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CBM economics

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The commercial success of any gas project depends on a number of critical factors including gas production rates, capital requirements, operating costs, gas markets, and economies of scale.[1] In conventional gas projects, gas rates are known from well tests before development, and capital costs for water processing and disposal typically are deferred until later in reservoir life. High-value gas contracts can be established at project startup with reasonable certainty that a specified plateau rate can be maintained for many years.

In contrast, coalbed methane (CBM) reservoirs initially produce little or no gas and require a large initial capital commitment for well drilling, stimulation, and water handling. Because it may be several years before commercial gas rates are achieved, if at all, it can be difficult to obtain long-term gas contracts or financing. As a result, CBM projects require more work to fully quantify and manage the risks involved. Technical risk can be reduced through reservoir data analysis, pilot projects, and staged reservoir development. Commercial risks can be reduced by the use of decision analysis, fiscal incentives, and creative project financing.

Assessing economic viability

Appraising and developing CBM resources require a series of decisions and associated investments over an extended period. These projects are ideal candidates for applying decision analysis or real-option evaluation methods to plan and guide the process.[2][3][4] Both methods can be used to create a decision pathway for evaluating a prospect and characterizing its value at each decision point. As part of the decision analysis process, profitability measures including net present value, internal rate of return, investment efficiency, and payout should be calculated.[5][6] Net present value, which is determined by discounted cash flow analysis, is the most appropriate method to assess the value returned by a CBM project. Investment efficiency is commonly used as a secondary ranking tool to allocate capital among projects in a capital-constrained environment.[6] In CBM projects, the use of payout as a financial performance indicator is generally misleading because of the nature of the cash flow streams; consequently, it should not be used as a primary decision criterion.[7]

Fiscal incentives

A variety of tax exemptions, tax deductions, tax credits, capital assistance programs, and price subsidies have been developed to encourage CBM development and coal-mine methane recovery projects.[8][9][10]The U.S. CBM industry was brought to maturity by the Federal Sec. 29 tax credit, which was designed to promote the development of unconventional fuels. Fig. 1 shows that although the subsidy expired at the end of 1992, drilling and completion activity continued, resulting in nearly 6,000 CBM wells by 1994 and substantially increased gas production.

  • Fig. 1—The effect of the Section 29 tax credit on CBM drilling and production in the United States. Successful drilling before the expiration of the federal tax credit at the end of 1991 provided the impetus for continued CBM exploration and development in the mid-1990s.

    Fig. 1—The effect of the Section 29 tax credit on CBM drilling and production in the United States. Successful drilling before the expiration of the federal tax credit at the end of 1991 provided the impetus for continued CBM exploration and development in the mid-1990s.

Other countries have developed similar incentives.[8] Poland provided a 10-year corporate tax exemption through the late 1990s to encourage oil, gas, and coal-mine methane prospecting. China passed a law in 1998 exempting CBM producers from royalties and land occupation fees for production of up to 70 Bscf annually. Some countries provide tax deductions to CBM projects because they are considered to provide a clean alternative to burning coal or oil.

International issues in CBM development projects

While the U.S. domestic CBM industry developed and matured from 1975 to 2000, international CBM development has languished because of a variety of technical and commercial issues. While many of the commercial issues are common to both conventional and unconventional gas development, there are a number of issues specific to CBM development.

Regulatory and payment issues

Because the international CBM industry is relatively immature, there are numerous hurdles in negotiating and implementing production-sharing contracts (PSCs) and technical service agreements.[11] These hurdles are less daunting in more-developed countries, which tend to have efficient legal and regulatory systems that provide protection and legal recourse. In contrast, developing countries and transitional economies tend to have less-dependable, incomplete, or dysfunctional systems, creating numerous problems.

In some countries, there is overlap and rivalry between various licensing and regulatory agencies, creating considerable confusion. In some cases, provincial governments have signed contracts with foreign companies to develop a CBM project before national laws were established defining jurisdiction. When national laws were enacted, these took precedence over provincial laws, negating the ownership rights of the foreign companies without eliminating their work commitments. These cases show that it is imperative for a company to understand which government agencies have legal authority to negotiate and regulate agreements.

By their nature, CBM resources tend to be located onshore and generally in land-locked areas. This is not a serious problem in developed, free-market economies with deregulated natural gas markets. However, in developing countries, the operating firm may be faced with selling gas into a limited domestic market and may receive payments in a currency that is not fully convertible. Under these circumstances, a foreign firm should consider creative payment alternatives such as trading gas for crude-oil equivalent for export sales or using local currency for operations but taking net profits in a convertible currency for repatriation. Foreign firms also should maintain expertise in project financing and risk hedging for these ventures.[12][13][14][15]

Production-sharing contracts

Most international CBM PSCs evolved from petroleum PSCs.[11] In general, CBM PSCs contain commonly accepted principles and requirements with regard to royalties, severance taxes, and income taxes. Some contracts require an additional profit split (X-factor) with the government after payment of all expenses, royalties, fees, and taxes. Additionally, some PSCs limit the maximum annual rate of return that a foreign enterprise can earn on gas production. In essentially all PSCs, the foreign company takes on the majority of, if not all, financial risk during exploration and appraisal. Many countries limit the ownership share of production that the foreign company can hold, ensuring that the company remains a minority owner. Most contracts in developing countries also require that operatorship revert to a national company or government-owned enterprise at a specified future date.

Many PSCs also contain performance requirements that the foreign operator must meet. These may require mandatory training of nationals and/or a fixed percentage of jobs reserved exclusively for national employees. Some contracts have local content clauses in which a fixed percentage of materials, labor, and services must be provided by national sources rather than obtained through global markets. PSCs also may contain back-in clauses, which allow a domestic company to take an ownership interest in a CBM reservoir after it is demonstrated to be commercial. Most PSCs in developing countries do not provide specific terms regarding pricing and marketing of produced gas. The contracts contain vague language and assurances that the operator has the freedom to market produced gas in domestic natural gas markets, which, in most developing countries, are fragile, fragmented, or nonexistent. This lack of clarity generally leads to lengthy gas sales negotiations once commerciality is declared and extends the time frame before the gas reserves can be monetized.

Access to gas markets

In the U.S., development of the CBM industry was facilitated by access to a fully integrated gas pipeline system into which early low-volume gas production could be sold and the existence of deregulated natural gas markets to purchase the available gas. Other countries with fully developed market economies (Canada, Australia, and western European countries) also possess highly developed gas pipeline systems and liberalized (if not fully deregulated) natural gas markets. Some economically developed countries have not liberalized their natural gas markets (Japan, Korea) as a matter of national energy policy or national security priorities.[16][17]

Developing countries typically do not have an extensive pipeline infrastructure to transport gas or a spot market to purchase produced gas. In addition, many countries will not allow foreign firms to invest in infrastructure projects, thus limiting their ability to transport produced gas to a domestic marketplace. Operators usually are forced to flare produced gas from early appraisal and pilot wells, although some of this gas may be used as lease fuel. As reserves are being proved up, long-term sales contracts can be pursued with domestic purchasers. Potential market segments for natural gas include (given in order of value to the supplier) power generation, chemical and industrial feedstock, compressed natural gas for vehicles, town gas for residential and commercial heating, and feedstock for manufacturing fertilizer.

Access to operational support services

Growth of the CBM industry in the U.S. relied heavily on technologies and operational practices developed by a competitive oil and gas service industry. Outside the U.S., these services generally are concentrated in basins containing large conventional oil and gas fields. Because many CBM projects are in frontier areas, there may be no locally available field services or materials, resulting in high mobilization costs. Alternatively, oilfield services may be provided by a single state-owned enterprise, making it difficult to negotiate favorable prices and performance guarantees. In some cases, there may be little familiarity with standard CBM operational practices, resulting in learning through trial-and-error. Maintaining high-quality, consistent services in this environment is generally quite challenging.

Environmental considerations

Most developing nations, including China, the former Soviet Union, and eastern European countries, are heavily dependent on coal combustion for energy. In these countries, converting from coal to natural gas will result in significant environmental benefits from reductions in greenhouse gases, coal-mine methane emissions, and air pollutants including NOx, SOx, and particulate matter. CBM can be a viable substitute for coal in many of these countries and has the added benefit of improving mine safety by producing the gas before mining the coal seams.

Over the past decade, several international conferences have focused on stabilizing greenhouse gas concentrations in the atmosphere, and many countries have signed documents committing themselves to this goal.[18] Methods to achieve stabilized levels are still under discussion but may include emissions taxes, external offsets, and tradable permits.[8][19][20] Tradable permits appear to be the most popular of these alternatives and would require that participating countries be issued permits to emit carbon dioxide at a specified level. To exceed these levels, a given country would have to purchase or lease permits from other countries with excess capacity.[8] Environmental programs such as these could substantially increase the value of CBM projects that reduce coal combustion, reduce mine emissions, or sequester CO2 through injection of this gas into coal reservoirs. Such a program could result in additional incentives for international energy companies to participate in CBM projects. This concept is likely to grow in importance as global concerns over environmentally sustainable economic activity continue to grow.[21][22]

Project financing and international capital resources

Obtaining capital to fund CBM projects can be a substantial hurdle. Historically, oil and gas companies have funded development projects from operating cash flow when sufficient cash is available and the project risk is low. However, CBM projects possess a number of financing, regulatory, and risk components that make project financing and international capital resources attractive alternatives.[14][23]

Project financing

There are five principal features of a CBM project funded and structured with project financing. First, the project is established as a separate company and operates under a concession obtained from the host country government. This structure protects the assets of the equity investors, allows creditors to evaluate the risks of a singular project, and guarantees that cash flows from the project can be recognized and used to service project debt.

Second, the project manager, or sponsor, provides a major portion of the project equity, thus linking the provision of finance to project management throughout its life. Third, the project entity enters into comprehensive, long-term contracts with suppliers and customers. Take-or-pay contracts typically are used to guarantee revenues, and long-term supplier contracts are established to control costs. The resulting predictability of net cash inflows to long-term contracts eliminates much of the project’s business risk, which allows heavy debt financing without creating financial distress.

Fourth, the project company operates with a high debt-to-equity ratio, and lenders have only limited recourse to the equity holders or to the government in the event of default. Fifth, the project contains a partnership and management structure that aligns the appropriate expertise of a partner with appropriate risks and rewards. For example, the lead equity partner in the project must have expertise in managing finance, currency, and political risk, while the operator needs to hold an equity interest in the project to ensure its performance.

International capital resources

Domestic capital can be very difficult to obtain for project financing in developing nations and economies in transition. Reasons for this include the limited information available to capital owners regarding the scope and potential of available projects, the large scale of investment needed to finance a project, and the perception that the political and commercial risks are too great. Because of these issues, resource development projects in these countries commonly are funded through broad joint ventures between private sector corporations, governmental units, and international lending institutions. These institutions provide access to capital through grants, low-interest loans, loan guarantees, and venture capital.[9][14][24]

Mulilateral institutions, such as the World Bank, are funded by contributions from member countries.[24] The World Bank finances numerous environmental and energy infrastructure projects in developing countries. Regional multilateral banks play a role similar to that of the World Bank. Coalbed and coal-mine methane projects have been funded in China by the Asian Development Bank and the Asia Pacific Economic Cooperation. The European Commission has funded projects in Poland. The European Bank for Reconstruction and Development and the African Development Bank could fund projects in their client countries. Another source of assistance is the United Nations Development Program, which manages technical assistance projects under the Global Environmental Facility. This entity provides resources needed to demonstrate technologies, develop training programs, and provide technical assistance in creating public policy in countries focused on encouraging environmentally favorable projects and practices.

Most industrialized nations also provide assistance to developing countries through bilateral international aid and energy, environmental, and trade agencies, which may include coalbed or coalmine methane projects.[24] In the U.S., the U.S. Agency for Intl. Development supports efforts to achieve sustainable economic and social progress in developing countries and economies in transition. Aid also may be available to help nations meet obligations to limit greenhouse gas emissions through the U.N. Initiative on Joint Implementation, which is a pilot program to execute an article of the U.N. Framework Convention on Climate Change. Various countries also support trade agencies to provide financing for companies and projects. U.S. government trade agencies include the Overseas Private Investment Corp., the Trade and Development Agency, the Export-Import Bank, and the Small Business Admin.

Unconventional private financing of projects also may be available through a number of venture capital firms.[23][24] These companies invest in projects with moderate risk balanced by high potential returns. Some firms specialize in oil and gas investments, alternative energy projects, or have a regional focus. Significant growth has occurred recently in financing projects that lead to reductions in greenhouse gas emissions. Electric utilities, other major energy producers, and consumers have been driving this market. A few companies are specializing in brokering greenhouse gas emissions credits, and this market has grown substantially since the conclusion of the Kyoto accords in 1997.

References

  1. ↑ Kuuskraa, V.A. and Boyer, C.M. II. 1993. Economic and parametric Analysis of Coalbed Methane. Hydrocarbons from Coal, 38, 373-394, ed. B.E. Law and D.D. Rice. Tulsa, Oklahoma: American Assn. of Petroleum Geologists Studies in Geology.
  2. ↑ Newendorp, P.D. 1975. Decision Analysis for Petroleum Exploration. Tulsa, Oklahoma: The Petroleum Publishing Co.
  3. ↑ Aswath, D. 2000. The Promise of Real Options. J. of Applied Corporate Finance 13 (2).
  4. ↑ Amram, M. and Kulatilaka, N. 1999. Real Options: Managing Strategic Investment in an Uncertain World. Cambridge, Massachusetts: Harvard Business School Press.
  5. ↑ Stermole, F.J. and Stermole, J.M. 1987. Economic Evaluation and Investment Decision Methods, sixth edition, 44-99. Golden, Colorado: Investment Evaluations Corp.
  6. ↑ 6.0 6.1 Ross, S.A., Westerfield, R.W., and Jaffe, J. 1999. Corporate Finance, fifth edition. New York City: McGraw-Hill Book Co. Inc. Cite error: Invalid <ref> tag; name "r6" defined multiple times with different content
  7. ↑ Rogers, R.E. 1994. Coalbed Methane: Principles and Practice, 345. Englewood Cliffs, New Jersey: Prentice Hall.
  8. ↑ 8.0 8.1 8.2 8.3 Bibler, C.J., Marshall, J.S., and Pilcher, R.C. 1998. Status of Worldwide Coal Mine Methane Emissions and Use. Intl. J. of Coal Geology 35 (1–4): 283.
  9. ↑ 9.0 9.1 United States Environmental Protection Agency. 1995. Finance Opportunities for Coal Mine Methane Projects: A Guide for Southwestern Pennsylvania. EPA 430-R-95-008, U.S. Environmental Protection Agency, Washington, DC.
  10. ↑ Berggren, L.W. 2001. Recent Developments in the Application of the Section 29 Tax Credit to Coal Seam Gas. Proc., Intl. Coalbed Methane Symposium, Tuscaloosa, Alabama, 257–269.
  11. ↑ 11.0 11.1 Johnston, D. 1994. International Petroleum Fiscal Systems and Production Sharing Contracts. Tulsa, Oklahoma: PennWell Publishing Co.
  12. ↑ Stulz, R. 1996. Rethinking Risk Management. J. of Applied Corporate Finance 9 (3): 8–24.
  13. ↑ Lessard, D.R. 1996. Incorporating Country Risk in the Valuation of Offshore Projects. J. of Applied Corporate Finance 9 (3): 52–63.
  14. ↑ 14.0 14.1 14.2 Brealey, R.A., Cooper, I.A., and Habib, M.A. 1996. Using Project Finance to Fund Infrastructure Investments. J. of Applied Corporate Finance 9 (3): 25–38.
  15. ↑ Eitman, D.K., Stonehill, A.I., and Moffett, M.H. 2000. Multinational Business Finance, ninth edition. Boston, Massachusetts: Addison Wesley.
  16. ↑ Oyama, K. 2000. Japanese Energy Security and Changing Global Energy Markets: Trends and Prospects of Deregulation in Japan. The James Baker Inst. for Public Policy, Rice U. (May 2000).
  17. ↑ Yergin, D., Elk, D., and Edwards, J. 1999. Fueling Asia’s Recovery. Foreign Affairs '77 (2): 36.
  18. ↑ Submission of the United States of America under the United Nations Framework Convention on Climate Change. 1995. US Dept. of State, Washington, DC.
  19. ↑ Schultz, K. 1997. US Environmental Protection Agency’s Promotion of Coalbed Methane. Proc., 1997 Intl. Coalbed Methane Symposium, Tuscaloosa, Alabama, 93–104.
  20. ↑ Options for Reducing Methane Emissions Internationally, Volume II: International Opportunities for Reducing Methane Emissions. Report to Congress, EPA 430-R-93-006 B, U.S. Environmental Protection Agency, Washington, DC.
  21. ↑ Levy, D.L. 1997. Business and International Environmental Treaties: Ozone Depletion and Climate Change. California Management Review 39 (3): 54–71.
  22. ↑ Hart, S.L. 1997. Beyond Greening: Strategies for a Sustainable World. Harvard Business Review 75 (1): 66–73.
  23. ↑ 23.0 23.1 Karolyi, G.A. 1998. Sourcing Equity Internationally with Depositary Receipt Offerings: Two Exceptions That Prove the Rule. J. of Applied Corporate Finance 10 (4): 90–101.
  24. ↑ 24.0 24.1 24.2 24.3 Schultz, K.H. 1999. International Finance and Coal Mine Methane Projects. Proc., 1999 Intl. Coalbed Methane Symposium, Tuscaloosa, Alabama (May 1999) 429–438.

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See also

Coalbed methane

CBM reservoir fundamentals

CBM reservoir evaluation

CBM well drilling and completion

CBM production operations

PEH:Coalbed_Methane

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