Will LNG Exports Rescue the North American Natural Gas Market?

Will LNG Exports Rescue the North American Natural Gas Market?

Editor”s Note: This piece was originally published in a brief by Raymond James

It wasn’t that long ago – as recently as 2008 – that people were debating whether the U.S. could build enough liquefied natural gas (LNG) import infrastructure to fulfill the needs of an undersupplied natural gas market. Now, of course, the problem is the polar opposite: what to do with North America’s massive and persistent glut of natural gas. Some solutions are essentially incremental and are visibly materializing, albeit less slowly than gas producers would want. This includes coal-to-gas switching by electric utilities and a rebound in gas-intensive domestic manufacturing (especially petrochemicals and fertilizer). Other solutions are more structural in nature and therefore more distant, such as a surge in natural gas vehicles (which we discussed in our Stat from May 14) and the development of a domestic gas-to-liquids industry (where Sasol is leading the way). In this Stat, we focus on what is probably the most high-profile – and controversial – outlet for excess North American gas. We are referring to the prospect of the U.S. and Canada becoming significant exporters of LNG. The earliest this could materialize would be late 2015, and it’s doubtful whether it will truly move the needle vis-`a-vis the supply/demand balance before the end of this decade. That said, LNG exports could eventually be a game-changer for the North American gas market, presenting both opportunities and risks for energy investors.

20+ Bcf/d of LNG export projects on the drawing board… but how much will actually get built?
Believe it or not, the U.S. is already an LNG-exporting country. The Kenai LNG facility near Anchorage, Alaska, which started up in 1969, was, in fact, the second liquefaction plant ever built worldwide. It remains North America’s only liquefaction plant. Formerly a joint venture between Marathon Oil and ConocoPhillips, and since last year owned entirely by the latter, it was temporarily idled in November 2011 but may restart in 2H12. While Kenai represents a pioneering milestone in the LNG industry, at 0.19 Bcf/d it is obviously far too small to make a difference for either the global LNG market or the North American gas market.

One of the few projects in an advanced stage of development is Sabine Pass on the Louisiana-Texas border. Cheniere Energy has operated an LNG import terminal on this site since 2008, but since LNG imports are the last thing the U.S. needs these days, the company is working to transform the facility into a bi-directional hub, capable of importing as well as exporting LNG. The liquefaction component has been designed with maximum capacity of 2.8 Bcf/d, though the first phase, expected to start up in late 2015, would comprise only two trains rather than four. Final federal approval for the project was given in April.




Click to Enlarge

Thinking of building your own LNG plant? Read this first.
From what we’ve already written, it should be clear that you shouldn’t hold your breath waiting for North American LNG export plants to come to fruition. Sabine Pass is a useful case study of just how difficult and time-consuming it is to develop these projects. Cheniere’s original plan to develop liquefaction capacity at Sabine Pass dates back to June 2010. Nearly two years later, construction has not yet started – even though this specific project has the big advantage of having a well-developed site with existing LNG infrastructure. Let’s look at some of the challenges faced by North American LNG developers.

Slow permitting.
Let’s face it: if this was China rather than the U.S., building LNG plants (and refineries, and nuclear reactors, and just about anything else) would be a lot easier. The undeniable reality is that the permitting process for domestic LNG developers is expensive, burdensome and excruciatingly slow. The Federal Energy Regulatory Commission (FERC) is the lead agency, though the Department of Energy (DOE) also plays a role. The U.S. Fish and Wildlife Service and the Army Corps of Engineers can also be involved. In addition, state and local permits are required. For example, Cheniere’s follow-on liquefaction project, near Corpus Christi, Texas, was authorized by FERC to begin “pre-filing” in December 2011. The company aims to file the completed application in August 2012 and receive approval in September 2013. Assuming no delays, this would allow project startup in late 2017. For projects in Canada, permitting is also complex. The Kitimat project in British Columbia – a joint venture between Apache, EOG Resources and Encana – received a 20-year export license from the Canadian National Export Board in October 2011. This was nearly three years after the project received environmental approval (both federal and provincial).

Industry opposition.
While by no means the sole factor, one of the reasons for the slow permitting is the fact that these LNG projects face a considerable amount of public opposition. Protests from environmentalists – which helped sink the Keystone XL pipeline, and now seem particularly focused on Dominion’s Cove Point project – are not surprising. What may be more surprising is that some major industry groups are also opposed, though, of course, for different reasons. Specifically, large gas consumers do not want LNG exports for the exact same reason why large gas producers such as Chesapeake Energy applaud these projects: they would put upward pressure on gas prices. The American Public Gas Association, which represents gas utilities, testified in November 2011 before the Senate Energy and Natural Resources Committee, stating: “APGA maintains that the export of LNG is not in the best interests of our country and most notably that it will increase natural gas prices at the expense of consumers while sacrificing a unique opportunity to reduce our dependence on foreign energy sources.” The Industrial Energy Consumers of America, which represents manufacturers, has also expressed its concerns, stating: “It would be irresponsible for the DOE to approve export applications without first doing an economic analysis of the impact.”

Financing constraints.
LNG plants are never cheap. Even in the best of circumstances, they are immensely capital-intensive projects, with price tags that range from a few billion to tens of billions of dollars, and almost invariably they tend to come in over budget (as well as behind schedule). This needs to be seen in the context of a highly competitive commodity market where global liquefaction capacity will rapidly increase between now and 2020. Australia alone, led by projects such as Chevron’s Gorgon and Inpex’s Ichthys, is expected to surpass Qatar as the world’s #1 LNG producer by the end of the decade. Combined with other projects in West Africa, Papua New Guinea and elsewhere, the jury is out as to whether global (especially Asia-Pacific) LNG pricing will remain as strong it is currently, i.e., whether the close linkage with crude oil can be maintained. Thus, not everyone is willing to invest in North American liquefaction plants. Among companies that are willing, some (e.g., Apache) are clearly better capitalized than others (e.g., Cheniere). For project loans to be secured, offtake agreements are essential, hence Cheniere’s recent deals with KOGAS, BG Group and others.

Will LNG exports make a difference for gas prices?
The short answer is: yes, but not anytime soon. Other than the tiny Douglas Island project in 2014, the first two new export projects – Sabine Pass and Kitimat – wouldn’t start up until late 2015 as the best-case scenario. By the end of 2017, eight new projects could be operational (totaling ~10 Bcf/d) – again, best-case. Even more importantly than the hazy timeline: while it’s tempting to forecast what effect all this would have on gas prices, the reality is that this would be a rather arbitrary modeling exercise. The reason is that LNG exports do not happen in a vacuum. Given the ability of U.S. unconventional plays to supply practically limitless quantities of gas – limited only by the industry’s willingness to drill – any incremental gas demand for LNG could be offset nearly 1:1 by increased production. Above and beyond supply, factors like overall economic growth, expansion in natural gas power generation and transport, and the state of the global LNG market are all “black boxes” that far into the future.

In January, the DOE published a study that attempts to forecast the price impact of LNG exports. The verdict: wellhead prices could be raised by anywhere from 33% to 54% in 2018, with the delta being a function of different levels of shale gas production. However, the DOE’s most important assumption is that there will be 12 Bcf/d of exports by 2018. (For some perspective, total U.S. gas production was 72.5 Bcf/d at the end of 2011.) As shown in the table on the first page, the 12 Bcf/d figure is a very ambitious assumption. And in any case, the DOE notes that the price effect would narrow after 2018, declining to a range of 5% to 20% by 2035. All that being said, one reason it’s obvious that there will be some price effect is the fact that, as we already mentioned, industries that benefit from cheap gas are opposed to LNG exports. In fact, while the DOE’s price study has received its fair share of criticism, one of its biggest cheerleaders was – you guessed it – the Industrial Energy Consumers of America.

The big picture: Will there ever be a single global gas market?
In our Stat from August 8, 2011, we compared gas price trends internationally and discussed what would need to happen for North American and overseas prices to converge. At the risk of stating the obvious, let’s recap why you currently must pay at least 3x (vs. North America) for gas in Europe, and at least 5x in Japan. The oil market is fully globalized, even though there are regional differentials, such as WTI vs. Brent. Gas, on the other hand, is bought and sold in multiple regional and sub-regional markets. North America is the only gas market that has a truly continental scope. The European Union, for example, consists of at least three distinct gas markets: the Mediterranean Sea region, the North Sea region, and Central/Eastern Europe. Asia-Pacific, given its size and large number of island economies, has many separate gas markets.

So, what would have to happen to achieve true convergence between the North American gas market and Europe/Asia? Broadly speaking, there are two hypothetical scenarios possible here – a bullish one and a bearish one (from a North American standpoint). As far as which one seems more likely, the short answer is that neither seems remotely realistic until the second half of this decade, though the bullish scenario is more plausible in the long run.

Bullish scenario.
This would entail bringing North American gas prices up to the levels of Europe (or even Asia), i.e., rough parity with oil on an energy-equivalent basis. This could be accomplished in one of two ways. The only supply-side solution to systematically eliminate the gas glut would be to ban or severely restrict shale gas drilling in North America, presumably on environmental grounds (e.g., fear of fracking risks). We simply cannot envision the U.S. or Canada following the lead of countries like France and Bulgaria in this regard. This means that, in practical terms, a demand-side solution would be needed to rebalance the market, and the timeline is therefore very lengthy. A significant expansion in gas-fired power generation, a revival of gas-consuming industries (especially petrochemical and nitrogen fertilizer plants), and something along the lines of the Pickens Plan for dramatically boosting the number of natural gas vehicles – these are all realistic drivers for domestic gas demand in the long run. As discussed in this Stat, yet another possible driver would be for North America to build a large amount of liquefaction capacity, thus adding demand from Europe or Asia on top of domestic demand. We don’t expect any of these factors to move the needle until 2015 at the earliest, and even then, it’s quite possible that the incremental demand will do nothing more than offset the supply growth in the meantime.

Bearish scenario.
This would entail bringing European (or even Asian) gas prices down to the level of North America. As with the bullish scenario, both supply-side and demand-side solutions can be imagined. One supply-side solution would be an LNG infrastructure buildout on such a scale that it creates structural overcapacity and ends up depressing gas prices in all LNG-dependent markets – mainly Asia, and Europe to a lesser extent. This theory is not particularly credible, however. While cyclical factors can lead to short-term LNG oversupply, structural overcapacity is unlikely, given that liquefaction projects have tended to start up considerably later than scheduled (and some have been canceled for lack of funding or regulatory uncertainty). Alternatively, a surge of shale gas drilling in shale-rich countries outside North America (China, India, Germany, Poland) could lead to a similar gas glut. Again, this is not a realistic outcome, at least not anytime soon. As detailed in our Stat from April 18, 2011, “Can Shales Double the World’s Natural Gas Reserves?” a constrained supply of onshore rigs and trained personnel – not to mention political opposition in a number of countries – is slowing down the pace of development overseas. If neither supply-side solution seems realistic, the demand-side one is even more of a fantasy. Could Europe or Asia suddenly sharply curtail their gas consumption? What is happening, of course, is quite the opposite: in the aftermath of last year’s Fukushima nuclear disaster, a wide range of countries have reviewed their nuclear policy. Those, like Germany and Japan, which have decided to curtail or phase out nuclear power, are bound to increase their gas demand, since gas is currently the only low-carbon source of baseload power that can replace nuclear power. Beyond 2015, large-scale renewables (with grid storage) and/or clean coal may displace some nukes, but for now, gas is it.

Conclusion
The structural imbalance between North American natural gas supply and demand can be addressed in many ways, and no single solution is sufficient on its own. In addition to small incremental changes (more coal-to-gas switching and gas-intensive domestic manufacturing), some structural changes are also underway, such as a surge in natural gas vehicles and the emergence of gas-to-liquids production. On top of all this, the U.S. and Canada will, over time, begin to export LNG in significant quantities. However, while there are 13 export projects at some stage of development, there is a long way to go until this could even begin to become a reality. The best-case scenario for the startup of the first meaningful new liquefaction plants (Sabine Pass and Kitimat) is late 2015 – and that timetable is more likely than not to be pushed out. LNG exports are unlikely to become truly needle-moving until the end of this decade. A painfully slow permitting process (partly a reflection of opposition from large gas consumers) and constraints in project financing are combining to make LNG exports a distant reality. While energy investors should be aware of the LNG export trend and its potential long-term effect on gas prices, the notion we occasionally hear – that LNG exports will reshape the North American gas market in the foreseeable future – strikes us as wishful thinking on the part of gas bulls.

© 2013 Energy Tribune

Scroll to top