Why shale will drive scale

What impact will the dramatic increase in shale gas reserves have on the power project finance market in the US? Keith Larson of Hogan Lovells provides answers

According to recent estimates, over 800 trillion cubic feet of natural gas lies in shale formations beneath the surface of several US states. So prevalent is this resource base – which alone is sufficient to satisfy all US gas demand for 25 years – that industry analysts expect shale gas to account for 50 percent of US gas supply by 2035.

Naturally, the dramatic increase in US shale gas reserves has profound implications for the global oil and gas industry. However, when considered in light of domestic regulatory developments and emerging issues regarding the safety of nuclear energy, the impending surge in US gas production is also expected to influence both the volume and sectoral allocation of project finance in the US.

Ironically, shale gas exploration and production is not likely to garner a meaningful share of project finance activity. The industry is comprised of a few large, and dozens of smaller, independent operators holding acreage in the various shale basins which typically finance their operations through equity capital or corporate borrowings.

Rather, industries that complement the increase in domestic gas supply – or that, because of market and regulatory developments, may rely more heavily on natural gas as opposed to other fuel sources or technologies – should witness significant growth and seek opportunities to access the project finance market.

This article focuses on the potential impacts of US shale gas on the project financing of gas-fired power generation.


Power generation dominates the US project finance market. The low cost of money in the debt market has made project finance increasingly attractive to both developers and utilities looking to finance or refinance the construction of power generation assets. In recent years, renewable energy  projects have captured lenders’ attention in light of the tax incentives and regulatory policies favouring the generation of clean energy.

Conversely, with the exception of two conventional  new-build plants financed in 2010, the market for new greenfield gas-fired generation remains stagnant. However, while US electricity demand is not anticipated to grow substantially for several years, the nation’s generation fleet is poised to undergo a dramatic restructuring later this decade.

In particular, most analysts predict that looming federal regulations controlling  the emission of sulphur dioxide, nitrogen oxide, particulates and hazardous air pollutants are expected to put between 50 to 55 gigawatts of coal-fired generating facilities out of business between 2015 and 2020. None of these facilities, many of which are over 30 years old, have any emissions control equipment. The capital costs to retrofit them and extend their operating lives – particularly amid the uncertainty regarding the cost of compliance with future carbon regulations – are better directed towards constructing new and more efficient generating plants.

While many technologies could be deployed to replace decommissioned coal-fired generation, natural gas-fired power generation should prove most attractive. Indeed, for a utility seeking to clean up its portfolio at the lowest overall cost, gas-fired generation is, at current gas prices, considerably more competitive than wind, solar and nuclear.

As the ongoing development of the nation’s shale gas reserves creates a huge fuel stock for new natural gas plants, independent power producers will recognise additional opportunities to deliver gas-fired power to key regional markets currently served by coal facilities. In fact, the longer gas prices remain low, even more coal facilities may be retired in favour of gas-fired generation than expected.

Gas-fired generation also faces fewer challenges than competing technologies. With no near-term prospects for a federal policy regulating carbon dioxide, developers cannot accurately estimate and model the price of carbon regulation, making the financing of new coal unlikely. Renewable energy projects will continue to represent a measurable and important portion of project lenders’ portfolios. However, as they have low capacity factors and are in many cases limited by significant transmission constraints, such projects are not ideal candidates to replace sizeable retired coal facilities.

Finally, notwithstanding the ramifications of the accident at Fukushima in Japan, capital-intensive nuclear projects are not considered to be financeable without billions of dollars in federal government loan guarantee assistance. Even with that support, the lack of a national solution for storage of spent fuel and radioactive waste, as well as the potential for stricter safety and compliance requirements, are certain to make some utilities and project finance lenders more reticent to finance a nuclear project.


The resurgence of new natural gas-fired power plants, as well as new natural gas pipelines necessary to transport additional gas volumes and potentially even LNG export facilities, will likely lead to an increase in US project finance transaction volumes over the coming years. Assuming gas produced and delivered from US shale deposits will play a role in that expansion, project participants may need to address several additional issues in developing a successful project, including: (i) the credit profile of shale gas producers, many of which may not be investment grade; and (ii) long-term pricing risk (if, for example, a US LNG export industry develops and alters the supply/demand balance in the US market).

These risks alone suggest that longer loan tenors for gas-fired generation projects may be unlikely, insofar as shale gas suppliers to power projects are subject to long-term gas price volatility and may have restricted access to capital.

More importantly, however, project lenders will need to assess the risk of stricter environmental regulation and greater regulatory oversight over shale gas exploration and production to the extent that shale gas reserves are dedicated to new gas-fired power generation. The expansion of US shale gas reserves has focused the attention of federal, state and local governments on the horizontal drilling techniques used by producers to extract shale gas. Known as hydraulic fracturing, the process involves the creation or expansion of cracks, or fractures, in shale formations underground into which water, sand and other (largely chemical) additives are pumped under high pressure. Once fractures are created or expanded, natural gas can more easily flow from the rock through the well to the surface at economic rates.

Many states have implemented and continue to consider rules and regulations that affect the way hydraulic fracturing activities are conducted and disclosed, with several imposing or threatening a temporary drilling moratorium until more studies can be performed. A recent well blowout in Bradford County, Pennsylvania that resulted in a spill of hydraulic fracturing liquids has not inspired confidence among critics of the procedure. Industry participants will be particularly focused on an initial report on hydraulic fracturing to be issued by the Environmental Protection Agency before the end of 2012, and whether its preliminary recommendations will dampen investment plans in US shale gas during the critical retirement period from 2015 to 2020.

For power projects, the gas supply arrangements are a critical piece of the security package as they support the reliable and continuous operation of a generating facility over a number of years at predictable costs. If fuel supply arrangements for gas-fired power plants are linked to designated shale formations, states or producers, the additional regulation, or even prohibition, of hydraulic fracturing activities could disrupt the reliable supply of gas to a borrower.

Project lenders can utilise targeted change in law protections in their financing documents to allocate the risks and costs associated with increased regulation to the project borrower or the gas supplier, but ultimately it will be essential to consider alternative sources of supply in case the primary supplier is unable to deliver.


To embark on a significant portfolio restructuring commencing in 2015, owners of US coal-fired power plants need to start planning and developing replacement generation soon. As project lenders look to finance large gas-fired projects designed to replace aging coal facilities, they will have to consider and allocate certain risks in an era of increasing domestic gas supply.

For although drilling activity has recently declined as some shale operators transition to liquids to capture high oil prices, it appears likely that the domestic gas surplus created by shale gas will drive power generation growth,  and in turn stimulate greater project finance activity, in the years to come.

Keith Larson is a partner in the Washington, D.C. office of Hogan Lovells US LLP and focuses his practice on the development and financing of domestic and international energy and infrastructure projects. The views expressed in this article are solely those of the author.