THE RELATIONSHIP BETWEEN MONTANA’S AND ALBERTA’S OIL AND NATURAL GAS INDUSTRIES: A POLICY ANALYSIS by Julie Ann DalSoglio A professional paper submitted in partial fulfillment of the requirements for the degree of Master of Public Administration MONTANA STATE UNIVERSITY Bozeman, Montana July 1989 P3W Dll 11 APPROVAL of a professional paper submitted by Julie Ann DalSoglio This professional paper has been read by each member of the graduate committee and has been found to be satisfactory regarding content, English usage, format, citations, bibliographic style, and consistency, and is ready for submission to the College of Graduate Studies. Date 'f. i Chairperson, Graduate Committee Approved for the College of Graduate Studies ^ /f Date Graduate Dean Ill STATEMENT OF PERMISSION TO USE In presenting this professional paper in partial fulfillment of the require¬ ments for a master’s degree at Montana State University, I agree that the Library shall make it available to borrowers under rules of the Library. Brief quotations from this professional paper are allowable without special permission, provided that accurate acknowledgement of source is made. Permission for extensive quotation from or reproduction of this paper may be granted by my major professor or, in his absence, by the Dean of Libraries when, in the opinion of either, the proposed use of the material is for scholarly purposes. Any copying or use of the material in this paper for financial gain shall not be allowed without my written permission. IV ACKNOWLEDGEMENTS I would like to thank the members of my graduate committee: Dr. Richard L. Haines, for helping me with the administrative and editorial tasks to complete the paper; Dr. Michael Copeland, for sticking with me through two years; and Mary Ellen Wolfe, for stepping in at the end and providing me with the final direction I needed. I would like to thank especially Dr. Lauren S. McKinsey, my teacher, mentor and friend. I greatly appreciate his support, confidence and advice over the last four years, and I have benefitted from the opportunity to work with Dr. McKinsey, Stephen Maly and Mary Ellen Wolfe at the 49th Parallel Institute for Canadian-American Relations. This paper is partially a product of Dr. McKinsey’s interest and expertise in U.S.-Canada energy relations. Thank you, Lauren. V TABLE OF CONTENTS Page APPROVAL ii STATEMENT OF PERMISSION TO USE iii ACKNOWLEDGEMENTS iv TABLE OF CONTENTS v ABSTRACT viii CHAPTER: 1. WHY STUDY ALBERTA? 1 The Impact of Alberta on Montana 2 Should Montana Take the Initiative? 4 Summary 7 End Notes 8 2. THE PETROLEUM INDUSTRY IN WESTERN CANADA .. 10 Crude Oil 11 Natural Gas . . 13 Oil Sands 15 Summary 16 End Notes 17 3. CANADIAN FEDERAL-PROVINCIAL POLICY 19 The National Oil Policy 19 The National Energy Program 21 The Western Accord Agreement 22 Current Energy Policy 23 The Effect on Continental Trade 23 End Notes . . . 26 vi TABLE OF CONTENTS-Continued Page 4. THE IMPACT ON MONTANA 28 Crude Oil 28 Natural Gas 29 Summary . . 32 End Notes 33 5. COMPARING PRODUCTION REGULATION 35 Land Classification 35 Alberta 35 Montana 36 Disposition of Production Rights . 37 Alberta 37 Montana 39 Comparison of Disposition of Production Rights 41 Production Differentiation 42 Alberta 42 Montana 43 Comparison of Production Differentiation 43 Conservation Practices 44 Alberta 44 Montana 45 Comparison of Conservation Practices 46 Regulation of Marketing 47 Alberta 47 Montana 50 Summary 51 End Notes 52 6. COMPARING REVENUE GENERATION 56 Royalties 56 Alberta 56 Crude oil 56 Natural gas 59 Montana 60 vu TABLE OF CONTENTS-Continued Page Taxation 61 Alberta 61 Provincial government 61 Federal government 62 Montana 63 Severance tax 63 Net proceeds tax 63 Resource Indemnity Trust tax 64 Privilege and license tax 65 State corporate license and income tax 65 Lease, License Bonuses and Rentals 65 Alberta 65 Montana 66 Disposition of Revenues 67 Alberta . . 67 Montana 67 Revenue Methods and Production 68 End Notes 71 7. CONCLUSION . ......................... .... 74 End Notes . . 80 REFERENCES ....... 81 APPENDIX . 89 viii ABSTRACT Montana state energy planners and policy makers have historically respond¬ ed to the crisis-driven international petroleum market with a patchwork of laws and regulations which has often limited the formation of effective energy and revenue policies. This paper provides the basis for arguing that Montana should take a regional approach in assessing options for the state’s energy and tax policies. The purpose of this paper is to demonstrate the importance of focusing on Alberta, Canada, in any systematic study of the conditions of Montana’s petroleum industry. To understand the importance of the Alberta industry on the Montana markets, the character of the petroleum industry in Western Canada (crude oil, natural gas, and oil sands) and the provincial and federal policies which have driven market development are described. The importance of Alberta’s crude oil and natural gas trade for Montana’s energy consumers is outlined by describing the historical trade relationship. The basis of the paper is a comparative analysis of Alberta’s and Montana’s petroleum production regulations and revenue genera¬ tion policies. Alberta maintains ownership of petroleum resources and leases the rights to production. Revenues are collected primarily from royalties set as a percentage rate on production. This system rewards production and taxes profit¬ ability. By contrast, ownership of petroleum resources is more fragmented in Montana, divided among state, federal, tribal, and private interests. Consequently, most revenue comes from the severance tax and the net proceeds tax, both of which are ad valorem taxes that address levels of production rather than profit¬ ability. The author concludes the comparative analysis by asking what can state lawmakers and energy policy analysts learn from a Canadian comparison. The overall lesson is knowing the value of regional differences. Knowledge of the differences also provides the basis to argue that Montana should take a regional approach to planning energy policy. Two alternate approaches to include a Canadian perspective are offered: first, to fold a Canadian component into the analysis of regional policies; or second, to develop a comprehensive regional energy policy that would cover petroleum production, trade and taxation. The point is that the world is moving toward an integrated international economy. 1 CHAPTER 1 WHY STUDY ALBERTA? Montana belongs to one of the world’s petroleum producing regions, the Rocky Mountains in North America. In combination, petroleum products and natural gas satisfy nearly 75 percent of Montana’s energy requirements while the state has relied upon the development of domestic production to supply up to 45 percent of its natural resources tax revenues. As is the case for all petroleum producing regions, the overwhelming factor influencing petroleum production in Montana is the world price of oil. The result is a state energy policy which responds to the cyclical pattern of surplus and shortage within the global petroleum market. In recent years, state energy planners have addressed a variety of policy questions that have arisen in response to specific crisis driven situations. Should tax breaks be given to stimulate production in Montana? Should environmental regulations be relaxed and more areas be made available for exploration? If so, what effects will these decisions have on the health of the petroleum industry and ultimately on petroleum trade? The concomitant policies developed in response to these questions have yielded a patchwork of laws and regulations related to 2 state energy policy which has often limited the formation of effective energy and revenue policies. Previous state responses to crisis situations have been to assess neighboring states’ environment and tax policies. However, at Montana’s doorstep lies one of the world’s most important oil producing regions, Alberta, Canada. Oddly enough, the implications of Alberta’s proximity to Montana are not well understood by the state’s officials, by its citizens or by researchers. The purpose of this paper is to demonstrate the importance of focusing on Alberta, in addition to neighboring states, in any systematic study of the conditions of Montana’s oil industry. Aside from the need for Montana government officials to anticipate the impact Alberta’s energy policies may have on Montana’s short term oil and natural gas policy decisions, there is a broader, more significant justification for pursuing this line of research. It is clear that not only is Montana affected very substantially by Canadian and Alberta oil industry policy, but that there are emerging opportunities to take a direct role in negotiating state-provincial agreements that may ameliorate these effects. Indeed, this paper will provide the basis for arguing that Montana should take such a regional approach. The Impact of Alberta on Montana It is easy to document the historical dependence of Montana on Alberta for both natural gas and oil refinery feedstock. As discussed later, in Chapter 4, Montana has discovered both the advantages (e.g., ready availability) and the 3 disadvantages (e.g., rising prices) of proximity to Alberta’s supply over the last two decades. Security-of-supply concerns, of particular importance 10 years ago, have receded, but their return would confirm the need to re-evaluate Montana’s energy trade relationship with Alberta. A second point concerns Montana’s position as a net producer of petroleum, rather than a consumer. While the state is not a major North American producer, like Texas, Alaska or Alberta, still it has a substantial revenue stake in assuring the health of the industry, in 1985, the state realized more than $232 million from the petroleum industry in taxes and royalties/ Just recently, Montana revised its taxation of petroleum downward in order to retain or expand its share of the producer market during a time of flat world oil prices. A comparison between the two regions is therefore vital because Alberta has done the same. These actions could negate the appeal of Montana’s new tax provisions to refineries and producers alike. Finally, the idea of comparing the states and the provinces is likely to be useful in many areas beyond petroleum policy. Montana and other states are learning that it is possible and there are benefits to be derived from asserting interest in policy areas, especially trade, traditionally thought to be international in scope and therefore reserved for the federal government. As Montana looks to expand its interests in the international economy (e.g., agricultural, timber and coal trade, and foreign investment), it will ultimately compete with other states and provinces looking to gain the same economic advantage. Policy lessons 4 learned from the regional petroleum comparison could guide decisions made in regard to other competitive trade commodities. Should Montana Take the Initiative? A basic tenet of the U.S. Constitution (Art. I, Secs. 8 and 10, Art. 2, Sec. 2) is that the states transferred exclusive control over foreign affairs to the central government. In reality, however, the states have historically been involved in foreign affairs on a number of occasions.2 Examples include state involvement in American annexation movements on both the Canadian and Mexican borders, and later involvement in national immigration issues. Interestingly, though states have occasionally been involved in foreign affairs, most writers have ignored this aspect of federalism. One notable exception is W. Brooke Graves. Graves notes that most involvement by states has been in the form of barriers to foreign commerce, obstructing national policy, or racial discrimination practices, which embarrassed federal efforts in foreign relations.5 Nevertheless, he foresees an increasing move toward a more positive role for state government. Graves notes the increase in activity on the part of state governors in international affairs, pointing out that ”. . . the governors discovered that American foreign policies tangibly affect internal state affairs."* In addition to Graves* work, there has been a small but growing body of research in transborder and international relations among subnational polities in federal systems.5 Some have helped to conceptualize and describe the types of 5 interactions among such polities. Swanson and Leach et al., for example, have categorized and quantified the relationships between U.S. states and Canadian provinces.6 Ivo Duchacek has identified two characteristic sets of relations that help organize much of this material: "subnational microdiplomacy" and "trans- border regionalism."7 Subnational microdiplomacy is the effort of subnational units of government to seek cooperative contacts and relations with distant centers of economic and political power. The activities encompass a variety of pursuits and spring from a new awareness of a universal interdependence on the part of local political officials who are responsible for the well-being of their own communities.5 Transborder regionalism emerges from a physical proximity of two or more subnational units of government, and results in various formal institutions, or compacts, and informal networks. Duchacek points out, "The cooperating subnational units do not intend to weaken substantially their membership in, and basic allegiance to, their respective national states," even though the development of the formal or informal linkage may arise from cases of tension or conflict with the central government.9 The development of microdiplomacy and transborder regionalism is particularly interesting in light of the fact that, while U.S. policy is thought invariably to influence Canadian policy, one doesn’t expect the reverse.26 In the case of strong regional independence in foreign economic policy, the Canadian provinces have been more active for a longer period of time than their 6 counterparts in the U.S.i2 Initially led by Quebec’s push to assert cultural independence within the Canadian federation by courting France’s political and economic recognition, the provinces have aggressively pursued foreign contacts with both national and subnational units of government over the last 15 years. In contrast, the American states have only recently begun to aggressively pursue the same level of contacts.22 American states can look to the Canadian provinces for leadership in areas of trade promotion, cultural education, and international knowledge and outreach. Montana has already helped create the Montana-Western Canadian Provinces Boundary Advisory Committee, and its governor often meets with provincial premiers regarding a range of issues. In addition, the U.S. federal government seems to tolerate if not encourage direct state-provincial relations. Montana should take this opportunity to broaden its "microdiplomatic" contacts, perhaps with a view to "transborder regionalism." In both the U.S. and Canada, natural resource management has been, in large part, left up to subnational governments. Hence, Montana has an opportunity to develop a comprehensive energy policy within a context of transborder regional energy resource development. In order to understand this context, however, it is necessary to review the Alberta oil industry and provincial policies, and compare them with Montana’s own. 7 Summary Montana has been and will continue to be affected in a variety of ways by the Alberta oil industry, but its policies have been reactions to short term crises rather than based on forward looking planning, taking into account its nearest large competitor. This paper is intended to provide a comprehensive understand¬ ing of Canadian and Albertan oil and natural gas policy, in particular as it will affect the future of Montana’s own industry. The analysis begins with a description of the petroleum industry in western Canada, and explains the nature of federal-provincial policies affecting oil production and export. This is followed by an explanation of the regional aspects of the petroleum trade as they affect Montana’s oil and natural gas industry. The main contribution of the essay is a comprehensive comparison of the institutional and policy contexts within which Montana and Alberta must plan for this industry. In summary, several conclusions and recommendations are presented. 8 End Notes iSteve Bender, Bureau Chief, Department of Revenue Collections: 1981- IM, Oil and Gas Summary by County. 1985 Production/Taxable 1986. unpub¬ lished reports, Research Bureau, Montana Department of Revenue, Helena, 1986. Daniel J. Elazar, "Introduction," Publius: The Journal of Federalism 14 (FaU 1984): 1-4. 3W. Brooke Graves, American Intergovernmental Relations: Their Origin. Historical Development, and Current Status (New York: Charles Scribner’s Sons, 1964), 385-387. 'Ibid., p. 359. 5Elazar, p. 3. 6Roger Frank Swanson, State/Provincial Interaction: A Study of Relations Between U.S. States and Canadian Provinces. U.S. State Department Report (Washington, D.C.: Government Printing Office, 1974); and Richard Leach et al., "Province-State Trans-Border Relations: A Preliminary Assessment," Canadian Public Administration 16 (1973): 468-482. 7Ivo D. Duchacek, "The International Dimensions of Subnational Self- Government," Publius: The Journal of Federalism 14 (Fall 1984): 5-31; and Ivo D. Duchacek, The Territorial Dimension of Politics Within. Among, and Across Nations (Boulder, CO: Westview Press, Inc., 1986). ^Duchacek, "The International Dimensions...," pp. 13-15. pIbid., p. 15. ipSee "Burden of Sovereignty: National Defense," Borderlines 3, no. 5 (May/June 1987): 7; Stephen Maly et al., Sharing the 49th Parallel (Bozeman, MT: Falcon Press, 1983), 117-125; and Stephen Maly et al., U.S.-Canada Free Trade: A Western Regional Perspective (Bozeman, MT: 49th Parallel Institute for Canadian-American Relations, Montana State University, 1988). 9 ^Elliot J. Feldman and Lily Gardner Feldman, "Provincial Foreign Policies and Raison d’Etat," Tufts University, n.d., Photocopy. i2Ellen Hoffman, "Overseas Sales Pitch," National Journal 3 (16 January 1988): 129-133. 10 CHAPTER 2 THE PETROLEUM INDUSTRY IN WESTERN CANADA In the last two decades Canada has moved from a minor position in the world’s petroleum industry to that of a major producer. In 1985, Canada ranked tenth in crude oil production (1.6 billion barrels) and fourth in natural gas production (1.6 trillion cubic feet). In 1986, 70 percent of Canada’s exports to the U.S. consisted of energy products, making energy trade important to the overall economy.2 Canada supplied nine percent of crude oil demand in the U.S. and four percent of the natural gas demand.5 Canadian crude oil and natural gas production has been dominated by the Western Canadian provinces since the Leduc oil find of 1947 in Alberta. Western Canada (British Columbia, Alberta and Saskatchewan) has contributed over 99 percent of all crude oil and natural gas produced in Canada since 1968. Alberta produces between 82 and 85 percent of Canada’s crude oil and up to 88 percent of Canada’s natural gas.¥ The three major components of the Canadian petroleum industry include crude oil, natural gas and oil sands (crude bitumen and synthetic crude oil). Data concerning drilling activity, production levels and reserve estimates all demonstrate the concentration of the industry in Alberta. 11 Crude Oil More than 5,000 oil reserves have been discovered in Alberta, with about half of the conventional oil production coming from 25 major pools. Alberta’s petroleum industry reached record drilling activity levels in 1985 in anticipation of the domestic price deregulation for crude oil. The Alberta Energy Resources Conservation Board (ERCB) issued 8,761 well drilling licenses. This is 22 percent higher than in 1984, and 77 percent greater than in 1983. The previous high number of wells drilled was 7,820 in 1980.5 Alberta crude oil production in 1985 was 56,994,700 cubic meters, or 358,661,940 barrels.*5 This is a 5 percent reduction from the 1984 production level, and contrasts with the high level of drilling activity. Adjustments to the deregulation of oil prices and limitation in pipeline delivery capacity to eastern Canadian markets were cited as the reasons for the decline in production.7 Along with all major oil producing nations, the Canadian petroleum industry took a free-fall dive in 1986 as a consequence of the drop in the world price of crude oil. Western Canada suffered rough times in 1986, with only 42 drill rigs working in late April - just 7.4 percent of the 571 available. Alberta’s Energy Resources Conservation Board (ERCB) estimated that the 1986 oil well completions were down 48 percent from 1985, at 2,059 wells.5 Overall crude oil production of 1.5 million barrels per day was down only 1.3 percent in 1986. 12 Production of light crude dropped by 8.9 percent, reflecting a natural resource decline in the older fields in western Canada.9 Canada’s National Energy Board (NEB) and Alberta’s ERCB monitor the nation’s oil supplies in order to determine whether the domestic resources can satisfy demand for petroleum products. Supply is assessed by determining established reserves, reserves additions and the ultimate potential reserves in the conventional producing area of western Canada and the firontier areas of the Northwest Territories and the Arctic Ocean.19 The National Energy Board defines the crude oil resource base as "the total quantity of hydrocarbons, known or inferred to exist, in reservoirs or deposits from which crude oil or its equivalent may be obtained."77 Since 1982, reserves additions have exceeded production, reversing a trend toward decline which occurred from 1969 to 1981.72 The remaining total reserve of conventional crude oil in Canada is estimated at about 4.663 billion barrels.73 The NEB notes that only part of the resource base will ever be recovered because of geological, technological and economic factors. Reserves additions from enhanced oil recovery (which includes oil recovered from techniques other than those which use the natural energy of the reservoir) in currently established pools is estimated at between 1.47 and 1.88 billion barrels.7* The projections of reserves additions that result from future drilling activity (from new discovery and incremental volumes from current reserves) were based on an extrapolation of the historical relationship between 13 the rate of reserves additions and the amount of exploratory drilling carried out. The estimate of the remaining potential for future reserves additions related to drilling was between 1.43 and 1.97 billion barrels in 1985.15 The frontier regions are believed to have the geological potential for substantial levels of petroleum production. The Canada Oil and Gas Lands Administration (COGLA) estimates of discovered resources of crude oil in the frontier regions are 1.15 billion barrels for the Mackenzie/Beaufort area, 419 million barrels in the Arctic Islands, and 1.29 billion barrels in the East Coast Offshore area.76 The ultimate potential recovery of crude oil in areas that are currently producing is estimated to be 23.6 billion barrels, an increase of 755 million barrels over the 1984 estimates.77 Because of the favorable economic climate for exploration and development that existed between 1982 and 1985, the total supply of crude oil has increased to an estimated 1.6 billion barrels per day.75 Natural Gas Alberta producers have discovered more than 18,000 natural gas reservoirs, although most are relatively small, requiring only one or two wells to recover the supplies.79 The drilling success ratios for natural gas exploratory drilling have declined from 60 percent to below 50 percent since 1981. This trend is because of the decline of gas reserves in the productive Western Canada Sedimentary Basin.25 14 Raw gas production in 1985 was 3,498 billion cubic feet (bcf).2i This is a 10 percent increase from 1984.22 The growth in production was in response to increased export sales to the U.S. which, in turn, were a result of the lower border price allowed for export markets to the U.S. The supply situation for marketable natural gas in the U.S. continued into its seventh year of surplus in 1986; consequently, Canadian exports of natural gas slumped by 12.5 percent. Canadian domestic demand for natural gas also dropped 2.4 percent last year as consumers substituted low-priced residual fuel oil for natural gas.25 As in crude oil estimates, the NEB calculates Canada’s natural gas supplies to determine domestic and export needs. The NEB estimates Canada’s remaining reserves of marketable natural gas as of December 1984 to be approximately 913.9 bcf.24 The NEB calculates natural gas reserves additions based on the extrapola¬ tion of the historical relationship between the rate of reserves additions and the amount of exploratory drilling. Reserves additions per unit of exploratory drilling in western Canada is assumed to decline over time, as gas reserves prospects become fewer and harder to find. A combined total of 35,150 bcf is projected to be added to reserves during the projection period, 1985-2000.25 An estimate for the ultimate potential recovery of natural gas for the Western Canadian Sedimentary Basin is set between 161,500 and 190,000 bcf.26 The COGLA provided estimates of discovered resources of natural gas in frontier regions in its 1985 annual report. The Mackenzie Delta/Beaufort Sea could 15 possibly provide 10,070 bcf, the Arctic Islands 14,725 bcf, and the East Coast Offshore 9,880 bcf of natural gas.27 Oil Sands During the energy crisis of the 1970,s, Canada became a world leader in the development of oil sands that produce crude bitumen and synthetic oil. Alberta's crude bitumen reserves are contained in deposits within the oil sands areas of Athabasca, Cold Lake and Peace River. Development of the oil sands operations continued in 1985, with a total of 1,095 exploratory wells drilled and 15 new production projects approved by the Alberta ERCB.25 Bitumen and synthetic crude oil production has increased over the last decade. Production from surface mining of oil sands at the end of 1986 increased by 85 percent to 419 million cubic meters. Crude bitumen reserves from in situ (in place) oil sands projects were reduced by 18 percent to 52 million cubic meters due to production and adjustments in various deposits.29 The ERCB calculates the reserve for crude bitumen oil based on two categories: surface mineable and in situ production. The gross volume of crude bitumen determined to exist within the surface mineable category was estimated at 26.7 billion cubic meters or 168 billion barrels as of December 1985.J0 Taking into account current technological and economic criteria, the actual remaining mineable reserve volume is estimated at 5.2 billion cubic meters or 32.7 billion barrels. The Board’s estimate of the established in situ crude bitumen reserves 16 under development and production for 3,295 wells is an estimated 72.2 million cubic meters (454 million barrels).52 Summary The fact that the U.S. borders Canada, a source of relatively large petroleum reserves, led to the logical continental trade pattern of Canadian exports to the U.S. The importance of these exports has grown in the last decade, with the U.S. relying on Canadian supplies to fulfill nine percent of crude oil demand and four percent of natural gas demand in 1986. Moreover, energy products comprise 70 percent of the value of Canadian exports to the U.S. The petroleum industry is dominated by Alberta which provides 85 percent of Canada’s crude oil and up to 88 percent of Canada’s natural gas. Alberta contains 65 percent of the estimated remaining reserves of conventional crude oil and 69 percent of the remaining reserves of natural gas. All of the crude bitumen and synthetic oil production from oil sands deposits will come from Alberta and the Alberta/Saskatchewan border areas. It is clear, then, that Canadian oil and natural gas policy is predominantly a policy on Alberta’s industry. End Notes iAmerican Petroleum Institute, Basic Petroleum Data Book: Petroleum Industry Statistics Vol. 7, no. 1 (Washington, D.G: Author, January 1987), n.p. National Governors’ Association, U.S.-Canadian Energy Trade: Executive Summary. NGA special report, Boise, ID, August 1986, n.p. ^American Petroleum Institute, n.p. ‘'Alberta Economic Development Council, Alberta Industry and Resources. 1984. AEDC special report, Edmonton, Alberta, December 1984, pp. 98-99. 5Energy Resources Conservation Board, Energy Alberta. 1985: Energy Resources Conservation Board Review of Alberta Energy Resources in 1985. ERCB special report, Calgary, Alberta, January 1986, p. 10. ^Energy Resources Conservation Board, ERCB. Alberta Oil and Gas Industry Annual Statistics. 1985. Vol. 45, Calgary, Alberta, June 1986, pp. 44-45. Conversion of thousands of cubic meters to Canadian barrels using: 1 cm = 6.2929 Canadian barrels. 7Energy Resources Conservation Board, Energy Alberta. 1985. p. 6; Tricia Crisafille, "Oil Firms Courting U.S. Refineries," The Globe and Mail [Toronto, Ontario, Canada], 10 November 1986; and Dennis Slocum, "Cash-Short Energy Firms Cut Spending," The Globe and Mail [Toronto, Ontario, Canada], 19 March 1987. s "Alberta Fails to Replace 1986 Oil, Gas Production," Oil and Gas Journal [Tulsa, OK], 15 June 1987: 30. pSlocum, "Cash-Short. . ." National Energy Board, Minister of Supply and Services, Canadian Energy: Supply and Demand. 1985-2005. NEB special report, Ottawa, Canada, October 1986, pp. 77-90. "Ibid., p. 77. J2Ibid., p. 79. 18 i5Ibid., p. 78. ^Ibid., p. 80. i5Ibid., pp. 81-82. i<5Ibid., p. 77. i7Ibid., p. 82. iaIbid., pp. 86-87. i9Energy Resources Conservation Board, Energy Alberta. 1985. p. 10. 2%id., p. 12. 2iEnergy Resources Conservation Board, ERCB. Alberta Oil and Gas Industry Annual Statistics. 1985. p. 15. 22Energy Resources Conservation Board, Energy Alberta. 1985T p. 13. ^Slocum, "Cash-Short. . ." ^National Energy Board, Canadian Energy: Supply and Demand. 1985- 2005. p. 59. Converted 96.2 exajoules to billion cubic feet: 1 exajoule = 100 petajoule; 1 petajoule = .95 billion cubic feet; 96,200 petajoule x .95 billion cubic feet = 913.9 billion cubic feet. ^Ibid., p. 62. Converted 37 exajoules to 35.15 billion cubic feet. 2<5Ibid., p. 63. Converted 170 and 200 exajoules. 27Ibid., p. 64. Converted 10.6, 15.5 and 10.4 exajoules. Energy Resources Conservation Board, Energy Alberta. 1985. p. 11. ^"Alberta Fails to Replace. . .p. 30. Energy Resources Conservation Board, Alberta^ Reserves of Crude Oilr Oil Sands. Gas. Natural Gas Liquids, and Sulphur at December 31.1985T 25th ed., Calgary, Alberta, 1986, pp. 2-3. Converted 1 cubic meter of oil = 6.2929 Canadian barrels. J1Ibid., pp. 3-4. 19 CHAPTER 3 CANADIAN FEDERAL-PROVINCIAL POLICY In addition to the size and volume of the petroleum industry in Canada, U.S.-Canada trade in oil and natural gas products has been shaped in large part by government policies. While most U.S. policy observers are aware of the American responses to national energy security issues, the Canadian governmental dimension is not widely understood. The following outlines the Canadian responses to petroleum policy issues that have affected U.S.-Canadian petroleum trade. The evolution of Canadian government policies falls into four phases: (1) the National Oil Policy (1955-1979), (2) the National Energy Program (1980- 1981), (3) the Western Accord Agreement (1984), and (4) current provincial- federal relations regarding petroleum policy. The National Oil Policy Prior to the Leduc oil discovery in 1947, the only involvement of provincial or federal governments in the Canadian petroleum industry was to provide drilling incentives to the infant Canadian petroleum industry. After the major oil reserve discoveries in Alberta, the provincial government began to regulate production 20 through prorationing controls that allocated market shares among producers, much as Texas had done to conserve and maintain price floors in the 11.8/ During the 1950’s, the increase in cheap Middle East supplies of crude oil led to protectionist measures in the North American domestic markets. The United States drafted voluntary petroleum import controls in 1955 and then imposed mandatory controls in 1959.2 Canada responded to U.S. protectionist policy by adopting a program to substitute domestic crude oil for foreign crude oil and products. This market expansion allowed Canada to sustain its own domestic petroleum industry. Canada also maintained some access for Canadian crude oil exports to the U.S. through the means of voluntary export quotas set by the two governments. These policies, known collectively as the National Oil Policy, effectively drew a "line" through the Ottawa Valley reserving domestic oil for western Canada and exports to the western U.S., while allowing foreign oil, including U.S. oil, to be imported into eastern Canada. Exports were to be limited on a voluntary basis, but in practice export sales greatly increased and usually surpassed the limits established for Canadian sales to U.S. markets.5 Following the 1973 international oil market crisis, the Canadian federal government moved to protect Canadian consumers from the impact of rising crude oil prices. The federal government placed controls on the price of crude oil at the wellhead and on the wholesale prices of petroleum products. (These controls extended until June 1985.) An export tax was imposed on crude oil exported from western Canada to the U.S. Finally, the federal government 21 introduced the Oil Import Compensation Program to subsidize the cost of imported crude oil and products to eastern Canadian refiners/ These measures were not welcomed by the provincial governments in the producing provinces. If the domestic oil prices were allowed to rise to the international price levels, the provincial governments would reap windfall profits in the form of royalties from oil and natural gas production. The federal tax and control measures set the stage for several confrontational meetings between the Liberal government in Ottawa and the Progressive-Conservative government in Alberta. The National Energy Program Open warfare between the provincial and national governments broke out in the fall of 1980 when the Liberal government introduced the National Energy Program (NEP). The NEP included a federal wellhead production tax, subsidies for exploration and development activity in the frontier areas of the north and offshore (federally owned "Canada Lands"), and provisions to "Canadianize" the industry through increased domestic ownership.5 Because resource ownership rights are guaranteed to the provincial governments under the authority of the Resource Transfer Act of 1930, the Albertans saw the NEP policies as a direct infringement on the rights of the provincial government to determine the amount of taxation and regulation of petroleum and natural gas production. 22 Alberta Premier Peter Lougheed threatened to "shut off the tap" and suspend provincial sales unless the federal government negotiated with the province. In fact, the Alberta government imposed a 15 percent reduction in crude oil supplies to eastern Canada for several weeks.* Eventually, an agreement was reached between the federal and Alberta governments in 1981, including a new schedule of oil price increases. The Western Accord Agreement The election of Brian Mulroney and the Progressive-Conservative Party in 1984 led to a "peace treaty" between the federal government and the western petroleum producing provinces. The Western Accord and Natural Gas Agreements of 1985 called for phasing out the wellhead production tax and the drilling incentives of the NEP. This reduction allowed the Alberta government to pass through to the industry a variety of production incentives without having to lower royalty revenues collected by the government and thereby encourage greater production activity in the province.7 It is difficult to determine how the changes called for in the Western Accord would have worked because the sharp reduction in world oil prices changed the terms of the agreement before the program had any significant impact. In 1986, distressed producers called for an immediate end to the wellhead tax in place of the phased reduction outlined in the Western Accord. During the summer of 1986, Alberta Premier Don Getty and Federal Energy 23 Minister Marcel Masse argued about the plight of the oil industry and the need for the immediate phaseout of the tax.® While full deregulation of natural gas prices went into effect in November 1986, as scheduled, the federal government ignored the Alberta government’s pleas for increased aid to help the sagging energy industry.9 Current Energy Policy The federal government relented in March 1987 and announced a $350 million (Canadian) grant program for the beleaguered oil patch/9 Aimed at small and medium sized companies, the program is designed to stimulate oil and gas exploration and development activity throughout Canada, but especially in the west. While the oil industry has received the new program favorably, some have accused the Tories of reviving aspects of the old National Energy Plan, particularly the Petroleum Incentive Program, which covered up to 80 percent of the costs of offshore and frontier drilling/7 Nevertheless, the grant program was enthusiastically embraced by both industry and Alberta representatives. The new agreement abated the recent round of tension between the federal and provincial governments over natural resource ownership. The Effect on Continental Trade The four phases of Canadian government policies concerning the oil and natural gas industry have influenced trading patterns with the U.S. During the 24 National Oil Policy period from the late 1950’s to 1973, Canada followed the Ottawa Valley line in trade, exporting crude oil and natural gas to the western U.S. and importing supplies from the eastern U.S. to Canadian refineries in a counterclockwise pattern meant to overcome transportation cost barriers. Following the 1973 OPEC oil embargo, Canadians instituted policies that discouraged exports to the U.S. and increased central Canadian reliance on western supplies, reversing the natural continental pattern of trade in North America. The National Energy Program further restricted Canadian exports and emphasized increased domestic production and consumption. The dismantling of the NEP and the elimination of crude oil price controls led to a resurgence of the continental trade patterns in 1984 and 1985 with increased western Canadian exports and eastern Canadian imports. Both the U.S. and Canada have progressively eliminated energy price controls and restrictions on bilateral trade of energy resources, marking the beginning of a return to the free market conditions of the 1950,s. The cycle of unrestricted and restrictive trade in crude oil seems to have come full circle. The 1986 world oil price collapse and continued surplus of natural gas supplies are situations that have created political pressure for a reemergence of national protectionist policies in the U.S. If the U.S. Congress enacts some proposed legislation, Canada may once again seek exemptions from oil import fees and import quotas as they did during the 1950,s and 1960,s. 25 On the more immediate agenda is the adjustment to the provisions of the Free Trade Agreement (FTA) signed by Prime Minister Brian Mulroney and President Ronald Reagan and passed by the U.S. Congress. The Agreement prohibits any restrictions on imports or exports, including quantitative restrictions, export or import taxes, minimum import or export price requirements, or any other equivalent measure, except under limited provisions as defined by the General Agreement on Tariffs and Trade (GATT) rules. The FTA creates the essentials of a continental energy market by cementing in place the actions independently taken in both countries to progressively eliminate controls in the respective domestic markets, controls which had both direct and indirect consequences for cross-border trade. In the short term, the FTA appears to affect minimally the variety and volume of energy trade; however, the long term implications are far more important. The nature of continental energy trade could change greatly, especially if it is borne out that Canada possesses larger reserves that can be developed at comparable costs. Under the FTA, Canada is not entitled to cut off exports. How the federal and provincial governments would respond to a return to an energy shortage is unclear. Provisions in the FTA may become clear only when implementing legislation is approved and then applied over time.72 26 End Notes Restrictive Trade Practices Commission, Minister of Supply and Services Canada, Competition in the Canadian Petroleum Industry: Introduction. Conclu¬ sions and Recommendations. RTPC special report, Ottawa, Canada, 1986, pp. 29-30. 2Ibid., p. 30. JIbid. Rid., p. 31. Rid. ^Stephen Hopkins, "Lougheed Era, Energy: Alberta Takes Charge," Alberta Report. 8 July 1985: 10. 7Energy Pricing and Taxation Understanding. 17 March 1985 (Agreement between governments of Canada, Alberta, Saskatchewan and British Columbia on: I. Deregulation of Crude Oil Prices; II. Domestic Natural Gas Pricing; and IB. Fiscal Principles), Photocopy; and Statement by Premier Peter Lougheed and Energy Minister John Zaozimy on Alberta’s Oil and Gas Incentives, 24 June 1985, Photocopy. 5Kevin Cox, "Oil Groups Anxious to Make Pitch to Masse," The Globe and Mail [Toronto, Ontario, Canada], 3 July 1986; Kevin Cox, 'Masse Avoids Showdown/Getty Warns Alberta May Shut Off Taps," The Globe and Mail [Toronto, Ontario, Canada], 10 July 1986; David Hatter, "Masse Lands in Natural Gas Hotseat," The Financial Post [Toronto, Ontario, Canada], 12 July 1986; and Ted Byfield, "Masse Scoffs at Alberta's Plan," Western Report [Edmonton, Alberta, Canada], 22 September 1986: 25. Revin Cox, "Oil Job Losses Fail to Move Ottawa on Aid," The Globe and Mail [Toronto, Ontario, Canada], 21 October 1986: B6; MitchaU Rose and John Howse, "Ottawa Strikes a Deal," MacLeans 99, no. 45 (10 November 1986): 14-15; Dan Westell, "Ontario Minister Seeks to Clarify Aspects of Gas Deregula¬ tion Deal," The Globe and Mail [Toronto, Ontario, Canada], 13 November 1986; and Kevin Cox, "Syncrude to Continue with Project Despite Ottawa's Refusal of Aid," The Globe and Mail [Toronto, Ontario, Canada], 6 January 1987: B5. 27 i(>Fay Orr, "At Long Last Relief: Ottawa Unveils Its Long-Awaited Aid for the Oil Patch," Western Report [Edmonton, Alberta, Canada], 6 April 1987: 6-10. iJIbid., p. 9. i2Lauren McKinsey, "Energy Trade: Introduction," 49th Parallel Institute for Canadian-American Relations, Montana State University, Bozeman, 1988, pp. 1-4, Photocopy. 28 CHAPTER 4 THE IMPACT ON MONTANA Almost all of Canada’s petroleum production is in the western provinces, mainly Alberta. Not surprisingly, Alberta’s proximity has made it a major supplier of both natural gas and refinery feedstock to Montana. Currently, Montana relies less than in the past on Canadian supplies, but the state’s energy industry is firmly tied to Alberta’s system of production and distribution. Crude Oil Montana began importing crude oil from Canada in 1956, with deliveries made to the Union Oil refinery in Cut Bank, the Diamond Asphalt refinery in Chinook, and the Phillips Petroleum refinery in Great Falls. Pipeline deliveries to Continental Oil and Humble Oil (Exxon) refineries in Billings began in 1962, with the completion of the Glacier Pipeline. The Farmers Union refinery in Laurel began receiving imports in 1970/ The availability of Canadian imports contributed to a substantial growth in Montana’s refining capacity through the 1960’s and early 1970’s. Canada’s share of Montana’s total crude oil refinery receipts rose dramatically in 1970, from 21.9 percent of the share of total receipts to 32.8 percent, peaked at 48.1 percent in 29 1974, and then fluctuated between 43 and 46 percent until 1980 and the advent of the National Energy Program in Canada. Canadian exports dropped to a decade low of 30 percent (10,862 million barrels) of the total crude oil refined in Montana in 1981. Imports to Montana rose again to reach 39 percent in 1985, second only to imports from Wyoming at 42 percent2 (refer to Appendix). An examination of the state's crude oil pipeline system reveals the importance of Canadian crude oil to the state's refineries. No crude oil pipeline system exists between Montana's productive Williston Basin and the Billings oil refineries. The Williston Basin produces about 70 percent of total state crude oil production and all of this oil is shipped east to North Dakota or south to Wyoming for delivery to out-of-state refineries.3 Several reversible crude oil and refined oil pipelines exist between Billings and points in Wyoming, and Wyoming exports of crude accounted for 42 percent of the Montana refined products in 1985. One crude oil pipeline, the Wascana line from Regina, connects Montana with Saskatchewan. Texaco Trucking and Transportation owns the share of the line from Poplar, Montana to the Canadian border. Trade was temporarily suspended in December 1984, when contracts for Saskatchewan crude oil expired.4 Natural Gas The Montana Power Company (MPC) is the only major importer of Canadian natural gas to Montana and owns the only intrastate pipeline system 30 making Canadian deliveries. MFC had a special role in the development of Alberta’s export markets to the United States as the first American company to receive a removal permit for Alberta gas, in 1952.5 Two Canadian subsidiaries of MFC (the Canadian-Montana Pipeline Company and the Canadian-Montana Gas Company) continue to operate in Canada today, providing supplies from the Aden fields. MFC also maintained special contract terms with a Canadian-owned company, the Alberta and Southern Gas Company, Ltd., to maintain gas supply sources in the Carway gas fields. Deliveries were terminated in 1983.5 From the initial imports of 10 billion cubic feet (bcf) in 1952, MFCs dependence on Canadian gas supplies grew steadily until the early 1970,s. In 1958, the company applied for the first request for authority to import additional supplies and by 1972, MFC relied on Canadian reserves to supply over 80 percent of its consumer demand in Montana.7 The 1970’s energy crisis changed MFC reliance on "secure” supplies from Canada. Canadian national concerns switched from marketing of excess gas supplies to conservation of domestic supplies for energy security. In 1971, the National Energy Board (NEB) denied the first request for authority to increase imports made by MFC in two decades. In 1974, the NEB actually reduced the amount of gas allotted for export.5 The Canadian border price of gas was raised substantially, squeezing MFC between the high price of gas and concern about future access to supplies in Canada. MFC chose a middle course of seeking to reduce its reliance on Canadian supplies while increasing use of new Montana gas 31 sources. MFC also worked to stabilize contract extensions with the Canadian government. The result was a drop in natural gas imports from a high of 35.6 bcf in 1975 to 28 bcf in 1978.p The increase in price for natural gas, tied to the rising prices in crude oil, led to better economic incentives for drilling. By the early 1980’s, the U.S. and Canadian natural gas producers had discovered enough new reserves to create a "gas bubble," or excess supplies. By the fall of 1981, MFC was obligated under provisions of its contracts to take and pay for 39 bcf per year of Canadian gas while needing only 20 bcf to meet consumer demand/0 Gas from the Carway field was shut off by MFC in 1983 because of further market declines, and MFC imports from Canada fell to 13.9 bcf/2 MFC has continued to decrease its reliance on the Canadian supplies, importing 6.6 bcf in 1984, 8.042 bcf in 1985, and 7.63 bcf in 1986/2 MFC exports some natural gas to Canada, which accounts for supply exchanges within the MFC system. In 1985, MFC exported 178,358 million cubic feet (mcf) to Canada while exporting 89,553 mcf in 1986/3 Montana’s natural gas pipeline system is also part of an interstate/inter¬ national gas distribution network. The Northern Border Natural Gas Pipeline enters the U.S. interstate pipeline system at Port of Morgan, Montana, carrying Canadian natural gas supplies to the midwest markets; no Canadian gas is delivered in Montana/4 32 Summary Clearly, Montana’s oil and natural gas industry has been dramatically impacted by both the proximity of western Canadian production and distribution and shifts in the energy policy issuing from Ottawa. Montana industry investors, energy company employees, state consumers, and elected officials looking for a steady source of public revenue all have a stake in following the course of events north of the 49th parallel. To provide a baseline of information, the following two chapters offer a detailed comparison of Montana and Alberta, with particular concern for the government’s role in the industry. End Notes ;Lynda Steele, Montana Historical Energy Statistics. 5th ed. (Helena, MT: Montana Department of Natural Resources and Conservation, Energy Division, 1984), pp. 64-66; and Natalie Walsh, Montana Natural Gas and Petroleum Review (Helena, MT: Montana Department of Natural Resources and Conservation, Energy Division, May 1983), p. 25. ^Montana Department of Natural Resources and Conservation, Oil and Gas Conservation Division, Montana Oil and Gas Annual Review. 1980. Vol. 24, Helena, MT, 1980; and Montana Oil and Gas Annual Review. 1984. Vol. 28, Helena, MT, 1984, p. 12. 5Walsh, p. 24. 'Don Buckland [Texaco Trucking and Transportation, Glendive, Montana], telephone interview with author, April 1987. 5Stephen Maly et al., Bridging the 49th Parallel (Bozeman, MT: 49th Parallel Institute for Canadian-American Relations, Montana State University, 1984), p. 126. 6Ibid., pp. 129-130. 7Ibid., p. 126. *Ibid., p. 128. ^ynda Steele, notes for Montana Historical Energy Statistics. 5th ed., Department of Natural Resources and Conservation, Energy Division, Planning and Analysis files, Helena, MT, 1984. i ‘Maly et al., Bridging the 49th Parallel, p. 130. ^Montana Department of Natural Resources and Conservation, Oil and Gas Conservation Division, Montana Oil and Gas Annual Review. 1983. Vol. 27, Helena, MT, 1983, p. 2. 34 i2Montana Department of Natural Resources and Conservation: Montana Oil and Gas Annual Review. 1984. Vol. 28, p. 2; Montana Oil and Gas Annual Review. 1985. Vol. 29, p. 2; and Montana Oil and Gas Annual Review. 1986. Vol. 30, p. 2. iJIbid. "Walsh, p. 6. 35 CHAPTERS COMPARING PRODUCTION REGULATION In order to provide policy makers a framework for understanding Alberta’s oil and natural gas industry and an explanation for how this relates to issues of public policy, it is useful to take a detailed look at how the provincial government regulates the industry in the public interest. In this and the next chapter the paper will focus on two dimensions of public policy: the regulation of production and the generation of public revenues. In each case, the Alberta experience will be compared and contrasted with that of Montana. Production regulation addresses several issues: land classification, the disposition of production rights, production differentiation, conservation practices, and regulation of marketing. Land Classification Alberta The province of Alberta contains approximately 255,200 square miles or 163 million acres/ Holders of land and mineral rights are classified into Crown- owned and free-hold. The province owns about 85 percent of all the land and mineral rights (Crown-owned lands).2 Crown-owned land varies by region, e.g., 36 southern areas are about 30-40 percent Crown lands and northern areas are almost exclusively Crown-owned (between 99-100 percent).5 The remaining 15 percent of Albertan lands are ffee-hold lands, a mixture of private and federal government ownership. Montana The state of Montana is about 60 percent of the size of Alberta, with approximately 93 million acres/ Land and mineral rights are divided among state, federal, Indian and private interests. Private interests control the largest share, 51 percent of Montana mineral rights (47,415,088 acres).5 Jurisdiction over all U.S. federal subsurface mineral rights belongs to the Bureau of Land Management (BLM). BLM administers the second largest share of subsurface mineral rights, 35,789,866 acres, or 38 percent of Montana/ The remaining mineral rights are shared between the State of Montana and the tribal governments. The State owns approximately 6.6 percent, or 6.2 million acres of trust and leased lands and the adjoining mineral rights.7 The tribal governments in Montana control 5,870,984 acres, or approximately 6 percent of the state’s mineral rights. (Mineral rights add up to over 100 percent because of rounding of the figures.)5 37 Disposition of Production Rights Alberta The majority of oil and gas exploration and production takes place on Crown-owned lands. The Department of Energy handles mineral rights disposition under the authority of the Mines and Minerals Act. Lease sections are offered after companies post requests for exploration licenses and for the right to undertake exploration and development of undisposed mineral rights. The Department reviews the requests and either accepts, adds to, deletes from, or refuses the project. Lease and permit sales are normally held two times per month.9 Exploration licenses are limited in the following areas to allow for a more equitable distribution of drilling activity among large and small petroleum companies: Plains area, 29 sections on two-year terms; Northern area, 32 sections on four-year terms; and Foothills area, 36 sections on five-year terms. The various yearly terms provide for a more rapid turnover of unexplored Crown petroleum and natural gas rights. The terms also allow the same on ground exposure time because of the varying geological factors. Developers with exploration licenses must perform a schedule of work in a specified period to earn the right to convert a portion of an area to a production lease/9 Rights to develop exploration leases are disposed as five-year leases subject to annual rent. To retain rights, the developer must drill and establish 38 production. The developer retains rights down to the deepest zone as long as production is economic/2 If the drilling and production is adequate, the producer retains 100 percent of the lease rights; otherwise, all unexplored rights lying stratisgraphically below the base of the deepest zone determined to be productive revert back to the Crown/2 The Crown retains an interest in all rights below the base of the deepest productive zone found in each existing lease from a date prescribed in the Mines and Minerals Act. These lease rights are called depth leases. The conventional lease tenure is up to five years for all leases issued after July 1, 1976. The rights revert to the Crown only in those instances where productivity from an upper or shallow zone has not been established at the expiration of the lease term. Provisions in an act can allow for extension or deferment. The Alberta Energy Department has reported an increase in depth lease bonus sales over shallow leases during 1986, indicating increased activity and additional reserves being found at the lower levels/5 Once developers decide to drill for production, they have to apply to the Energy Resources Conservation Board (ERCB) for an operating well license. The ERCB handles permitting and safety regulations for all energy projects. The ERCB also prepares and administers policies for the development of oil sand projects. The agency approves all applications for mining and production and evaluates all remaining reserves. The Energy Department administers dispositions of rights to explore and develop oil sands through permits and leases 39 on a case-by-case basis. The Energy Department administers all incentive programs and schedules royalty and tax payments. The Alberta Oil Sands Environmental Research Program (AOSERP) is responsible for the investigation of all environmental effects from oil sands mining and production.2^ Montana Because mineral rights are divided among a wide range of interests in Montana, disposition of the exploration, leasing and drilling rights is a more fragmented process. State mineral rights disposition is administered by the Department of State Lands. A competitive oral bid is held on a quarterly basis for exploration and production leases. The winning bid is considered a bonus payment and covers the first year rental payment. The primary term of the lease awarded is not to exceed 10 years and not to be less than five years unless otherwise determined by the Board of Land Commissioners. Yearly rental payments revert from the bonus payment amount to $1.50 per acre per year.15 The Bureau of Land Management (BLM) handles all leasing of mineral rights on U.S. federal lands. The leasing process is divided into three main procedures: (1) competitive oil and gas leasing, (2) noncompetitive oil and gas leasing, and (3) simultaneous noncompetitive oil and gas leasing.26 Competitive leasing is used for Known Geological Structures (KGS), which are areas known to contain producible oil and gas deposits. The process consists of a competitive lease sale in which the BLM offers producing tracts for lease 40 through competitive sealed bids. Noncompetitive leases are issues for areas outside KGS. The noncompetitive leases are either awarded directly to the one individual applicant or are awarded by the drawing of lot when more than one application for exploration (simultaneous noncompetitive) is received. While the BLM handles the bidding procedure, the Mineral Management Service (MMS) handles acceptance of the bids for geologic structure clearance. The BLM then issues the lease for the proposed operational activities of oil and gas development on the federally owned lands for a primary term of five years for the KGS.i7 The Montana Oil and Gas Board handles all permitting procedures for exploration and production on all lands within the state and monitors all drilling activity for compliance with state laws on safety. The lessee must file for a geophysical exploration permit and a notice of intent to explore must be filed with the individual county Clerk and Recorder. The Clerk and Recorder issues the permit for geophysical exploration for one year and the Oil and Gas Board checks for compliance with state laws and regulations. The permit to drill a well is obtained from the Board by filing a notice of intent to drill. The developer must supply information on the drilling activity planned and post a bond for well abandonment. Once the plan is approved for compliance with rules and regulations, the permit is issued. All developers pay a drilling permit fee and a privilege and license tax on all production to support the Board’s activities.15 41 Comparison of Disposition of Production Rights Several differences are apparent in mineral rights disposition between Montana and Alberta. The main difference is who owns the resources and how they are allocated. The Alberta Crown always retains title to its oil and gas minerals. The rights, to develop the resource are disposed on a competitive basis to the oil industry. Montana ownership of mineral rights is fragmented among federal, state and private interests. Disposition of rights to explore and develop oil and gas minerals depends on ownership. Alberta has an extensive depth leasing program and depth leases are more commonly issued. The exploration and development of deeper productive zones has led to significant additions of oil and gas to Alberta’s reserves. Although the State of Montana allows for the leasing of the mineral rights for oil and gas production below the deepest depth drilled on expired leases, as of 1986 the State had issued only two depth leases.79 The BLM does not allow depth leasing on federally owned lands. Another difference in petroleum production between Montana and Alberta is the development of heavy crude oil sands and oil shale projects. Alberta is the leading producer of these unconventional sources of crude oil and expects their importance in the world energy market to increase as sources of cheap and accessible crude oil diminish over time. While Alberta is actively pursuing large projects in oil sands/shale production, the U.S. has no similar projects. The 42 significance of this fact is that the future focus of the North American petroleum industry may shift to the northern heavy crude oil fields in Alberta. Production Differentiation Alberta Petroleum production is differentiated according to time for tax, regulation, royalty and production incentive purposes. In Alberta, the royalty levied on crude oil production depends upon whether the oil is "new production" (oil produced after December 31,1980) or "old production" (oil produced between April 1,1974 and December 31,1980). It is possible that a single well could be producing both old and new oil, depending on the recovery schemes employed.20 For the purposes of the Western Accord Agreement of 1985 and the subsequent phaseout of the federal Petroleum and Gas Revenue Tax, new production is defined to include production from new wells drilled after March 31, 1985. Incremental production from enhanced recovery schemes that commenced after March 31, 1985 is also defined as new production. Production from wells existing prior to April 1, 1985 will not qualify for the exemption from the tax.22 The differentiation of production in Canada is significant to the producers. In Alberta, the Crown imposes a sliding scale royalty on oil production that is dependent on volume of production, the price received for the oil and the time of its discovery.22 The marginal royalty rates can vary between 14 and 45 percent 43 on old oil production and between 11 and 35 percent on new oil production.23 The gas royalty rate, while primarily dependent on price, is also subject to product classification according to the time of production. Montana Montana law differentiates between petroleum and natural gas production for tax and regulation purposes. While "old production" is not specifically defined in Montana law, "new production" is defined as ... production of natural gas, petroleum, or other crude or mineral oil from any lease that has not produced natural gas, petroleum, or other crude or mineral oil during the five years immediately preceding the first month of qualified new production.2^ New production of oil and natural gas was exempted from the net proceeds tax for one year and the oil severance tax for two years beginning in July 1987. (Taxation of the Montana petroleum industry is discussed in the following section.) Comparison of Production Differentiation While both governments have similar product classification schemes, Alberta’s classification system has a greater impact on revenue generation for the province. Through the ownership of the natural resource, Alberta has the ability to negotiate a broader range of royalty schedules compared to Montana’s tax regime. A royalty rate of approximately 22 percent on $20/barrel oil yields the Alberta government about $4.50 per barrel. A Montana producer pays an 44 effective rate of about 17.5 percent on oil and 12.5 percent on new oil, as a result of changes made by the 1985 session of the legislature, yielding about $2.50 to $3.50 per $20/barrel from four taxes. Conservation Practices Alberta In 1938, Alberta established the Oil and Gas Conservation Board (now the Energy Resources Conservation Board) to regulate energy resource development and to ensure that these resources would be produced in the most efficient and economic manner. Through administrative policy setting, the Board continues to monitor the activity of Alberta's energy production industry as a means of conserving energy resources in the field at the point of production. The ERCB interprets these responsibilities to mean that the recovery of energy resources should be optimized or "conserved," not wasted.25 The ERCB administers regulations that limit the rate at which wells can produce, restrict the amount of gas and water that can be mixed with the oil in order to maintain natural energy forces in the reservoir, and require operators to reinject gas or water to maintain reservoir pressure. In order to achieve optimum recovery in energy production, the ERCB sets enhanced oil recovery (EOR) regulation and administers the Gas Resources Preservation Act. This Act calls for the gas from oil production to be gathered, processed and delivered to the provincial gas gathering system. 45 The powers of the ERCB are set out in eight Alberta statutes and related regulations. In addition to the original responsibilities for oil and gas conserva¬ tion, the ERCB has responsibilities that can be grouped into three major categories: (1) reviewing applications for energy projects, (2) regulating energy facilities, and (3) providing advice and information.2^ The ERCB is run by a six member board, with staff support of 887 persons located throughout the province. The geographic division of field inspectors allows the ERCB to inspect oil and gas deposits that cover nearly three-quarters of the province.27 Montana Montana established rules and regulations governing oil and gas explora¬ tion and production on all lands within the state in 1953. The Oil and Gas Conservation Board, a quasi-judicial board, was created to administer the new regulations. The powers and duties of the Board include the determination of standards to prevent well contamination and damage, investigations against waste, establishment of a well classification system, and the authority to set administra¬ tive rules for compliance.25 Montana’s conservation division is much smaller and performs fewer functions than its Alberta counterpart. The Board consists of seven members appointed by the governor and is supported by a staff of 20. With a field inspection staff of seven, the division regulates well drilling, spacing, production 46 and oil well ratios (oil to water and gas), in addition to authorizing the pooling of interests within oil spacing units. The Oil and Gas Conservation Board also administers drilling and seismic operations permits and collects well samples and well data information. Moreover, the Oil and Gas Conservation Board was designated as the State jurisdictional agency for purposes of the Natural Gas Policy Act of 1978 and processes applications to qualify for the maximum lawful price as prescribed under the Act.29 Comparison of Conservation Practices In Alberta, resource ownership has dictated an early and extensive involvement on behalf of the provincial government in resource conservation practices. Montana has relied on the stimulus of outside interests (both the petroleum industry itself and the federal government) to implement a conserva¬ tion regulatory structure. The Montana Environmental Quality Council (EQC) completed a comparative study on the Rocky Mountain states and Alberta environmental regulation regimes for the oil and gas industry in July 1986.50 The study concluded that Montana and Alberta have similar regulatory programs. However, Montana relies more on general-rule language that the Board of Oil and Gas Conservation can interpret in a broad manner. Alberta’s administrative rulings appear much more specific and often require detailed inspections. The EQC study also compared the size of the oil and gas industry and the size of the field 47 inspection staff in the various states and Alberta. Montana’s inspector workload appears to be in the middle range and Alberta’s inspector workload is about one- half of Montana’s when compared to the other states. The EQC analysis suggests that the size and complexity of a jurisdiction’s regulatory regime increases with the size of the respective oil and gas industry. Alberta, with a comparatively larger petroleum industry than Montana, has stronger environ¬ mental regulations that do not appear to impede petroleum production and trade. Regulation of Marketing Alberta Alberta’s petroleum and natural gas production is regulated and marketed by two independent commissions, one on a provincial level and the other on the federal level. The Alberta Petroleum Marketing Commission (APMC) was formed in 1974 to displace the disposition of provincial production by a small number of major multinational oil companies. The APMC is an independent commission that reports directly to Alberta’s Minister of Energy. The APMC’s functions and responsibilities include the movement and selling of the province’s petroleum and natural gas supplies, fiscal functions such as the remittance of proceeds to the Provincial Treasurer, and the determination of regulated field prices for natural gas.5i 48 In the past, the province took royalty shares of production in the form of cash payments; therefore, the major function of the Commission was to prescribe selling prices for petroleum and natural gas. After the 1985 Western Accord Agreement and the subsequent deregulation of crude oil price controls, the major function changed to one of marketer. The Commission now takes royalty payments due the government of Alberta in the form of in-kind products rather than dollars.52 The functions of the Commission related to natural gas are more complicated. Almost all of the natural gas acquired by the original buyers in Alberta is purchased by the Commission. The Commission then sells gas for the Canadian market back to the original buyer at the purchase price, while it resells gas for export to the U.S. to the original buyer at the higher export price minus transportation costs. The proceeds from the buy/sell transactions for export gas constitute the "fund" from which price adjustments and market development incentive payments are made. The Commission calculates the price adjustment each month based on the proceeds in the fund and estimated quantities of natural gas produced. Alberta producers receive a monthly price adjustment for all eligible deliveries either through the regulated field price paid by the buyer or paid directly from the fund.35 The National Energy Board is a federal agency that regulates exports of natural gas from Canada. The original licensing procedure permitted exports of natural gas only if the gas was not needed for Canadian requirements. The 49 Board developed estimates of the overall reserves, additions to the reserve, and a schedule of the ability of deliverable gas. The estimate of future demand in Canada was compared to the reserve information and each export application was approved only if the supplies were excess to Canadian needs.5* On November 1, 1984, the federal natural gas export pricing policy was changed to permit Canadian exporters to directly negotiate prices with U.S. customers. The result of these contracts has been an increase in export volumes, but at a lower export price under the renegotiated terms. This has caused a decline in the unit price adjustment paid to the Alberta Petroleum Marketing Commission.55 The Alberta government has considerable power over the marketing of petroleum and natural gas products within the province and Canada. However, the federal government’s National Energy Board has been the dominant factor in influencing international trade patterns between Alberta and Montana. Albertans generally favor increased exports to the U.S. and have clashed with the federal government over the issue of "saving" Alberta energy supplies for Canadian use or increasing sales to the U.S. Intergovernmental conflict eased considerably after the NEB first reduced from 25 years to 15 years the reserves test to determine whether surplus gas was available for export and then eliminated the test altogether in 1987. The reserves test was meant to ensure Canadian consumers would be guaranteed a substantial 50 supply of natural gas, but was considered by the Albertan producers and government a hindrance to provincial control over production and revenues. Montana In the United States, petroleum price setting has not been a state function as in Canada, but is governed by the world market price, private international markets, and U.S. demand. Neither the state nor the federal government currently markets petroleum products; however, the U.S. Department of Energy does buy petroleum supplies for the national Strategic Petroleum Reserve. Oil price controls were deregulated by the federal government in 1980. There are no marketing price controls on the international sale of natural gas in the United States. However, natural gas imports are monitored by the U.S. Federal Energy Regulatory Commission (FERC). In natural gas trade between Montana and Alberta, the Montana Power Company must submit applications and receive approval from FERC on the intent to import supplies from Canada.56 Natural gas prices are regulated in interstate trade. Under the Natural Gas Policy Act of 1978, the federal government sets the price of natural gas in interstate markets by establishing a schedule of price ceilings for all production of natural gas. The Montana Board of Oil and Gas Conservation is the designated agency in Montana for local administration of the Act57 51 Natural gas prices are not regulated in the intrastate market. Canadian supplies to Montana are considered intrastate (no gas supplies enter interstate pipelines), so there is no formal approval the Montana Power Company must receive when acquiring or selling Canadian supplies. However, MFC must get PSC approval for its "mix" of domestic and foreign gas supplies and it must receive approval to pass along border gas price increases to consumers.58 Summary There are rather substantial differences between Alberta and Montana on matters of production regulation. These stem to a large degree from the fact that the Alberta provincial government retains title to its mineral rights, and thereby has more direct control over the industry. There is control over disposition rights, leverage in negotiating royalty schedules, the ability to specify in detail environmental quality and conservation practices, and a substantial role in the marketing of products, both in domestic and international trade. Inevit¬ ably, this affects the Alberta provincial government’s ability to generate revenue. 52 End Notes ^Alberta Economic Development Council, Alberta Industry and Resources. 1984. AEDC Special Report, Edmonton, Alberta, December 1984, p. 183. Converted 66 million hectares to acres. 2Luigi Di Marzo [Director, Resource Statistics and Intelligence, Alberta Energy and Natural Resources], 'Talking Points Presented to the Montana Department of Natural Resources and Conservation," 21 February 1986, Photocopy, n.p.; and Frank J. Holubowich, "Will Reversion of Deep Rights Lead to a Resurgence in Exploration in Alberta?" The Journal of Canadian Petroleum Technology (April 1983): 81-82. JDi Marzo, 'Talking Points ..." 4Montana Promotion Division, Montana Department of Commerce, Montana Highway Map. 1985-86 Official Highway Map, Helena, MT, 1985. Calculation by author based on information from footnotes 4, 6, 7 and 8. ^Bureau of Land Management, U.S. Department of Interior, Billings (MT) District Office, Department of Information and Public Affairs, personal telephone conversation with author, June 1986. 7State of Montana, Office of the Legislative Auditor, Performance Audit: State-Owned and Leased Lands. Special report, Helena, MT, June 1983, p. 9. ^Montana State Library (Helena), telephone conversation with author, June 1986. A 1974 publication listed the total acreage of mineral rights leased to tribal governments as follows: Blackfeet Crow 950,643.24 acres 1,554,253.87 acres 1,243,968.00 acres 616,047.66 acres 964.864.75 acres 433,594.21 acres 107.612.76 acres Flathead Fort Belknap Fort Peck Cheyenne Rocky Boy 53 9G.A. Warne [Technical Assistant to the Board, Energy Resources Conservation Board, Calgary, Alberta], personal letter to author, 28 July 1986; Mike Day [Assistant Deputy Minister, Department of Energy, Edmonton, Alberta], personal telephone interview with author, August 1986; and Holubowich, pp. 81-82. i0Day, August 1986. JiWame, 28 July 1986. i2Holubowich, p. 82. iJDay, August 1986. "Ibid. i5Nancy McLane, Montana Energy Almanac: 1982. Energy Division, Department of Natural Resources and Conservation, Helena, MT, May 1983, pp. 41 and 71; and Barbara Odegard [Chief, Mineral Leasing Bureau, Montana Department of State Lands, Helena], personal interviews (various) with author, 1986. i6Bureau of Land Management, U.S. Department of Interior, Miles City (MT) District Office, Oil and Gas Environmental Assessment of BLM Leasing Program. Special report, 1980, p. 11. i7Ibid.; and Don Gilman [Branch Chief, BRASS System, Fiscal Accounting Division, Minerals Management Service, U.S. Department of Interior, Denver, CO], personal telephone interview with author, July 1986. ^Environmental Quality Council, State of Montana, EOC Directory: Resource and Energy Permit Directory Index of Environmental Permits (Helena, MT: Author, 1984): 68-71. i9Barbara Odegard [Chief, Mineral Leasing Bureau, Montana Department of State Lands], personal telephone conversation with author, July 1986. 2aPrice-Waterhouse, Oil and Gas Taxation. Special accounting report, Calgary, Alberta, March 1986, p. 38. 2;Ibid., p. 30. 22Ibid., p. 38. 54 ^Ibid., p. 39. ^Montana Code Annotated. 15-23-601. 25Energy Resources Conservation Board, Energy Alberta. 1985: Energy Resources Conservation Board Review of Alberta Energy Resources in 1985. ERCB special report, Calgary, Alberta, Canada, January 1986, p. 31. 2 *Ibid., p. 35. 27Ibid., p. 39. ^Montana Code Annotated. 2-15-3303, ref. Board of Oil and Gas Conservation; Montana Code Annotated. 82-11-111, ref. Powers and Duties of Board; and Montana Code Annotated. 82-11-112, ref. Intergovernmental Cooperation. 29Montana Department of Natural Resources and Conservation, Oil and Gas Conservation Division, Montana Oil and Gas Annual Review. 1985. Vol. 29, Helena, MT, 1985. 30Gm\ Kuntz, Comparison of Environmental Regulation of the Oil and Gas Industry in the Rocky Mountain States and Alberta. Special report, Montana Environmental Quality Council, Helena, MT, July 1986. 3iAlberta Petroleum Marketing Commission, 1984 Annual Report. Calgary, Alberta, Canada, 1985, pp. 2-6. 52Luigi Di Marzo, "Talking Points ..." J3Alberta Petroleum Marketing Commission, pp. 6-7. ^National Energy Board, Minister of Supply and Services, Canadian Energy Supply and Demand. 1985-2000: Summaryf NEB special report, Ottawa, Canada, 1986, pp. 77-90. 35Alberta Petroleum Marketing Commission, p. 8. 36Federal Energy Regulatory Commission (U.S.), 42 U.S.C. 7172. J7National Gas Policy Act (U.S.), 1978, 15 U.S.C. 3301 et. seq.; 15 sec. 3341 et seq.; and 15 sec. 3411. 55 5SMike Lee and Eric Eck [Montana Public Service Commission, Helena], telephone interviews with author, July 1986; and Lauren McKinsey [49th Parallel Institute for Canadian-American Relations, Montana State University, Bozeman], personal interview notes, May 1987. 56 CHAPTER 6 COMPARING REVENUE GENERATION The differences between Alberta and Montana in the degree of direct and indirect control over their respective oil and natural gas industries are reflected in differences in both the amount and the types of revenues each generates. The following is a comparison of the two revenue enhancement systems. These systems are influenced by and result from the factors described in the preceding chapter. Royalties Alberta Crude oil. Alberta collects royalties as its share of oil and gas mineral rights when leasing such rights on Crown Lands. The royalty levied is dependent upon the volume of production, the price received for the oil, and the time of the discovery/ The royalty collected is based on a formula using a sliding scale and the concept of a "reference well." The reference well has been fixed at 572.1 cubic meters per month (3,600 barrels) since 1978 and the royalty formula corresponds to the level of production from each well.2 The fixing of the reference level has a significant impact on average royalty rates; e.g., lower 57 productivity wells face reduced royalty rates. Effective April 1982, the govern¬ ment receives 21-2/3 percent of the first $40.90 per cubic meter of $6.50 per barrel. In addition, the government receives a varying percentage of the selling or par price in excess of $40.90 per cubic meter. Crude oil production is classified as either "old oil" (discovered before April 1, 1974) or "new oil" (discovered after April 1, 1974). It is possible under Alberta regulations that a single well could be producing both old and new oil, depending on the recovery schemes employed.3 Royalties are set at a flat 5 percent for enhanced recovery or oil sands projects designated as experimental. The royalty schedules for full- scale oil sands projects are negotiated on a case-by-case basis/ The provincial government has often exempted crude oil from royalty levies over the last few decades in order to stimulate increased production. Royalty exemptions usually take the form of "holidays" from payment of royalties or outright cash grants given directly to producers to offset the impacts of royalty charges. Current energy policy contains a mixture of these two types of exemptions. The Western Accord Agreement of March 1985 set into motion a new federal and provincial response to Canada’s petroleum industry. The agreement outlined new fiscal principles for the oil and gas industry that included promoting industry investment and basing taxes on profits, not gross revenues. In order to accomplish these priorities, the federal government deregulated crude oil pricing, 58 repealed five federal taxes, and replaced the Petroleum Incentive Programs (PIP) or grant system with a tax based incentive system.5 In response to federal government initiatives, Alberta responded with a two-part program of its own: royalty reductions and royalty holiday programs. Under the royalty reductions program, beginning in June 1985, marginal rates on new production were reduced from 45 percent to 40 percent, and old production rates were reduced from 35 percent to 30 percent.6 The provincial government also reviewed its incentive programs and determined that the existing grant-oriented programs that favored mere exploration activity should be replaced by a new system of royalty holidays that rewarded successful exploration. Alberta phased out and eliminated the following grant incentive programs: (1) the Alberta Petroleum Incentive Program (APIP), (2) the Exploratory Drilling Incentive System (EDIS), and (3) the Geophysical Incentive System (GIS). Beginning in June 1985, and effective to May 1988, the New Crude Oil Royalty Holiday Program replaced the grant programs. New crude oil was exempted from royalty payments to a maximum of $1 million per well based on volume of production for each eligible well for a period up to 12 months. The royalty exemptions account for approximately 35 percent of the industry’s average drilling costs in each geographic region.7 In June 1986, Alberta announced a $200 million aid program to support the slumping oil industry. In a reversal from the Western Accord principles, and a return to a grant-based incentive system, a $100 million Development Drilling 59 Assistance Program provided cash grants or royalty credits up to a maximum of $200,000 per well. A $50 million Well Servicing Assistance Program paid producers 50 percent of contract labor costs for maintenance and service. Limits of $50,000 per well, $50,000 per pipeline, and $100,000 per battery were placed on the grants. A $50 million Geophysical Assistance Program paid as much as 35 percent of field expenses to geophysicists for reflection seismic work. In addition, an $85 million interest-free loan to Syncrude from the Heritage Savings Trust Fund and a reduction in royalties from 12 percent to 1 percent were granted, with an estimated savings of $23 million for Suncor, Inc.5 Natural gas. Natural gas production is also classified into two categories: old gas discovered prior to 1974 and new gas discovered after that date. The royalty paid depends on price and not quantity, except for low production wells producing less than 16,900 cubic meters per day (106,350 barrels). The royalty schedule is 22 percent of the first $ 17.75/thousand cubic meters plus a percentage of any selling price in excess of the base amount. Marginal royalty rates are being reduced in conjunction with the crude oil marginal royalty rates. The total royalty payable is based on gross revenue and includes a Gas Cost Allowance which incorporates deductions for eligible operating costs, capital cost allowances, and a return on average capital.9 The Natural Gas Holiday Program is a 12-month royalty holiday program for exploratory natural gas wells and sets a $2 million maximum per well rate. A new deep gas well royalty holiday program applies to all new wells drilled into 60 new gas pools or into extensions of existing pools below 2,500 meters (8,000 feet). The holiday program is defined in terms of a dollar amount applied against royalties payable from the sale of natural gas and products from a well drilled below 2,500 meters.70 Montana Royalties from state-leased land are set by the lease terms and are not to be less than 12.5 percent of production value for gas and 13 percent for oil. They are paid on the reserve fraction of oil or gas not used for on-site purposes, from the posted field price or fair market value on the day the oil or gas is delivered to storage or a pipeline. Royalty rates on production of gas which is shut-in (not delivered) are set at $400 per well per year or the amount of the annual rental, whichever is less. As long as the well is maintained and royalty is paid, the lease is considered a producing lease.77 On federally-owned lands, producers begin royalty payments upon commencement of production. Royalties on KGS leases are set during the competitive bid process and are not to be less than 12.5 percent per year on production value. Royalties are set at 12.5 percent on noncompetitive leases. Royalties on oil shale production may be set by the Secretary of the Interior and may be waived for the first five years of the lease to encourage production.72 61 Taxation Alberta Provincial government. Alberta imposes a corporate income tax with a basic rate of 11 percent. Small businesses are taxed at 5 percent. Effective April 1, 1985, and continuing for five years, corporations with manufacturing and processing operations in Alberta are eligible for a tax rate reduction. Taxes for corporations will be reduced from 11 percent to 5 percent and rates for small businesses will be reduced from 5 percent to 0 percent (a tax holiday).75 Alberta allows a royalty tax deduction/rebate to corporate taxpayers in the computation of provincial taxable income and a royalty tax credit to provide limited relief in connection with the federal income tax payable on nondeductible Crown royalties. A deduction for corporate taxpayers and a rebate to individuals is given "in the computation of provincial taxable income of the difference between the 25 percent resource allowance claimed and the disallowed Crown royalties."74 A corporation where Canadian royalty income exceeds taxable income may carry forward excess deduction to the next tax year. After 1983, credit limits were equal to 50 percent of Alberta royalties paid to a maximum of $2 million per year. Effective April 1, 1986, the credit limits to small producers were increased to 95 percent and $3 million annually per eligible company or investor for the balance of 1986.75 62 Federal government. The Canadian federal government imposes a federal income tax with a host of deduction allowances and tax credits particular to the oil and gas industry. The federal income tax does not allow a deduction for Crown royalties paid to the Alberta government. Other federal tax changes in the Western Accord Agreement have been included in the federal budget beginning May 23, 1985. The Petroleum and Gas Revenue Tax (PGRT) was to be phased out over the following three years. The Natural Gas and Gas Liquids Tax (NGGLT), the Petroleum Compensation Charge (PCC), and the Canadian Ownership Special Charge (COSC) have all been repealed/6 In response to the 1986 decline in the world price of oil, the federal government forgave $275 million in tax revenues from the oil industry by abolishing the PGRT in October 1986. In March 1987, the federal government announced an additional plan to aid the oil industry. The government provided cash incentives of 33-1/3 percent of exploration and development costs anywhere in Canada, up to a maximum of $10 million in annual spending per company. Producers spending $10 million or more could elect either to receive the cash grant or to issue flow-through shares to raise new equity capital, passing on the tax incentive to investors. The program was established to benefit small independent drilling service and supply companies. The current aid package has no scheduled expiration date/7 63 Montana Severance tax. Montana’s oil and natural gas severance tax is paid by all producers of oil and natural gas. The tax is computed as a percentage of the total gross value of production. The tax is computed monthly by multiplying the number of barrels of oil or cubic feet of gas produced during the month by the average value of the wellhead price. The tax rate is 5 percent on crude oil and 2.5 percent on tertiary recovery oil. Natural gas is taxed at 2.65 percent.75 Montana law allows a three-year severance tax exemption for natural gas from wells 5,000 feet deep or deeper drilled between December 31, 1976 and December 31,1992. The exemption applies if the gas is placed into a distribution system in which a majority of the consumers are within Montana or at least 20,000 natural gas customers are within Montana.79 Beginning in 1987, production from new oil and gas wells will be exempt from the severance tax for two years. The exemption is designed to sunset when oil prices reach $25 a barrel. On stripper oil wells (wells producing no more than 10 barrels a day), only the first five barrels a day will be tax exempt. The exemption for stripper wells will terminate when oil prices hit $30 a barrel. On stripper gas wells that account for a maximum of 60,000 cubic feet per day, the first half of daily production is now tax-free.29 Net proceeds tax. The net proceeds tax is a property tax based on the net proceeds of production from a well. Under Montana’s natural gas and oil net proceeds tax, producers file an annual statement of income derived from 64 each well to the Montana Department of Revenue. The Department then calculates the net income based on the gross income minus deductions (royalties paid and cost of production, including reclamation and windfall profits tax deduction of 70 percent to balance refunds from the federal government). The Department of Revenue sends the net income figure to the assessor of the county in which the well is located and the well is subject to the mill levy property tax l of the local school district. The tax can be levied only on production sold during the taxable year.2i A flat tax of 7 percent of net proceeds for petroleum and 12 percent for natural gas is assessed on new production of oil and gas. This is defined as that production from a well in which no production was taken in the previous five years. The value of net proceeds for new production is calculated without allowing the federal excise tax deduction.22 For the 1987-1989 biennium, new production of oil and natural gas will be exempt from net proceeds taxes for one 2.? year. Resource Indemnity Trust tax. An annual tax of $25 plus one-half of 1 percent of the gross value of production over $5,000 is assessed to provide funds for environmental protection and reclamation projects. The monies collected are disposed into the Resource Indemnity Trust Fund and invested by the Montana Board of Investments. Thirty percent of the interest income is allocated to the water development special revenue account and 6 percent of the interest income goes to the Department of Health and Environmental Science for hazardous 65 waste program implementation. The balance of the interest income is approp¬ riated for environmental reclamation.2^ Privilege and license tax. To help defray expenses and operations of the Oil and Gas Conservation Board, the Board may impose a tax of not greater than 2/10 of 1 percent on each barrel of oil or each 10,000 cubic feet of gas produced. The tax money is deposited into the state special revenue fund and appropriated by the legislature.25 State corporate license and income tax. A corporate license and income tax is paid by most corporations doing business in Montana. A rate of 6-3/4 percent of net income (gross income minus allowable deductions) or $50, whichever is greater, is levied. Deductions applicable to the oil and gas industry include the resource depletion allowance and an investment credit. Revenues are disposed as follows: 64 percent to the general fund, 25 percent to the school foundation, and 11 percent to the Long-Range Building Program.26 Lease. License Bonuses and Rentals Alberta In Alberta, licenses for exploration and leases for production are offered through competitive bidding normally held twice per month. The Alberta Department of Energy posts tracts available for leasing approximately two months in advance and leases and licenses are awarded to the highest bidder paying a one-time bonus for the right to explore and develop oil and gas on Crown Lands. 66 Revenues received from bonuses are deposited into the Alberta general revenue fund.27 Montana In Montana, the State of Montana Board of Land Commissioners offers state lands for oil and gas exploration and development through competitive oral bidding on a quarterly basis. Lease rights are awarded to the highest bidder paying a one-time bonus and the monies received are credited to the permanent fund arising from the land grant lease (including school trust funds) or credited to the state general fund.25 Montana requires a rental payment on all leased state lands. Rent is $1.50 per acre per year, but not less than $100, and is paid on producing and nonproducing land up to the lease expiration of 10 years. First-year rental and the bonus bid are paid upon the lease issuance. The monies are deposited into the income fund of the land grant from which the lease arises.29 The United States Department of the Interior offers oil and gas leases in KGS on federal lands through competitive bidding. Leases are awarded to the highest bidder who pays a one-time bonus for the leasing rights. The monies received are deposited into the Department of Treasury account, 50 percent of which is returned to the state in which the leased land is located.55 The Department of Interior charges rental fees on federally leased lands for oil and gas exploration and development. Rent is set at $0.50 per acre per year, with the first year payment due on lease issuance.52 67 Disposition of Revenues Alberta All revenues generated by oil and gas royalties and taxes are deposited into the Alberta general fund. Since 1976, Alberta has maintained a savings account, held in trust, supported by nonrenewable resource revenues. Prior to 1983-84, 70 percent of the nonrenewable resource revenues (98 percent generated by the oil and gas industry) went into the general revenue fund and 30 percent to the Heritage Savings Trust Fund. Interest income from the fund was reinvested into the account. Since 1983-84, 85 percent of resource revenues are left in the general fund and 15 percent of the revenues are channeled into the Heritage Fund.52 In addition, the fund’s interest income is transferred to the general fund. Revenues deposited into the fund peaked in 1981-82, with $1.43 billion coming from oil and gas royalties and $1 billion reinvested from interest income. In 1984-85, the Heritage Fund received $737 million (Canadian) in oil and gas revenues and earned a total net income of $1,575 million on its investments.55 Montana Disposition of monies from royalties, rentals, lease and license bonuses generated on state land is placed into the income fund of the land grant lease or into the state’s general fund. 68 Beginning in July 1987, monies collected by the oil and gas severance tax are allocated to the general fund. (Previously, 33-1/3 percent, not to exceed $42 billion per biennium, went to the local government block grant account.) Any amount collected over the previous fiscal year from a county, as a result of an increase in production, is allocated to the county’s general fund.5* The U.S. Department of Interior, Minerals Management Service (MMS) collects all royalties, rentals, bonuses, interest fees, and penalties from federally leased lands and deposits the funds into the U.S. Secretary of Treasury account. Under the 1976 Bureau of Land Management Organic Act, the federal government returns 50 percent of the monies collected from the lease lands for deposit to the state in which the money was collected. Before repeal of the windfall profits tax, the tax was deducted from the state’s collection by the federal government and then 50 percent of the remaining funds were transferred back to the state.55 Revenue Methods and Production A jurisdiction possessing natural resources attempts to maximize return on development through revenue-generating mechanisms that combine: (1) a rate high enough to cover external costs of production; (2) a rate not so high that it discourages production; (3) a rate appropriate to an anticipated or planned producing life of the resource; (4) a rate that corresponds in equity terms to other business activity; and (5) where appropriate, a rate that compensates government 69 as the owner of the resource. Hence, in the same jurisdiction, there may be a combination of methods to raise revenues to achieve these multiple objectives: leases and rents, licenses and reclamation fees, production royalties, severance taxes, property taxes and income taxes. The picture is complicated further by concerns of intergovernmental revenue-sharing in federal systems, involving federal governments, regional governments (state and provincial), and local governments. Any one or all of these methods of revenue generation may create financial incentives that affect levels of production which, in turn, will impact public revenue. Alberta takes the vast share of its revenues in the form of royalties and does not depend on a complicated mixture of severance taxes and property taxes, as in Montana. A royalty rate of approximately 22 percent on $30 per barrel oil yields the Alberta government about $6.50 per barrel. A Montana producer pays an effective rate of about 17.5 percent on old oil and 12.5 percent on new oil, as a result of changes made by the 1985 session of the legislature, yielding about $3.75 to $5.25 per $30 per barrel from four taxes. The Alberta Crown royalty rate is also set as a percentage rate, but this comes as revenue to the owner of the resource, not as a secondary tax on property or to compensate for depletion. Thus, because the royalties are deductible from Alberta corporate taxes, the purpose of the Alberta system is to reward production and to tax only profitability. The current set of tax provisions in Alberta is a result of two important events. One was the so-called "Western 70 Accord" agreement of 1985, whereby the Canadian federal government vacated some tax room to the province which it, in turn, gave the industry as production incentives; the second was the expansion of the industry royalty deductions and holidays to help the industry through the current depression in world oil price. The two events were discussed in detail in Chapter 3. In the case of petroleum, Montana employs every avenue for raising revenue. It leases and rents state lands, it charges regulatory license fees and resource indemnification taxes, it receives royalty shares from leases on federal lands in the state, it charges a severance tax that gives to the state general fund and a net proceeds tax that goes to the counties, and it applies a corporate income tax to producers. Most revenue comes from the severance tax and the net proceeds tax, both of which are ad valorem taxes that address level of production rather than profitability. With changing world oil prices, many wonder if this is the best approach, keeping in mind the several criteria introduced. Though the nature of the Alberta provincial government’s relationship with the oil and natural gas industry is significantly different from that of Montana, it does seem that at least one lesson can be drawn on the matter of taxation. End Notes iPrice-Waterhouse, Oil and Gas Taxation. Special accounting report, Calgary, Alberta, Canada, March 1986, p. 38. 2Ibid. 5Ibid. 4lbid., p. 39. 5Energy Pricing and Taxation Understanding (Agreement between the governments of Canada, Alberta, Saskatchewan, and British Columbia), 17 March 1985, Photocopy; and Statement by Premier Peter Lougheed and Energy Minister John Zaozimy on Alberta's Oil and Gas Incentives, 24 June 1985, Photocopy. ^Statement by Premier Peter Lougheed and Energy Minister John Zaozimy. . . , p. 4. 7Price-Waterhouse, pp. 39-40. 5 "Alberta Offered Oil Subsidies Worth $200 Million,” Oil and Gas Journal [Tulsa, OK], 16 June 1986: 44. ^rice-Waterhouse, p. 40. i0Ibid., p. 41. ^Montana Code Annotated. 15-31-304; 15-23-607; 15-23-106; 15-23-602; and 15-23-605. i2Bureau of Land Management, U.S. Department of Interior, Miles City (MT) District Office, Oil and Gas Environmental Assessment of BLM Leasing Program. Special report, 1980, p. 11. i3Price-Waterhouse, p. 24. 72 "Ibid. 75Ibid., p. 25. "Energy Pricing and Taxation Understanding. Agreement between the governments of Canada, Alberta, Saskatchewan, and British Columbia, 17 March 1985, Photocopy, pp. 4-5. ""Industry Assesses Effect of End to Canadian Tax," Oil and Gas Journal [Tulsa, OK], 22 September 1986: 24-25; and "Canadian Aid Program Draws Mixed Reactions," Oil and Gas Journal [Tulsa, OK], 6 April 1987: 31. "Montana State Department of Revenue, Report of the State Department of Revenue to the Governor and Members of the Forty-Ninth Legislative Assembly of the State of Montana for the Period July 1. 1982 to June 30. 1984. Helena, MT, n.d., p. 10. "Nancy McLane, 1982 Montana Energy Almanac. Montana Department of Natural Resources and Conservation, Energy Division, Helena, May 1983, p. 49; and Montana Code Annotated. 15-38-103. ^'Montana Legislative Highlights," Montana Oil Journal [Billings, MT], 11 June 1987: 4; and "Most Producing States Move to Give the U.S. Industry a Boost," Oil and Gas Journal [Tulsa, OK], 22 June 1987: 16. 2iMontana State Department of Revenue, pp. 16-17; and McLane, p. 49. 22Montana Code Annotated. 15-23-601. 2J "Most Producing States Move. . . ," p. 16. "McLane, p. 49; and Montana Code Annotated. 15-38-103. "Montana Code Annotated. 82-11-131. 2<5Steve Bender [Chief, Research Bureau, Montana Department of Revenue], personal interview with author, June 1986; and Montana State Department of Revenue, p. 25. 27Luigi Di Marzo [Director, Resource Statistics and Intelligence, Alberta Energy and Natural Resources], letter to author, 31 July 1986; and Mike Day [Assistant Deputy Minister, Department of Energy, Edmonton, Alberta], personal telephone interview with author, August 1986. 73 25McLane, p. 71; and Barbara Odegard [Chief, Mineral Leasing Bureau, Montana Department of State Lands, Helena], personal interview with author, 28 July 1986. 29Ibid.; Montana Code Annotated. 77-3-401, Administrative Rules of Montana (ARM), 26.3.205; and State of Montana, Office of the Legislative Auditor, Performance Audit: State-Owned and Leased Lands. Special report, Helena, MT, June 1983. 3<7McLane, p. 112; and Bender, interview with author. 3iIbid. 52Di Marzo, letter to author. 3JIbid. ^Montana Code Annotated. 7-6-302, 15-1-501, 15-36-112; and Bender, interview with author. J5Don Gilman [Branch Chief, BRASS System, Fiscal Accounting Division, Minerals Management Service, U.S. Department of Interior, Denver, CO], personal telephone interview with author, July 1986. 74 CHAPTER 7 CONCLUSION The purpose of this paper has been to stress the importance of focusing on Alberta as well as Montana for a more broad and systematic study of regional oil industry conditions. This recommendation is made in response to state policy makers’ expression of helplessness in the face of world conditions and national policies that virtually dictate the fate of the oil industry in this state. Nonetheless, Montana does shape its own state policy and certainly looks at the experience of neighbor states in doing so. As described in the previous chapters, Montana’s reliance on the regional trade patterns and market competition in petroleum products directs state policy makers to include the Canadian component in their analysis as well. Petroleum trade with Canada has to be analyzed according to the different effects it may have on Montana consumers and producers. Historically, Canada has been a source of cheap and abundant natural gas and crude oil supplies for Montana. However, a combination of high energy prices and changed Canadian federal energy policies reduced Montana’s reliance on long term supplies from Alberta. The more recent market situation of energy surplus has seen a return of increased crude oil imports for Montana refineries. In contrast, Montana 75 Power Company has continued to reduce its reliance on Canadian natural gas supplies, relying instead upon alternative resources such as coal-generated electricity. As a result, current trade patterns appear more beneficial to Montana consumers, for they provide cheap crude oil for the Billings/Laurel refineries and lower prices for the MPC natural gas customers. In spite of this trend, the recent focus for Montana policy makers has been on the production side of the coin. The impact on the state’s economy from the depressed worldwide price of crude oil and the shift in regional trade patterns, which impacts the health of the industry, dominate energy policy discussion in the state legislature. Legislative solutions focus on tax policies and industry incentives to stimulate production. At this juncture, what can state lawmakers and energy policy analysts learn from a Canadian comparison? The overall lesson is knowing the value of regional differences. One important lesson can be found from assessing the preference multi¬ national oil companies have for Alberta over Montana. Why have multinationals concentrated their activity in Alberta when the two regions have basically the same geological structure? Alberta differs from Montana because it is a proven area of abundant oil and gas reserves. In contrast, not all of Montana has been explored for its oil and gas potential and no similarly large reserve has been found in the state. Alberta, both in terms of size and reserves, compares more favorably with Alaska or Texas. In terms of sheer abundance of proven reserves, then, Montana has a second-rate oil and natural gas production potential when 76 set alongside energy giants like Alberta. No policy action in Montana can alter this geologic reality. Second, Alberta’s regulatory approach toward the petroleum industry differs from Montana’s because the provincial government owns the resource. As a result, the province has developed a unique regulatory and tax regime in response to production and trade. Because of this, Alberta takes the vast share of its revenues in the form of royalties and does not depend on a complicated mixture of severance and property taxes, as does Montana. The Crown royalty rate is set as a percentage rate, and because royalties are deductible from Alberta corporate taxes, the purpose of the system is to reward production and tax only profitability. In Montana, most revenue comes from the severance tax and the net proceeds tax, both of which are ad valorem taxes that address levels of production rather than profitability. The Alberta system also allows the government to offer massive incentive packages such as royalty reductions and royalty holiday programs. The ability of the government to respond to changes in the world market conditions in this manner means that the industry can receive and respond to special incentives in a relatively short time period. By contrast, Montana’s industry is dominated by small and independent producers, located primarily in the Williston Basin of eastern Montana. Net proceeds and oil severance tax breaks on new productions for one or two years will likely help to sustain the current level of production in the state. Attempts 77 by Montana to compete with $1 billion Albertan economic aid packages for the oil industry and draw additional activity south of the 49th parallel are not realistic goals. Moreover, because the existing pipeline transportation system sends 70 percent of Montana oil production out of state to be refined, Montana producers are not competing with Canadian suppliers for refinery markets in state. It is important to be realistic about the limits to the comparisons. The Alberta petroleum industry dwarfs that in Montana; Alberta has produced as much as one billion barrels per year, compared with a recent Montana peak production of 32 million barrels. Canada has relied on Alberta for as much as 85 percent of its total production, whereas Montana has only supplied nine-tenths of one percent of U.S. production/ Another important difference is that Alberta owns most of the mineral rights on oil producing lands, in contrast to the public and private pattern of ownership in Montana.2 The question that remains is: How do past and current policy lessons affect the future of Montana’s own industry? One could argue that policy makers have responded well to energy planning issues and therefore should be satisfied with the status quo. This paper, through its review of one component of regional trade and tax policies, provides the basis to argue that Montana should take a regional approach to planning energy policy. It is just as important for lawmakers to understand the differences (e.g., tax regimes and production incentives) as well as the similarities (e.g., regional and international markets) when designing and implementing petroleum policy. Two alternatives are presented. 78 First, as planners and decision makers respond to shifts in the world energy markets, a Canadian perspective could be folded into the analysis of regional policies. A primary example of this approach is the Environmental Quality Councirs analysis of regional environmental policies which included an Albertan review. The Alberta example could be used to argue for stronger regulatory controls which would still allow a more intrusive industry in environmentally sensitive areas. The support for a second alternative lies within the context of the state’s move toward more formalized ties with Alberta. 'Transborder regionalism" provides the opportunity for the state to develop a comprehensive energy policy. Market ties, e.g., natural gas and crude oil imports, have already established the informal network that might be a prelude to more formal public policy ties. To develop a comprehensive policy, it would be advisable to form a team of policy analysts and economists from the academic, government and industry fields. This team would be able to address the broader issues which include a Canadian perspective. The energy policy could cover petroleum production, trade and taxation. The benefit of this type of policy rests with the potential to mitigate the effects of unfocused regional responses to changes in the international petroleum market. Finally, the idea of comparing the states and the provinces is likely to be useful in many areas beyond petroleum policy. Montana could look to provincial experiences in the area of petroleum policy for alternate choices in other state 79 natural resource policies such as timber production and marketing. The point is that as the world moves toward an integrated international economy, Montana should focus on its regional markets to gain an understanding of the options it has in developing state policy. 80 End Notes ^American Petroleum Institute, "U.S. Marketed Production of Natural Gas by State, mcf and "U.S. Crude Oil Production by State, 1000 Barrels," in: Basic Petroleum Data Book: Petroleum Industry Statistics. Vol. 7, no. 1 (Washington, DC: Author, January 1987). 2Alberta Energy and Natural Resources, Mineral Resources Division, "Current and Historical Oil and Gas Tenure Legislation in Alberta," AENR working paper, Edmonton, Alberta, June 1984, p. 3. 81 REFERENCES 82 REFERENCES Alberta Economic Development Council. Alberta Industry and Resources. 1984. AEDC special report. Edmonton, Alberta, Canada, December 1984. Alberta Energy and Natural Resources, Mineral Resources Division. "Current and Historical Oil and Gas Tenure Legislation in Alberta." AENR working paper. 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Historical Development, and Current Status. New York: Charles Scribner’s Sons, 1964. 85 Hatter, David. "Masse Lands in Natural Gas Hotseat." The Financial Post [Toronto, Ontario, Canada], 12 July 1986. Hoffman, Ellen. "Overseas Sales Pitch." National Journal 3 (16 January 1988): 129-133. Holubowich, Frank J. "Will Reversion of Deep Rights Lead to a Resurgence in Exploration in Alberta?" The Journal of Canadian Petroleum Technology (April 1983): 81-82. Hopkins, Stephen. "Lougheed Era, Energy: Alberta Takes Charge." Alberta Report. 8 July 1985: 10. "Industry Assesses Effect of End to Canadian Tax." Oil and Gas Journal [Tulsa, OK], 22 September 1986: 24-25. Kuntz, Gail. Comparison of Environmental Regulation of the Oil and Gas Industry in the Rocky Mountain States and Alberta. Special report. Montana Environmental Quality Council, Helena, MT, July 1986. Leach, Richard, Donald E. Walker, and Thomas Allen Levy. "Province-State Trans-Border Relations: A Preliminary Assessment." 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National Governors’ Association. U.S.-Canadian Energy Trade: Executive Summary. NGA special report. Boise, ID, August 1986. Odegard, Barbara. [Chief, Mineral Leasing Bureau, Montana Department of State Lands, Helena.] Personal interviews (various) with author, 1986. "Oilmen See Little Drilling in Overthrust Belt." Bozeman (MT) Daily Chronicle. 19 October 1986: 9. Orr, Fay. "At Long Last Relief: Ottawa Unveils Its Long-Awaited Aid for the Oil Patch." Western Report [Edmonton, Alberta, Canada], 6 April 1987: 6-10. Price-Waterhouse. Oil and Gas Taxation. Special accounting report. Calgary, Alberta, Canada, March 1986. Restrictive Trade Practices Commission, Minister of Supply and Services Canada. Competition in the Canadian Petroleum Industry: Introduction. Conclu¬ sions and Recommendations. RTPC special report. Ottawa, Canada, 1986. Rose, Mitchall and John Howse. "Ottawa Strikes a Deal." MacLeans 99, no. 45 (10 November 1986): 14-15. Slocum, Dennis. "Cash-Short Energy Firms Cut Spending." The Globe and Mail [Toronto, Ontario, Canada], 19 March 1987. "Speakers Predict Oil Industry Will Rebound." Bozeman (MT) Daily Chronicle, 3 November 1986. State of Montana, Office of the Legislative Auditor. Performance Audit: State- Owned and Leased Lands. Special report. Helena, MT, June 1983. 88 Statement by Premier Peter Lougheed and Energy Minister John Zaozimy on Alberta’s Oil and Gas Incentives. 24 June 1985. Photocopy. Steele, Lynda. Montana Historical Energy Statistics. 5th ed. Helena, MT: Department of Natural Resources and Conservation, Energy Division, 1984. Steele, Lynda. Notes for Montana Historical Energy Statistics. 5th ed. Department of Natural Resources and Conservation, Energy Division, Planning and Analysis files, Helena, MT, 1984. Swanson, Roger Frank. State/Provincial Interaction: A Study of Relations Between U.S. States and Canadian Provinces. U.S. State Department report. Washington, D.C.: Government Printing Office, 1974. Walsh, Natalie. Montana Natural Gas and Petroleum Review. Helena, MT: Department of Natural Resources and Conservation, Energy Division, May 1983. Warne, G.A. [Technical Assistant to the Board, Energy Resources Conservation Board, Calgary, Alberta.] Personal letter to author, 28 July 1986. Westell, Dan. "Ontario Minister Seeks to Clarify Aspects of Gas Deregulation Deal." The Globe and Mail [Toronto, Ontario, Canada], 13 November 1986. 89 APPENDIX 90 Table 1. Percentage of total refinery receipts by source of crude oil, 1976-1985. Year Location Montana Wyoming Canada 1976 16.93 36.38 46.69 1977 18.49 37.78 43.32 1978 18.51 36.64 44.71 1979 17.12 36.29 46.58 1980 17.92 42.60 39.42 1981 22.40 47.16 30.40 1982 21.40 42.13 36.47 1983 16.98 45.75 37.16 1984 18.21 47.86 33.80 1985 18.97 41.94 39.06 Source: Montana Department of Natural Resources and Conservation, Oil and Gas Conservation Division, Montana Oil and Gas Annual Review (various issues), Helena, MT.