active since the ANGTA era, some have been shelved, some are new, and some were formerly shelved but now are being dusted off. Some have already participated in the lower portion of the pre-build as referenced previously under ANGTA. Firms such as El Paso, Foothills (TransCanada), Williams, West Coast (Duke Energy), Marubeni, Phillips, BP Amoco, Chevron and others have valiantly brought about a resurgence in this topic, but each firm has their own internal estimations on the true validity of the project, what risk they are willing to bear, in what capacity they are willing to participate in such a project (transporter, marketer, producer, processor, etc.) and what time any project would come to market.
The great majority of Alaskan projects can be distilled into four major routes of consideration:
I. The ALCAN Highway Route
This route is proposed to bring between 3 and 6 bcf/day of natural gas from a gathering and processing station in the North Slope (Prudhoe Bay) down through a large pipeline that crosses mountainous terrain (as does TAPS) to the city of Fairbanks, where it will turn eastward and follow the Alaska-Canada Highway into the Yukon territories of Canada (where there are varying proposals to have it join with another pipeline from the Mackenzie Delta region), then flow southerly in Canada, where it can potentially connect into the Nova/AECO/TransCanada/Foothills pipeline system or a totally new build. This route is the choice endorsed under ANGTA, and has as recently been supported and lobbied by outgoing Alaskan Governor Tony Knowles. Although incoming Governor (and former United States Senator) Frank Murkowski has not committed to a specific route, it is believed that this route may also be a consideration of his office.
II. The TAGS Route
Sponsored by the Yukon Pacific Corporation, this route is proposed to deliver between 2 and 4 bcf/day of natural gas from a gathering and processing station in the North Slope (Prudhoe Bay) down through a large pipeline that crosses mountainous terrain, through the city of Fairbanks, and on to the City of Valdez or Nikiski. This route is to follow almost exactly the route of the TAPS. Unlike the ALCAN Highway route, the natural gas in converted into LNG utilizing liquefaction “trains” and other LNG-related on- and off-shore infrastructure. The LNG was originally planned for delivery into Japan, Taiwan, Korea or other Asian destination through a Presidential Decree, but ran somewhat contrary to the language of the resurgent ANGTA.
III. The Over-the-Top (“OTT”) Route
Sponsored by the Arctic Resources Commission (headed up by former Enron Oil & Gas Chief Executive Forrest Hoglund), this route is proposed to deliver between 2 and 4 bcf/day of natural gas from a gathering and processing station in the North Slope (Prudhoe Bay) to northern Canada (Yukon Territories) via a large artic sub-sea pipeline, then passing into the Mackenzie Delta (where it has also been considered to join with other proven Mackenzie Delta gas reserves owned by a plethora of producers aching to bring that gas to market) down into British Columbia or Alberta. This route, like the ALCAN Highway route can connect into the Nova/AECO/TransCanada/Foothills pipeline system, or a totally new build. The sub-sea portion of this pipeline is the subject of intense political, technical and economical scrutiny. Also, the fact that none of the natural gas explored gets sold into Alaska stands to be problematic and is vociferously challenged from a state perspective.
IV. The Y-Line Route
Simply put, this route is sponsored by several consortiums, but has many permutations. The major idea behind this route is its “hybrid” structure of the ALCAN Highway route and the TAGS route. That is, 3 to 6 bcf/day of natural gas from a gathering and processing station in the North Slope (Prudhoe Bay) down through a large pipeline that crosses mountainous terrain (as does TAPS) to the city of Fairbanks, where it will turn eastward and follow the Alaska-Canada Highway into the Yukon territories of Canada, then flow southerly in Canada, potentially connecting into the Nova/AECO/TransCanada/Foothills pipeline system, or a totally new build. However, there is a “fork” at the city of Fairbanks, where approximately half of the volume is planned to go to Valdez or Nikiski for liquefaction into LNG. Thus, this route can serve many more markets of varying types, but is much more capital intensive and complex.
Since the natural gas from Prudhoe Bay is inherently rich (or “wet”, “hot”, “heavy”), that is, it contains gas that is well over the 1050 btu/cf approximate United States heat content quality, it is very likely that this gas would have to be injected with inert gases or more likely “stripped” of its heavier elements. These heavier elements can in turn be marketed as liquids and serve as a revenue enhancement or a contra-expense to the project. The only case in which this is not necessarily true is when the gas is taken to the Asian markets in the form of LNG, where allowable heat content of natural gas is much higher.
Expected Costs of Each Route
HEAI has provided below some approximate costs of each of these routes, assuming different volumes that are relevant and sensible to each scenario, but a constant rate of return on infrastructure capital.
Within each cost is a detailed estimation of relevant figures, such as engineering costs, infrastructure costs (gas conditioning plants, pipelines, compressor stations, fractionation plants, and where applicable, LNG plants and LNG-related infrastructure (including shipping charges)), regulatory costs, ANGTA sunk costs (where applicable, and assumed not ‘written off’ as many of the former ANGTA consortium have plowed hundreds of millions of dollars into the feasibility studies and construction of initial phases and would proclaim recoverable under ANGTA provisions), operational costs, fractionation efficiencies and other related “soft” costs. * one spoke is gaseous gas to Canada, the other is LNG to Asia, thus the total cost range encompasses the differences.
** calculated total costs do NOT include pipeline capacity to US markets from Canada for ALCAN, OTT and Y-Line routes. If assuming US market delivery for such ANGTA portions, add approximately $0.60-$0.70/mmbtu for delivery to Midwest and Northeast markets.
Expected Market Prices and Issues at Market As stated previously, HEAI expects long term domestic gas prices to be approximately $3.50/mmbtu for Henry Hub per calendar year until 2010, and over $4.00/mmbtu thereafter. Assuming that basis prices in the Midwest and West Coast are flat to Henry Hub and about 60 basis points higher than Henry Hub in the Northeast in the long term, there is compelling evidence that any current Alaska pipeline scenario that delivers gas to the United States via a transcontinental pipeline would be marginal at best, from a pure economics perspective. Opinions would vary on this interim conclusion depending on what price forecast is assumed. In addition, assuming that Asian LNG prices continue to average approximately $4.00 - $4.50/mmbtu (based on the standard Japanese Crude Composite Index (“JCCI”) historical figures), the LNG scenarios are a bit more compelling at face value.
But the analysis cannot end there. Consideration must to be given to the fact that every scenario will result in a massive amount of natural gas volumes delivered to any market. Based on standard microeconomic supply-demand theory, an abundance of supply will bring down overall market prices until new a new market clearing price is established. This market clearing price can be substantially lower than the average price, making even the most optimal current scenario tenuous at best. Therefore, a cyclical argument will result in relation to project economics. That is, if the project looks marginally economical now when comparing costs to current price forecasts notwithstanding additional volume from Alaska, what will it look like when the project cost is compared to the new (and theoretically lower) market price once new Alaska volume is taken into consideration?
For example, HEAI believes that, assuming any such project were to come on line at earliest would be approximately the year 2008 (assuming that all infrastructure, construction, and regulatory approvals are attained in a logical and efficient timeframe, which is not an easy assumption), 4 bcf/day of volume can bring prices down in the long term approximately $0.10 - $0.20/mmbtu in the delivered markets. HEAI assumes that the gas will come in every year after 2008 at 1 bcf/day until full production capacity is reached. Although this downward price pressure will only exist until demand projections ‘catches up’ to the temporary oversupply, it is still compelling enough to discourage major energy firms from strongly participating in such a project, citing legitimate reasons of economics in the short- to medium term, making the whole project life economics unstable (again, depending on expected long-term market prices).
Notwithstanding varying long-term price views on natural gas, HEAI has maintained and continues to maintain that it would take federal, state and local easements to make these projects economically viable for the private sector. Although varying financing structures can somewhat improve its economics, good projects should not be done on clever financial structures (equity, debt, tax-free financing, etc.), but on the operational validity of a project on a stand-alone basis first and foremost.
HEAI believes that such easements would include things that look very much like a government subsidy, which again in microeconomic terms, will either put a “cap” on the market gas price (at a level that makes it economical for buyers) or a “floor” price for the producer and pipeline companies that undertake the project. This may be a federal energy policy mandate, guaranteed producer netback, tax relief package, combinations of all, or something equivalent.
Alaska gas can be a viable alternative, if there is sufficient government intervention, long-term price views above an economically viable level, or a combination of both. One certainty is that natural gas supply to the United States is not as abundant as it once was. Continued deep-water Gulf Coast and WCSB drilling has yielded fewer molecules of usable natural gas per dollar spent on capital infrastructure (diminishing marginal returns). Also, with the possibility of medium-term Canadian gas export curtailment for growing in-country needs, the time is high to seriously evaluate whether this Alaskan gas could be brought to market. If it is an inferior gas source to LNG or coal-bed methane alternatives on the national gas supply stack, then those sources must be prioritized.
Demand-side management and other forms of energy (such as wind, photovoltaic, hydro, nuclear, coal, etc. for power generation) are being considered. However, HEAI believes that long-term demand-side management reduces gross domestic product (“GDP”) and is unhealthy for long-term national economics, while technology associated with renewable forms of energy don’t quite measure up in terms of cost, or is still relatively unproven. HEAI further believes that additional coal and nuclear energy sources can make sense economically, but once environmental considerations, political blowback and regulatory measures are added in to the scenario, mixed feelings reign.
Alaska gas is one alternative for the natural gas needs of the United States, but clear, accurate analysis must be performed on it in combination with an intense evaluation of other viable sources. Then, a more meaningful domestic natural gas supply stack hierarchy can be formed.