Race to monetize shale gas assets

Sept. 1, 2012
Unconventional gas is coming online at a time when markets are struggling to manage the transition away from coal-fired power generation.

Unconventional gas is coming online at a time when markets are struggling to manage the transition away from coal-fired power generation.

Roger D. Stark and Dena E. Wiggins, Ballard Spahr LLP, Washington, DC

With several major shale gas players either signing or negotiating long-term gas contracts with electric energy producers, the race to monetize shale gas assets that promise to transform the US energy sector has begun.

Long-term contracts are the mainstay of project finance, and some of the unconventional gas producers appear ready to lead the field into the project development and finance fray. Equally important, unconventional gas reserves are coming online at a time when markets are struggling to manage the impending transition from coal-fired generation (thousands of megawatts of which are being retired) to more environmentally benign resources.

The development of electric generating facilities in the United States has been in a largely moribund state lately because of uncertainties created first by the financial upheaval of 2008, and then by the expiration of certain provisions of the American Recovery and Reinvestment Act of 2009, which included substantial incentives for new investment in the energy sector. Equally important, the risk profile for electric power projects has worsened, owing to federal/state struggles over power purchase agreements and how to bid new generating capacity into wholesale markets operated by Regional Transmission Organizations (RTOs).

Long-term contracts with shale gas producers are only the latest confirmation that "unconventional natural gas will likely produce transformational effects in US energy markets. According to some industry observers, there are sufficient unconventional gas reserves in the United States to last at least several decades, and perhaps close to a century. Equally important, the downward trajectory of natural gas prices and the advantages of gas over coal from an emissions perspective signal a paradigm change for US energy generators and consumers alike.

The next chapter of the unconventional gas revolution will turn on three phases of implementation:

  • First and foremost, the execution of long-term gas contracts that lock in fuel costs while maintaining sufficient price flexibility to avoid contract-busting tactics by parties on the wrong end of a market spike (up or down).
  • Second, the provisions of such contracts will have to survive the scrutiny of project lenders who are eager to finance gas projects but are wary of "merchant risk in projects with less than fully baked-in margins.
  • Third, they will have to remain viable throughout a contract term that, based on prior experience, may range between 15 and 25 years.

There are sound reasons to believe that natural gas prices will remain substantially below the levels they occupied only a year ago. A significant portion of the unconventional gas being produced in the United States is actually a by-product of liquid hydrocarbons that are significantly more valuable in today’s marketplace. For example, a barrel of crude oil can produce dozens of products (multiple specialty fuels and petrochemicals, to name two of the larger categories) with a market value that exceeds comparable quantities of natural gas. Likewise, various constituents of "wet gas (liquid hydrocarbons found with certain natural gas deposits) also have a market value that may exceed the value of the gas itself. Thus, significant quantities of unconventional natural gas are being produced as a by-product rather than as a commodity responding to its own independent price signals.

Moreover, two initiatives with the potential to "move the needle on gas demand are unlikely to occur in the near term and, in any event, would require several years to fully implement. One proposed initiative—the conversion of transportation fleets from gasoline to natural gas—will require substantial capital commitments to implement, and any CAFÉ standard requiring such a change is unlikely to be considered before the November elections. The other proposal—permitting the export of substantial amounts of gas in the form of liquid natural gas—is even less likely to take hold in the near future and will likely be taken up by the administration that takes office after the election.

Market observers estimate that 40,000-60,000 megawatts of existing coal-fired capacity will be retired or mothballed by 2020. As a result of both economic and regulatory pressures, much of that lost coal capacity is likely to be replaced by new gas-fired generation. Thus, low-priced unconventional gas offers both the prospect of a smooth transition away from coal and the benefits of reduced emissions of greenhouse gases and hazardous air pollutants (e.g., mercury). Achieving these benefits will, however, likely require that gas producers provide long-term contracts.

A potentially significant adverse effect of a shale gas boom also should be considered: low-priced gas has the potential to increase energy price volatility and crowd out renewable energy resources. After 40 years of periodic oil shocks, the United States is only now beginning to reduce its dependence on highly price-volatile oil commodities. In this light, it makes sense to avoid the mistake of substituting a gas bias for an oil bias and to consider shale gas as one of many components of a US energy inventory.

Likewise, low-priced shale gas may have the effect of crowding out some renewable energy projects, owing to the absence of a carbon pricing, cap and trade, or other system that recognizes the value of zero-emission electricity production. Duke Energy CEO Jim Rogers has stated that we should avoid an "all gas, all the time approach to electricity generation in favor of recognizing renewables as an integral component of an "all of the above energy policy. In short, we should avoid trading one dominant/volatile fuel source for another.

The willingness of shale gas producers to negotiate long-term contracts with power project sponsors signals a transformational tipping point in the evolution of US power production. With suitable allocation of commercial and regulatory risks and with attention to maintaining a robust resource mix, negotiation of long-term gas contracts to support project debt are the next logical step toward embracing, and advancing, the shale gas revolution.

About the authors

Roger D. Stark is an Energy and Project Finance partner in the Washington DC office of Ballard Spahr. For more than 20 years, he has advised clients on the structuring and financing of a range of domestic and international energy projects, including hydrocarbon, renewable, and clean technology energy projects and related financings, some of which were industry firsts. He represents clients before FERC and state electric utility commissions and advises on energy mergers and acquisitions and public-private partnerships in the US and abroad.

Dena E. Wiggins is an Energy and Project Finance partner in the Washington DC office of Ballard Spahr. She represents clients in federal regulatory matters involving natural gas transportation and storage, crude oil, petroleum products, and hydropower. She has participated in numerous natural gas and oil pipeline rate proceedings and in rulemakings affecting FERC regulation of those commodities. She provides regulatory and transactional advice regarding natural gas storage and contracts, including precedent agreements and rate and tariff advice. She also advises clients on FERC enforcement and compliance.