It is LNG, not oil, that’s truly behind the European energy giant’s $70 billion acquisition of Britain’s BG Group, which was announced on Wednesday. Together, the two firms would control a significant amount of the world’s LNG supply, besting rival ExxonMobil by a considerable margin.

But while being bigger is usually better in the energy world, it may not pay off as well when it comes to the volatile and niche LNG marketplace.

LNG suppliers used to have the upper hand, but that advantage has degraded sharply over the last few years as demand growth has waned. Contract terms are now shorter and less lucrative for suppliers. To make matters worse, rising construction and maintenance costs have made LNG imports less appealing to many customers, all while continued tepid demand is causing supply to build up. This doesn’t bode well for the new king of LNG.

Prolonged weak oil prices usually leads to consolidation in the energy industry. Bigger and better capitalized firms tend to gobble up smaller and weaker ones at a price relative to where they believe oil prices will end up once the market recovers (whenever, or wherever, that may be). But Shell’s chief executive, Ben van Beurden, told reporters on Wednesday that his company’s decision to acquire rival BG Group was “not a bet on the oil price.” Instead, he insisted, the deal was centered on creating a stronger company in both oil and natural gas. The key word here is gas, more specifically, liquefied natural gas, or LNG, which is basically natural gas compressed and chilled into a liquid, allowing it to be transported by sea to destinations far away.

Shell has bet big on LNG over the years and believes in its growth potential. Countries such as Japan and Korea, which can’t receive natural gas via pipeline, depend on LNG for all their gas needs. Shell has major investments in Australia and the Middle East and owns and leases around 40 LNG tankers, including the Prelude liquefaction ship, which is the largest ship ever built.

BG Group has invested in LNG as well, with projects in Egypt, Trinidad, and Australia and a fleet of around 25 owned and leased LNG carriers. BG also has an agreement with Cheniere LNG to purchase 3.5 million tonnes per annum (“mtpa”) of LNG from the U.S. Gulf Coast.

Together, Shell and BG are expected to produce as much as 33 mtpa of LNG this year. That’s equivalent to around 14% of global LNG imports for 2014. ExxonMobil, the largest of the energy “supermajors,” is slated to produce 22 mtpa. By 2018, after new projects under construction get rolling, the Shell-BG combo will pump an impressive 45 mtpa of LNG, which is equivalent to around 19% of 2014 global LNG imports.

So, this deal seems pretty much centered on gaining and protecting market share. Shell wants to be the undisputed leader in LNG. But is that wise? While LNG can be an extremely profitable venture, it can also turn out to be a total money-sucking disaster. The LNG market has gone from a seller’s market to a buyer’s market over the years. This is only going to get worse as supply increases.

To be sure, Shell is no novice in this space. The company assisted in building the first LNG gasification terminal in Algeria in the 1960s, so it has been in the LNG business from the very beginning. But Shell’s experience may actually be a liability in this case. The LNG market today is very different than it was just a few years ago.

In the past, Shell and other LNG suppliers could force its customers to sign long-term agreements known as take-or-pay contracts. Under these deals, Shell’s clients, usually a Japanese or Korean utility, would agree to take a specified amount of LNG per month for a long time, usually 20 years, and agree to pay the market price to the supplier even if it didn’t necessarily want or need the gas that second. The price of LNG is dynamic and has usually moved with the price of oil, which is used for totally different applications. This became a major problem in the 2000s, as oil and natural gas prices diverged significantly. In some cases, LNG was being sold to customers, mostly in Asia, at a rate that was as much as six to 10 times what natural gas was being sold for in the United States.

Eventually, everyone wanted in on this racket, leading to an explosion of gasification projects all around the world, from Malaysia to Qatar to even Peru. As the supply of LNG has crept up over the years, the power of suppliers has waned. With LNG demand growth slowing in Asia, which soaks up 75% of LNG imports, the market has become less favorable to sellers.

In response, sellers are now demanding shorter commitments, averaging four years instead of 20, and a more rational pricing structure based on the supply and demand dynamics of the natural gas market, not the oil market. This means that many of the LNG gasification projects Shell has been developing for years, such as the Gorgon LNG project in northwestern Australia or the Sakhalin 2 LNG project in Siberia, may end up not being as lucrative as originally imagined. Sellers are also choosing to resell gas they don’t need via a newly developing LNG spot market, where prices can differ wildly from contracted prices, much of the time far lower.

A record 70 mtpa of LNG was traded on a spot or short-term basis in 2014, equating to 29% of its total global trade. A competitive spot market for LNG might work to the advantage of certain suppliers, but it could also backfire if there is too much supply on the market at any given moment. Suppliers desperate to move errant cargo of LNG will be forced to sell it at a discount, which could have a profound impact on the entire market.

The spot LNG cargo hasn’t been too disruptive over the last few years, though, given the extraordinary demand for surplus LNG from Japan. The country needed the extra LNG to make up for energy lost from its downed nuclear reactors in the wake of the Fukushima incident in 2011. But Japan no longer needs all that extra LNG due to its weak economy and the potential restart of its nuclear plants. That not only means that it will be much harder for spot cargoes to find a home but also means contract prices for LNG bound for Japan will also suffer, falling as much as 38% through 2016, according to Australia & New Zealand Banking Group.

Having extra LNG floating around in the market would have been unheard of just a few years ago, but it will become more common in the near future. This is because LNG gasification terminals are being built on spec. Nowhere is this better illustrated than in Australia, where both Shell and BG have large LNG interests. An estimated 11 mtpa of LNG production capacity under construction is unspoken for, according to Tri-Zen, a consultancy. Such a huge amount of LNG without a home is alarming and could move the overall LNG market to the downside.

China is expected to absorb a lot of the LNG set to come online in the next few years. The country has a number of regasification terminals under construction to receive the LNG shipments, much of which is expected to come from Australia. But unlike Japan, Korea, and Taiwan, which have no choice but to use LNG for its gas needs, China has options. Not only does China have its own domestic natural gas production, it also can easily receive natural gas from producers via pipeline. For example, Russia announced last year that it had inked a deal with China to deliver $400 billion worth of natural gas over the next 30 years.

If China can receive billions of dollars’ worth of Russia gas through a pipeline at a fraction of the cost of LNG, then it is unlikely that China will want to expand its LNG intake capacity beyond what’s currently on the books. With China out of the mix, suppliers have a big problem. As more capacity is turned on, a price war could break out, causing LNG prices to sink like a rock. While that might be great news to consumers in Japan, Korea, and Taiwan, it doesn’t bode well for Shell’s acquisition of BG Group.