next wave of demand, driven in large part by more stringent power generation environmental regulations. There may be increased contracting tension for capacity between traditional LDCs and electric power generators unless pipelines can be creative in their operations and services in supporting the needs of power generators.
Most LDCs will retain their storage. There are minimal amounts of storage available and much of the pipeline infrastructure is used during the summer to inject natural gas into storage.
Since spare seasonal pipeline capacity may not be available, incremental pipeline infrastructure will be needed to serve an increasing summer power generation market.
Power generators will have to be continually creative in their use of pipeline capacity release opportunities, parking, lending services and other pipeline services as well as operations communication and coordination with the pipelines’ Control Operators to meet summer and winter requirements.
Marketers can play a key role in providing gas delivery capacity to MISO region electric power customers. While LDCs and electric companies hold a majority of capacity on the pipelines, marketers are able to assign long-term capacity to their customers who may be companies that require capacity for future electric power generation projects.
Timing Issues
There is a gap between the timing when the market indicates it is ready to commit to new infrastructure projects and how long it takes supply and infrastructure to respond. If infrastructure utilization approaches 100% utilization, the value of infrastructure capacity increases in the market. The problem is even though prices increase, this usually cannot result in an immediate increase in capacity.
Capital Cost Recovery Uncertainty
Major infrastructure projects today are often sponsored by producers who are reluctant to commit (i.e., cost of warranty) for longer than 10-15 year terms. Since regulated recovery of capital is usually for longer terms, pipeline and storage infrastructure developers are uncertain of recovering new capital investments. An approach to incentivize pipelines and power generators, in particular, is needed to move forward with greater certainty about regulatory cost recovery.
Less Spare Flexibility and Shorter-Term Contracts
Most current infrastructure was sponsored and constructed during a highly regulated environment when the market supported development with long term purchase, sales and transportation contracts. The demand increase of the past twenty-five (25) years absorbed much of the previously excess supply and capacity in the system, so demand increases over the next twenty years could have a more difficult time aligning new supplies to infrastructure developments.
LDCs, which have retreated to “short-term” contracting (3, 5, 7 years versus the 15 to 20 year contracts of old which provided cost-recovery certainties to pipelines) may be particularly fearful of entering into long-term contracts out of concern that regulators may find longer term contracts “imprudent” at a time when their transportation infrastructure and supply options are changing rapidly in today’s market. This same concern is a major problem for regulated electric utilities as well. This type of regulatory uncertainty is a major impediment to pipeline and storage infrastructure financing and a common gas and electric
interdependency issue.
Adding to this short-term contracting environment and increasing pipeline capacity uncertainty are the standard right of first refusal (RORF) provisions of firm transportation contracts. These encourage continuous “contract rollover” by firm contract shippers. Under ROFR, the current customer must match the rate (up to max rate) that another customer is willing to pay in order to retain the capacity. Existing customers have the security of knowing that the ROFR provisions will allow them to keep that capacity and match any offer up to the maximum rate, ad infinitum. Pipelines, therefore, are handicapped in their ability to market the capacity since a customer can retain the capacity even though others in the market are willing to pay more or contract for greater quantities over a longer term.
In essence, there are four (4) options to obtain firm capacity:
1. Released capacity from existing shipper;
2. Bundled capacity with supply from marketer or asset manager;
3. Contract directly with pipeline or obtain a customized tariff service; or, 4. Pay to build capacity.
Other Uncertainties
A number of variables could change, resulting in either more or less natural gas market or production growth and in turn, impact natural gas infrastructure. Important demand variables such as natural gas as a transportation fuel, limitations on the use of hydraulic fracturing, LNG exports, coal-fired capacity, economic growth, electricity demand growth, nuclear power growth and gas-to-liquids and oil production mix, and others that impact natural gas and electric infrastructure interdependency.
Reviewed below are the four (4) capacity options in more detail. The Right of First Refusal (“ROFR”) provisions in firm transportation contracts are a problematic issue for potential firm customers (or shippers) that may value the capacity more that the current holder of the firm capacity. In our review of the MISO-identified pipelines’ firm customer contracts, the majority of contracts will enter the ROFR period starting in 2014 through 2017. Potential gas-fired power generators must be aware of this situation and be prepared to act accordingly, as this may impact whether or not firm capacity may be obtained.
1. Released capacity from existing shipper
In addition to firm transportation capacity, there is also interruptible capacity. Interruptible capacity is only available if there is capacity that is not being used by a firm transportation shipper and is bought from the pipeline.
There is also a category of firm transportation capacity called “released capacity”. Released capacity is capacity that a holder of firm transportation can release via a pipeline’s electronic bulletin board (EBB) on a recallable or non-recallable basis. Recallable capacity resembles interruptible capacity and the primary holder may call-back the capacity should they need it.
So essentially, recallable firm capacity resembles interruptible capacity and non-recallable capacity resembles firm capacity. Along these lines, to obtain capacity, the power generator could either strike a deal with an existing holder or bid during an open season related to the ROFR capacity up to the maximum rate to become a primary holder of capacity.50
2. Bundled capacity with supply from marketer or asset manager
Marketers and asset managers are mostly firm capacity holders or managers of released capacity. Large producer-marketers hold vast amounts of firm transportation capacity that they bundle with gas supply for deliveries. Asset managers manage the gas supply and transportation contracts for another party. Typically a shipper holding firm capacity on a pipeline or a number of pipelines may temporarily or longer, release all or a portion of their unused capacity and often with associated gas production, relinquish the capacity and supply to an asset manager. The asset manager will use that capacity to manage the requirements of the releasing shipper and when there is excess or unneeded capacity, uses that capacity to make releases or bundled sales to third parties.
50Ideally in auction practice, a party that wanted to pay above the maximum rate could “out-bid” the existing ROFR shipper. However, this is not in the FERC’s Order No. 712 regulations.