Traders often call natural gas the widow-maker, and for good reason. Since the price of the fuel was fully deregulated nearly two decades ago, it has literally surged and plummeted with the seasons.
In the 1990s, expectations that gas would trade indefinitely near $1 per million British thermal units (MMBtu) spurred construction of nearly 100 gigawatts (GW) of natural gas-fired power plants. Credit raters slashed ratings of nuclear and coal plant owners across the board, and speculation raged that bankruptcies would follow as these assets became “stranded costs.”
Then, just as abruptly, the worm turned. With demand rising, natural gas in North America was suddenly no longer in such abundance, and prices steadily rose. Those who had bet heavily on future competitiveness of gas-fired power plants rapidly weakened under the burden of soaring fuel costs and debt. By mid-2005, one-time poster child Calpine (CPN) had declared bankruptcy.
By the time Hurricanes Katrina and Rita wreaked their devastation on New Orleans and the Gulf Coast region a few months later, gas was trading in the high teens. Many wondered whether it would ever be competitively priced again.
That, of course, marked yet another turning point for the fuel. With gas relatively more expensive than oil, both industrial and residential customers began switching fuels. Demand fell further as a mild winter in 2005 turned to a relatively mild summer 2006. Finally, high prices coupled with technological advances accelerated the development of North American shale gas reserves.
By mid-2006, natural gas prices has fallen by more than half, finally touching bottom at around $5 per MMBtu in late September. Gas held in a rough trading range between $5 and $8 until spring 2008, when it blasted off again in the wake of surging global oil prices. Then, the collapse of the global economy and unfolding credit crunch sent the fuel on its fastest decline yet. The $2.41 per MMBtu reached on Sept. 4, 2009 is the lowest level since late 2001.
Over the past three months, gas has fared considerably better. Colder weather and evidence that drilling has fallen precipitously has pushed prices back up to around $5 per MMBtu. And this week the fuel staged a one-day surge of better than 8 percent on news of an unexpectedly large inventory drawdown.
Up or Down?
Where’s gas headed from here? Almost half the analysts canvassed in a Bloomberg survey this week stated they expect prices to rise as the winter wears on. A slightly higher percentage, however, expressed a decidedly bearish opinion, with weather figuring prominently in both forecasts.
Looking out beyond the winter, weather will continue to play a primary role, particularly in how it affects inventories, which are still at very high levels continent-wide. A recovery in industrial activity is also critical. As third-quarter results attest, most electric power companies reported improved industrial sales over second-quarter levels. That would be a very positive trend if it continues, as it appears to be.
A more entrenched positive is the continued rapid growth of renewable energy capacity. As I’ve reported previously in Utility Forecaster, 33 states and the District of Columbia have enacted legislation requiring electric utilities to convert from 10% to 33% of their generating capacity to renewables over the next 10 to 20 years.
Some of the qualifying sources such as geothermal and conservation can be counted on to provide relatively consistent output. Most of the new load under construction, however, is wind and solar, which are considerably more intermittent. That means companies need backup supplies, and the most reliable by far is natural gas.
Gas plants can be constructed far more quickly than other sources, fuel can be shipped and stored and output can be ramped up or down far more effectively than baseload coal or nuclear. Moreover, gas-fired plants produce less than half the carbon dioxide per megawatt produced than do coal-fired plants.
Finally, there’s the question of production. As the devastation in the drilling services sector attests, much of North America’s gas output has been taken off line in the wake of the crushing fall in gas prices. Spring and summer utilization was the lowest this decade.
Canadian gas production was off 20% in 2008 from its highs in 2007 and continues to drop as fields deplete and companies curtail new development expenditures to only the most promising finds. Meanwhile, US output is expected to be down 5% to 10% in 2009 from 2008 levels.
Sooner or later, falling production and recovering demand always add up to higher prices--just as high prices ultimately sow the seeds of their own demise by discouraging usage and encouraging output. The questions in the gas market, however, are when that will happen and whether prices will take yet another dive beforehand. Inventories, for example, are still extended in North America at a time when the US economy is still working toward recovery.
One concern making the rounds is that a flood of liquefied natural gas (LNG) is headed for US ports, as production facilities come on stream in the Middle East. Given that North American natural gas prices are still well below those of Europe, for example, that doesn’t seem to make a lot of economic sense.
On the other hand, there are a large number of newly constructed US LNG processing facilities--notably by Cheniere Energy Partners LP (CQP)--that are currently idle. The capacity at Cheniere’s facilities is mainly contracted by Super Oils Chevron (CVX) and Total (TOT), and these companies could make the determination that it makes sense to take delivery.
A flood of LNG could well take down gas prices again as many fear. On the other hand, this is also precisely the kind of talk that extremely depressed markets are famous for at major turning points. And if there’s one truth about natural gas in its relatively brief history as a deregulated commodity, it’s that survival depends on being ready for tectonic shifts.
Energy and Yield
My focus here is on how volatile natural gas prices will affect energy-related income investments. Here, in brief, is my sector-by-sector take, starting with the least affected.
Regulated Natural Gas Utilities. With very few exceptions, regulated natural gas utilities pass through all changes in gas prices directly to consumers.
Rates for a growing number are also “decoupled” from demand, meaning profits aren’t affected by weather and conservation either. Instead, they depend on how much companies spend on their systems, and the rate of return allowed by regulators on that investment.
The upshot: Most regulated gas utes have no real exposure to energy prices. The possible exceptions are utes operating in states that require fuel cost rate filings, which could make them vulnerable to disallowances in a period of spiking prices.
Regulated Electric Utilities. Natural gas prices are integral to setting the price of electricity in the US wholesale market.
Texas, for example, actually links the price of power to gas. That matters not to most regulated power companies, however, as the cost of fuel and purchased power is passed through automatically to customers. Again, that insulates profits against volatile natural gas prices, though regulatory review could trigger disallowances when prices spike in states where relations are bad.
Energy Infrastructure Companies and Master Limited Partnerships. One size definitely does not fit all with this sector.
Some of these assets are contracted on a capacity basis. As long as the customer can pay its bill, margins are unaffected by either energy prices or throughput, i.e. how much of that capacity is actually used. Other assets make their money off throughput, which is only affected by energy prices if they trigger higher or lower usage.
Finally, margins at some, such as refineries and processing facilities, are affected by pricing spreads between the raw energy that comes in and the refined products that go out. Their profits can be deeply impacted by gas price swings, unless management does a very good job hedging exposure. Anyone buying and holding had better know the difference.
Super Oils. The world’s biggest investor-owned oil and gas producers no longer control the lion’s share of global reserves. That distinction is now reserved for mostly state-owned giants. They do, however, control the lion’s share of the infrastructure needed to bring energy to market.
Their operations dominate the world’s biggest energy projects, from Australia to Kazakhstan to offshore Angola and deepwater Brazil. And their balance sheets are stronger than the lion’s share of sovereign nations. When energy prices plunge, so do earnings.
The difference with other producers, however, is these companies remain strongly profitable, keeping dividend coverage secure and balance sheets strong.
Unregulated Power Producers. In contrast to regulated electric utilities, where profits are virtually unexposed to volatile energy prices, unregulated power sellers’ margins are affected in two major ways.
First, they can’t automatically pass through changes in fuel costs, so changes flow directly to the bottom line unless they’re hedged. Second, the price of the power they sell generally tracks natural gas prices, unless it’s hedged or locked in under long-term contracts.
Here too, one size definitely does not fit all. The type of power plants, selling contracts and hedging are all key factors determining exposure. Companies that also operate regulated utility assets, such as Dominion Resources (D), enjoy a financial and operating cushion that pure plays like NRG Energy (NRG) do not.
Fuel costs at nuclear plants owned by companies such as Exelon Corp (EXC) are basically unaffected no matter what natural gas prices do, though selling prices for output are.
The good news: Unlike during the previous recession, there were no disasters in the US power sector, largely because management has been cutting debt and operating risk since late 2002. In fact, earnings for companies like Dominion, Exelon and even NRG have remained very strong. The next time gas prices spike, nuclear, renewables and even coal will benefit, while gas-dependent producers like Calpine will suffer unless they’re extremely hedged.
And when the industry does lever up again, a plunge in gas prices that hammers power will be just as deadly as it was in 2001-02. For now, however, there’s not a lot to worry about from another relapse in gas prices.
Canadian Producer Trusts and US MLP Producers. This group has certainly been through the fires since gas prices starting to plunge in late 2008. With very few exceptions--such as Linn Energy LLC (LINE) and Vermilion Energy Trust (VETMF.PK)--most have been forced to cut distributions at least once, as falling oil and particularly natural gas prices have taken down cash flows.
Thanks to hedging all output through 2011, a renewed plunge in North American gas prices wouldn’t hurt Linn. Vermilion, meanwhile, would be insulated by hedging as well as the fact that 70% of cash flow is generated in Europe and Australia.
Other trusts and MLPs would see their cash flows affected to varying degrees, depending on how much gas they produce. The good news is most are hunkered down, reining in debt and costs and with distributions at very conservative levels. Even the most gas-dependent produced enough cash flow in the third quarter to cover distributions comfortably, even though they sold gas in many cases at less than $3 per MMBtu.
Trusts are nearing near-certain conversions to corporations in late 2010. A growing number, however, appear to be positioned to maintain current distribution rates even with new taxes. If that holds, it would smash all expectations and the result would be a post-conversion windfall gain for their unitholders.
In fact, we’ve already seen that for converted trust Crescent Point Energy (OTCPK:CSCTF). Shares are up 54% since management announced in May that it would convert without cutting. But no matter how today’s MLPs are organized and what taxes they pay, cash flows do depend on energy prices. And no one should buy unless they’re willing to take the risk of the ups and downs.