## Economic Analysis for The Proposed Commercial Oil Shale Management Regulations Introduction By statute and executive order , an agency proposing a significant regulatory action is require d to provide a qualitative and quantitative assessment of the anti cipated costs and benefits of that action

. Executive Order 12866 requires agencies to assess the benefits and costs of regulatory

actions , and for significant regulatory actions, submit a detailed report of their assessment to the Office of Management and Budget (OMB) for review. A rule may be significant under Executive Order 12866 if it meets any of four criteria. A significant regulatory

action is any

rule that may :

 Have an annual effect on the econom y of $100 million or more or adversely affect in a material way

the economy , a sector of the economy , productivity , competition, jobs, the environment, public health or safet y, or s tate, local, or tribal governments or communities;

 Create a serious inconsistency or otherwise interfere with an action take n or planned b y another agency;

 Materiall y alter the budgetary impact of entitlements, grants, user fees, or loan programs or the rights and obligations of recipients thereof; or

 Raise novel legal or policy issues arising out of legal mandates, the Presi dent’s priorities, or the principles set forth in the Executive Order. For a major rule, as defined by the Small Business Regulatory Enforcement Fairness Act (SBRE FA), the agency

must prepare an initial regulatory flexibility

anal ysis. For SBRE FA , a rule may

be major if i t meets an y of three criteria:

 Have an annual effect on the econom y of $100 million or more;

 Create a major increase in costs or prices for consumers, individual industries, Federal, State, or local government agencies, or geographic re gions; or

 Have significant adverse effects on competition, employ ment, investment, productivity , innovation, or on the ability of United States

- based enterprises to compete with foreign

- based enterprises in domestic and export markets.2

If determined to b e a major rule SBRE FA requires an agency to prepare an anal ys is when issuing a proposed rule that will have a significant impact on a substantial number of small entities. 

### Statem ent of Need The Energy

Policy Act of 2005 (42 U.S.C

. 15927) requires the Dep artment of the Interior (DOI) to publish oil shale commercial leasing program regulations

. In 2008, regulations were promulgated addressing the leasing and management of oil shale development on Federal lands. In 2009, these regulations were challenged i n court. As a result of this suit, D OI entered into an agreement that included proposing specific changes to the existing regulations. 

### Proposed Rule This new rule provide s the BLM an opportunity to consider the 2008 regulations in light of the still nas cent character of the technology necessary

to economically

develop the oil shale resources. In addition, after publication of the final rule in 2008, the regulations were challenged in Federal C ourt. As part of the settlement agreement, the BLM agreed to propose revisions to the 2008 regulations b y addressing the ro yalt y rate and certain environmental protection requirements applicable to commercial oil shale leasing. This proposed rule would revise the regulations at 43 CFR Parts 3900, 3920, and 3930. This proposed rule considers whether the ro yalt y rate for commercial oil shale production should not be set until more is known about the emerging oil shale technologies, whether future applications to lease should include specified resource protection pla ns (watershed and groundwater protection plan, an airshed review, an integrated waste management plan, and an environmental protection plan) , and activity would not be approved unless operations could proceed without unacceptable environmental risk

. 

### Alter native Approaches Pursuant to the settlement agreement , the Secretary of the Interior (Secretary) must propose revisions to the existing oil shale leasing and management regulations

. Three main areas under consideration are the ro yalt y rate, specific res ource protection plans , and specific environmental standards. Royalt y Rates The Energy

Policy Act of 2005 directs the Secretary to “establish royalties, fees, rentals, bonus, or other pay

ments for leases under this section that shall:
E ncourage developm ent of the oil shale and tar sands resource; and
E nsure a fair return to the United States.”3

Encourage Development

- For economicall y developable resources, the various pay ments required to obtain, hold , and produce on a Federal oil shale lease will affe ct the lease’s development potential. The lower those pay ments, the less likely

those costs will adversel y impact that potential. However, a reduction in those payments will not make an uneconomic operation financiall y viable. Fair Return

- In the conte xt of this regulatory initiative, fair return is considered the functional equivalent to fair market value (FMV). Fair market value is a well

- established concept in law, case law, regulation , and practice for a number of BLM mineral and non

mineral manage ment programs. The Federal Land Policy and Management Act (FLPMA) declares a policy that “the United States receive fair market value for the use of the public lands and their resources unless otherwise provided for b y statute.” A propert y’s FMV is based on the appraisal concept of the price a property would sell for given a knowledgeable and willing, but not obligated, buyer and seller. It is intended to be an estimate of what would occur in a market situation. Two commonly

accepted procedures for valu e estimation are the comparable sales approach and the income approach. The comparable sales approach is an appraisal procedure in which the prices paid in prior transactions of similar properties are used to value the propert y to be disposed of through l easing, exchange, or other means. This procedure generall y is preferred to other appraisal procedures since it is thought that prices paid in prior market transactions of similar properties provide the best indication of value. The income approach involv es the estimation of annual costs and revenues associated with the development of the propert y under realistic conditions. Annual cost and revenue streams are reduced to a single number in which future costs and revenues are discounted to the present. Th e property 's net income potential, discounted to the present, provides an estimate of current sale value. Under either approach, ascertaining a value figure must consider all factors that might affect the propert y’s market value. When estimating a prop erty ’s FMV, the agency is generall y focusing on the bonus bid, assuming all other factors, including the ro yalt y rate, to be held constant. Conversel y, in making a determination about what ro yalty rate would ensure a fair return requires the bonus bid to be held constant. Whether estimating the bonus bid or the ro yalty rate, to make a meaningful estimate, the oil shale lease must have the potential to be economically developed. In the absence of an economic propert y, the bonus bid and/or ro yalty rate wou ld be a negative figure. For economicall y developable resources, these payments will affect the lease’s development potential. These pay ments are cost, and as with all acquisition, development and production costs, must be considered when determining the ro yalt y rate and bonus bid level that will allow the proposed operation to go forward. Under no scenario can the fair return for these pay ments be so onerous that the proposed development becomes uneconomic.4

The ability

to set a royalty

rate that meets both these requirements is dependent on a demonstrated technology to economicall y develop the resource. At this point in time, such technology

has not been demonstrated. In 2009, e nvironmental groups sued the Secretary , arguing in part that the royalt y r ates established in the 2008 oil shale regulations were insufficiently supported and did not assure a fair return to the United States. Indeveloping this rule, a pproaches the BLM considered in addressing the royalty rate to apply

to oil shale leases included : R etaining the current ro yalty scheme ; P ropos ing a new rate or sy stem of rates; or E stablish ing the rate prior to a lease sale or lease conversion. During negotiations to settle that litigation, the BLM considered again the analy sis of the royalt y rate alternatives that was considered prior to the promulgation of the 2008 oil shale regulations to determine whether to propose any amendment to those rates. The BLM determined that the 2008 anal ys is was the best possible given the information availabl e at that time, but there could be doubt as to whether that information would accuratel y predict the relevant financial conditions of a commercial oil shale industry in the United St ates. Therefore , the BLM has decided to propose that royalt y rates should be established on a lease

- by

- lease basis, with the benefit of information from Research, Development, and Demonstration (R, D and D) leases or other oil shale operations on non

- Federal lands ; information that is not available at this time. The BLM expect s that the comments on the proposed regulations will include detailed discussions of how best to establish roy alt y rates for an industry

that has not y et become commerciall y viable. The BLM also considered whether to propose establish ing a new ro yalt y rat e or rates. The BLM decided that there is no new information since the 2008 rule about the costs and revenues of commercial oil shale operations or about ro yalties actually paid to non

Federal mineral owners in the United States that would support establi shi ng ro yalt y rates at this time. In addition to the proposal, the BLM is also requesting comments from the public on various options for establishing an applicable ro ya lty scheme. These options are discussed below. Option 1

- Invite Comment on Proposed Lease Terms in a Proposed Notice of Lease Sale Under this option, the BLM would first publish a proposed notice of sale or conversion to a commercial lease for a period of not less than 30 day s. That proposed notice would include all proposed lease ter ms and stipulations, including proposed royalty and rental rates. It also would include an explanation of how the BLM determined the proposed5

royalt y rate. This would give interested parties and the public an opportunity to comment on all the proposed te rms, including the proposed royalt y rate. Under this option , and so as to allow adequate time for both comment and consideration of the comments, the BLM would amend s ection 3924.5 to require at least 60 day s between publication of the proposed notice of sale and the notice of sale. Option 2

- Invite Public Comment Using Coal Lease Sale Process As an alternative to publishing a proposed notice of sale, the rule specifically seeks comments on a possible alternative procedure that would be modeled after a provision in the Federal coal leasing regulations at 43 CFR 3422.1. Instead of publishing a proposed notice of sale, the BLM would, at least 30 day s before the notice of sale, solicit public comment on the fair market value of, and expected economic reco very from, the oil shale lands proposed to be offered for lease and on what royalt y rate and other lease terms or stipulations commenters believe should be required. The authorized officer would prepare a report evaluating the comments and containing his or her recommendations for the minimum bid and for the royalty rate and other lease terms to be included in the leases offered. Option 3

- Sliding Scale Royalt y Based on the Market Prices of Oil and Gas In the 2008 proposed oil shale rule, the BLM consid ered and sought comment on a sliding scale ro ya lty

. That approach was not adopted in the final 2008 rule, but in light of the need to reconsider the existing royalty rates under the terms of the settlement agreement , this rule seeks public comment on the best approach to implementing a sliding scale ro ya lty

structure. Although the BLM has expressed concerns in the past about the complexity of administering certain proposed sliding scale ro yalty proposals, we recognize that there is merit to the sliding sc ale concept, and in a simpler form, a sliding scale ro yalty could prove extremel y useful in meeting the dual goals of encouraging production and ensuring a fair return to taxpay ers from future oil shale development. One of the concerns that has been expre ssed regarding oil shale development is that potential oil shale developers may be reluctant to make the large up

- front investments required for commercial operations if they believe there is a chance that crude oil prices might drop in the future below th e point at which oil shale production would be profitable (i.e., competitive with conventional oil production). A sliding scale ro yalt y sy stem could allow the government to at least partiall y mitigate this development risk by providing for a lower ro ya lty rate if crude oil prices fall below a certain price threshold. The basic concept is that in return for the Federal G overnment accepting a greater share of the price risk that an operator faces when prices are low (in the form of a lower ro ya lty), the G ov ernment would receive a greater share of the rewards (through a higher royalt y) when prices are high.6

The BLM has not decided on the specific parameters of a sliding scale ro ya lty sy stem, but is considering a simplified two

- or three

- tiered sy stem based o n the current royalty rates already in effect for conventional fuel minerals. The applicable ro yal ty rate would be determined based on market prices of competing products (e.g., crude oil and natural gas) over a certain time period. In a two

- tiered s ys te m, if prices remain below a certain point during the applicable period, the ro yalt y rate on oil shale products would be the lower of two options. If prices are above that range for the period, the higher royalt y would be charged. In a three

- tiered s ys tem , a third royalt y rate would apply if prices rise above a second price threshold during the applicable period. Option 4

- Establish a Minimum Royalt y of 12.5% in Regulation, with Secretarial Flexibility to Establish a Higher Rate Later Under this option, a minimum royalt y of 12.5% would be established to address concerns about the existing rate and implement the terms of the settlement agreement. The minimum royalty

rate of 12.5%, the same rate as currentl y applied in the BLM's oil and gas program, is be ing considered as it is contemplated that the primary products produced from oil shale will compete directl y with those from onshore oil and gas production. However, the Secre tary

would have the authorit y to establish a higher rate, if determined to be ap propriate, without completing a new rulemaking. This option would provide flexibility for the the Secretary

to adapt and respond accordingl y to new information , such as emerging oil shale technologies , future oil shale production cost information , and changes to the price of this commodity , in order to help assure a fair return to the United States

. Establishing a minimum royalt y would be consistent with how other conventional fuels (e.g., oil, gas , and coal) are treated under existing statutes and regulations. In order to promote transparency in connection with the proposed change to allow a higher ro yalt y rate to be established at a later time, the BLM would add a requirement to first publish a proposed notice of sale. That proposed notice would includ e all proposed lease terms and stipulations, including proposed roy alty and rental rates. It also would include an explanation of how the BLM determi ned the proposed ro yalt y rate. The notice would invite comment on the proposed lease terms for a period o f not less than 30 day s. This would give interested parties and the public an opportunity to comment on all the proposed terms, including the proposed ro yalt y rate. So as to allow adequate time for both comment and consideration of the comments, the BLM would require at least 60 day s between publication of the proposed notice o f sale and the notice of sale. The rule also invites comments on any other royalty

sy stem or rates that would meet the dual two requirements of the Energy Policy Act of 2005 to enc ourage production and ensure a fair return to the public. The cost of implementing the se alternative ro yalty schemes would not vary significantl y for either the industry

or the BLM. The proposed scheme , where the royalty rat e will be established on a l ease - by

- lease basis , will, however, add a level of uncertainly for7

prospective lessees. The uncertaint y in ro yalt y rates might discourage commercial oil shale development b y requiring entities to make business decisions with less information. Although th is is a concern in theory , the proposed approach mirrors the approach used b y the BLM for non

- energy

solid mineral leases. Resource Protection Plans Under the settlement agreement the BLM is required to propose expand ing the information required from ope rators as part of its plan of development (POD). The BLM considered several alternatives , including:
Re lying on the requirement in the 2008 regulations to provide an y additional information necessary

for the BLM’s review of a proposed POD; or Propos ing various specific resource protection plan, information , and review requirements. The BLM considered whether such new requirements were necessary in view of the provision in the regulations allowing the BLM to require operators to provide an y additional i nformation necessary for the BLM’s review of a proposed POD. The BLM agreed to propose regulations requiring operators to submit a watershed and groundwater protection plan, an airshed review, an integrated waste management plan, and an environmental prot ection plan as part of each proposed POD because such information would likely

be necessary

in all cases to conduct a complete analy sis under the National Environmental Policy

Act of 1969 (NEPA) , and to assure that resources on the public lands are manage d in the best interests of the United States . Thus, not including those plans and reviews would result in the BLM requiring that additional information from operators on an ad hoc basis even though it would not have been specified in the regulations. Th e proposed requirements would more completel y inform the industry and the public of the minimum requirements for a complete POD.
T he proposed specific resource protection plan requirements might appear to be a significant additional co st to the applicant t o prepare and for the BLM to review. This proposal , however, simply codifies in regulation what would likely be required for compliance with the requirements of NEPA prior to approval of a POD . T he cost of implementing the various resource protection plans and review requirements sh ould not vary significantl y between the alternatives for either the industry or the BLM. Environmental Standard Under the settlement agreement the BLM is required to propose an environmental performance standard for approval of oil shale leases and operations. The BLM considered several alternatives including: Continuing to make decisions based upon the BLM’s judgment subject to the mandate of the Federal Lands and Policy Management Act of 1976 ( FLPMA ) to prohibit unnecessary8

and undue degradation ( UUD ) of the public lands, except that the existing R , D and D lease s include an additional standard for conversions to commercial leases that operations would not cause unacceptable environmental consequences (UEC) ; a ppl ying the UE C standard for all decisions; or applying the unacceptable environmental risk (UER) standard to all decisions. The BLM had included in the eight outstanding R , D and D leases a standard for deciding whether to approve conversion to commercial leases

– UEC

. The BLM took that standard from a decision by the United States Court of Appeals for the District of Columbia Circuit in a case concerning compliance with N EPA . Although UEC is not defined, the intent was that it would be a n appropriate qualitative standard for oil shale operations . In the course of its consideration of proposing regulations, however, the Department of the Interior ( D OI ) decided to propose as the standard UER

. The D OI reasoned that the BLM should not be placed in the unintended positi on of having to issue leases or to approve plans of development unless it could prove that “consequences” would result, rather, it should be the proponent’s burden to establish that the risk of unacceptable environmental outcomes was acceptable. The notic e of proposed rulemaking expressly

requests public comments on both UEC and UE R.
T he BLM also considered proposing no environmental standard, but instead employing for oil shale the practice of the BLM of using its best professional judgment instead of a regulatory

standard of environmental acceptability in light of the mandate in FLPMA to prevent UUD of the public lands. This approach is used by the BLM in managing other resource uses. The BLM would benefit from thoughtful comments on whether an environmental standard is necessary and , if so, what it should be. Assessing the cost differences between these alternative is problematic. The BLM has extensive experience in evaluating environmental consequences, specifically tied to carryi ng out its FLPMA , UUD , and NEPA anal ys is and disclosure responsibilities. The agency has limited experience in evaluating and measuring environmental risk, and that standard generall y applies to laws that govern hazardous materials. The BLM does not anticipate that a quant itative risk assessment would be possible for its decisions regarding oil shale leasing and development. The application of this standard qualitatively may increase the economic burden for the agency and the proponent, potentiall y including the costs of n on - approval. However, there is no practical way of quantifying the potential costs of this regulatory

alternative. As a practical matter, applying either the UUD or the UEC standard would probably result in the same level of protection. Both standards are based on the BLM’s und erstanding of the environmental impacts of a proposed action. Application of either standard would involve the BLM’s professional judgment. As such , the cost of implementing these different standards are anticipated to be the sam e.9



### Background
Oil Shale

- Oil shale is organic

- rich marlstone that yields significant quantities of oil when processed b y conventional destructive distillation methods. The organic

- rich shale is composed of fine

- textured sedimentary rock containing a h igh percentage of combustible organic matter. The world’s largest known oil shale deposits are located on Federal lands in the W estern United States. Domestic commercial

- quality oil shale resources , including undiscovered resources, exceed 2 trillion bar rels, including about 1.5 trillion barrels of oil equivalent in high qualit y shales concentrated in the Green River Formation in Colorado, Utah, and Wyoming

. 1 Recent estimates for domestic oil shale resources range from 2.1 to 26 trillion barrels (see Tab le 1 ). For geographic reference , Figure 1 shows the location of the Green River Formation. In a report, Oil Shale Development in the United States

– Prospects and Policy Issues , prepared for the U.S. Department of Energy , National Energy Technology

L abor atory

in 2005, the RAND Corporation cites in

- place resource estimates of 1.5 to 1.8 trillion barrels for the Green River Formation

. 2 RAND’s recoverable resource estimates for the Green River Formation ranged from 500 billion to 1.1 trillion barrels of oil . The Strategic Unconventional Fuels Task Force 3 estimated that “as much as 800 billion barrels of oil equivalent could be recoverable from oil shale resources yi elding >25 gallons per ton. ” 4 To put these estimates in perspect ive, domestic oil consumptio n in 2010 was about 19.2 million barrels per day

. 5

1 America’s Strategic Unconventional Fuels Resources, Volume I

- Preparation Strategy Plan, and Recommendations , Task Force on Strategic Unconventional Fuels , September 2007 , page I

- 17 (http://www.unconventionalfuels.org). 2 Oil Shale Development in the United States

– Prospects and Policy Issues , RAND Corporation, 2005, page 6 (www.rand.org). 3 The Task Force on Strategic Unconventional Fuels was established in 2005 as required by the Energy Policy Act to promote the development of the nation’s unconventional fuel resour ces. 4 America’s Strategic Unconventional Fuels Resources, Volume I

- Preparation Strategy Plan, and Recommendations , Task Force on Strategic Unconventional Fuels , September 2007 , page I

- 17 (http://www.unconventionalfuels.org). 5 U.S. Energy Information Ad ministration ( http://www.eia.gov/energyexplained/index.cfm?page=oil_use )

. More recent information is available for some of these figures

- for instance, the EIA AEO of 2012 includes updated estimates for oil prices. How ever, as discussed below , the BLM has used figures throughout consistent with those relied on in the task force report and the RAND report. Updating any figure would not be particularly meaningful absent an update of those two reports.10 Figure 1 Green River Formation

Table 1 U.S. Oil Shale Resource Estimates Source of Estimate Oil Shale (billion barrels) U.S. Geological Survey 6 2,100 Am erican Petroleum Institute 7 5,600 Office of Technology Assessment 8 26,000

6 Dy ni, J.R., Geology and Resources of Some World Oil

- S hale Deposits , U.S. Geological Survey, Investigations Report 2005

– 5294 , June 2006 (http://pubs.usgs.gov). 7 Porter, E.D., American Petroleum Institute, Policy Analysis and Strategic Planning Department , Are we running out of oil? , Discussion Paper #081, De cember 1995 (http://ne w. api.org)

. 8 Congress of the United States, Office of Technology Assessment, An Assessment of Oil Shale Technologies , June 1980, OTA Report # OTA

- M

- 118 (http://govinfo.library.unt.edu/ota/).11

Quality and Grade

- Oil shale resources of the United States have been extensively characterized. Yields greater than 25 gallons per ton are generally viewed as the most economicall y attractive, and hence, the most favorable for initial development. The most economicall y attractive deposits, containing in excess of 1.2 trillion barrels, are found in the Green River Formation of Colorado (Piceance Creek Basin), Utah (Uinta Basin), and Wyoming (Green River and Washakie Bas ins). More than a quarter million assay s have been conducted on the Green River oil shale. In the richest zone, known as the Mahogan y Zone, oil yields vary from 10 to 50 gallons per ton and, for a few feet in the Mahogan y zone, up to about 65 gallons per ton

. 9 An estimated 418 billion barrels of the se resources are in deposits that will yield at least 30 gallons per ton in zones at least 100 feet thick. Additional resource estimates are for 750 billion at 25 gallons per ton in zones at least 10 feet thi ck.
T he mineral deposits (conventional crude oil versus oil shale

–kerogen) are distinctly different. Uncertainty

relating to the quantit y of recoverable oil is a function of technological efficiency . All oil shale technologies and projects are purely e xperimental and technological efficiency would not be known until a technology has been perfected. Technological Advances

- While there has been a great deal of interest recently in the potential of oil shale resources, utilization of this material is sti ll, for the most part, in the research and development mode. Currently , there is no commercial production of oil from shale in the United States. Recent technological developments have proven to be of great interest, and those developments, along with te chnologies that were developed during the last wave of interest in oil shale, are now being considered for application in tapping this potential resource.
E xisting technologies for producing domestic oil shale have not yet been tested beyond the pilot sca le. Major investments by industry and government have resulted in an in

depth understanding of oil shale resources and the development and testing of a broad spectrum of surface retorting and in

- situ technologies for converting oil shale to liquid fuels. The lessons learned and the technologies developed from these past efforts remain available and provide the technical basis needed to advance oil shale commercialization efforts. Economic Viability

- The last concerted effort to bring domestic shale oi l into production was in the 1970s and 1980s. There was significant interest in developing the vast oil shale resources on Federal lands, specifically in Colorado and Utah

. T he last of these operations ceased in 1991. Numerous times throughout history , there have been attempts to produce oil from shale with limited reported success. T he availability of relativel y inexpensive alternative sources of oil has generally made shale oil production uneconomic.

9 America’s Strategic Unconventional Fuels Resources, Volume III Resource and Technology Profiles , Task Force on Strategic Unconventional Fuels , September 2007 , page III

- 2 (http://www.unconventionalfuels.org).12

At present, o il shale production is characterized by high initial capital investment s , high operating costs, and long periods of time between expenditure of capital and the realization of production revenues and return on investment. For first

- generation facilities , there is substantial uncertaint y about the magnitude of capital and operating costs because technologies are not yet proven on a commercial scale. Table 2

- Estimated Costs and Minimum Economic Prices for Oil Shale Processes presents recent cost and minimum price estimates associated with oil shale development. However, d emonstration of first

- generation technologies will be required at a commercially representative scale before definitive capital and operating costs of oil shale projects will be known

. Table 2 Estimated Costs and Minimum Eco nomic Prices for Oil Shale Processes 10 Technology Average Minimum Economic Price (Dollars per Barrel ) Capital Cost ( $1000 per SDB 11 ) Operating Costs (Dollars per Barrel ) Surface Mining $44.24 $40

- $41 $12

- $13 Underground Mining $54.00 $41

- $42 $16

- $1 7 Modified In

- Situ 12 (MIS) $65.21 $27

- $40 $18

- $26 True In

- Situ 13 $37.75 14 $36

- $56 $19

- $20 Source: America’s Strategic Unconventional Fuels Resources, Volume III Resource and Technology Profiles , Task Force o n Strategic Unconventional Fuels, February 2007, page III

- 14 , Table III

- 3

. Estimated Costs and Minimum Economic Prices for Oil Shale Processes , (http://www.unconventionalfuels.org). Revenues are uncertain because world crude oil prices are volatile and future market prices for shale oil and by p roducts are unknown. These and other uncertainties pose investment risks that make oil shale investment less attractive than other potential uses of capital. Oil shale technologies must be demonstrated at commercial scale before definitive capital and op erating costs of oil shale projects will be known. Cost estimates will vary according to the oil shale resource and the extraction process selected

.

10 Capital and operating costs are reported in constant 2005 dollars. 11 S treaming daily b arrels (SDB) is a measure of an operations productive or installed capacity. Capital costs are the sum of investments needed per barrel of installed capacity. These costs include investments in mining, retorting, solid waste disposal, refining and upgrad ing, plant utilities, and other facilities. 12 MIS involves mining below the target shale before heating. Once the shale is mined, the virgin shale is rubblized by explosions to create a void space of 20 to 25 percent. Com bustion is started on the top of the rubblized shale and moves down the column. In advance of the combustion front, oil shale is raised to retorting temperature that converts the kerogen to shale oil and to gases. Both products are captured and returned to the surface. 13 A true in

- situ process involves no mining. The shale is fractured, air is injected, the shale is ignited to heat the formation, and shale oil moves through fractures to production w ells. 14 Shell Oil Company had estimated the average minimum economic per barrel price for a true in situ operation to between $35 and $40 per barrel.13



### Economic and Distributional Effects The proposed regulation changes would modify the commercial oil sha le leasing and management r egulations that were promulgated in 2008. The main proposed revisions to the existing regulations include changes in the ro yalty applied to production, changes in the information required prior to authorization, and changes in t he standards applied to an authorization. The primary proposed provision with the potential to significantly alter the future distributional effects 15 is the royalt y provision. Royalt y Rate

- Without a demonstrated technology , costs and production scenari os are speculative , at best. Instead of generating our own hy pothetical costs and production scenarios, for the 2008 rulemaking we adopted the cost and production scenarios prepared b y the Task Force on Strategic Unconventional Fuels

. 16 In preparing the o riginal anal ys is , we also relied on the Department of Energy , Energy Information Administration’s (EIA) Annual Energy Outlook (AEO) crude oil price projections. 17 Using these 2006 oil price assumptions m esh ed with the Task Force’s 2006 cost assumptions in presenting the simulation based analy sis of the possible relationships underlying potential ro ya lt ies under various scenarios

. Since the Task Force completed their work in 2007, there has been no comparable effort to analyze and report on oil shale develo pment potential, including production cost projections or production scenarios. EIA continues to publish their crude oil price projections. However, using these newer price projections creates a disconnect , i.e. using financial inputs for two different t ime periods, with the older cost assumptions. Royalt y pa ym ents are recurring income to the Federal G overnment and costs to the operator/lessee. As such, they are transfer pay

ments that do not affect total resources available to societ y. Changes in the ro yalt y rate have the potential to significantly alter the future distributional effects; however, the revenues that they generate would not represent a net cost or benefit to the econom y. The OMB defines “transfer pay ment” to include pay

ments to the gov ernment in addition to the unearned pay ments from the government (Economic Analy sis of Federal Regulations Under Executive Order 12866, January 11, 1996, http://www.whitehouse.gov/omb/inforeg_riaguide). In addition, the definition OMB uses encompasses the revenue collected through a fee, surcharge, or tax

15 Note, an important, but sometimes difficult, problem in cost estimation is to distinguish between real costs and transfer payments. Transfer payments are not social costs , but rather are payme nts that reflect a redistribution of wealth. While transfers should not be included in the economic analysis estimates of the benefits and costs of a regulation, they may be important for describing the distributional effects of a regulation. Scarcity re nts and monopoly profits, insurance payments, government subsidies and taxes, and distribution expenses are four potential problem areas that may affect both social benefits and costs as well as involve significant transfer payments. (See Economic Analysi s of Federal Regulations Under Executive Order 12866 , January 11, 1996, http://www.whitehouse.gov/omb/inforeg_riaguide ) 16 America’s Strategic Unconventional Fuels Resources, Volume III Resource and Technology Profiles , Task Force on Strategic Unconventiona l Fuels , September 2007 ( http://www.unconventionalfuels.org). 17 Department of Energy, Energy Information Administration, Annual Energy Outlook 2007, Report #: DOE/EIA

- 0383(2007) , February 2007.14

(in excess of the cost of any service provided) as a transfer pay ment. Since a royalt y is not a pay ment for service, this OMB transfer payment definition holds that a royalty is a transfer pay

ment and is not to be included in the annual effect to the economy calculation. Thus, even if oil shale ro yalties were to increase annual government revenue, such revenue would be excluded from the annual effect to the economy calculation because ro ya lties are trans fer pay ments for purposes of this analy sis and as defined in OMB guidance. Other potential Federal revenues associated with an oil shale leasing program would include rents and bonus bids. Rental rates are set by 43 CFR 3903.40 and would not be affected by

this proposed rulemaking. Although the leasing process, including bonus bidding (see 43 CFR 3924.10) , is not being modified by the proposed changes in this rulemaking, a change in the ro yalt y rate will likely affect a lease’s fair market value

. Lessee s pay

bonuses, rentals, and royalties reflecting the fair market value of the rights to explore and potentially

develop and produce oil shale resources. An increase in the ro yalty rate, for example, will likely lower the amount producers are willing to pay for bonus bids, and thereb y generate less net revenue for the Federal G overnment (and have a lower impact on producer profit) than would be anticipated by anal yz ing ro yalt y rates alone. These are factors the Secretary will need to consider in establishi ng the ro yalt y rate for a lease , but cannot be quantified at this point in time since under this proposal the royalt y rate will be set on a case

- by

- case basis in the notice of lease sale

. In addition to potentially

affecting a lessee’s interest in acquiri ng a lease, or at a minimum , the amount they are willing to bid, the timing of pay ments and the financial risks are also shifted. Because a bonus bid is an up

- front cost to the lessee, regardless of the economic success of the operation, the lessee/operat or takes on all the financial risk. A ro yalty on the other hand is only payable when there is actual production. However, with a gross ro yalt y, the economic burden still rests with the operator as the ro yalt y pay ment is based on the value of the output r egardless of the operation’s profitability . An alternative to a gross ro yalty would be a net ro yalty that allows for the accounting of certain production costs in determining the ro yalt y base. Establishing an appropriate royalt y rate requires an understanding of the d ynamics between the ro yalt y base and the royalt y rate. Any anal ys is of government revenues, including ro yalt y revenues, of what constitutes a fair return and what ro yal ty rate encourages development of the resource must consider a number of factors including the government’s take and the operator’s return on investment. What revenue scheme ensures a fair return to the government and also encourages development is much more complicated than simply picking a royalt y rate. If changing the ro ya lty

rate were not to impact oil shale production, then this rule would have no net national costs or benefits. The onl y potential impact would be on government revenues and producer profits , but as discussed above , the magnitude of this distributional imp act would also be uncertain due to the expected interaction between15

royalt y rates and bonus bids. If, however, changing the ro ya lty rate were to affect production, then there would be benefits and costs. Lo wering the ro yalt y rate, for example, would be e xpected to increase the value of shale oil produced b y diverting scarce resources (capital, skilled labor, etc.) from other economic activity

. The cost to society would be the value of the output foregone by the diversion of these productive resources. In theory , the net national impact could be either positive or negative. Similarly , the net impact of government revenues is also ambiguous since reduced royalt y revenues from foregone production elsewhere would have to be netted from increased gross gover

nment revenues from oil shale production. In light of the fact that c urrentl y there is no domestic oil shale industry or even a definitive commercial technology

fo r extracting oil from the shale, the BLM does not believe it has sufficient information to quantify

the costs, benefits, or net government revenues arising from any given ro ya lty

rate. The rule seeks public comment regarding quantitative analy sis on the potential supply

implications of alternative royalt y rates. The interested reader may consul t the anal ys is of revenue, profit, and ro ya lty implications under various production scenarios that was prepared for the 2008 rulemaking. This anal ys is may help fram e the potential implication s of the proposed ro ya lty provision. However, the reader shoul d keep in mind that since that analy sis assumed that royalt y rates would not affect production, it necessaril y i mplied that the rule would have no net national benefit , the onl y impact would be on government revenues and producer profits

. Moreover, the pr ojections of these transfer pay ments in the 2008 analy sis are gross royalt y pay

ments only since they

do not include potential countervailing effects of changes in bonus bids in response to changes in royalty rates. Other Proposed Revisions

- In addition t o the proposed changes to the existing ro yalt y provisions, there are a number of provisions related to the information requirements and performance standards associated with lease issuance and operational approv al. The proposal is to amend 43 CFR 3926.10 by specifying that the BLM may deny an application to convert an R, D , and D lease to a commercial lease based on “environmental or other natural resource considerations.” In addition, 43 CFR 3931.10 would be amended b y adding that the BLM may deny or require a modification of the proposed plan of development based on “environmental or other resource considerations.” At 43 CFR 3931.11, the plan of development content provisions would be amended b y identifying specific required content, including a “waters hed and groundwater protection plan,” an “airshed review,” a “integrated waste management plan,” and an environmental protection plan.” As these proposed additions for the most part codify

into regulations what the agency currently requires b y policy

and procedure, and these proposed provisions are not expected to significantl y increase the costs to the agency , lessees , or operators

. Qualitative benefits include clarit y in expectations for applicants regarding information requirements as well as for the B LM’s consideration of environmental issues. Under the proposed language at 43 CFR 3925.10, 3926.10 , and 3931.10, the BLM would not issue a lease or approve an operation unless it determine d that the operations can16

occur without unacceptable environmental risk. The agency has extensive experience in evaluating environmental consequences, specifically tied to its Federal Lands and Policy Management Act of 1976 responsibilities. This process is intended to help the agency make decisions that are based on un derstanding the environmental consequences of a proposed action. The agency has limited experience in evaluating and measuring environmental risk and that standard generall y applies to laws that govern hazardous materials and public health risks

. The app lication of this standard may increase the economic burden for the agency and the proponent , potentially including the costs of non - approval

. The BLM does not have sufficient information to quantify the potential costs or benefits of this proposed regulat ory provision

. Short of a lease or plan of development being denied, the requirement is primarily on the BLM to make the determination of whether a lease or operations pose an unacceptable environmental risk

. To the extent there is an increase in compl iance costs , the agency would bear most additional cost associated with making such a determination under the proposed standard. 

### Conclusion
Executive Order 12866 and SBRE FA require agencies to assess , where practical, the anticipated costs and benefits o f a proposed regulatory action to determine if it is a significant regulatory

action

. For the 2008 rulemaking , the BLM projected distributional implications of various royalt y rates under the assumption that royalt y rates affect neither output nor bonus b ids

. A s has been noted , there is no domestic oil shale industry to help substantiate or form the basis for the projections , and the BLM does not have new information with which to update that anal ys is

. As proposed, the oil shale applicant would not have a basis for a ro yalt y rate until the time of a notice of sale or at the time of conversion of an R, D , and D lease. The effect of this change would be to permit royalty rates to be established on the basis of contemporaneous market conditions; however, it would also introduce uncertainty . The intent of the proposed removal of the ro yalt y rates from the regulations is to allow rates to be set in the future when more information may be known about the costs and revenues of oil shale operations. Uncertainty in ro yalt y rates, however, might discourage commercial oil shale development by requiring entities to make business decisions with less information. There are other proposed provisions that may change the information requirements and performance standard s associated with lease issuance and operational approval. Short of a lease or plan of development be ing rejected due to the proposed performance standard, potential increase s to the processing cost, if the y occ ur, would primarily be associated with analy sis by

the agency

.17



### References
Task Force o n Strategic Unconventional Fuels, Development of America’s Strategic Unconventional Fuels Resources , Volumes I, II , and III, September 2007 (http://www.unconventionalfuels.org)

. RAND Corporation, RAND Infrastruc ture, Safet y, and Environment, James T. Bartis, Tom L aTourrette, Ll oyd Dixon, D.J. Peterson, Gary Cecchine , Oil Shale Development in the United States

– Prospects and Policy Issues , 2005 (www.rand.org)

. U.S. Geological Survey , Department of the Interior, Dy ni, J.R., Geology and Resources of Some World Oil

- Shale Deposits , Investigations Report 2005

– 5294, June 2006 (http://pubs.usgs.gov). American Petroleum Institute, Policy Anal ys is and Strategic Planning Department, Porter, E.D., Are we running out of oil ? , Discussion Paper #081, December 1995 (http://new.api.org)

. Congress of the United States, Office of Technology Assessment, An Assessment of Oil Shale Technologies , June 1980, OTA Report # OTA

- M

- 118 (http://govinfo.library .unt.edu/ota/). Executive Offi ce of the President, Office of Management and Budget, Circular A

- 4 , September 17, 2003 (http://www.whitehouse.gov/omb/inforeg/circular_a4.pdf)

. Executive Office of the President, Office of Management and Budget, Economic Analysis of Federal Regulations Un der Executive Order 12866 , January 11, 1996 ( http://www.whitehouse.gov/omb/inforeg_riaguide ). Department of Energy , Energy Information Administration, Annual Energy Outlook 2007, Report #: DOE/EIA

- 0383(2007), February 2007 (www.eia.gov)

.