1 The extraction of natural gas from shale using techniques of hydraulic fracturing (fracking) currently takes place in several jurisdictions in the United States and Canada, notably in British Columbia and Alberta. At the same time, several political jurisdictions have imposed moratoriums on fracking, including the state of New York and the Canadian provinces of Quebec, Nova Scotia, and New Brunswick. In these cases, there was a process of public engagement, supported by analytical research of the economic, social, environmental, and public health implications of fracking, varying in the depth of the analysis and the transparency of their proceedings. Part of the economic research was concerned with the revenue implications of alternative systems of royalties.

2 In the case of New Brunswick, a re-evaluation of the natural gas royalty system was initiated by the New Brunswick Department of Finance in 2011. This continued during the public shale gas consultation process and culminated with the introduction of legislation in 2014, which replaced the previous 10% natural gas royalty with a more complex economic rent royalty1 that varied with the profitability of the businesses. The government consistently argued that the new system would increase revenues to the province. For example, the government’s natural gas group suggested in 2012 that natural gas royalties could yield $2.2 billion per year within twenty years (“Sharing of Royalties” 7), an amount greater than the $1.5 billion in equalization payments received from the federal government. More recently, the February 2016 report of the New Brunswick Commission on Hydraulic Fracturing provided illustrations with annual natural gas royalty revenues between $400 and $600 million annually within twenty years (28). The variations in the estimates were, however, difficult to explain given the lack of transparency regarding the methodologies employed.

3 The principal objective of this paper is to provide a publicly accessible model for estimating New Brunswick royalties from shale gas. To that end, the spreadsheets containing the complete models are available on the website of the Journal of New Brunswick Studies and readers are encouraged to provide their comments to the authors.

4 As context, we begin with a brief description of provincial natural gas royalty systems in Canada, identifying the distinctive aspects of the New Brunswick system. We summarize the historical origins of the current New Brunswick system, followed by a detailed description of how the royalties are calculated. We then explain the methodology we have used to estimate shale gas royalties under four alternative scenarios and provide our quantitative estimates of the potential revenues that could be generated by the new system compared with the old system in those scenarios. The final section of the paper summarizes our conclusions.

5 In most provinces, royalty systems for shale gas developed as modifications of conventional natural gas royalty systems. Table 1 summarizes these conventional provincial royalty systems which, with some variations, increase their royalty rates when the price of natural gas and/or the productivity of the particular well increase. They differ in the degree to which royalty rates change with changes in market prices and well productivity, and the extent to which they use developmental incentives to reduce royalty rates. For example, the basic rates in Alberta and Saskatchewan vary with productivity while those in British Columbia do not, except for special programs that provide royalty reductions for especially unproductive wells.

6 In recent years, the major natural gas producing provinces of Alberta, Saskatchewan, and British Columbia have introduced incentives for shale gas exploitation, driven primarily by tax competition and the desire to accelerate the speed of development, especially in remote areas. With a few exceptions (due primarily to the nature of the particular shale deposits), British Columbia and Alberta have royalty systems for shale gas that are similar in terms of royalty rates and incentives for development of similarly situated reserves. Our focus here is on the royalty systems and not the revenue generated from auctions of exploration rights (bonus bids), which are significant in the western provinces but are not used in New Brunswick.

7 Between 2011 and 2014, the government of New Brunswick carried out an internal review of the natural gas royalty regime, as part of a more general review of royalties for natural gas, oil, potash, and minerals. A cornerstone of that review was the conceptual difference between royalties calculated as a percentage of the selling price and royalties designed to capture the economic rent associated with the resource. In the past, royalty payments in New Brunswick were viewed as payment by the private sector for the transfer of ownership of a public resource. No attempt was made to account for the profits or the losses that businesses might experience when extracting the resource. As Table 1 indicates, New Brunswick’s royalty was historically 10% of the wellhead selling price, in contrast with Alberta where royalties could be as high as 36% of revenues, depending on the selling price and the productivities of individual wells.

8 From the economic rent perspective, royalties could capture for the public all “excess profits” (i.e., economic rent or profits in excess of some normal rate of return) that firms might receive from high resource prices or the low production costs that could result from unusually productive gas wells. Moreover, economic rent-based royalties require that the public sector share the risks of losses from low resource prices or high production costs. From this perspective, economic rents could be taxed up to 100% without changing the behaviour of firms. This is so because, by definition, economic rent is a rate of return above and beyond that which is required to induce a firm to undertake a particular investment.

9 In July 2011 the Department of Finance contracted with a private consultant to conduct a theoretical analysis of royalty structures and “propose a royalty structure for oil and gas (including natural gas)…that optimizes the value of resources to New Brunswick in a manner that does not interfere with investment” (New Brunswick “Contract” 4). The report, “An Assessment of Royalty Policy in New Brunswick” (hereafter, “Assessment”), recommended a shift to an economic rent royalty system, a recommendation that became the basis for the shale gas royalty system. Specifically, the consultant recommended a rent-based royalty of 25% (of net cash flow) with a minimum 4% tax on revenues from sales. Current and capital costs were to be fully deducted from revenues in calculating net cash flow; any unused deductions could be carried forward, and minimum royalty payments were to be fully credited against the cash flow tax. The consultant’s recommendations were informed by the theoretical advantages of economic rent royalties and recent experience with rent-based royalties for unconventional oil production in Alberta and internationally (New Brunswick “Assessment” 7). The consultant did not estimate the revenue impacts of the proposed royalty regime.

10 In May 2012, the New Brunswick government announced their public-input process (chaired by Louis LaPierre) for June and provided the public with two documents: “Responsible Environmental Management of Oil and Gas Activities in New Brunswick: Recommendations for Public Discussion” and “Responsible Environmental Management of Oil and Gas Activities in New Brunswick: Sharing of Royalty Revenues from Natural Gas Activities in New Brunswick” (New Brunswick Natural Gas Group). The documents recommended continuation of the historical royalty of 10% of natural gas revenues in addition to a new 40% economic rent royalty calculated using the same methodology as in the consultant’s report (New Brunswick “Assessment”). Of special note is that the proposed royalty regime would not follow the “ring fence” approach of western Canadian provinces; that is, in New Brunswick, shale gas companies could deduct expenses from all of their provincial operations (all wells) against their province-wide net cash flow before paying their economic rent royalty.

11 In October 2012, LaPierre released his report, The Path Forward, which did not comment on the proposed royalty system. In May 2013, the New Brunswick government released “The New Brunswick Oil and Gas Blueprint,” which provided no additional information related to their proposed royalty system. It mentioned that it was continuing to review revenue sharing, and indicated that it was also continuing with stakeholder consultations. In April 2014, the New Brunswick government implemented the new natural gas royalty, combining a minimum percentage royalty on sales revenues (between 2% and 4%) with a 25% economic rent royalty. No background studies were provided to justify the tax rates or to estimate the expected revenues compared with the previous system.

12 The economic criteria applied to any tax or royalty include the implications for economic efficiency, equity, costs of administration, tax transparency, and the reliability of the revenue stream (Boadway and Wildasin 225). On efficiency grounds, taxes on economic rents are considered superior to other revenue sources, given their limited impact on private decision-making under competitive market conditions, even when economic rents are taxed at up to 100%.2 However, there is less consensus about the other criteria. From the equity perspective, the issues relate to the distribution of the costs and benefits of resource exploitation for both current and future generations, their methods of estimation, and how the distribution compares to other taxes. Administration of an economic rent royalty will require costly auditing of the financial records of each firm’s operations within the province; such auditing would not be required with a simpler revenue tax. Additionally, tax transparency is limited by the lack of access by the public to corporate proprietary financial information, which is at the core of the royalty calculations. While all of these issues are important in the choice of royalty regime, we confine ourselves in this paper to the analysis of one economic aspect of the shale gas royalty system in New Brunswick: the reliability of the revenue stream, specifically the size and timing of the royalty revenues that New Brunswick might expect from the current royalty system in comparison to the old system.

28 In Table 2, we summarize our findings for the four scenarios. There are three main points of interest. First, the royalty revenues are highly sensitive to the EUR. Given an EUR of 2.0 Bcf (slightly higher than the historical Marcellus experience), the old system yields 32% more present value revenue than the new system. With a higher EUR of 2.5 Bcf, the new system yields 15% more revenue. With the higher EURs of 3.0 and 3.5 Bcf, the new system yields, respectively, 46% and 69% more revenue than the old system. Second, the impact of the current royalty system on provincial revenues is relatively small in the context of an $8 billion provincial budget. For example, in the EUR 2.5 scenario, it is ten years before there is a net cash flow for purposes of calculating the economic rent portion, and annual revenues are less than $35 million during the first nine years. It is only in the high EUR cases where revenues are high enough to have significant impacts on provincial finances. Third, our scenarios suggest that it is unclear whether the royalty system introduced in 2014 will yield higher revenues than the previous system. That will depend on the average EUR of wells, which is uncertain. Fourth, the scenarios demonstrate that all projections are very sensitive to the choice of assumptions. We have based our scenarios on alternative assumptions about the productivity of the resource, as it has a great deal of uncertainty. Our other assumptions are given with the detailed spreadsheets (available at the JNBS website) and the specific cost assumptions are described in Appendix 3.

29 All royalty systems based on economic rent, as opposed to a fixed percent of revenue, involve the government sharing more of the risk associated with the uncertainty of future well productivity. This is demonstrated in Figure 1, which illustrates how the new royalty system gives up revenues in the early years in expectation of higher royalty revenues in later years. In this case (EUR 2.0), it is not until the nineteenth year that the new system generates revenues greater than the previous system. Further, the higher revenues in later years would not compensate for the lost revenues in the early years. Should the average EUR prove to be significantly higher, then the converse would apply. This is demonstrated by the relatively higher discounted present value of the revenue stream of the new royalty system when the average EUR is 2.5 or higher. If the productivity of the average well is higher, then the new system will generate relatively higher revenues.

30 The decision about whether or not to produce natural gas by fracking requires consideration of its social, environmental, public health, and economic consequences. One component of the economic consequences is the effect on government royalties paid by corporations for the privilege of exploiting the publicly owned resource.

31 The objective of this research was to develop a publicly available model to evaluate the revenue claims associated with the new natural gas royalty system introduced in New Brunswick in 2014. In the process, we have drawn attention to some of the economic aspects of the royalty system. These include the considerable uncertainty associated with any revenue projections and the general risk sharing (with private developers) that the province has taken by including a tax on economic rent as an important component of the new system. We have focused on one area with a great degree of uncertainty—the productivity of the shale resource and its relation to royalty revenues.

32 We have concluded that the new royalty regime could produce more revenues than the old regime on a present value basis only if well productivities are relatively high. Additionally, the time profiles of revenues differ significantly between the old and new systems. The old royalty regime produces relatively more revenues in the early years of development, while the new regime postpones revenues in the hope that economic rents will materialize to be taxed in the future. As a result, shale gas royalties under the new regime would not make a significant contribution to the province’s finances in the early years of development, and would only do so in the longer term with high well productivities. In the future, if New Brunswick decides to open the shale gas moratorium for public discussion, our model may be of assistance in providing the public with an understanding of the royalties which shale gas may, or may not, deliver.