In September 2013 - and in close coordination with the Governor of Louisiana - Shell (NYSE:RDS.A) (NYSE:RDS.B) announced its intent to potentially develop a world-scale Gas-To-Liquids (GTL) facility, to be located near Baton Rouge. Shell committed to spending at least $12.5B on the project, and the State of Louisiana committed to providing a supporting incentive package for the project, including a $112M grant.
Just ten weeks later, Shell issued a press release on December 5th stating it will not pursue the Louisiana GTL project at this time. Why did Shell make such a quick position change? What were the real reasons behind Shell's decision? Should Shell's decision be interpreted as a bellwether for GTL in the United States? What figures should be used to characterize Shell's proposed (and now halted) project in Louisiana?
It appears that Shell's decision was not so much based on concerns regarding forecasted price spreads between crude oil and natural gas, but was based primarily on its internal capital allocation needs, corporate portfolio considerations and shareholder concern about cash flow. I disagree with those who interpret Shell's statements to imply that GTL in the United States is not attractive. Apparently, it is not attractive to Shell but in my opinion GTL in the United States remains an attractive investment. My conclusion reflects analyses of commodity price forecasts and the price spread that drives GTL feasibility, as well as analyses of Royal Dutch Shell, both of which are discussed below. But before we get into those details, let's take a careful look at some key elements in Shell's December 5th Press release.
Understanding what Shell said, and what Shell did not say
In its December 5th press release Shell said "GTL is not a viable option for Shell in North America, at this time, due to the likely development cost of such a project, uncertainties on long-term oil and gas prices and differentials, and Shell's strict capital discipline." In the release CEO Peter Voser was quoted saying "We are making tough choices here, focusing our efforts and capital on the most attractive opportunities in our world-wide portfolio to add value for shareholders."
These two quotes tell us: 1) Shell did not cancel the project per se, but decided to not pursue a GTL plant in North America at this time. This implies that Shell will continue to consider GTL options in North America (and, presumably, elsewhere worldwide), particularly since Shell's Pearl GTL plant in Qatar contributes significantly to the company's profits. 2) Given the high CAPEX of a world-scale GTL facility, Shell must prioritize this capital investment vis-à-vis its full set of investment priorities and options and corporate strategies. As discussed further below, I believe that Shell had no choice but to direct its limited capital towards projects that better enhance its upstream position.
The third point from the December press release: Shell's CEO acknowledged that the decision was a tough choice, and the decision indicated that Shell currently needs to be pursuing other strategic options with relatively higher consequences for shareholder value. It is important to recognize that Mr. Voser will be retiring in 2014, and that his stated greatest regret during his tenure was the huge bet on U.S. shale gas that soured and led to a $2B-plus write-down. This strategic blunder may have left Shell more exposed to potentially higher-cost feedstock for Shell's proposed GTL plant in Louisiana, and undoubtedly affects its decisions on capital allocations looking forward.
The fourth point from the December press release: Shell stated that uncertainties on long-term oil and gas prices and differentials were a part of their decision to not pursue the Louisiana GTL project at this time, thereby implying that such uncertainties constitute unacceptable risk (at least from Shell's perspective). I do not agree with the implication that forecasted price differentials reflect unacceptably high risk for commercial-scale GTL facilities located within the U.S. As discussed below, the economics of GTL - essentially an arbitrage play between crude prices and natural gas prices - are truly compelling for commercial-scale facilities located in the Lower Forty Eight.
In response to Shell's announcement of halting the Louisiana GTL project, the following day Sasol Limited (NYSE:SSL) was quoted as saying, "While we cannot speak to another company's plans, we continue to view our proposed GTL facility in Louisiana as a very attractive opportunity as we advance it through the front-end engineering and design phase." Sasol is proceeding with its plans to develop a 96,000 bpd GTL facility at its Westlake complex, building on the successes of its GTL plants in Qatar and South Africa.
Sasol's bullish perspective on future oil and gas prices and the GTL arbitrage opportunity were quantified last year when David Constable, the company's CEO, noted that the price ratio of crude oil (in $/bbl) to natural gas (in $/MMBtu) needs to be at least 16 to 1. This statement indicates that Sasol's minimum ratio for financial attractiveness is 16:1, which also implies that the breakeven price ratio of crude:gas would be even lower.
To put that ratio into perspective: The Energy Information Administration (EIA) expects average 2014 prices for crude oil (Brent) and natural gas (NYMEX) to be $104 per barrel and $3.78 per MMBtu, respectively. This constitutes a price ratio of 27.5 to 1, which is 72% higher than the 16:1 minimum needed by Sasol to achieve financial attractiveness. More about this later.
What were the estimated capacity and estimated CAPEX for Shell's GTL facility in Louisiana?
Statements attributed to Shell have noted that the estimated CAPEX of the proposed GTL facility in Louisiana is $20B. Shell, however, has never given a CAPEX number for the facility in any formal media release. Moreover, little specific information has been provided by Shell as to the design capacity of the Louisiana facility, which means that unit CAPEX figures set forth in the various articles that have discussed Shell's proposed GTL plant in Louisiana are purely speculative. If we use the GTL industry's rule-of-thumb unit CAPEX figure of $100,000 per daily barrel of production, then this would indicate that the Louisiana plant would produce roughly 200,000 bpd for a $20B investment. Shell says the plant would have had a 140,000 barrel per day capacity. This indicates that there must have been more to the facility than just the GTL plant and probably included at least an ethane cracker. Shell's Pearl facility in Qatar produces 140,000 bpd of GTL liquid fuels plus 120,000 bpd of NGLs/ethane/other. We would not expect the plant to separate liquids from natural gas as there is more than sufficient gas plant capacity in Louisiana. Thus, this and all other articles that discuss unit CAPEX for Shell's Louisiana GTL plant are purely speculative, since the precise configuration of the plant has not been made available.
Projected prices for oil and gas and the spread risk
I have followed Fischer-Tropsch (FT) and gas to liquids (GTL) technologies off and on for close to a decade and Shell's announcement that it was not going forward with a project it announced less than 3 months ago raised two questions. Are GTL economic risks acceptable (i.e., is the projected price spread sufficient for profitability of a project?), or was this decision specific to Shell and to this proposed project?
Our analysis indicates that Sasol's 16:1 ratio for profitability is reasonable. To further understand this price ratio we looked at the last 6 years of oil and natural gas prices, which included the aberrations of the Great Recession in 2008. Figure 1 shows the average monthly spot price of West Texas Intermediate crude oil at Cushing, Oklahoma. We see the price spike in 2008, which contributed to the severity of the recession, and we see the recession-induced price collapse that followed.
Figure 2 shows the monthly average spot price for natural gas at the Henry Hub in Louisiana. When the gas price spiked in 2008, the volume of gas in storage was below the five-year average, and oil and gas prices were still linked by electric utilities and industrial users that would switch at times between natural gas and fuel oil. That link has vanished and the use of petroleum by utilities is negligible. In 2008, low summer levels of gas in storage and the link to oil prices saw natural gas prices peak as oil set its historic high in July of that year.
In the summer of 2008, natural gas storage levels were below the 5-year average, as shown in Figure 3. The red line shows the difference between gas in storage and the 5-year average for the same week. Prices may not be as sensitive to this measure as in the past because the current high levels of gas production (especially in the Marcellus shale) mitigate the need for some of the winter storage.
Figure 4 shows the ratio of WTI spot prices to natural gas and compares it to the 16:1 Sasol baseline. From 2008 to present the ratio averaged 22:1, and when natural gas prices collapsed to $2 in early 2012 it passed 50:1. For comparison purposes, we have also included the line reflecting Sasol's 16:1 ratio of acceptability.
However, the use of WTI understates the Crude:Gas ratio for two reasons. GTL plants make liquid fuel products which are almost identical to (and in some cases superior to) petroleum-derived liquid fuels, meaning that GTL products should command prices at (or above) petroleum-derived liquid fuels' prices. Liquid fuels' prices correlate better with Brent than WTI because high stocks at Cushing have depressed WTI prices, causing WTI to trade below world markets (Brent) for the last several years - refer to Figure 5.
When we recalculate the oil to gas price ratio using Brent, the average ratio increases from 22:1 to over 24:1. Figure 6 depicts the Crude:Gas ratios using both WTI and Brent.
Factors that can impact future Oil and Gas Prices
Acceptable financial performance of a GTL project is obviously dependent upon the spread between oil and natural gas price. The recent success of oil drilling in shale and other tight formations in the U.S. has led to numerous speculations that OPEC would lose its power over oil prices, leading to a price collapse worldwide. Recently we have seen some articles using the following two graphs of U.S. imports to support views of the impending demise of OPEC. Figure 7 shows net product imports; since that number is now indicating net exports of nearly 2 million barrels per day, some conclude that OPEC must be in trouble.
Figure 7: Net Product Imports, Source: EIA
A better measure for looking at imports versus exports is net imports of crude and petroleum products - refer to Figure 8. While the U.S. is certainly importing less at this time, it still imports 5 million barrels per day.
Figure 8: Net Crude Oil & Product Imports, Source: EIA
Of course a graph of recent U.S. oil production might lead to similar conclusions - refer to Figure 9. At the current rate of growth the U.S. will set an historical high level of production passing the 1970 peak sometime in 2015.
However, the critical factors missing from those arguments are: projected increases in global consumption (particularly in Asia), and anticipated decreased production in the U.S. after 2019. Figures 10 and 11 show the latest projections for petroleum consumption in China and India. Note that the EIA's 2014 Early Release shows higher growth rates in this reference or base case in both China and India than in EIA's 2013 reference case.
OPEC's market share of global crude production is currently just over 40%. As shown in Figure 12, EIA's 2014 Early Release forecast shows only a modest short-term drop in OPEC's market share to 39.7% in 2015, but rebounding to 45.5% by 2040.
With OPEC producing over 40% of the world's crude oil it is absurd to believe it cannot establish a floor on global oil prices. One could argue that with only 2.2 million b/d of spare capacity it is limited in how low it could drive prices, but with over 30 million b/d of production a substantial cut could easily send prices to historic highs.
One of the things seldom mentioned in discussions of ever-increasing U.S. production is price. If prices were to collapse then drilling activity in most of the unconventional plays would drop below levels necessary to maintain current output, let alone production growth. Data from the EIA's new drilling productivity report indicates that 75% of the current level of drilling activity in the Bakken in North Dakota and the Eagle Ford in south Texas is necessary just to maintain current production levels and that incremental growth comes from the remaining 25% of the rigs. (Refer to Figures 13, 14, 15, and 16.) If oil prices fell to a level that would make GTL economics fall below Sasol's 16:1 profitability ratio, U.S. oil production growth would come to a halt, thereby removing any threat to OPEC, and setting the stage for price rebounds.
Figure 13: Bakken Oil Production, Source: EIA Drilling Productivity Report
From an OPEC perspective, if prices drop much below the current level most OPEC countries would face a budget deficit leading to undesirable fiscal pressures and potential social instability. According to a recent study by APICORP, most OPEC nations need prices over $100 per barrel to meet their fiscal needs and balance their budget. Even Saudi Arabia requires over $90 per barrel. Thus, OPEC is incentivized to take steps to maintain current or higher oil prices. Note in Figure 17 the lag between the price collapse in the second half of 2008 and OPEC's response with lower production. OPEC would face a similar problem cutting production today as it would require lowering the total and reapportioning the percentage share of each country.
Figure 17: OPEC Production and Oil Price, Source: EIA, WTRG Economics
While it might take OPEC a while to react if prices fall significantly below $90 (as OPEC did in 2008 and on several other occasions), we expect OPEC would eventually cut production sufficiently to support prices between $90 and $100 per barrel. As shown in Figure 18 for most of the last two decades OPEC has been able to maintain a market between 40% and 45%.
Other possible increases to global supplies and impact on global prices: A halt to the internal strife in Libya could put an additional 1.3 million barrels per day on the market. Complete lifting of Iranian sanctions would add 600,000 b/d in the short term and over a million b/d over the next two years. If this happens it may become necessary for OPEC to reestablish a member quota system at a lower level of production. History shows it may take more than one meeting to arrive at individual country quotas, but it also indicates it is a near certainty that they will eventually be able to support prices. With 42% of the oil market, it is difficult to see OPEC as powerless. As shown in Figure 12 above, the EIA's most recent forecast expects OPEC's share of the global market will increase over the long term.
Based on the above, we can reasonably conclude that prices of crude oil and petroleum-derived products are not likely to decrease significantly in the foreseeable future. Further, if prices were to drop below $90 per barrel, then it is likely that two things will occur that will bring prices back up and limit the duration of the low-price periods: 1) OPEC will take steps to maintain high prices; and 2) drilling rigs in the U.S. will be taken offline until supplies drop and prices rebound, at which point they will be brought back into production.
Natural Gas Prices
Gas prices in December 2013 have been in the range of $3.83 - $4.51, reflecting the seasonal price bump and colder than normal weather. In early December, the EIA estimated that the cost of natural gas in the U.S. (Henry Hub) for the calendar year 2013 would average $3.69/MMBtu.
While many of the dry gas plays are not attractive to most producers at current prices, the wet gas and oil plays are generally profitable at current prices. These wet gas plays have been the source of most of the production growth in 2013. As shown in Figure 19, production of gas in the Marcellus has increased by about 700% in the past 4 years. Similarly, production of gas in the Eagle Ford has increased by over 300% in the past 4 years (refer to Figure 20).
Figure 20: Eagle Ford Gas Production, Source: EIA Drilling Productivity Report
Many natural gas plays require higher prices to justify drilling for more gas. These plays tend to have dryer gas or deeper formations or both. It is these dry gas formations that establish a cap on natural gas prices. The Haynesville Shale serves as an example. As prices fell in the last two years so did drilling in the Haynesville. See Figure 21.
Figure 21: Haynesville Drilling Activity, Source: Baker Hughes
As a consequence of the lower drilling activity Haynesville production shown in Figure 22 fell from a peak of 10.5 Bcf per day in 2011 to near 6 Bcf / day in 2013. It is important to emphasize that the lack of drilling and declining production in this play is due to the price of gas and not the lack of gas in this formation. At higher prices drilling in the area will again increase and production gains should follow. A similar argument can be made for the dry gas side of the Eagle Ford formation and other dry gas formations.
Since there is a lot of gas not currently targeted that can be produced in the $4.50 to $6.00 range, if prices rise to that range the additional gas from plays not currently profitable should raise supply enough to cap prices below $6.00.
The Haynesville may have played a role in Shell's decision to not proceed with the Louisiana GTL plant as they do have production in that play which could be used as feedstock for a GTL plant.
Based on the above, we can reasonably conclude that prices of natural gas are unlikely to rise significantly in the foreseeable future as prices much above $5.00 will add enough production to prevent them from rising further. We see this view confirmed in the EIA's most recent forecast.
Crude : Gas price ratios
Building on the data presented in Figure 6, Figures 23 and 24 show the most recent EIA long-term forecast of oil (Brent) and gas (Henry Hub) prices, respectively. The following are from the 2014 Early Release base or reference case of the EIA's Annual Energy Outlook.
Figure 25 shows the forecasted Crude:Gas price ratio, based on the two foregoing pricing projections from EIA. Note that the average Brent:Henry Hub price ratio for the period 2013-2040 is projected to average 20.8:1, whereas the average WTI:Henry Hub ratio is projected to average 20.2:1.
Based on the above, we can reasonably conclude that the projected price spreads between oil and gas are likely to continue, and that the risk of this price ratio dropping is low. Using Sasol's 16:1 ratio as an indicator of acceptable financial performance, we can reasonably conclude that commercial-scale GTL projects in the U.S. will be well-positioned to take advantage of this price spread.
What are Shell's capital expenditure priorities?
In addition to the indefinite postponement of the Louisiana GTL plant, recent actions by Shell may shed further light on their capital expenditure priorities. We will just provide a few examples as Shell's acquisitions and divestitures are well covered by a bevy of analysts.
Shell's Jackpine Project, which will produce 100,000 b/d from Canadian oil sands, just received approval from the Canadian Government. Shell announced it has completed the acquisition of an additional 23% interest in the Parque das Conchas (BC-10) project offshore Brazil for US $1 billion and the Mars B in Gulf of Mexico scheduled to come online in 2014. All of these projects will add to oil reserves and production. Even the Prelude floating liquid natural gas (FLNG) facility should add to reserves as it provides the mechanism to bring previously stranded gas to market.
There is news that Shell is canceling a £8.3bn refinery and petrochemical project in China with China National Petroleum Corp (CNPC) and Qatar Petroleum, but the reasons are not clear.
Shell's share in Woodside, an Australian oil and gas company, valued at close to $7 billion is apparently up for sale. Arrow Queensland coal-seam gas assets are considered candidates for sale by Shell and the Geelong refinery in Victoria is on the market.
There seems to be a bias toward projects that can add to reserves, and this would make sense, since Shell's upstream portfolio is weak compared to other majors. Shell has been under pressure for its large capital budget and weaker cash flow in the last quarters. In response it has been postponing projects and selling non-core assets.
While GTL in North America apparently does not seem to fit in Shell's current plans, we think GTL in the United States provides attractive margins over the long term. Shell probably sees itself as better served by investing in oil reserves and production as its current production is far below the needs of its less profitable refining sector. Most of the other majors are weighted heavier than Shell to upstream production.
My conclusion is that despite Shell's decision not to go forward at this time, GTL has a very acceptable level of risk from the perspective of forecasted crude oil and natural gas prices in the United States. Given the potential arbitrage opportunities between oil and gas (as evidenced by EIA's 2014 Early Release forecasts) I anticipate that Sasol's Louisiana GTL project will not be the only large-scale GTL plant developed in the U.S. within the next few years.
Disclosure: I have no positions in any stocks mentioned, and no plans to initiate any positions within the next 72 hours. I wrote this article myself, and it expresses my own opinions. I am not receiving compensation for it (other than from Seeking Alpha). I have no business relationship with any company whose stock is mentioned in this article.