The Massif Capital Review volume 1, No. 1 for the month of January-February 2017, titled, “LNG.”
Investors are regularly confronted with a challenge when evaluating growth. It is frequently difficult to differentiate between growth that creates value and growth that destroys value. Although conceptually straightforward, any growth that occurs in which the cost of capital exceeds the return on the capital expended to achieve the growth is value destructive, the idea that growth is not always a positive often befuddles investors. When combined with the tendency of the investing community to drift from one growth driven infatuation to another, the fact that markets swing like a pendulum from overzealous buying to despondent selling is unsurprising.
The value of growth is even harder to evaluate when projects have extended timelines, which delays corporate feedback on profitability, increasing management reliance on forecasts. The commodity super cycle from the mid-2000s to 2012-2013 is a clear demonstration of the many issues with a growth at any cost mindset. Chinese-led demand growth for iron ore, coal, zinc, and numerous other industrial commodities resulted in a significant increase in mining profitability. Return on capital employed within the industry rose from around 7.5% at the turn of the century to a 35% in 2005 and remained high throughout much of the decade including in the wake of the financial crisis.
The understandable response by mining management was overconfidence; an assumption that good results were a because of their managerial skill rather than a consequence of uniquely favorable industry conditions. Capital allocation decisions were driven by overly optimistic demand forecasts anchored to recent experience with Chinese demand, and decisions were tainted by what Daniel Kahneman referred to as the inside view, which is when individuals in a group focus on “specific circumstances and search for evidence in their own experiences.” The reflexivity of markets is lost on those taking an inside view.
The result of these corporate actions: projects started, and capital investments made, that would not be operating (providing feedback to the company) until the operating environment changed. The outcome of these decisions well captured by figure one. ROCE for mining firms was high, investment ramped up, the cycle turned and profits dipped. The life of mines is long, so determining whether or not the dollars invested by management from 2005 to 2013 will yield more than a dollar in the marketplace (a core test for any business) over the next decade will not be known for some time, but the failure of management to take into account the industries changing asset base (an outward shift in the supply curve) and put a check on capital expenditures is surely responsible for much of the pain they have experienced over the last three to four years.
Timelines and capital expenses in the Liquid Natural Gas (LNG) industry are similar to the mining sector; and like the mining sector between 2005 to 2013, the LNG industry has also experienced a boom in investment. In Australia, the LNG industry in the last decade have started or is constructing a total of 9 LNG terminals, with an output capacity of 24% of 2015 global liquefaction capacity, the total cost of which is expected to be $152 billion, or roughly $50 billion more than initially budgeted. The cost overruns are likely to extend the payback periods for projects many years, if not decades.
Meanwhile, throughout the rest of the world, roughly 88 million tons per annum (mtpa) of liquefaction capacity (excluding the 75 mtpa discussed above) is being constructed and expected to come online over the next four years. In total, the projects above will boost global liquefaction capacity by 53%. Since 2011 demand has grown 10% but much of that growth (about 20%) comes from Japan as a result of that countries decision to shut down its fleet of Nuclear reactors following the 2011 Fukushima disaster. In the last two years, Japanese LNG demand has shrunk as nuclear reactors have started to come back online, to date 3 of 54 reactors has restarted with 23 reactors progressing towards restart. The impact on Japanese demand from restarting those reactors is unclear, but unlikely to be positive.
Compounding the problems associated with the global boom in LNG investment has been the rising capital expenditures related to the construction of a ton per annum of liquefaction capacity. In 2003 it cost roughly $300 to construct a ton per annum of liquefaction capacity, the cost is now $1,200 per ton per annum, a fourfold increase. The increase in LNG construction costs, according to the IHS CERA Upstream Capital Costs Index, is roughly double the cost increase associated with other upstream oil and natural gas facilities. Although all the firms in the space will see absolute growth in revenue, the costs related to achieving that growth have increased at rates which will make it difficult to earn a return on.
The ROIC for new LNG projects remains to be seen, but at the current time, the slump in oil prices appears to have significantly dented the potential of most, if not all new projects. LNG pricing remains highly regional with different pricing dynamics, but regardless LNG prices have suffered a downward trend globally over the last few years. LNG out of the US is tied to Henry Hub Natural Gas prices, and as such has been forecasted for many years to be a cheap source of LNG for Asia, where LNG prices have historically been tied to oil prices. Since 2014 the oil-indexed LNG contracts have seen significant price depreciation, and some grumbling by buyers who have long-term contracts that did not respond to the drop in the price of oil as much as may have hope for.
In recent months spot prices for LNG have fallen as low at $5.14/MMBtu in Europe and $6/MMBtu in Asia. Most projects are unlikely to recoup invested capital at those rates let alone turn a healthy profit. In the United States, most final investment decisions were made by management when Japanese LNG prices were north of $12/MMBtu, in 2012 prices peaked at $18.07/MMbtu. According to the Japanese Ministry of Economy, Trade, and Industry, in February of this year, the average price for spot based LNG imported into the country was $8.5/MMbtu. One is hesitant to forecast this trend continuing, but the continuation seems as likely as the reversal, which is the crux of the issue.
Management for many oil and natural gas companies spent billions of shareholder’s dollars on projects with dubious ROIC profiles except in very well defined circumstances. The question now becomes can the winners be separated from the losers, or is the whole category to be written off until the market digests the growth and the pendulum swings from exuberance to despondency?
Golar LNG (GLNG): Midstream Giant or Pipedream?
Golar LNG is one of Wall Street’s favorite LNG plays and what’s not to love: the share count has grown at a CAGR of 6% a year, free cash flow has averaged (-$338) million a year for the last decade and the Altman Z-score (a measure of potential bankruptcy risk) has been signaling distress for all but two of the last twenty years. Despite the distressing financials, of the 17 sell-side analysts that cover the company, 15 rank it a Strong Buy or a Buy. So what are we missing? The potential future growth, of course. More specifically the potential growth arising from an untested Floating Liquid Natural Gas (FLNG) technology.
The current story told about Golar LNG is that it is an industry disrupter, a company transitioning from a core competency of LNG shipping to one of liquefaction, shipping, and regasification. Golar looks to facilitate the development of stranded offshore natural gas finds with floating liquefied natural gas ships (FLNG), ship LNG via the firm’s tanker fleet, and simplify the consumption of LNG by renting Floating Storage and Regasification Ships (FSRU). The result of this ambitious plan is an LNG midstream player with its hands on every aspect of the LNG value chain. The firm also has an MLP so that it can drop down the long-term assets for quick monetization, debt shifting, and risk transfer.
Like much in the world of LNG, the primary question is: do the numbers support the narrative? Moreover, if so, is their margin of safety to compensate for the risk? This year will likely go a long way in answering those questions for intrepid Golar investors as the company is set to deliver its first FLNG ship, the Hilli. The Hilli is the first of three potential FLNG ships Golar has planned, all built on the hulls of 1970s era LNG tankers.
The Hilli is currently on track for delivery to the Sanaga gas field off the coast of Cameroon in West Africa in the third quarter of this year. If delivered on time, and commissioned successfully, Hilli will be the world’s second operating FLNG (the Satu, operated by Petronas in Malaysia, was the world’s first) and the first example of an LNG tanker to FLNG conversion. The Sanaga gas field project is a joint field development by Perenco (an independent Anglo-French oil and gas company) and SNH (the Cameroon National Oil Company).
The impact of the delivery on Golar’s finances will be significant, resulting in a reported minimum boost to EBITDA of $170 million a year for eight years (with potential upside tied to oil prices), as well as a cash release from Golar’s significant restricted cash reserves. Although the narrative is appealing, the numbers seem to tell a different story.
The Hilli contract is 8-years long and will generate a forecasted EBITDA on a per year basis of $170 million to $300 million and the total expected conversion cost of the tanker to an FLNG is $1.3 billion. Generously assuming that the forecasted EBITDA is equal to FCF generated from the project, and a 10% discount rate, the Hilli has a net present value, on per share basis, of (-$3.54) to $2.70. Golar certainly hopes to get more than one contract out of the Hilli, but at the low end of the EBITDA range, the Hilli does not break even until its 16th year of operation when the NPV is $27.3 million, at which point the hull will be 58 years old.
Furthermore, achieving the high end of the potential EBITDA estimate generated from the project requires oil to trade at or around $100 a barrel; any upside to the minimum EBITDA of $170 requires oil to sell at more than $60 a barrel. At the current time, Golar needs oil to rally at least 20% before the firms can earn more than the $170 EBITDA minimum. This simple, but bleak, valuation does not take into account either interest or taxes, maintenance capital expenditures or the complex financing, sale, and leaseback agreement that GLNG has with CSSC Shipping for the Hilli. The long and short of it is that even in the scenario EBITDA equals free cash flow, Hilli is unlikely to have a significantly positive cash flow return on invested capital or positive net present value.
Golar has two further FLNG projects in the works: the FLNG Fortuna project, in partnership with Schlumberger and Ophir for the development of the Block R natural gas field offshore Equatorial Guinea, and a yet to be contracted LNG Tanker to FLNG conversion of the Golar Gimi. FLNG Fortuna looks likely to move forward but has not received a final investment decision, although one is expected in the first half of 2017.
The Fortuna project has a twenty-year life with a projected pre-debt servicing cash flow of $560 million a year (assuming LNG produced is sold for $6/mmbtu, which is a very modest assumption), and upfront capital expenditures of $2 billion. At a 10% discount, this yields a project NPV of $2,516 million of which $849 million accrues to Golar LNG via its stake in the project. A pre-tax, pre-debt value per share of $8.41, but with potential upside due to the conservative LNG pricing assumption.
Under the assumption that Golar finds a contract for the Gimi with a tolling structure similar to the Hilli contract, the Gimi likely has a per share value of $3.55 to $8.63. This NPV is based on the assumption that the 3rd LNG Tanker to FLNG conversion benefits from lessons learned from the first two conversions, reducing the upfront cost to $1.1 billion, a range of EBITDA outcomes $50 million better than Hilli ($220 million to $350 million), and a 20-year contract the. In total, the FLNG operations have potential value to shareholders of $8.42 per share to $19.74 a share, on a pre-debt and pre-tax basis.
Golar also has an LNG Shipping business. The firm’s current fleet is comprised of 16 LNG tankers, 13 of which were ordered after 2011. If the 13 new tankers fetch a market price 25% greater than the amount received for a 2005 build tanker that Golar sold in 2015, the estimated Net Asset Value of Golar’s LNG shipping fleet (proposed market value less associated debt) is $11.53 a share. Golar is also engaged in a JV with Stone Peak Private Equity related to the FSRU business, that is worth approximately $2.62 a share, a value based on the pledged commitment of Stone Peak to the project. Finally, the firm’s investment and General Partner stake in Golar LNG Limited Partners (the previously mentioned MLP), is likely worth, at market value and assuming 10x multiple on the general partner stake, around $5.50 a share. There is an additional (-$0.41) a share in net debt excluding restricted cash, and $2.09 in restricted cash.
This sum of parts analysis yields a valuation range of $29.75 to $41.07 a share vs. a current stock price of $28.06 (a margin of safety between 6% and 32%). The high end the valuation seems generous given the approach taken to valuation of the speculative FLNG projects but does potentially undervalue Golar’s FSRU business and a potential return of LNG Tanker day rates to the more favorable spot rates earned in the 2011 to 2013 period (more than 2x the current rates).
In regards to shipping, over the course of the next two years 86 new LNG tankers are expected to be delivered. Based on new liquefaction capacity projected to come online over the next two years, there is likely demand for about 74 ships. In the near term, the market appears oversupplied. Between now and 2020, there is likely demand for a total of 120 new ships again based on expected new LNG liquefaction capacity, but the order book is for 115 ships. In that situation, the market appears slightly tight, but not in a terribly significant way, especially given that new liquefaction capacity does not necessarily mean new ships are needed.
Complicating Golar’s position is the firm’s significant exposure to spot rates for shipping, with more than 30% of its fleet exposed to market rates. Most LNG shippers have fleets that are tied to specific long-term contracts between LNG suppliers and buyers. Nevertheless, Golar has moved so far beyond being an LNG shipping company, that it is unclear what impact, good or bad, returns from the shipping segment will have on the investing communities’ views of the company going forward.
Wall Street sell-side analysts seem to be in agreement that Golar LNG is a buy, with an average target price of $34. Even though this is within the valuation range calculated above, it seems to leave little room for missteps, nor much in the way of upside given the risks. With at least 30% of the company’s value coming from untested, and in two of the three cases unbuilt FLNG projects, the potential for unforeseen events to derail this speculative growth story appear significant.
A Brief Review of The Early LNG Industry
The process by which gasses could be liquefied was first discovered by Michael Faraday (1791- 1867) in the early 1820’s. Faraday was not able to liquefy methane at the time but did succeed at liquefying several other gasses such as chlorine and carbon dioxide via the application of pressure. It was not until 1878 that French physicist Louis Paul Cailletet was able to liquefy methane. Seventeen years later Carl von Linde (1842-1934) built the first liquefaction facility but was unable to figure out a method for liquefied gas storage. It took a further 20 years before Godfrey Cabot, founder of the Cabot Corporation, solved the storage puzzle.
Finally, 1937 Howell C. Cooper, President of the Hope Natural Gas Company, a former subsidiary of Standard Oil, combined the discoveries to create the first Liquefaction facility, at the time capable of liquefying 400,000 cubic feet a day of natural gas. Although the plant never went into commercial production, it served as the model for a plant built in 1940 by the East Ohio Gas company (another former Standard Oil subsidiary). The East Ohio LNG facility was the world’s first commercial LNG operation.
The plant operated successfully for three years but was closed down after a cylindrical storage tank ruptured on October 20, 1944, spilling thousands of gallons of LNG over the plant and nearby neighborhood. The resulting fire caused multiple casualties.
Following the East Ohio accident, US LNG industry went dormant until 1951 when the Union Stockyard Company of Chicago went in search of a cheaper source of gas to meet its power needs. Continental Oil (now Conoco Phillips) was hired to advise on the potential of building a liquefaction facility and transporting LNG up the Mississippi to Chicago. The project proved uneconomical, but Continental Oil believed that trans-oceanic shipments to the UK were feasible. The Union Stockyard and Continental created a JV called the Constock Liquid Methane Corporation that in 1957 struck a deal with the British Gas Council to liquefy gas at a Lake Charles facility and transport it Canvey Island in the UK.
The first trans-ocean shipment of LNG, totaling 5,000 cubic meters of LNG, left Lake Charles Louisiana in January 1959 onboard the Methane Pioneer, a converted world war two Liberty Freighter. The Methane Pioneer made a total of 8 trips before being retired in march of 1960. Though short lived, proof of concept had been achieved, and in 1960 Constock Liquid Methane Corporation was reconstituted as Conch International Methane Limited, now with Shell as a 40% partner, to develop LNG in Algeria.
In 1964 Conch opened the first Algerian LNG facility. The facility was capable of producing 1.1 mtpa. At the time the facility cost $89 million, or approximately $695 million today. For comparison, a modern liquefaction train usually produces 2+ mtpa, Cheniere’s liquefaction trains each produce 4.5 mtpa, the largest produce 8+. The average cost to build a ton per annum of liquefaction capacity in 2014 was $1,200. In current dollars, the Algerian facility cost $4,930 per ton per annum of liquefaction capacity to build. The first cargo was 76 cents/MMBtu delivered or $5.94 today, well below the cost of LNG on an MMBtu basis anywhere in the world today. Delivery accounted for $0.23 of the $0.76, today shipping from Algeria to the UK costs approximately $0.30.
The world’s second liquefaction faculty was built in 1969 in Kenai, Alaska and was capable of producing 1.3 mtpa; the facility was significantly more expensive than the Algerian plant, with a total cost of $200 million. During the 1970’s LNG capacity (both liquefaction and regasification) grew considerably with seven further facilities capable of producing 30 mtpa being built. Even in the early days Japan was the largest LNG consumer, anchoring and financing several of the 1970s facilities. Australia constructed that countries first liquefaction train in the 1980s.
By 1989, 25 years after the first commercial LNG shipment, there were still only eight liquefaction complexes worldwide. Since then 17 further liquefaction facilities have been built. Output capacity has grown considerably, from 52 mtpa in 1989 to 308.5 mtpa today, with the vast majority, 65%, constructed since 2000. In 1989 roughly 7.6% of global liquefaction capacity went unutilized, today underutilized liquefaction capacity as a percentage of the global capacity has grown to 13.7%.
Cheniere: The Newst Major LNG Player
It is impossible to talk about LNG without talking about Cheniere, as controversial a company as many widely touted hedge fund holdings. Not only is short seller Jim Chanos of Kynikos publicly short Cheniere, but legendary investor Seth Klarman is long the stock. The opposing positions are in fact what initially attracted our attention. How can two such thoughtful investors make such divergent calls on what should be a frankly straightforward valuation of a business that generates cash flows based on 20-year fixed price contracts?
The Cheniere Story
The Cheniere story started in 1996 with Charif Souki; an investment banker turned Los Angles based restaurateur, who started the company to bring the internet revolution to the exploration for oil and natural gas. After the internet bubble burst, Mr. Souki pivoted from E&P to an ambitious plan to build four LNG import terminals at the cost of $300 million apiece. By 2004, Mr. Souki had raised sufficient capital to move the project forward and signed Total and Chevron to 20-year import agreements at the proposed Sabine Pass LNG Import Terminal.
Mr. Souki and Cheniere delivered the project on time and budget but were soon dealt a blow by the surge of domestic natural gas resulting from the spread of fracking (to date the import terminals have never been used). When Mr. Souki started Cheniere, the US was running out of natural gas, by the time the facility was operating, the US was on the verge of being swamped with cheap natural gas.
In 2010, as a result of the growing domestic glut of natural gas, the Cheniere strategy pivoted, and the firm applied to the Department of Energy for a permit to export LNG. The DOE approved Cheniere’s application in early 2011, and by the end of the year Mr. Souki had signed an $8 billion take or pay off-take agreement with BG, the largest player in the LNG industry.
As of last year, 80% of Sabine Pass’s capacity has been contracted to buyers via take-or-pay contracts, and 20% of the company’s liquefaction capacity has been retained for use by Cheniere Marketing (the internal trading arm of the company). Not satisfied with having the first five liquefaction trains constructed in the lower 48 (with a sixth train awaiting FID), Mr. Souki got Cheniere started on three further liquefaction trains at Corpus Christi (with a possible fourth and fifth train still under regulatory review). In total, the under-construction or completed LNG trains commissioned by Cheniere will create a platform capacity equal to roughly 9% of the expected global LNG market in 2020.
Turning the swampy land at Sabine Pass and Corpus Christi into a thousand acres of liquefaction capacity has been a smoothly executed construction and engineering challenge, at least in comparison to LNG projects in Australia, but it has not been an easy financial endeavor. Cheniere has spun out two publicly traded subsidiaries (in addition to the publicly traded parent): Cheniere Energy Partners Holdings LLC and Cheniere Energy Partners LP, and has created a maze of cross-held debt with several convertible issues (paying Wall-Street investment banks $589 million in debt issuance fees along the way). See Appendix A for Cheniere Corporate Structure and Debt Summary. Mr. Souki has also been ousted as CEO, and a third legendary investor (Carl Ichan) has taken a 13% position in the company agitating for change. Nevertheless, liquefaction trains 1 & 2 at Sabine Pass are up and running, with Train 3 substantially completed.
The Long and Short Take on Key Risks
Mr. Klarman has, unsurprisingly, not spoken about his position publicly, which as of the end of 2016 was 11.85% of Baupost’s portfolio. Jim Chanos has been more public with his thinking, calling Cheniere “financial engineering gone crazy.” Mr. Chanos argument is based on his belief that while LNG has experienced significant supply growth, it has not experienced similar demand growth. The bull case, according to Mr. Chanos, is that Cheniere has no exposure to commodity price risk, that utilization will be 100% and that the assets have a lifespan of 100 years (a claim made by Cheniere), selling into a growing market.
In reviewing Cheniere, we have identified five variables/questions around which the company’s valuation hinges. These five variables represent known unknowns that an investor must think about and take a position on in order to have conviction in their investment case:
The risks presented above cast significant doubt on the security of a long position from a purely qualitative perspective. At the very least the narrative is not nearly as simple as 20 years of assured cash flow from take-or-pay contracts. Turning to the numbers, the net present value of future EBITDA generated from all trains from just the 20-year take or pay contracts is positive, but just barely. After accounting for FY2016 debt, the NPV of future EBITDA from signed contracts is just $319 million.
A complete DCF analysis, considering specific flows to Cheniere Energy Inc. from subsidiaries and assuming modest successes by Cheniere Marketing, is more abysmal, as not all payments from contracts flow directly to Cheniere. Even absent the repayment of debt, the future cash flows present little in the way of upside, roughly 11% upside at the current share price. As amusing as that calculation sounds, a DCF valuation of equity without accounting for debt payment is in fact how some Wall Street sell-side analysts are valuing Cheniere. For example, Credit Suisse, whose build-up of FCF we utilized in part of our analysis, calculates a discounted Free Cash Flow to the Firm, not to equity, and then divides that value by the shares outstanding to get a target price.
According to Credit Suisse, the present value of future free cash flows to the firm (which is free cash flows available to both debt holders for principal payment and shareholders) on a per share basis is $53, but as of the end of FY2016 Debt per share was $95.88. An analyst could argue that if the debt is continuously rolled, setting a price target for equity based on free cash flow to the firm, without accounting for principal payment makes, makes sense. However, that seems an inappropriately risky decision, more akin to gambling than investing.
The famed economist Hyman Minsky characterized three types of borrowers: hedge borrowers (sensible borrowers, those who could afford to repay debt from their cash flows), speculative borrowers (borrowers that could afford to meet interest payments but must regularly roll over debt to repay original loans) and Ponzi borrowers (borrowers that could neither repay the interest, nor the original loan, these borrowers rely on the potential appreciation of value of their assets to refinance debt). Whether Cheniere is a speculative borrower or a Ponzi borrower is open to debate, but the company has certainly not borrowed sensibly. Should debt markets close to them, an assumption that all management should make when they borrow money, there will be trouble.
The Cheniere Complex (LNG, CQH and CQP) does appear a potentially rich hunting ground for a short. At the current time, the short interest in Cheniere Energy Inc. (LNG) is 7.6%, and the borrowing fee is roughly 0.25%, so it is relatively easy to short. Given the complexity of the accounting and corporate structure, and the expected volatility around the commissioning of each new liquefaction trains, having high conviction and a strong stomach is a necessity for this short. Significant legwork will be required to achieve high conviction, but it seems likely to prove worthwhile.
Energy Transistions and LNG
Energy transitions represent a structural change in the way we generate, transmit and consume energy resources. Changes occur worldwide; they are incredibly complex, massive in scale, and are not an isolated phenomenon. Transitions, however, can occur locally and differ in terms of motivation, objectives, governance, and risk mitigation. Broadly, they can unlock tremendous value and historically have represented tectonic shifts in both local and global economies.
It is widely cited that energy plays a critical role in supporting modern living standards. The U.N Human Development Index shows a strong correlation between energy use per-capita and a country’s achievement in their citizens’ life expectancy, education, and income. Growth, and consequently the demand for energy, has never been stronger. Examining the world’s long term economic and demographic trends, we observe that by 2040, the world’s population is expected to reach approximately 9 billion, an increase of roughly 2 billion people. Over that same time horizon, global GDP is expected to double, with non-OECD (Organization of Economic Cooperation and Development) countries far outpacing OECD countries.
By 2040, almost two-thirds of the world’s primary energy will be consumed in non-OECD countries. This burst of economic expansion, driven by billions entering the middle class, helps drive a 48% increase in global energy demand, with non-OECD country demand expected to grow by 71% and OECD country demand expected to grow by 18%. Will our current primary energy resources be sufficient to power this expansion? Independent of the risk mitigation exercise for reducing atmospheric emissions, it seems clear that our fuel sources will continue to evolve to help service the global economic expansion in the next several decades.
Energy Transitions
Historically there have been three primary energy transitions that have shaped our energy ecosystem1. The first was the transition from timber to coal—a remarkable discovery that largely fueled the industrial revolution. The second was from coal to crude oil—a discovery that fundamentally altered transportation and gave us modern industrial products such as plastics and the pharmaceutical industry.
Today we are in the midst of a third global energy transition from crude oil to natural gas, a shift that will likely not fully materialize for several more decades. The speed at which we are making transitions today far outpaces previous transitions. Paradoxically, the scale of each succeeding transition is an order of magnitude greater than the previous. For several millennia, up until the 19th century, the world was largely powered by biomass.2
A mere one century later fossil fuels dominate the landscape with approximately 72% of primary energy sources coming from coal and crude oil products. The scale of transitions is immense; in 2012, the world consumed roughly 550 quadrillion btu (British thermal units) of energy, approximately 95 billion barrels of oil equivalent. Today, as we explore a third possible transition, our task is even more daunting.
Current global consumption is well over 20 times greater than at the beginning of the 20th century when the inflection point tipped from biomass products to coal and oil. Global energy consumption is not slowing down: the US. Energy Information Administration (EIA) forecasts that by 2040 we will be consuming 813 quadrillion btu, a 47% increase in the next 20 years. The challenge with scale is that, even with aggressive growth estimates, new technologies and fuel sources that challenge incumbents must have a sustainable cost and operational advantage to make even a slight impact. Wind, solar, and biofuels are forecasted to have a combined growth rate of over 5% per year for the next 20 years. Yet by 2040, they still will only represent approximately 4% of global energy demanded.3
The latest transition from oil to natural gas is illustrative of the daunting time horizon required to secure resources and develop the appropriate infrastructure to reach critical mass. From its commercial beginnings in the late 1800’s, it took approximately 60 years for natural gas to reach just 5% of the global energy market. It took another 50 years for it to account for 25% of the total primary fuel energy supply.
The recent decade of technological advancement in horizontal drilling and hydraulic fracturing have enabled economic recovery of reserves that have sufficiently dropped the production and distribution costs such that the market price makes natural gas cost competitive, and dominant in certain regions, relative to coal and crude oil. As a result of the Natural gas is predicted to be the fastest growing fossil fuels resource over the next thirty years, largely driven by its abundant supply (which we now have access to economically in the United States), its superior thermal efficiency, and its ability to produce lower atmospheric emissions compared to coal and oil.
Liquefied Natural Gas (LNG)
One of the unique characteristics of natural gas though, in contrast to coal and oil, is that it is cost prohibitive to transport and impossible to transport by sea unless liquefied. Consequently, while natural gas is prolific globally, markets are regional. Unlike oil, which has an established global benchmark,4 regional natural gas spot prices vary tremendously and are subject to greater price volatility.
LNG condenses gas into a liquid at atmospheric pressure by exposing it to temperatures around -162?C (-260? F), yielding an energy density in its liquid state approximately 60% greater than diesel fuel. LNG takes up about 1/600th of the volume of natural gas in its gaseous state and thus can be transported by ship in a similar capacity to crude oil products.
Liquefying, transporting, and re-gasifying comes with significant costs though. Until recently, when comparing resource-rich countries looking to export to those looking to import, the spread between spot prices has not usually been wide enough to absorb the processing and transportation costs required to move and sell the asset. Natural gas also had several strong economic substitutes that challenged its growth and development (namely coal and oil).
The recent flurry of LNG projects does not necessarily represent a transition to a new fuel source, but rather an economic transition to a global market through the ability to store and transport natural gas more effectively. Pathways to link supply and demand play a large role in establishing a global market price. Absent a cost-effective means to transport, a region’s gas price will be almost entirely set by its local supply resources and appetite for consumption.5 Similar to primary energy source transitions of the past, LNG has taken decades to make a meaningful impact. Technically, we have had the ability to cool, liquefy, and transport gas for well over 60 years. Yet until the recent natural gas supply expansion in Australia and the US it has not been very economically build and sell LNG.
Is the recent surge real? How do we articulate value, and where is LNG going?
The LNG value proposition became particularly attractive when U.S. pricing moved from a world oil indexed price to a Henry Hub indexed prices,6 giving the U.S. a competitive advantage when it came to selling the LNG produced by capital-intensive export terminals. As the onset of fracking made gas resources flush in the United States, the spread between world oil prices (largely floating around $100/barrel) and Henry Hub prices nearly cut in half from $8/MMBtu to sub $4/MMBtu, widening substantially.
Brownfield sites in the United States, originally designed as import terminals, have subsequently been redeveloped as export terminals. For a time, the value proposition seemed clear and the U.S. appeared likely to soon be in a dominate strategic position. The global LNG market became much more competitive in 2015 and 2016 as the crash of oil prices threatened the margins required to process and transport the resource, putting existing contracts and projects at risk, both in the United States and around the world, although primarily in Australia.
Independent of price risk, the volume of liquefaction capacity has quadrupled in the last 20 years and is expected to increase by at least 50% over the next four. While growth looks promising, development is contingent upon global economic growth, excess capacity, shipping costs, and new markets/demand. Any slip in regional growth, particularly China, may flatten gas demand in importing countries.
New capacity is weighing down an already saturated market. Liquefaction capacity in 2016 was around 308.5 mtpa, demand was only 266 mt. Some estimate that as few as one in twenty planned projects may be needed to meet global demand through 2035. The recent widening of the Panama Canal and introduction of more flexible contract structures may help alleviate shipping costs which will improve the investment opportunity or reduce a projects exposure to price volatility.
New markets and new demand must also open as Japan and South Korea are currently importing almost half of the global volume, a significant increase to the pre-Fukishima years as a result of Japan shutting down its fleet of nuclear reactors. Should this decision change, as it appears to be doing, albeit slowly, Japanese demand may fall significantly (as much as 30mtpa). A bulk of gas demand to date is driven by the power generation industry; however, LNG has possibility to be used as a substitute for oil in the transportation industry, potentially doubling global demand (holding current demand growth rates flat).
High up-front capital costs for export/import terminals drive the need to secure revenue upfront. As such, it is estimated that 70-80% of all off-take capacity is sold prior to commissioning of an LNG liquefaction train. For companies that manage an array of oil and gas positions, LNG may provide a stable and diversified cash flow in an otherwise exposed market. Additionally, markets are maturing and becoming more liquid. Contract structures to extract and deliver the gas are more creative, and several facilities try and utilize brownfield sites, which has the kept down total CAPEX. 7
The risk, however, is real. Cost overruns and project delays are status quo, especially in Australia. The Oxford Institute for Energy Studies predicts that the global per unit development costs have risen 3x over the last decade. As natural gas reserves become depleted, the cost per unit of energy also goes up. Producer cost overruns can have a very real, negative impact on returns, since it is typical for the deliver price of the product to be independent from the cost of supply.
Recent estimates suggest that Henry Hub needs to maintain a price of $3.00 – 3.50/MMBtu or lower to sustain exports from U.S. at levels that are competitive with oil-indexed contracts out of Australia. Examining the LNG supply chain: liquefaction can add anywhere from $0.90 to $3.50/MMBTU, transportation can add $0.3 to $4.3/MMBTU, and regasification can add $0.4 to $0.7/MMBtu. In total, a viable contract price may need to demand anywhere from $5.6/MMBTu to $12/MMBtu, assuming natural gas is delivered to the liquefaction facility at a price of $4/MMBtu.
At peak oil prices prior to 2014, natural gas prices in Japan floated around $15/MMBtu, a far cry from the current $7.5 to 8.5/MMBtu after oil dropped by 50%. The dramatic reduction in world oil prices have depressed delivery prices that are necessary to offset operational issues. Further, many predict that the price of oil will stay below $60/barrel in the short term and $80/barrel in the medium to long term. With new projects coming online in the US, near term supply is likely to outpace demand growth, just as spot prices have dropped significantly.
Lower margins for producers moving forward will likely cause smaller, independent producers to back away from the market, which may eliminate the optionality for traders to dispatch assets. If executed properly, LNG contracts to have significant longevity, which can minimize total revenue exposure on any one given year or point in time. As with oil and other commodities, gas will likely be cyclical in nature: low oil prices may supply growth, contributing to a surge in demand and increasing future prices.
Absent extracting value from price arbitrage, traditional economic theory suggests that the market is largely driven by robust demand projections. At issue is that before LNG demand can be met, it is expected that in the United States alone an estimated $130-$160 billion in investment is needed in shale gas to produce the gas needed to me domestic demand and export market demand. Should demand projects prove lofty, as they often do there is significant risk of wells that don’t recoup their drilling and development costs.
For the LNG supplier, competition is only increasing. European gas markets historically have been fundamentally different than the US due to the lack of cross-border interconnections and reliance on Russian gas. With load growth down, much of the new energy economy will be powered by natural gas combined cycle plants. It will be intriguing to see how Europe handles a potentially oversupplied gas market in the coming years, especially with Russia claiming it will defend market share. Interestingly, most long-term contracts are still indexed to oil carry a lag of several months. This may result in lower gas prices in the short and medium term.
See the full PDF below.
