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Natural gas industry and markets organization

At the inception of the natural gas industry, the vertically integrated company (VIC) was the prominent form of organizational structure. In this type of organization, a single operator controls the entire value chain, from exploration and production to transmission and distribution to end users (FIG. 1). The main drive for the emergence of VICs can be found in the low energy density (kWh/m³) of natural gas relative to liquid fuels. In fact, the energy content of natural gas is almost 1,000 times less than the energy content of crude oil.

Micucci Fig 01

FIG. 1. Natural gas value chain.

The result is that the investment in gas transportation, being capital-intensive, requires reductions in business uncertainties and economy of scale to curb capital expenditure. The large scale lends to transport and distribution systems the characteristic of a natural monopoly, since a single operator can supply energy at lower cost relative to the sum of costs borne by a number of small companies.

The VICs were in the position to exclude competing suppliers from the use of the transmission infrastructure. Preventing any competition, they could rely on a broad customer base to raise the cashflows required to remunerate their large invested capital costs and to cover the debt service.

Due to their natural monopoly characteristics, gas transmission and distribution systems are regulated either as public utilities or as government monopolies. Political systems generally promoted the formation of large companies to pursue reasonable prices for energy; consumer access in less profitable areas (with help from incentives and subsidies); and long-term, strategic investments in the public interest.

Gas market foundations. Plentiful gas reserves were discovered in the U.S. during the course of oil exploration. Prices were low because of competition among suppliers for limited end-use markets. After World War 2 ended, the rapid expansion of pipeline networks began to absorb some of the surplus reserves, and demand grew. However, prices remained low because both wellhead and distribution systems had become regulated. Since the gas was significantly lower-priced than oil and coal (neither of which was regulated), an excess of demand accumulated.

The regulated pricing mechanism was based on “cost-of-service,” under which prices were set by historic costs of individual facilities, plus a reasonable return on investment. Since the costs of individual facilities may not represent the overall investment in exploration and production, producers were not encouraged to develop additional supply to meet growing demand.

In the 1970s, the steep rise in energy prices due to the oil crisis set in motion significant demand for natural gas. The gas prices control at wellhead set forth by regulatory authorities brought about supply shortages that resulted in soaring utility bills. An increasing number of industrialized countries, notably those with abundant resources, launched liberalization policies to implement market mechanisms to promote competition, reduce costs and increase efficiency. The liberalization process entailed the progressive dismantling of the VICs.

Liberalization of the gas market. Dislodging the wellhead price control was the first phase of the liberalization process, followed by the opening of markets to allow competing operators for the third-party access to gas transmission infrastructures to spark the competition mechanism. The key element to achieve this objective was unbundling, or the separation of the ownership of transport infrastructures from their operation. Unbundling can be achieved in three different ways:

  1. Ownership unbundling. The distribution systems are sold to an independent operator, over which the seller has no stewardship control. The major drawback of this model is the weakening of domestic companies relative to large international suppliers, which are often state-owned, monopolistic companies. In these cases, the energy security of the importer countries becomes vulnerable.
  2. Independent system operator (ISO). The infrastructure property remains in the hands of the former integrated companies, but its operation is entrusted to an independent legal entity subject to strict monitoring by a regulatory authority. The lack of integration of regional networks is reportedly the result of infrastructure ownership retention by the former monopolists.
  3. Independent transmission operator (ITO). In this unbundling model, the energy company owns both the infrastructure and the operating company. However, jurisdictions mandate that this latter be self-contained and subject to stringent regulations to prevent bias for the parent company.

The second stage of liberalization involved the establishment of an independent, impartial and transparent energy authority committed to regulatory function and supervision. This authority ensures effective opening of markets and protection of consumers.

With the opening of markets, the former monopolies had no more interest in investing in new infrastructure. To spur investments in strategic infrastructures of public interest, regulations allowed for temporary exemptions to third-party access. The exemption was also allowed for old projects, until the transportation capacity was committed to long-term contracts signed in the past.

Generally, the ultimate objective of a liberalization policy is the implementation of a commodity-type market. However, the achievement of this goal is conditional on the endowment of abundant gas reserves and on a sufficient number of suppliers willing to compete in the gas market. This was the case in the U.S., Canada and the UK, which have high shares of domestic supply from small- and medium-sized gas fields, along with a substantial absence of swing producers (i.e., a supplier with a large production capacity that is capable of influencing prices and market balance).

In some importer countries, liberalization involves only the unbundling of onshore transportation systems from gas marketing activities, establishing third-party access on both pipelines and LNG terminals, and permitting customers to choose their own suppliers. The resulting gas industry can be defined as “contract gas-to-gas competition market” instead of “commodity gas-to-gas competition.”

The independent (often small-sized) operators of liberalized importer countries may have little bargaining power vis-à-vis the large, state monopoly companies of most export countries. Thus, the market opening in net importer countries may not be the best arrangement for the gas industry organization.

Gas-to-gas markets. A commodity-type market for natural gas has developed only in North America and, to a lesser extent, in the UK as the result of the liberalization process that unfolded in the 1970s.

The liberalization goal was the creation of a liquid and transparent market where suppliers and customers could interact. In doing so, consensus prices are established. In the marketplace, prices are of utmost importance as they signal the scarcity or surplus of a commodity and suggest the efficient allocation of capital, since they may indicate a need for investment in production capacity. The role of price as a market signal explains the cyclic nature of investment that characterizes the hydrocarbon processing industry.

By the mid-1980s, the process of price deregulation in the U.S. was largely completed, and a gas-to-gas market was fully implemented. The transition from the regulation regime to a commodity-type market structure was made possible by the combination of several factors:

  • Industry was made up almost entirely of private-sector companies
  • The availability of small- and medium-sized reserves was largely distributed throughout the region
  • Competitive suppliers enjoyed non-discriminatory access to transmission and distribution systems.

In the early days of the Canadian gas industry, the regulation framework developed differently. However, the transformation of the U.S. gas markets impacted the Canadian market through integrated transmission systems and import/export operations. Consequently, with the “hallowing agreement,” the price control system was dismantled and a competitive market was set in motion in Canada, as well.

In the UK, the gas industry was founded with the discovery of oil and gas reserves in the North Sea. Since all necessary conditions were met, the UK moved from a government monopoly to a liquid commodity market. The reorganization of the UK gas market began with the privatization of British Gas, a monopoly seller to UK customers and a monopsony buyer for all North Sea gas. After that time, the process developed in much the same way as the U.S. system—through the creation of a regulatory agency to oversee the private sector, the opening of the transmission system to third parties, releasing customers from their take-or-pay contractual obligations, and setting in place regulatory actions to organize the transmission system into a single market.

Gas hubs. Hubs are the central piece of a commodity market. These can be categorized as physical hubs or notional points. The former is placed where transmission lines and distribution networks converge, and their physical interconnections bring the gas flows together from different sources and redirect it to market areas. In the hubs, natural gas can be freely traded and moved at short notice through the market mechanism, and this provides the basis for both spot market trading and futures trading.

The notional points are virtual hubs, sometimes referred to as market centers or virtual points of exchange. These platforms are typical of markets that have a limited number of trunklines. Hence, the notional points are not related to pipeline junctions, where trading of physicals takes place, but rather to an entire infrastructure system—e.g., a state grid. These points are abstract places located between import/export terminals and receipt points.

Once the gas has passed the entry point, it is considered to be in the hub and both the utility and transportation capacity can be traded. These centers generally offer several services:

  • Facilitate the physical coverage of short-term receipt/delivery balancing needs so that if a single operator finds difficulty in adjusting the extra demand within its customer portfolio it can, for example, purchase the needed extra gas volume in the hub from other market participants that are facing excess supply
  • Expedite and improve the overall natural gas transportation process
  • Capacity release programs
  • Title transfer services between parties that buy, sell or move their natural gas through the center.

Henry Hub is one of the most widely-known hubs. Located in Erath, Louisiana, the hub interconnects nine interstate and four intrastate pipeline systems and has connectivity to gas storage facilities. Henry Hub is a very liquid market that has become a reference point for national quotations for physical gas trading, and it is the delivery point of the futures market trading on NYMEX.

In the UK, the National Balancing Point (NBP) is the hub for the gas-to-gas market. Asia and Continental Europe have fragmented pricing points, and the gas prices are often indexed to a basket of substitute energy products, including crude oil. In these cases, the natural gas price only partially reflects the demand-supply dynamics.

Structure of import markets. Many countries do not have sufficient, if any, domestic energy resources. To meet demand, they must rely on imports of natural gas. The gas markets in these countries have developed differently from the commodity-type markets—not only because they involve complex cross-border operations, but also because exporter countries are generally interested in maximizing their income as compensation for the depletion of their finite resources, while keeping the gas marketable. This philosophy collides with the development of a commodity market and leads to a contract market, where long-term sales and purchase agreements with minimum pay and replacement value, or market value pricing, dominate the gas landscape.

The international commerce of natural gas entails high specificity of investment—i.e., highly specialized and unique investment to support specific, large-scale gas supply that joins import, export and transit countries into tight relationships. These investments have long lead times between project initiation and completion, with significant front-end loads. Consequently, to ensure security of supply for consumers and security of demand for suppliers, long-term contracts have been introduced. These impede the creation of marketplaces for both LNG and pipeline gas transmission and classify import-dependent countries as contract markets.

Since investments in natural gas assets are generally debt-financed, long-term contracts typically include take-or-pay or minimum offtake provisions to secure the payment for the minimum volume contracted over the duration of the contract (20 yr or more), regardless of actual offtake. In this way, the investment payback and the expected minimum return on the invested capital are safeguarded.

The take-or-pay clause can also be seen as a risk-sharing tool. The typical provision is arranged so that the buyer agrees to take on the volume risk (marketing risk due to demand shocks), and the seller agrees to take on the price risk due to the price volatility of alternative fuels.

The principle of market value pricing was conceived (in opposition to the cost-plus pricing model for town gas) during the marketing decisions for the exploitation of the Groningen gas field as part of the Dutch government’s goal of extracting the maximum rent income from the field. The rationale behind the market value principle stems from the consideration that natural gas can be substituted for coal, light fuel oil (LFO) and heavy fuel oil (HFO), provided that it is priced in relation to competing fuels. In other words, the replacement value principle establishes fuel parity at the burner tip.

Accordingly, the price of natural gas was linked to the price of alternative fuels likely to be displaced by different types of consumers, which do not need to pay more for gas than for alternative fuels—although they would not pay much less, either.

In 1962, the market value concept was implemented for the first time for the export of natural gas to Germany, France and Belgium from the Netherlands. For each individual import country, the replacement value of the natural gas price was calculated on the basis of the average value of fuels in the buyer’s portfolio. Then, the price to be paid at the Dutch border (i.e., the netback price) was obtained by subtracting from the replacement value the cost to bring natural gas from the delivery point to the customer, along with the related marketing incentives. As the prices of substitute fuels change over time, the gas price must be adjusted to reflect these variations.

Long-term contracts also include price review provisions to reflect changes in the netback prices. These changes are due to the volatility of alternative fuel prices, technology development and changes in the energy mix of import countries.

The long-term contracts framework introduced for marketing the Groningen gas served as a reference point for many export contracts. Over time, variations and innovations have been made to consider the specificity of investment, to address the issues related to the distances between production sites and consumer markets, and to accommodate the energy policies of the parties. For example, in Algerian contracts, natural gas was pegged to the free-on-board (FOB) price of Light Algerian crude oil; in the UK contracts, the inflation indicator has a significant weight; in countries where the nuclear sector has an important share in the energy mix, natural gas is also electricity-indexed, and so on.

By and large, the netback and indexation formula for natural gas pricing, according to the market value principle and to current business practice, can be represented as shown in Eq. 1:

     Gas price = Netbacko + ∑jwj × aj × cj × Indicatorj           (1)

where:

  • Netbacko = Netback at the month (o)
  • wj = Weight of Indicatorj
  • aj = Pass-through factor (if set to 1, only the supplier assumes the price risk)
  • cj = Conversion factor for unit prices for fuels into units of gas price
  • Indicatorj = Indexation factor to consider the variations of agreed parameters between month (m) and month (o).

When the parameter is LFO or HFO price, the relevant indicator is (LFOm  – LFOo) or (HFOm – HFOo), for example. Note: Although the price set by the market value principle did not represent the price discovery mechanism of a commodity market, the fuel parity at the burner tip enabled a substantial increase in exploration and exploitation for gas and justified the further expansion of its use.

Structure of export markets. For a given export country, the netback price differs depending on the destination country; the more distant the end market, the lower the gas price. To avoid the use of lower-priced gas destined for more distant markets as a mechanism to undercut higher-priced gas in markets closer to the border, destination clauses were typically provided in contracts. These destination provisions prevent gas-to-gas competition.

However, in the current trend of new market openings, suppliers are increasingly waiving these destination provisions, thereby providing markets with greater flexibility. Moreover, the rise of global markets is pressuring traditional indexation structures, so that the percentage of gas prices linked to oil tends to dwindle, while the share of contracts that factor in spot or hub pricing tends to increase.

Although an ever-increasing share of LNG is exchanged on the spot market under short-term contracts, long-term contracts and the market value notion still apply to LNG trade in much the same way as pipeline gas. As LNG is commonly accepted as a substitute for crude oil, the indexation formula can be described as shown in Eq. 2:

     LNG price = A + Slope × PB           (2)

where:

  • A = Constant considering both liquefaction and transportation costs, quoted in $/MMBtu
  • Slope = Coefficient linking the price benchmark (PB) to the LNG price
  • PB = Price benchmark (Brent crude oil, Japan Crude Cocktail, Henry Hub, NBP, TTF, or other hubs), quoted in $/MMBtu.

Sometimes, to smooth the effects of market shocks, cap and floor price provisions are made. In these cases, the curve of LNG prices vs. the price benchmark become S-shaped.

Takeaway. The gas industry structure and markets differ by region, according to resource endowment and economic model preference (i.e., commodity market mechanism vs. natural monopoly). The U.S., Canada and the UK, being reliant on their own resources and having a relatively large number of competing players, have commodity market organizations. By contrast, Continental Europe, Japan and South Korea, being reliant on natural gas imports, are basically long-term contract industries.

The long-term contract concept has been recognized as a major instrument for accessing reliable and affordable sources of energy essential to the well-being, growth and competitiveness of energy-dependent economies. On the other side, the market value principle ensures reliable sales volumes for sellers at prices close to what can be sold in a competing environment while attaining the maximum rent income without losing competitiveness. GP

 

Author Pic Micucci

Lorenzo Micucci is a Senior Director at Siirtec Nigi SpA. He has more than 30 yr of experience in the engineering and contracting industry, most of which have been spent in the natural gas sector. In 2001, he joined Siirtec Nigi in Milan, where he directed the process design and operations department and the research and development department. During his time as R&D head, three patents have been granted to Siirtec Nigi, two of which have been implemented on an industrial scale. At present, he is the Senior Director of the technology and marketing departments. Mr. Micucci also worked for Saipem (Snamprogetti) as a Plant Designer for integrated gasification combined cycle and gas-to-liquids plants. He holds an MS degree in chemical engineering from the University of Bologna in Italy and is enrolled as a Qualified Engineer in the Register of Milan Order of Engineers.

 


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