Threats and Opportunities of Distributed Power Generation

• Rooftop solar panels aren't the only distributed generation technology that could challenge existing utility business models as it grows.
• Some power companies see DG as an opportunity and are entering this segment in ways that could prove challenging to their start-up competitors.

Two recent news stories highlighted different ways that utilities and large generating companies are beginning to respond to the emergence of distributed generation (DG) as more than back-up power. Arizona Public Service (APS) is launching its version of potentially the most challenging type of DG for utilities, rooftop solar. Meanwhile, Exelon Corp. announced an investment partnership with a provider of gas-powered fuel cells. The success of such ventures and the evolution of DG will have implications for electrical grid stability and our future energy mix, including the role of flexible, large-scale gas-fired generation.

APS is seeking regulatory approval for a program that might be characterized as free rooftop solar. In effect, they would lease approved homeowners' rooftops for $30 per month, in order to host a total of 20 MW of solar panels that would be owned and controlled by APS. The idea has generated some controversy, partly due to the utility's rocky relationship with the solar industry over issues like "net metering". 

The plan would enable homeowners who might not otherwise qualify for solar leasing from third parties to have solar installed on their homes, although they would apparently still receive their electricity through the meter from the grid, rather than mainly from the rooftop installation. That's a very different model from most DG approaches, though under current market conditions the net benefit to consumers reportedly would match or exceed that from solar leasing.

Exelon's announcement seems aimed at a different segment of the market, and based on a very different technology. The company would finance the installation of 21 MW of Bloom Energy's fuel cell generators at businesses in several states, including California. Bloom made quite a splash when it introduced its "energy servers", including a popular segment on "60 Minutes" in 2010.

Bloom's devices, which come in models producing either 100 kW or 200 kW, are built around solid oxide fuel cells.  At that scale they are too large for individual homes but suitable for many businesses. And because they are modular, they can be combined to meet the energy needs of larger offices or commercial facilities such as data centers. Unlike the fuel cells being deployed in limited numbers of automobiles, they do not require a source of hydrogen gas. Instead they run directly on natural gas from which hydrogen is extracted ("auto-reformed") inside the box.

In that respect, despite their novel technology, Bloom's servers are much closer than rooftop solar to traditional distributed energy, in which a customer owns or leases a small generator to which it supplies fuel. The advantages of Bloom's model are that its servers are designed for highly efficient 24x7 operation, without the expensive energy storage necessary to turn solar into 24x7 power, and with much lower greenhouse gas emissions and local pollution than a diesel generator.

In order to qualify as true zero-emission energy, these installations would need to be connected to a source of biogas, e.g., landfill gas, which effectively creates a closed emissions loop or recycles emissions that would have occurred elsewhere.  Even running on ordinary natural gas, the stated emissions of Bloom's energy servers are roughly a third less than the average emissions for US grid electricity, or 20% lower than the average for other natural gas generation. However, their emissions are over 10% higher than the 2012 average for California's grid.

I find it interesting that Exelon, the largest nuclear power operator in the US and owner of a full array of utility-scale gas, coal, hydro, wind and solar power, would make a high-profile investment in a technology that could ultimately slash the demand for its large central power plants. The company has invested in utility-scale solar and wind power, and as the press release indicated, is already involved in "onsite solar, emergency generation and cogeneration" via its Constellation subsidiary. In fact, it has apparently already achieved its goal of eliminating the equivalent of its 2001 carbon footprint.  However, the press release hints that something else might have attracted them to this deal.

Consider all the changes in store for the power grid. Baseload coal power is declining due to the combination of economic forces and strong emissions regulations such as the EPA's Clean Power Plan. Even some nuclear power plants, which have been the workhorses of the fleet for the last several decades, are facing premature retirement for non-operational reasons. At the same time, grid operators must integrate steadily growing proportions of intermittent renewable energy (wind and solar), along with increasingly sophisticated tools like demand response and energy storage. If any of this goes wrong, electric reliability will likely suffer.

From that perspective, Exelon's small--for them--step into DG also looks like a bet on the future value of reliability--"non-intermittent...reliable, resilient and distributed power." That's a bet even an old oil trader can understand: Uncertainty creates volatility, and volatility creates opportunities. I will be very interested to see how this turns out. 

A different version of this posting was previously published on the website of Pacific Energy Development Corporation.

The Missing Oil Crisis of 2014

• While the full impact of the surge in US "tight oil" may be masked by problems elsewhere, it is on the same scale--but opposite direction--as key factors that led to the 2007-8 oil price spike.
• In that light it does not seem like hyperbole to credit the recent revival of US oil output with averting another global oil crisis.

Several speakers at last month's annual EIA Energy Conference in Washington, DC reminded the audience that energy security extends beyond oil, starting with Maria van der Hoeven, Executive Director of the International Energy Agency (IEA). In her keynote remarks Monday morning she was quick to point out that it also encompasses electricity, sustainability, and energy's effects on the climate and vice versa. Still, the comment that got my wheels turning came from Dan Yergin, author and Vice Chairman of IHS. During his lunch keynote he suggested that without US tight oil production, this year's conference would have been dominated by another oil crisis.

Although shale energy development certainly deserves to be called revolutionary, crediting it with averting an oil crisis calls for a bit of "show me." Yet with problems in Libya, Nigeria and Iraq, while Iranian oil remains under sanctions and oil demand picks up again, even at first glance Mr. Yergin's assertion looks like more than a casual, lunch-speech sound-bite.

Start with current US tight oil (LTO) production of over 3 million barrels per day (MBD) and estimates of future LTO production rising to as much as 8 MBD--also the subject of much discussion at the conference. As recently as 2008 total US crude oil output had fallen to just 5 MBD and was only expected to recover to around 6 MBD by 2014, with minimal contribution from unconventional oil. Instead, the US is on track to beat 2013's 22-year record of 7.4 MBD, perhaps by as much as another million bbl/day.

With conventional production in Alaska and California declining or at best flat, and with Gulf of Mexico output just starting to recover from the post-Deepwater Horizon drilling moratorium and subsequent "permitorium", the net increase in US crude production attributable to LTO today is in the range of 2.5-3.5 MBD and growing, thanks to soaring output in North Dakota, Texas and other states.

That might not sound like much in a global oil market of over 90 MBD, but it brackets the IEA's latest estimate of OPEC's effective unused production capacity of 3.3 MBD. Spare capacity and changes in inventory are key measures of how much slack the oil market has at any time. When OPEC spare capacity fell below 2 MBD in 2007-8, oil prices rose sharply from around $70 per barrel to their all-time nominal high of $145 per barrel. It took a global recession and financial crisis to extinguish that price spike, and high oil prices were likely a major contributor to the recession.

Global oil inventories are now a little below their seasonal average for this time of the year. Compensating for the absence of over 3 MBD of US tight oil would require higher production elsewhere, lower demand, or a drain on those inventories that would by itself push prices steadily higher.

Concerning production, if the US tight oil boom hadn't happened, more investment might have flowed to other exploration and production opportunities. However, for non-LTO production to have grown by an extra 3 MBD, companies would have had to invest--starting in the middle of the last decade--in the projects necessary to deliver that oil now. Were that many deepwater and conventional onshore projects deferred or canceled because companies anticipated today's level of LTO production more than 5 years ago? And would Iraq, Libya and Nigeria be more reliable suppliers today if US companies hadn't been drilling thousands of wells in shale formations for the last several years? Both propositions seem doubtful.

As for adjustments in demand, US petroleum consumption is  already over 8% less than in 2007. And as we learned in the run-up to 2008, much of the oil demand in the developing world, where it has grown fastest, is less sensitive to changes in oil prices than demand in developed countries, due to high levels of consumer petroleum subsidies in the former. Petroleum product prices in the latter must increase significantly in order to get consumers there to cut their usage by enough to balance tight global supplies. That dynamic played an important role in oil prices coming very close to $150 per barrel six years ago, when average retail unleaded regular in the US peaked at $4.11 per gallon, equivalent to nearly $4.50 per gallon today.

So to summarize, if the US tight oil boom hadn't happened, it's unlikely that other non-OPEC production would have increased by a similar amount in the meantime, or that OPEC would have the capability or inclination to make up the resulting shortfall versus current demand out of its spare capacity. Demand would have had to adjust lower, and that only happens when oil and product prices rise significantly. With oil already at $100 per barrel, it's not hard to imagine such a scenario adding at least $40 to oil prices--just over half the 2007-8 spike. Combined with higher net oil imports, that would have expanded this year's US trade deficit by around $230 billion. US gasoline prices today would average near $4.60 per gallon, instead of $3.54, taking an extra $140 billion a year out of consumers' pockets.

We can never be certain about what would have happened without the current surge in US tight oil, but for a reminder of how a similar situation was characterized just a few years ago, please Google "2008 oil crisis".  If we found ourselves in similar circumstances today, then the heated Congressional hearings and angry consumers to which Mr. Yergin alluded in his remarks would almost certainly have been major topics at EIA's 2014 conference, instead of the realistic prospect of legalized US oil exports.

A different version of this posting was previously published on the website of Pacific Energy Development Corporation.