Brent C. Fryer, Sc.D.

2990 E Riverside Dr. Unit #100

ST. George, UT 84790

Telephone: 435-652-0941

Email: <fryerbc1@aol.com>

Date: September 21 , 2008

U.S. Department of Interior

Director (630)

Bureau of Land Management

Mail Stop 401 LS

1849 C. St., NW.

Attention:1004-AD90

Washington, D.C. 20240.

**[Subject: Comments on BLM's Proposal to Amend 43 CFR Subtitle B
Chapter II, Parts 3900 through 3936.40 (Proposed Policies and Procedures
for Implementation of a Commercial Leasing Program for the Management of
Federally-owned Oil Shale and Any Associated Minerals Located on Federal
Lands) --Federal Register Notice (FRN)/Vol. 73, No. 142/Wednesday, July
23, 2008/Proposed Rules]{.underline}**

**[My Credentials:]{.underline}** When it comes to the development of
oil shale technology/projects I am not operating from a position of
ignorance. I am the developer of the proprietary Black Box Oil Shale
Pyrolysis Processes I (above ground) & II (in situ). I was one of 18
applicants for the BLM's Oil Shale RDD program. I was Exxon USA's Lead
Senior Staff Mechanical Engineer on the Colony Oil Shale Project (a \$6
billion dollar effort) TOSCO Pyrolysis Unit, and have a Sc.D. from MIT
with over 45 years of Experience/Education in Energy/Process Industries
and Water Conservation/Utilization. I have been retired for 8 years. I
have two goals for oil shale: (1) beat out the competition on the basis
of the merits of my process; and (2) participate as a stakeholder in the
development of oil shale to insure this national treasure is developed
on a sound basis with: (a) minimum environmental impact, (b) maximum
resource recovery in the form of liquid and gaseous fuels; (c) maximum
energy efficiency; (d) maximum energy self sufficiency; (e) highest
economic benefit and profitability; and (f) minimum water usage.

**[A. INTRODUCTION]{.underline}**

A BLM representative recently made these comments to the press relative
to the Advance Notice of Proposed Rulemaking (ANPR) to Establish a
Commercial Leasing Program for Oil Shale. "We're, saying here, 'Hey,
we're writing regulations for commercial oil shale leasing, and we're
kind of stumped on some high visibility political issues.' " Those
issues included royalty rates, fair market value, and whether small
tracts of land should be set aside for small companies and "**[other
prickly subjects]{.underline}**". The BLM representative is further
quoted as saying, "Can we have a way for the small guy to get in there
through small-tract leasing, where we set aside a certain area in the
basin and say, 'You big boys can't bid on this stuff, this is only for
the small business-type guy?' ". Meanwhile one of the "Big Boys", is
quoted as saying "While the advance notice of proposed rulemaking is a
precursor to the development of a competitive leasing program, there are
regulatory elements that we assume would be common to the research and
development program and commercial leasing program", citing royalty
issues. The same "Big Boy" is quoted as saying they will likely submit
comments to the BLM about the future regulations, but he doesn't know
what they will say.

Well in spite of the fact that the DOI/BLM knew there was a problem with
big oil out competing the small guy with big money and political
influence, the DOI/BLM has Proposed Commercial Rules that have produced
the fate accompli desired by Big Oil and Wealthy Speculators and left
the "small guy" out in the cold. The Bush/Cheney Administration (I voted
for them twice) and the DOI/BLM have handed the US citizens' Federal Oil
Shale Reserves to the "Big Boys" on a silver platter---much akin to the
bail out of Big Financial Institutions by Bush/Cheney, the Fed, and the
Treasury going on right now at the expense of the US taxpayer. Big Oil
and Wealthy Speculators can speculate, exploit and pillage under the BLM
proposed rules since there are no technology qualification requirements
nor commercial viability demonstrations required either. With the
proposed rules, once Big Oil is high bonus bid awarded a lease, they can
then sit on a resource worth as much as \$100 million/acre for
perpetuity paying no more than \$256/acre per year for rental, payments
in lieu of minimum production, and penalties for lack of due diligence
waiting for the price of oil to rise, and in the meantime claiming the
lease as reserves on their annual reports to shareholders. Most rednecks
would willing pay that much an acre just for a place to squat their RVs.
As a serious and committed small oil shale technology/project developer,
rejected BLM RDD applicant, US taxpayer, with 50 years of experience in
the energy/process industries, a Sc.D. from MIT, and Exxon USA's lead
mechanical engineer on the Colony Oil Shale Project (remember Black
Sunday---I was there), I am totally disgusted and discouraged with the
actions being taken on the Federal Oil Shale Development Program.

The bases for my conclusions and recommendations for cleaning off the
table and starting over are provided below in summary form. This is
followed by an excruciating analysis of the entire Federal Register
Notice including detailed comments on specific sections of the proposed
rules which support both my conclusions and recommendations.

**[A.1 SUMMARY OF CONCLUSIONS BASED ON THOROUGH EVALUATION OF THE
PROPOSED RULE]{.underline}**

1.  The proposed rules won't meet the goals of the Energy Policy Act of
    2005 (EP Act) of:

    a.  Encouraging development of the oil shale resource, and

    b.  Ensuring a fair return to US citizens---including but not
        limited to monetary payments for the resource

2.  The proposed rules will exclude access by small oil shale
    entrepreneurs to federal oil shale for development and commercial
    demonstration by:

    a.  Being out bonus bid by big oil and wealthy speculators

    b.  DOI/BLM only offering large lease sale tract sizes, after
        nomination and delineation, which will be much larger than the
        minimum size of 160 acres which is much too large for research
        and development. Combining large tracts with large bonus
        bids/acre eliminates small entrepreneurs from competition.

    c.  Providing a means for foreign entities' control of the economic
        and strategic value of the national oil shale reserve.

    d.  Coming to the wrong conclusions on legal, domestic/foreign big
        oil and wealthy speculator competition, regulatory burdens, and
        cost burdens as they impact small business specifically in terms
        of the following:

        i.  *Executive Order 12866, Regulatory Planning and Review*

        ii. *Clarity of the Regulations* Executive Order 12866

        iii. *Small Business Regulatory Enforcement Fairness Act
             (SBREFA).*

        iv. Executive Order 13272

        v.  *Regulatory Flexibility Act* Congress enacted the Regulatory
            Flexibility Act of 1980 (RFA)

3.  DOI/BLM has defacto no intention of issuing any new BLM RDD leases
    although the Secretary of DOI has had the authority to do so even
    before the EP Act was passed

4.  The commercial rules have no requirement for commercial
    demonstration of the process technology before qualifying for a
    lease.

5.  The commercial rules have no qualifying acceptance requirement for
    an applicants\' proposed process technology. There are no qualifying
    acceptance thresholds on:

    a.  Net Fischer Assay and Tosco Assay raw shale oil and raw gas
        recovery

    b.  Energy self sufficiency through char chemical energy utilization
        for pyrolysis heat

    c.  Energy efficiency

    d.  Effective kerogen resource recovery

    e.  Minimal environmental impact

    f.  Consideration of requiring net benefits through dual outcomes of
        energy production and massive beneficial water storage or land
        utilization improvement by making positive use of the massive
        land reclamation that must be done for both mining and in situ
        operations.

6.  The DOI/BLM/MMS seeks a simple system of rules based on prior
    outdated mining and conventional oil/gas rules that will be easy to
    administer for a unique resource for which no one has yet
    demonstrated either functional and effective technology or
    commercial viability. In doing so they are attempting to promulgate
    an antiquated system that no longer brings a fair benefit to US
    citizens, and is no longer used or accepted by oil
    producing/exporting nations around the world.

7.  The set of rules proposed is flawed starting with "definitions" of
    terms such as "product", "production", and "MER" and further flawed
    in terms of the rules' bases considered and the resultant proposed
    rules for important factors such as FMV, royalty rates and point of
    determination, minimum production, minimum lease size, minimum bonus
    bid, and due diligence. In addition the "options" proposed for
    royalties have no meaningful basis. Further the DOI's poster child
    of oil shale development, Royal Dutch Shell, is willing to live with
    an 8% royalty rate and yet BLM's proposed Option 1 royalty rate is
    3% lower at a flat 5% thereby begging the question of how can BLM
    have the interest of the US citizen at heart. Further more the
    arguments raised for and against particular portions of the rules
    are based on out of date production costs for conventional petroleum
    and product prices, as well as meaningless production costs for
    shale oil production. Further, penalties for not meeting diligence
    milestones and minimum production levels are an invitation for big
    oil and speculators to tie up the national resource for up to 20
    years, and even perpetuity, with penalties equal to a miniscule
    fraction of the value of the resource.

8.  There never was a need for the BLM RDD 160 acre tract size for RDD.
    The five 160 acre Colorado RDD tracts will pyrolyze only .1-2 acres
    per tract as target zones. All surface tract needs for
    infrastructure and even underground freeze walls, etc. could have
    been met with surface leases with severed minerals rights. The Utah
    RDD lease will pyrolyze only about 16 acres at essentially
    commercial scale.

9.  Demonstration of commercial production on the RDD tracts is required
    before the preference rights can be converted to commercial leases.
    No demonstration of commercial production technology is required
    under the proposed commercial rules. Possession of new technology
    and related experience in oil shale was required for BLM RDD
    application (although obviously hasn't been enforced). There are no
    qualifying requirements related to technology to obtain a commercial
    lease.

10. The Federal Oil Shale development program has no big picture vision
    for dual benefits of energy production combined with massive water
    storage impoundments and beneficial land reclamation. Neither does
    it even consider the massive waste or resource left behind that will
    occur at individual lease boundaries because of a lack of a national
    integrated program.

**[A.2 SUMMARY OF RECOMMENDATIONS FOR FEDERAL OIL SHALE DEVELOPMENT
INCLUDING COMMERCIAL LEASING RULES]{.underline}**

Commercial oil shale development of Federal oil shale reserves should be
based on the follow criteria, including a competitive kerogen based
payment system from the lessee to the US citizens:

1.  A lease payment system must consider the following facts. Kerogen
    has no value without technology to convert it into hydrotreated oil
    and processed gas. Technology, no matter how effective, to pyrolyze
    the kerogen and convert it into hydrotreated oil and processed gas
    has no value if the technology owner has no access to the kerogen.
    The challenge is to develop a leasing monetary system where both US
    citizens and the developers of technology/projects receive a fair
    share or return, for: (1) the resource; and (2) the risk and
    investment of money, time and intellect into the development of both
    technology and projects. Besides a fair return, it behooves both
    parties to insure technological processes are required to be energy
    efficient, energy self sufficient, resource recovery effective, and
    environmentally benign as possible. Coming up with that system
    requires production cost information, and accommodation of changes
    in both production costs and product market prices over time. Both
    the US citizen, and the lessee/developer, should share in the
    difference between the time varying product price and the production
    cost---i.e. the net proceeds. As the net proceeds increase, the
    formula for share split must address which of the parties deserves,
    if either, a larger share. In order to benefit both parties,
    incentives should be present to reduce production costs. The
    following kerogen based payment system meets the challenge---the
    BLM's proposed rules do not.

2.  Lessee qualifications requiring demonstration of prior commercial
    production via RDD.

3.  Small tracts (1-2 acres of mineral rights) for RDD being offered as
    a separate leasing initiative by the BLM to demonstrate commercial
    production.

4.  Lessee qualifications requiring demonstration of not only the
    process technology's commercial viability but also:

    a.  Production of both 100% Net Fischer Assay and Tosco Assay raw
        shale oil and raw gas recovery

    b.  Energy self sufficiency through char chemical energy utilization
        for pyrolysis heat

    c.  High Energy efficiency

    d.  Effective kerogen resource recovery

    e.  Minimal environmental impact

5.  Consideration of net benefits through dual outcomes such as energy
    production and water storage or land utilization improvement through
    beneficial reclamation.

6.  Royalties and Bonus Bids should be eliminated and replaced with a
    competitive annual payment from the lessee to the Federal government
    that would be determined and work as outlined below based on the
    value of the kerogen in the ground, and net proceeds (time varying
    market price of products minus time varying production costs). In
    some regards this is similar to the Canadian Tar Sands system but
    with a different approach that eliminates the problems therein.

7.  Annual payments over the life of the resource would start at the end
    of the first year of production. A front end or down payment would
    be required to lock the lessee in at the time of bid award, and this
    would be credited towards the annual payments, with time value
    considered.

8.  The kerogen quantity in the leasehold would be defined and agreed to
    both by the BLM and lessee as a function of quality, thickness, and
    overburden depth.

9.  The lessee's competitive bid would be an offering to process given
    fractional amounts of the kerogen by quality, depth, and overburden
    thickness of the leasehold based on the total available kerogen
    resource. The lessee's bid would also offer to produce a given
    quantity of definable marketable products, at a given production
    cost at the start of production, and to return a given share of the
    products or value thereof to the Federal government based on both
    production costs and product prices at the start of production. Cost
    of production would include capital recovery. This would be the
    initial basis for the unmodified annual payment. The lessee could
    competitively offer to modify the share to the Federal government if
    product prices increased or decreased, and make a similar offer if
    production costs increased or decreased. The fair thing to do would
    be for the lessee to increase the share to the Federal government if
    product prices increase, and decrease the share if he were able to
    decrease production costs. Now once the BLM has all the bidders
    proposals in hand based on these bidder requirements the BLM can
    determine which bidder will return the most benefit to the US
    citizen based on the following: .

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a.  Of the total tonnage of kerogen in the ground and as a function of
    quality, thickness, and overburden depth, what fraction will be
    processed, left behind, and waste

b.  What will be the total integrated production, products, and value of
    those products

c.  What will be the total production costs

d.  How will the share of production be split as production costs are
    reduced or product prices increase.

e.  What is the total value of the production and the Federal
    governments net total share

f.  What is the magnitude and severity of the environmental impact

g.  What are the quantitative and qualitative value/benefits of the dual
    outcomes of energy production and water storage or surface
    utilization through beneficial reclamation?

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10. The bidder/lessee will be locked into his minimum offered kerogen
    impacted schedule as his minimum annual monetary or share payments
    will be based on that. Impacted kerogen includes processed, left
    behind and unprocessed, and wasted kerogen by what ever cause. If he
    impacts more he will pay more. If he impacts less than the base, he
    will pay for the base. If he produces more products for a reduced
    total production costs, for the same share, he gets a larger total
    return. If his formula for sharing is based on his share increasing
    as his production costs decreases, then he gets an even larger
    return. The bidder has to figure out what payment formula produces
    his maximum net proceeds and also those of the US government---in
    competition with other bidders. His bid offering is a payment
    formula and his commitment to recover a finite minimum amount of
    kerogen and process that kerogen into a minimum finite quantity of
    defined products.

11. This lessee payment system relies on competition setting the most
    attractive benefit terms for the US citizen for the kerogen resource
    development incorporating effectiveness of resource recovery, and
    technical and economic effectiveness of the process technology. The
    bidder with the most effective technology and resource recovery, who
    offers dual benefits, can also offer the best benefits to the
    federal government---a win, win developmental approach. If a bidder
    has the best technology in terms of both effectiveness and
    economics, but fails to offer the US citizen a fair or maximum
    return, could be beat out by a bidder with somewhat worse technology
    but who is willing to give the US citizen more total return.

12. This system essentially eliminates issues of what the 'product" is,
    what "production" is, achieving and enforcing MER, and trying to
    figure out a royalty and bonus bid that provides a fair return to
    the US citizen---both at the start of the lease and as production
    costs and product prices change with time. It eliminates issues
    associated with due diligence, minimum production, and penalties.
    Minimum required and defined payments are required over time and if
    not met the lease is extinguished.

13. Although the proposed competitively determined lease payment system
    will be argued to be to complex it requires no more information up
    front or later from the lessee, and it requires no more information
    which the BLM must ultimately develop, or obtain from the lessee,
    than that which is required by the proposed BLM leasing systems
    accounting rules. It will be argued that production costs are not
    required under the BLM proposed rules---well the internal revenue
    service requires both production and cost data to determine net
    income and therefore the lessee must provide this to the government
    ultimately in any event.

**[TABLE OF CONTENTS FOR MY DETAILIED RESPONSE AND SUPPORTING
BASES]{.underline}**

**[A. INTRODUCTION]{.underline}**

**[A.1 SUMMARY OF CONCLUSIONS BASED ON THOROUGH EVALUATION OF THE
PROPOSED RULE]{.underline}**

**[A.2 SUMMARY OF RECOMMENDATIONS FOR FEDERAL OIL SHALE DEVELOPMENT
INCLUDING COMMERCIAL LEASING RULES]{.underline}**

**[B. Organization of My Discussion/Comments of the Proposed Rules, by
Part, Subpart and Section number, Color Coding]{.underline}**:

**[C. PROPOSED COMMERCIAL RULES---SPECIFIC COMMENTS]{.underline}**

**C. 1 SUMMARY**

**C.2 I. Public Comment Procedures**

**C.3 II. Background**

**C.4 III. Discussion of the Proposed Rule**

> **C.5 IV. Procedural Matters**

**[D DISCUSSION OF 48 COMMENTERS TO ANPR]{.underline}**

**[D1. Summary of 48 commenters---Developers vrs
Non-Developers]{.underline}**

**[D.2 BLM RDD applicants/lessees/ANPR comments]{.underline}**

**[D. 3 BLM RDD applicants/rejected/ANPR comments]{.underline}**

> **[D. 4 BLM RDD applicants/lessees/ no ANPR comments---but leasing
> relevant comments made on PEIS]{.underline}**

**[D.5 Non-BLM RDD applicants/ANPR comments]{.underline}**

**[D.6 Individuals Associated with BLM RDD applicant organizations/ANPR
Comments]{.underline}**

**[D. 7 Other Developer Organizations]{.underline}**

> **[D. 8 Summary of 12 Developer's Comments, Recommendations, Relative
> to Actual Proposed Rule---BLM Acceptance, Rejection, or Inconclusive
> BLM Position.]{.underline}**

**[E. 32 Commenters on BLM RDD Leasing Terms]{.underline}**

**[F. RECOMMENDED CHANGES TO RULE AND DOI/BLM'S APPROACH TO FEDERAL OIL
SHALE DEVELOPMENT]{.underline}**

> **[F.1 General statement on the premature nature, and in-applicability
> of attempting to use, prior rules for mining and oil/gas production,
> for the leasing of oil shale, and of ever finding a very simple system
> that is easy to administer..]{.underline}**

**[F. 2 Royalty Options 1, 2, & 3]{.underline}**

> **[F. 3 Fundamental Basis needed to simultaneously meet the goals of
> optimizing the encouragement of oil shale development and providing
> the maximum benefit including total fair monetary return to US
> citizens.]{.underline}**
>
> **[F4 Amortized kerogen based annual payment approach rather than
> bonus bids and royalties.]{.underline}**

**[F. 5 A market price and/or net proceeds approach---intended and
unintended consequences]{.underline}**

**[F. 6 Bonus Bids and Royalties---intended and unintended
consequences]{.underline}**.

**[F. 7 Summary of Status of BLM Oil Shale Development
Program]{.underline}**

> **[F. 8 Where is the value of new technology---proven intellectual
> property factored in here---and in particular encouragement to develop
> such---and rewards there from??]{.underline}**

**[B. Organization of My Discussion/Comments of the Proposed Rules, by
Part, Subpart and Section number, Color Coding]{.underline}**

The following discussion/comments address the above **subject Federal
Register Notice** **(FRN) /Vol. 73, No. 142/Wednesday, July 23,
2008/Proposed Rules** and follows the outline of that notice starting on
page 42926 of said notice. My evaluation of the proposed rules, and the
basis used by the BLM for those rules, proceeds in the same sequence as
that used in the FRN starting on page 42957. The reader should note that
as the discussion of a particular proposed rule section is presented,
"reference" to other sections preceding or following after that
particular section may be made and is so noted. Reference is also made
to text contained within the Preamble as well as to other sources as
noted below. Note that all sections in the FRN are listed, however,
comments are not provided on all sections.

To help clarify the discussion/comments color coding of the text is used
as follows:

AR (in green color) =Direct extractions from the Actual Proposed Rule
starting on page 42957.

DR (in blue color)=Direct extractions from the FRN Preamble including
BLM's discussion of what is in the proposed rule, and the BLM's basis,
and including BLM's discussion of the 48 comments received per BLM's
request in the ANPR, starting on page 42926.

pgxxxxxx= refers to the page number in the FRN

R48(in yellow color) =Direct extractions from the 48 comments received
per BLM's request in the ANPR.

R32 (in orange color)= Direct extractions from the 32 comments received
per BLM's request on the RDD lease basis and requirements prior to
initiating that program.

RPEIS (in purple color): Direct extractions comments received on the
DRAFT PEIS.

Abcdefg (in pink color) =words, phrases, sentences of special interest

COMMENT (in red color) =Comments made by the author following extracted
references. Extracted references are provided to provide context for the
comments and to eliminate confusion regarding what the issues are, and
what specific rules or sections are being commented on.

**C. PROPOSED COMMERCIAL RULES---SPECIFIC COMMENTS**

**C.1** DR, pg 42927 **SUMMARY**: The Bureau of Land Management (BLM) is
proposing regulations to set out the policies and procedures for the
implementation of a commercial leasing program for the management of
federally-owned oil shale and any associated minerals located on Federal
lands. The Energy Policy Act of 2005 (EP Act) directs the Secretary of
the Interior to: Make public lands available for conducting oil shale
research and development activities; complete a Programmatic
Environmental Impact Statement (PEIS) for a commercial leasing program
for both oil shale and tar sands resources on the BLM administered lands
in Colorado, Utah, and Wyoming; and issue regulations establishing a
commercial oil shale leasing program.

These proposed regulations would incorporate specific provisions of the
Mineral Leasing Act of 1920 (MLA) and the EP Act relating to: Maximum
oil shale lease size; maximum acreage limitations; rental; and lease
diligence.

These proposed regulations would also address the diligent development
requirements of the EP Act by establishing work requirements and
milestones to ensure diligent development of leases. The proposed rule
would also provide for other standard components of a BLM mineral
leasing program, including lease administration and operations.

COMMENT: The DOI/BLM has issued only 6 RDD lease tracts, 3 of which are
to Royal Dutch Shell (RDS) and has defacto terminated the BLM RDD
program as far as any additional RDD leases. This program preceded the
EP Act and therefore no RDD leases have been, or will be, issued under
the EP Act. The "Draft PEIS" is not a PEIS for commercial leasing as
mandated by the Energy Policy Act of 2005 (EPA2005), rather it is a land
use planning document. The final PEIS for commercial leasing is now 1
year behind the required delivery schedule and will never be prepared by
the Secretary of Interior as directed by the EPA2005. The proposed
commercial leasing rules will not encourage oil shale technology and
project development, nor will they result in maximum benefit, including
but not limited to fair monetary return from development of this Federal
resource, to US citizens.

The BLM RDD program requires demonstration of commercial production
technology before preference rights will be converted to commercial
leases. Demonstration of commercial production technology is not
required to qualify for a commercial lease under the proposed commercial
leasing rules. In neither the BLM RDD program or the commercial leasing
rules are there any commercial leasing qualifications requiring that the
lessee's process technology will achieve Fischer Assay recovery of raw
shale oil and TOSCO Assay recovery of raw shale gas, nor be energy
efficient, energy self sufficient by utilizing spent shale char as the
pyrolysis heat source, effectively maximize the resource recovery, or
have minimal environmental impact.

Commercial leasing rules should require prior RDD/commercial
demonstration and the DOI/BLM should make RDD tracts available as
directed by the EP Act. Commercial rules should require Fischer Assay
recovery of raw shale oil and TOSCO Assay recovery of raw shale gas.
They should require thresholds on energy efficiency, energy self
sufficient by utilizing spent shale char as the pyrolysis heat source,
effective maximize the resource recovery, and minimal environmental
impact. The concept that the free market, based on bonus bids alone with
no qualifying technology requirements, will dictate effective
utilization of this resource is an illusion. That approach will only
result in Hygrading, waste, the re-incarnation of BIG OIL TRUSTS, and
minimal benefits to the nation and US Citizen---eliminating competition
and development of efficient technology. .

C.2 DR, pg 42926: **[I. Public Comment Procedures]{.underline}**

C.3 DR, pg 42926: **[II. Background]{.underline}**

DR, pg 42927: Generally, surface processing consists of three major
steps: (1) Oil shale mining and ore preparation; (2) pyrolysis of oil
shale to produce **kerogen oil**; and (3) processing kerogen oil to
produce refinery feedstock and high-value chemicals. This sequence is
illustrated below.

Conversion of Oil Shale to Products (Surface Process) Resource ---\>Ore
Mining---\>Retorting---\>Oil Upgrading---\>Fuel and Chemical Markets

For deeper, thicker deposits, not as amenable to surface- or deep-mining
methods, the shale oil can be produced by in-situ technology. In-situ
processes minimize or, in the case of true in-situ, eliminate the need
for mining and surface pyrolysis by heating the resource in its natural
depositional setting. This sequence is illustrated below.

Conversion of Oil Shale to Products (True In-Situ Process) Resource
---\>In-Situ Pyrolysis---\>Oil Upgrading---\>Fuel and Chemical Markets

COMMENT: Kerogen is a solid hydrocarbon. I've never heard of "**kerogen
oil**", try raw shale oil. Where's the raw shale gas? In some processes
1/3 of the product is raw shale gas. What's done with the char?
Processes should be required to make processes energy self sufficient by
utilizing the char chemical energy for pyrolysis heat. Where are the
excess electricity and/or surplus process steam products? Where's the
spent shale disposal and clean up/remediation/reclamation of
ground/surface water, surface/underground soil, and air? This simplified
description is misleading.

DR, pg 42927: As stated in the June 9, 2005 call for nominations for the
research, development, and demonstration (R, D and D) (70 FR 33753)
leases, the BLM opted for a staged oil shale leasing program. The first
stage is the research and development program followed by these proposed
commercial leasing regulations.

COMMENT: Wrong, second stage is the PEIS required by EP Act of 2005
before commercial leasing. In fact the final PEIS was to help shape the
development of the commercial rules. The "Draft PEIS" is not a PEIS for
commercial leasing as mandated by the Energy Policy Act of 2005
(EPA2005), rather it is a land use planning document. The final PEIS for
commercial leasing is now 1 year behind the required delivery schedule
and will never be prepared by the Secretary of Interior as directed by
the EPA2005.

From above: "The Energy Policy Act of 2005 (EP Act) directs the
Secretary of the Interior to: Make public lands available for conducting
oil shale research and development activities." This "first stage" BLM
RDD program came before the EP Act and the DOI/BLM has defacto
terminated any additional RDD leases mandated by the EP Act.

DR, pg 42927: During the 1973--74 oil shale prototype program, there
were expectations of an economic boom in western Colorado which never
materialized. The oil shale industry collapsed on **May 2, 1982,
commonly referred to as Black Sunday**. In 1983, the BLM established an
Oil Shale Task Force to address:

\(1\) Access to unconventional energy resources (such as oil shale) on
public lands;

\(2\) Impediments to oil shale development on public lands;

\(3\) Industry interest in research and development and commercial
opportunities on public lands; and

\(4\) Secretarial options to capitalize on these opportunities.

COMMENT: I was there on Black Sunday as Exxon USA's lead mechanical
engineer on the Colony Oil Shale Project Pyrolysis Unit (TOSCO Process).
I learned how not to do oil shale technology and project development and
have subsequently developed the Black Box Pyrolysis Process I (above
ground) and II (in-situ). From a practical standpoint, there has never
been access to oil shale on Federal Land to individuals, and
entrepreneurs. There has never been a lack of interest on the part of
serious oil shale developers. Politicians, DOI/BLM are the biggest
impediments because they have restricted access to federal oil shale and
have provided ill founded leadership---having no credible background in
oil shale technology, economics, or environmental impacts. The Secretary
of DOI has always had authority to make oil shale available as evidenced
by the BLM RDD program---which was initiated before the EP Act.

DR, pg 42927: On February 11, 1983, the BLM published a proposed rule
for an oil shale leasing program (48 FR 6510). Due to apparent lack of
interest in the development of oil shale, the BLM withdrew the proposed
rule, effective September 25, 1985 (50 FR 38867).

COMMENT: Too little, too late---apparently the BLM was unaware that
Black Sunday occurred on May 2, 1982. There has never been a lack of
interest by serious developers, only a lack of access to Federal oil
shale resources.

DR, pg 42927: In order to be better able to expand and diversify
domestic energy production, on November 22, 2004, the BLM published a
notice in the **Federal Register** (69 FR 67935) requesting public
comments on the potential for oil shale development within the Piceance
Creek Basin in Colorado, the Uinta Basin in Utah, and the Green River
and Washakie Basins in Wyoming. The **Federal Register** notice also
requested comments on a proposed draft oil shale R, D and D lease form.
Comments received were incorporated, as appropriate, into the final R, D
and D lease form.

COMMENT: This was poorly advertised and as a result I and many others
were blind sided by the BLM RDD leasing program announced June 9, 2005.
The Bush/Cheney, Clinton, Old Bush,and Reagan administrations had done
nothing in oil shale for 25 years and now all of the sudden without
warning this pops up.

COMMENT: The BLM requested comments on the following RDD leasing issues
in the November 22, 2004 Federal Register: 69 FR/Number 69, pg 67935)

\(1\) What terms (duration, royalty rental, acreage, diligence, option
for additional acreage) should BLM include in the R&D lease to provide
for short-term incentives, and also encourage long-term commercial
development;

\(2\) The adequacy of a 40-acre lease for a successful demonstration of
oil shale technology;

\(3\) The methodology for conversion of an R&D lease to a commercial
lease;

\(4\) The criteria to qualify a company or individual to acquire and R&D
lease and what documentation should be required;

\(5\) The level of National Environmental Policy Act (NEPA)
documentation that would be appropriate for R&D leasing; and

\(6\) The appropriate methodology for determining fair market value for
conversion to a commercial lease.

What came out of this in terms of lease terms were the following:

1.  40 acres increased to 160 acre tracts for a \$2000 application fee
    and the cost of an environmental assessment (EA).

2.  10 year lease royalty and bonus bid free.

3.  A preference right for an 8 section (5120 acres) commercial lease
    upon demonstration of commercial viability.

4.  Technology to be used must be described and should be innovative,
    new, or "today's" technology.

5.  Turns out requirements on technology being "new, innovative,
    today's" were never enforced.

6.  Not supposed to be speculation but no enforcement.

7.  Bonus bid required on conversion of preference right, but no process
    for defining fair market value (FMV)/or bonus bid value.

DR, pg 42927: On June 9, 2005, the BLM published a notice in the
**Federal Register** (70 FR/Number 110, pg 33753) which initiated a R, D
and D leasing program by soliciting nominations of 160-acre parcels of
public land to be leased in Colorado, Utah, and Wyoming for conducting
oil shale recovery technologies. In response to the 19 nominations of
parcels that the BLM received, the BLM issued 6 R, D and D leases---5 in
Colorado that were effective January 1, 2007, and an additional R, D and
D lease in Utah that was effective on July 1, 2007. Each of the R, D and
D leases contains a preference right for conversion to a commercial
lease of additional acreage upon demonstration of a successful method of
producing oil from shale rock

COMMENT: June 9, 2005 BLM RDD program has resulted in 4 organizations
with 6 leases, 3 leases of which have gone to Royal Dutch Shell (RDS)
with over 24 billion barrels of Fischer Assay recoverable oil, plus gas,
valued at well over 2.4 \$trillion. The Minerals Leasing Act in place on
June 9, 2005, and referenced several times in the RDD program RFP,
limited anyone individual or organization to no more than 5120 acres (8
sections). RDS applied for two leases on the day the RFP came out, and a
third after the EPA2005 was signed August 8, 2005. Of 18 applicants,
only one---RDS, applied for more than one RDD lease. There were 18
applicants and 20 nominations (not 19 nominations as stated above).

COMMENT: Politicians and DOI/BLM had done nothing on oil shale
development since the days of Black Sunday---25 years ago. This was an
ill thought out knee jerk reaction to escalating gasoline, jet fuel, and
diesel prices. Furthermore it superseded the EP ACT. DR, pg 42927: The
Secretary has discretion under the EP Act to offer additional tracts for
R, D and D leasing. These regulations do not decide whether additional
R, D and D leasing is necessary. The Secretary of DOI has always had
authority to make oil shale available as evidenced by the BLM RDD
program---which was initiated before the EP Act.

What can we conclude from the BLM RDD program thus far:

1\. There was no need for 160 acres, only .1-2 acres will be used as
pyrolysis target zones in Co and 16 acres in UT for a near commercial
operation.

2\. The DOI/BLM has no intention of creating anymore RDD leases.

3\. Although commercial demonstration is required of the BLM RDD leases
to get conversion of preference rights to a commercial lease---no
commercial demonstration is required in the proposed commercial rules as
a qualification for obtaining a commercial lease. If RDD
commercialization demonstration was required for commercial lease there
is no mechanism for RDD access to federal oil shale to conduct the
demonstration.

4\. FMV (bonus bid) and royalties to be defined later during commercial
leasing rule making.

5\. No enforcement of innovative, new, or "today's" technology
qualification requirement.

6\. No requirements for energy efficiency, self sufficiency, effective
resource recovery technological qualifications either for RDD or
preference lease conversion**.**

7\. No enforcement on speculation with 2 of the lessees having sold off
the majority or large fraction of their interests already.

8\. No enforcement of the MLA limit on 8 sections total for any one
entity based on MLA in force at time of June 9, 2005 FRN. No
announcement of EP ACT trumping the June 9, 2005 FRN.

DR, pg 42927: **The PEIS and National Environmental Policy Act (NEPA)
Compliance**

DR, pg 42927: The BLM intends to finalize the PEIS before these
regulations are final. The PEIS is primarily intended to analyze the
impacts of land use allocation and not site specific oil shale leasing.

COMMENT: The "Draft PEIS" is not a PEIS for commercial leasing as
mandated by the Energy Policy Act of 2005 (EPA2005), rather it is a land
use planning document. The final PEIS for commercial leasing is now 1
year behind the required delivery schedule and will never be prepared by
the Secretary of Interior as directed by the EPA2005

(The reader is referred to my public comments supplied earlier to the
BLM on the Draft PEIS).

DR, pg 42927: **Advance Notice of Proposed Rulemaking**

DR, pg 42927-8: The BLM recognizes that the creation of the rules
governing the development of oil shale would need to address different
possible technologies that have different associated impacts and costs.
Therefore, to increase public

participation and to aid in the development of oil shale regulations,
the BLM published in the **Federal** **Register** an advance notice of
proposed rulemaking (ANPR) (71 FR 50378) on August 25, 2006. The ANPR
requested

Public comments on the following five key components of the proposed
regulations:

\(1\) What should be the royalty rate and point of royalty
determination?

\(2\) Should the regulations establish a process for bid adequacy
evaluation i.e., Fair Market Value (FMV) determination, or should the
regulations establish a minimum acceptable lease bonus bid?

\(3\) How should diligent development be determined?

\(4\) What should be the minimum production requirement?

\(5\) Should there be provisions for small tract leasing?

DR, pg 42928: On September 26, 2006, the BLM published a **Federal
Register** notice reopening the comment period for the ANPR and
extending the comment period until October 25, 2006 (71 FR 56085). In
response to the ANPR, the BLM received 48 comments.

COMMENT: Although the above mentions different possible technologies
that have different associated impacts and costs, there is no
recognition of the dominant importance of process technology in terms of
energy efficiency, energy self sufficiency, and effective resource
recovery. These are key to both encouraging oil shale development and
ensuring a fair return to the US citizens. These factors are also key in
terms incorporating them into the development of commercial leasing
rules. Furthermore what's the connection between the BLM's recognition
that rules would need to address different technologies and the BLM's
issuing the above ANPR FRN to increase public participation, and the
above 1-5 key components. Other than Sections 3920.11, .12, .13 which
are broad brush rules on in situ, underground and surface mining there
is nothing in the proposed rules specific to different technologies and
their energy efficiency, energy self sufficiency, and effective resource
recovery.

**C.4** DR, pg 42928: **[III. Discussion of the Proposed
Rule]{.underline}**

COMMENT: In addition to reviewing the subject proposed rules (see FRN
starting on page 42957) I have also reviewed each of the 48 comments
(including recommendations) for the ANPR (see BLM discussion in FRN
starting on page 42928) and these are specifically referenced in the
following. Proposed rules which agree with, or were taken from, these
comments are pointed out. Proposed rules which disagreed with and which
rejected these comments are also pointed out. Relevant comments made on
the Draft PEIS are also included.

DR, pg 42928: ***[Part 3900---Oil Shale
Management---General]{.underline}***

DR, pg 42928 This part would contain regulations on the general
management of the oil shale program, including discussions of the
descriptions and acreage in oil shale leases, qualifications,
requirements, fees, rentals, royalties, bonds and trust funds, and lease
exchanges.

*[Subpart 3900---Oil Shale Management--- Introduction]{.underline}*

DR, pg 42928: This subpart would establish competitive oil shale leasing
administrative procedures for implementing a long-term commercial oil
shale leasing program.

The proposed rule would contain specific provisions required by Section
369 of the EP Act. Many of the sections of the proposed rule contain
regulatory requirements similar to the regulations in the BLM's existing
mineral programs namely, coal, non-energy leasable minerals, and oil and
gas. In creating a regulatory framework for this proposed oil shale
commercial leasing program, the BLM proposes to adopt certain basic
components and processes common to the BLM's leasing programs. Most of
the BLM's leasing programs are governed by the MLA. The regulations
governing those programs and this program would include the following
types of provisions: Pre-lease exploration; leasing processes; bonding;
operations (including plan of development); reclamation; and inspection
and enforcement.

COMMENT: Attempting to develop commercial oil shale leasing rules by
extrapolating BLM's existing leasing rules for previous mineral programs
namely, coal, non-energy leasable minerals, and oil and gas is
fundamentally flawed since the kerogen in oil shale is a unique natural
resource and requires a fundamentally different approach as discussed
herein. First there is no demonstrated commercial process for converting
kerogen (in situ or above ground) into useful marketable products.
Second it is certain that any commercial process developed to produce
refinery acceptable hydrotreated oil and pipeline quality gas will be
expensive---so much so that production costs may exceed product costs
thereby resulting in project bankruptcy. The proposed rules will not
encourage advanced oil shale technology development, nor will it assure
a maximum total benefit to US Citizens, including, but not limited to
total monetary return. Furthermore given the rise in prices of coal,
non-energy minerals, and oil and gas how can one conclude that the US
citizen is receiving fair monetary return for these resources based on
old royalty formulas and yesteryears bonus bids? And what of the future
as the prices double and triple. In the following and preceding Summary,
recommendations are made for rectifying the problem with the proposed
rules.

**Section 3900.2---Definitions**

DR,pg 42928 Section 3900.2 would contain the definitions and terms used
in these proposed regulations. Many of the terms and definitions found
in this section would be similar to terms and definitions in the
regulations of other BLM mineral leasing programs. Because most of the
terms and concepts in this section are well-established, this section of
the preamble does not address each of the definitions, but focuses only
on definitions for certain terms that directly affect the reader's
understanding of the regulatory framework of the oil shale leasing
program or that are unique to these regulations

COMMENT: Here's where the Rules package begins to run aground. Although
certain limited use of definitions and associated rules from Mining and
Oil and Gas leasing may be applicable, the oil shale industry is
primarily a different animal, and definitions, their purpose, and
resultant rules will be quite different if they are going to result in
effective technological development and maximum benefit to the citizens
of the USA.

*AR: **[Acquired lands]{.underline}*** means lands which the United
States obtained through purchase, gift, or condemnation, and mineral
estates that are not public domain lands, including mineral estates
associated with lands previously disposed of under the public land laws,
including the mining laws.

COMMENT: The reader is referred to Sections 3901.20---Acreage
limitations and 3901.30 Computing acreage holdings. What these two
sections state is that an entity may lease 50,000 acres of Federal oil
shale land plus an additional 50,000 acres of "acquired lands" as
defined above, for a total of 100,000 acres per state (156 square miles
or sections), or a total of 468 square miles for the three states of CO,
WY, and UT. If the thickest and highest quality reserves were
incorporated in this one entity's leases it would clearly corner the
largest single tract of hydrocarbon reserves in the world, let alone the
US. John D. Rockefeller would certainly have loved a trust like this
one. What were our politicians thinking of when they passed the EP Act??

AR: **[Act means the Mineral Leasing Act of 1920]{.underline}** as
amended and supplemented.

COMMENT: There are two critical dates regarding the Act as amended and
supplemented. The Act in force on June 9, 2005 at the time the BLM RDD
program was announced in the Federal Register and referenced therein
several times, and therefore the ruling document for the BLM RDD
program. The second is August 8, 2005 when Pres. Bush Signed the Energy
Policy Act of 2005 (EP Act) which changed the mineral's leasing
act---but DOI/BLM made no announcement that this had changed the
requirements of the BLM RDD program---particularly as it relates to how
many 160 RDD tracts one could apply for and receive, as well as the
adjoining 8 section preference lands. The Act changes in terms of the
Minerals Leasing Act (MLA) rules as they relate to the BLM RDD program
were discussed in the preceding Background Section.

AR: **[Commercial quantities]{.underline}** means **[production of shale
oil quantities]{.underline}** in accordance with the approved Plan of
Development for the proposed project, **[through research, development,
and demonstration]{.underline}** activities conducted on the lease,
based on, and at the conclusion of which, **[there is a reasonable
expectation that the expanded operation would provide a positive return
after all costs of production have been met, including the amortized
costs of the capital investment.]{.underline}**

DR, pg 42929: The term ''commercial quantities'' means production of
shale oil quantities in accordance with the approved Plan of Development
for the proposed project through the research, development, and
demonstration activities conducted on the lease, based on and at the
conclusion of which a reasonable expectation exists that the expanded
operation would provide a positive return after all costs of production
have been met, including the amortized costs of the capital investment.

COMMENT: Although the same definition is provided in both the "DR" and
"AR", there is no further discussion. Is this a requirement to obtain a
commercial lease under proposed commercial leasing rules? The answer is
no. Or does this only apply to conversion of the BLM RDD preference
lease to a commercial lease? The answer is yes. If it were required to
obtain a commercial lease, how does one demonstrate this without a BLM
RDD lease?? Does this include downstream hydrotreating of the oil and
gas processing/separations.? Are we talking about raw shale oil or
hydrotreated oil (see synthetic petroleum definition below) acceptable
to a refinery? Shale gas is production not mentioned, where does it fit
into the definition? Where is energy efficiency, energy self
sufficiency, and resource recovery efficiency included and quantified in
this definition? The answer is they are not requirements for RDD
preference right conversion, no for commercial leasing.

Commercial quantities for example means that you demonstrate you can
make a buck---nothing else. What about energy efficiency, energy self
sufficiency, maximum resource recovery, environmental impact. All that's
required here is making a buck---and a quick one at that will do just
fine. Commercial quantities are only required in subpart 3926---i.e.
conversion of RDD to commercial. Not a requirement for a commercial
leases outside the BLM RDD program---for new commercial leases outside
the BLM RDD program the lease simply goes to the highest bidder---i.e.
highest bonus bid---alah, highest fair market value as determined by the
bonus bid---end of story. That commercial lease applicant doesn't have
to demonstrate anything on commerciality, economic viability, RDD,
energy efficiency, energy self sufficiency, maximum resource recovery,
even environmental impact, technology or financial capacity---nada,
nothing. Hygrading is o.k., except for application of the term MER as it
relates to mining.

COMMENT: Commercial quantities in the BLM RDD program FRN Section 1,
Definitions is defined as: (b) "Commercial Quantities" quantities
sufficient to provide a positive return after all costs of production
have been met, including the amortized costs of capital investment. And
in the RDD FRN Section 23 (a) Upon documenting to the satisfaction of
the authorized officer that it has produced commercial quantities of
shale oil from the lease, the Lessee has the exclusive right to convert
the research and development lease acreage to a commercial leas and
acquire any or all portions of the remaining preference lease area up to
a total of 5120 contiguous acres upon:

So this definition in the RDD FRN is somewhat different than in the
Commercial Rules FRN. The RDD FRN requires actual commercial production
and showing of a profit from that production. But this may be 10
barrels/day if you can show on paper that it's profitable. The
Commercial Rules FRN only requires that you produce enough shale oil
that you can show via extrapolation that an expanded operation would be
profitable.

AR**: *Diligent development*** means achieving or completing the
prescribed milestones listed in § 3930.30 of this chapter.

DR, pg 42942 Diligent development is a component of other mineral
leasing programs such as coal and oil and gas and is required under
Section 369(f) of the EP Act. Section 3927.50 would require lessees to
meet diligent development

COMMENT: The above and following deal with diligence milestones and
annual minimum production requirements. The BLM considers continued
minimum annual production a necessary part of diligent development of
the lease. This requires that a company continue to produce the minimum
annual requirement or make payments in lieu of production in order to
hold the lease.

DR, pg 42928 **Diligent Development**---Section 369(f) of the EP Act
requires that the BLM establish work requirements and milestones to
ensure diligent development of Federal oil shale leases. The BLM
requested public comment on diligent development to assist us in
determining lease diligence requirements for an industry that has yet to
be successfully established. A discussion of the ANPR comments we
received on diligence can be found in section 3927.50 of this proposed
rule.

AR: **§ 3927.50 Diligent development.** Oil shale lessees must meet:(a)
Diligent development milestones;(b) Annual minimum production
requirements or payments in lieu of production starting the 10th lease
year, except when the BLM determines that operations under the lease are
interrupted by strikes, the elements, or causes not attributable to the
lessee. Market conditions are not considered a valid reason to waive or
suspend the requirements for annual minimum production. The BLM will
determine the annual production requirements based on the extraction
technology to be used and on the BLM's estimate of the recoverable
resources on the lease, expected life of the operation, and other
factors.

AR **§ 3930.30 Diligent development milestones.**

COMMENT: See Section 3930.30 for details.

AR:**§ 3930.40 Penalties for missing diligence milestones.** The BLM
will assess a penalty of \$50 for each acre in the lease for each missed
diligence milestone each year until the operator or lessee complies with
§ 3930.30(a) of this chapter

COMMENT: The penalty for missing each successive milestone plus the
minimum annual production results in penalties of \$50/acre after the 2
year of the lease, \$100/acre after the 3 year, \$150 after the 5 year,
\$200/acre after the 7 year and \$250 per year for years 10-20. This is
peanuts compared to the value of hydrotreated oil recoverable some high
quality acres in the Piceance Basin which could exceed \$100
million/acre. The penalty needs to be larger and consistent with the
quality, depth, and overburden thickness of the resource.

AR: *Fair market value (FMV)* means the monetary amount for which the
oil shale deposit would be leased by a knowledgeable owner willing, but
not obligated, to lease to a knowledgeable purchaser who desires, but is
not obligated, to lease the oil shale deposit.

COMMENT: FMV is a key definition and its difficulty of determination is
discussed or used in the text on pages 42928, 39, 41, 44, 58, 67, 73.
Comments are provided in the Rule sections where it is used.

AR: pg 42958: **[Maximum economic recovery means]{.underline}** that,
based on standard industry operating practices, all profitable portions
of a leased Federal oil shale deposit must be mined. This requirement
does not restrict the authority of the BLM to ensure the conservation of
the oil shale reserves and other resources and to prevent the wasting of
oil shale.

COMMENT: This definition is a simplified in-applicable extraction from
the DOI's definition for MER for coal. The coal MER definition is
provided below. Portions extracted verbatim are shown in "bold".

The attempt by the BLM to simply take the definition for coal MER,
replace the words "coal" with "oil shale" and delete over half of the
definition won't return maximum benefit nor encourage technology
development From Title 43, Part 3480, Subpart 3480, Section 3489.0-5
Definitions for Coal Exploration and Mining Operations Rules, Definition
(21):

\(21\) **Maximum economic recovery** (MER) **means that, based on
standard industry operating practices, all profitable portions of a
leased Federal** coal **deposit must be mined**. At the times of MER
determinations, consideration will be given to: existing proven
technology; commercially available and economically feasible equipment;
coal quality, quantity, and marketability; safety, exploration,
operating, processing, and transportation costs; and compliance with
applicable laws and regulations. The **requirement** of MER **does not
restrict the authority of the** authorized officer **to ensure the
conservation of the** recoverable coal **reserves and other resources
and to prevent the wasting of** coal.

COMMENT: For most aspects of a commercial oil shale operation there are
no "standard industry operating practices". Commercial oil shale
operation "A" may be profitable---but it may be extremely wasteful of
oil shale resources---compared to a similar operation "B" since "B" may
be a much more energy efficient, energy self sufficient, and resource
recovery efficient, and leave much less environmental damage and
mitigation expense than "A". Both may mine, extract, or effect the same
volume of oil shale resource---but the total quantity of high quality
shale oil and shale gas produced from that effected resource may be
significantly larger for "B" than for "A". In fact "B" will be able to
recover much more of the total available resource, such as lower grade
material, because it is simply technically more efficient and may also
be economically more efficient. In most cases "B" would be expected to
be more profitable than "A"---but not always. In situations where
"hygrading" is employed wherein an in-efficient process is used, "A" may
be more profitable than "B".

Trying to apply the proposed definition is an out of date, inapplicable,
and an overly simplistic approach and will not work to the benefit of
efficient oil shale technology development nor maximum benefit to the
citizens of the USA. Maximum benefit occurs when the maximum total
possible quantity of high quality shale oil and shale gas will be
produced from the total national resource and the royalties and bonus
bids (or alternate payments) on that resource have been optimized.
"Hygraders" with wasteful inefficient processes may in and of themselves
be profitable to the exploiters. They may even offer the highest bonus
bids. But the total quantity of high quality product they will produce,
and therefore the total royalties paid will be much less. In addition,
the strategic and economic benefit to the citizens of the USA will have
been squandered. **Maximum economic recovery, needs to be replaced with,
or made equivalent to, maximum energy efficiency, maximum energy self
sufficiency, maximum effective resource recovery, maximum product
quality and quantity, and minimum environmental impact and mitigation.**
MER should also mean maximizing the efficiency of processing of kerogen
such that Fischer Assay raw shale oil and Tosco Assay raw shale gas is
recovered, plus even the lowest grade oil shale is processed consistent
with the BAT (best available technology). BAT is energy self sufficient,
very energy efficient, and maximizes resource recovery. This will
produce the best technology and the maximum return to the citizens of
the USA. It will not benefit "hygraders" with in-efficient technology,
and in fact should ban them from participation in the development of US
Federal oil shale reserves.

The maximum economic recovery may require strip mining of the entire
Federal oil shale reserve. This may not be the most profitable---but
will likely produce the largest total national quantity of high grade
shale oil and shale gas. The effective recovery of the maximum quantity
of kerogen by strip mining may likely far exceed that obtainable with
underground mining or in situ processes. Strip mining and associated
reclamation could be combined with massive water storage projects badly
needed in the arid southwest. Such "Big Picture" or "Visionary Thinking"
is totally missing from consideration in either this rule, or national
policy.

How does this definition apply to in-situ pyrolysis oil shale processes?
At worst it doesn't, at best it is open to wholesale exploitation based
on interpretation.

MER is used in several places within the proposed rules. Other places in
the proposed rule where MER is used are as follows:

**Reference AR:** Section 3903.54, pg 42962 which deals with royalty
reductions to encourage MER.

**Reference AR:** Section 3930.10, pg 42968, which requires that all
operations must be conducted to achieve MER. (e) The operator/lessee
must conduct operations to: (1) Prevent waste and conserve the
recoverable oil shale reserves. This is treated from the standpoint of
mining of the resource, with no regard to the energy efficiency, energy
self sufficiency, or ultimate resource recovery---not in the form of
rock---but in terms of the quantity and quality of oil and gas products
produced. Besides effective mining regulations, effective pyrolysis and
downstream processing rules must be in place.

**Reference AR:** Section3930.20, pg 42969, which also deals with
requirements of MER in all operations.

**Reference AR: § 3930.20 Operations.**

\(a\) *Maximum Economic Recovery (MER).* All mining and in situ
development and production operations must be conducted in a manner to
yield the MER of the oil shale deposits, consistent with the protection
and use of other natural resources, the protection and preservation of
the environment, including, land, water, and air, and with due regard
for the safety of miners and the public.

\(c\) *Statutory compliance.* Operators must comply with applicable
Federal and state law, including, but not limited to the following: (1)
Clean Air Act (42 U.S.C. 1857 *et seq.*); (2) Federal Water Pollution
Control Act, as amended (30 U.S.C. 1151 *et seq.*); (3) Solid Waste
Disposal Act as amended by the Resource Conservation and Recovery Act
(42 U.S.C. 6901 *et seq.*);

Where's the specific protection to prevent scalping of the land, and
crapping up the ground water---and state statute compliance for air,
water, and ground?

**[Maximum economic recovery]{.underline}** is mentioned only once in
the preamble discussion, as follows:

Reference DR, pg 42929: Section 3930.20 would establish the various
standard operating requirements associated with the development of an
oil shale lease, including requirements concerning the maximum economic
recovery (MER) of the resource.

COMMENT: Regulations to ensure that the total maximum benefit to the
citizens of the USA are obtained from perhaps the nation's most
economically valuable and strategically critical resource while
encouraging sound development of the technology must be carefully
thought out. In the coal and hard rock mining industries this is
implemented with the concept of maximum economic recovery which is
defined for example for coal resources below. For the oil and gas
industry this is accomplished with oil and gas conservation laws.
Although portions of these approaches may be applied to parts of a
commercial oil shale industry, the attempt by the BLM to simply take the
definition for coal MER, replace the words "coal" with "oil shale" and
delete over half of the definition won't return maximum benefit nor
encourage technology development. Even adding back in some of the
"considerations" deleted from the coal definition would be better than
what has been proposed.

AR, pg 42958**[: Production means]{.underline}**:

> \(1\) The extraction of shale oil, shale gas, or **shale oil
> by-products** through surface retorting or in situ recovery methods;
> or
>
> \(2\) The severing of oil shale rock through surface or underground
> mining methods.

COMMENT: These, (1) and (2), are two vastly different definitions of
"production" and/or "products" and will have radically different end
results in terms of royalties and point of determination and maximum
economic recovery, etc. In addition, in a large integrated commercial
operation downstream processing of the raw shale oil by hydrotreating,
and raw gas separation and processing, to produce refinery acceptable
syncrude and pipeline quality gas, or gas for used in downstream
processing will likely be done at, or near the raw shale oil/gas
extraction site. What then is the "product" of this "production"---mined
oil shale, raw shale oil/gas, or syncrude and pipeline/downstream
processing quality gas, or gasoline, diesel, and jet fuel? Some shale
oil technologies will produce both Fischer Assay raw shale oil and Tosco
Assay raw shale gas, will be energy self sufficient, and very energy
efficient producing also surplus electricity and/process steam. Those
processes will utilize the resultant char to provide the heat of
pyrolysis and therefore will have no need for imported electricity nor
imported fuel, and will not consume product oil or gas for fuel. The
value of the different potential "products" is vastly different, and
therefore also is the royalty value for a fixed royalty rate, depending
on the point of determination (or product) of the royalty. This is an
attempt to apply either hard rock/coal mining, or conventional oil/gas,
definitions to oil shale and it simply is not applicable and is fraught
with problems if incorporated in final regulations. Production, royalty
rates, maximum economic recovery, energy efficiency, energy self
sufficiency, and products used internally are coupled together in a much
more complex way than for coal, hard rock minerals, other
non-hydrocarbon minerals, and conventional oil and gas. All of these
issues can be greatly simplified if the leasing regulations required all
processes to be very energy efficient, energy self sufficient, maximize
total resource recovery, and minimize environmental impact.

The problem is also further simplified if "production" means mining the
rock, or pyrolyzing the kerogen in place (in situ), with a requirement
for both Fischer Assay raw shale oil and Tosco Assay raw gas recovery
efficiency.

COMMENT The words "product, production and by-products" are used at 3
other points in the FRN:

> \(1\) DR .pg 42929: The BLM defined the term ''production'' to
> acknowledge the various technologies associated with operations for
> extraction of shale oil, shale gas, or **shale oil by-products**.
>
> **(2) AR, pg 42972 Section 3931.70 Production maps and production
> reports.** (a) Report production of all oil shale products or
> by-products to the BLM on a monthly basis.

**(3) AR, pg 42974 § 3935.10 Accounting records.**

\(a\) Operators or lessees must maintain records that provide an
accurate account of, or include all:

\(1\) Oil shale mined;

\(2\) Oil shale put through the processing plant and retort;

\(3\) Mineral products produced and sold;

\(4\) Shale oil products, shale gas, and **shale oil by-products sold**;
and

\(5\) **Shale oil products and by-products that are consumed on-lease
for the beneficial use of the lease**.

> \(b\) The records must include relevant quality analyses of oil shale
> mined or processed and of all products including **synthetic
> petroleum**, shale oil, shale gas, and **shale oil by-products** sold.

COMMENT: Clearly "production" and "products:" needs more work.

**[AR:]{.underline}** *Shale oil* means synthetic petroleum derived from
the destructive distillation of oil shale.

COMMENT: Raw shale oil, or hydrotreated shale oil? What about "shale
oil" produced by Chevron's hoped for in situ dissolution of kerogen with
supercritical carbon dioxide, is this "destructive distillation"/? Or
are they going to dissolve kerogen, then pyrolyze the resultant product
into some type of "shale oil"?

**[AR: Surface retort]{.underline}** means the above ground facility
used for the extraction of kerogen by heating mined shale.

**[AR: Surface retort operation]{.underline}** means the extraction of
kerogen by heating mined shale in and above-ground facility.

COMMENT: No kerogen is being extracted. Kerogen is being pyrolyzed into
raw shale oil, raw shale gas, and residual char products. The product
split between raw oil, raw gas, and char depends on the efficiency of
the process. In-efficient processes produce less liquid oil, more gas,
and much more char. Energy efficient and energy self sufficient
processes recovery maximum quantities of oil, less gas, and use the char
to supply the heat of pyrolysis therefore needing no external source of
energy and have no internal consumption of produced shale oil and gas.

**[AR: Synthetic Petroleum]{.underline}** means synthetic crude oil
manufactured from shale oil and suitable for use as a refinery feedstock
and for petrochemical production

COMMENT: Raw shale oil is converted to a refinery acceptable syncrude
through hydrotreating to remove large quantities of refinery
unacceptable nitrogen. Removal of nitrogen also results in removal of
sulfur and oxygen. In addition heavy metals such as arsenic must be
removed. A certain amount of upgrading also occurs during hydrotreating
resulting in more light end hydrocarbons suitable for jet fuel,
kerosene, and gasoline production and fewer heavy ends that must either
be sent to a cracker or coker. The hydrotreating may be the most
expensive component of shale oil production required to produce a
marketable product. Raw shale oil, without hydrotreating for nitrogen
removal and arsenic removal, is a perfect refinery catalyst poison and
is therefore un-marketable. Without this downstream processing it is a
hazardous waste and every expensive to dispose of.

COMMENT: **[TERMS THAT SHOULD BE A PART OF THESE RULES BUT ARE NEITHER
DEFINED NOR USED ARE THE FOLLOWING:]{.underline}**

Leasing rules that do not include these terms, their significance, and
implications will never encourage technological development of effective
oil shale processes nor return a fair benefit to the American Citizen.

Raw oil shale: Preprocessed rock consisting of inorganic mineral and
kerogen, a solid hydrocarbon.

Spent oil shale: Processed oil shale which consists of inorganic mineral
and with or without residual hydrocarbon char.

Charred spent oil shale: Processed oil shale which has residual
hydrocarbon char contained within and on the surface of the inorganic
mineral.

De-charred oil shale: Processed oil shale which consists only of
inorganic mineral and all residual hydrocarbon char has been removed.

Char: A hydrocarbon residue left on the spent shale following pyrolysis
to produce raw shale oil and raw shale gas.

Raw Shale Oil: The unprocessed condensable oil produced as a result of
pyrolyzing the kerogen contained within raw oil shale.

Raw Shale Gas: The unprocessed gases (condensable and non condensable,
hydrocarbon and non hydrocarbon) produced as a result of pyrolyzing the
kerogen contained within raw oil shale

Processed/Separated Gas: Gas produced from oil shale that has been
downstream separated into components and which has contaminants such as
hydrogen sulfide removed. Oil Shale produced raw gas cannot be sent
directly to a pipeline, or used directly on site in processing. Certain
components will be suitable for pipeline marketing or the condensate
market; others can be a source of heat and or hydrogen for downstream
raw oil/gas processing. Use of this gas for oil shale pyrolysis heat is
wasteful since there is adequate residual char energy to carryout self
sufficient and energy efficient pyrolysis.

Hydrotreated shale oil: Shale oil that has been downstream processed
primarily to remove nitrogen. As a result of the nickel catalysts
utilized almost all of the sulfur and oxygen will also be removed. To
avoid catalyst poisoning a heavy metal guard bed will be used to also
remove arsenic and other heavy metals. Properly done, the resultant
product will be a high quality, light refinery feedstock commanding a
premium price. Without this processing the raw shale oil is
un-marketable and becomes a liability as a hazardous waste.

Process Energy Efficiency: The net total energy output in terms of high
quality energy products divided by the net total energy input including
all fundamental root energy sources for imported energy. The net energy
input is the chemical energy value of the kerogen plus all imported
external root energy sources such as natural gas, or coal to generate
electricity for pyrolysis heat. The net high quality energy products out
are the net hydrotreated shale oil, separated and processed downstream
gases, plus exportable process steam and electricity.

Energy Self Sufficient: Means the after the process has been started, it
up has no demands for externally supplied energy in the form of
electricity, natural gas, or other fuels. When combined with high
process energy efficiency and Fischer Assay/Tosco Assay requirements it
means the pyrolysis heat must be supplied by residual char---not
internally generated shale oil or shale gas.

Effective Resource Recovery: Means that the maximum quantity of kerogen
is mined for above ground processing leaving as little behind as
possible, and further that the maximum effective oil/gas recovery
(Fischer Assay/Tosco Assay recovery, and Energy Self Sufficient, and
Process Energy via char) above ground including downstream hydrotreating
and gas separation/processing is achieved. For below ground or in situ
processing it means that the maximum amount of kerogen is processed and
maximum effective oil/gas recovery is achieved underground and also in
above ground downstream processing. The fraction of kerogen recovered
will be a function of the quality, thickness, and overburden depth.

Minimum Environmental Impact: Means the minimum possible environmental
impact on air, water, and soil is achieved and where possible left
better than in the original state. When combined with the above, this
may mean massive strip or surface mining, combined with massive water
storage projects and beneficial land use projects thereby exploiting and
utilizing in a positive way the massive earth moving operations that
would be required by reclamation.

Fischer Assay/TOSCO Assay: Means the process net recovers both the
Fischer Assay oil and Tosco Assay gas, and therefore consumes no
internally generated oil or gas for process pyrolysis heat. Fischer
Assay Barrels of Oil Equivalent (FBOE) is not allowed, since both the
separate raw oil and raw gas assay fractions must be recovered. This
eliminates excessive gas production and the expense of excessive oil
cracking and excessive resultant char production---while attempting to
meet this requirement via FBOE.

Section 3900.5\-- **Information collection.**

Section 3900.10

Section 3900.20

Section 3900.30

Section 3900.40

Section 3900.50

Section 3900.61

Section 3900.62

Subpart 3901**---Land Descriptions and Acreage**

Section 3901.10

Section 3901.20\-- **Acreage limitations.**

AR: No entity may hold more than 50,000 acres of Federal oil shale
leases in any one state. Oil shale lease acreage does not count toward
acreage limitations associated with leases for other minerals.

DR, pg 42929: Sections 3901.20 and 3901.30 would incorporate the
provisions of Section 369(j)(2) of the EP Act that 50,000 acres would be
the maximum acreage of oil shale leases on public lands that any entity
may hold in any one state and that the oil shale lease acreage would not
count toward acreage limitations associated with oil and gas leases.
Another 50,000 acres may be held on acquired lands. Since the provisions
in this section relating to maximum acreage holdings are statutory, the
BLM does not have the authority to revise the requirements in this
section.

COMMENT: The total public domain and acquired lands is therefore 100,000
acres per state, or a total of 300,000 acres for CO, WY, and UT
combined---spell it out. See Section 3900.2, Definition of Acquired
Lands and following Section 3901.30..

Section 3901.30 --**[Computing acreage holdings]{.underline}**.

\\AR: The maximum acreage in any one state refers to the acres an entity
may hold under a Federal lease on either public domain lands or acquired
lands. Acquired lands and public domain lands are counted separately, so
an entity may hold up to the maximum acreage of each at the same time.

DR, pg 42929: Sections 3901.20 and 3901.30 would incorporate the
provisions of Section 369(j)(2) of the EP Act that 50,000 acres would be
the maximum acreage of oil shale leases on public lands that any entity
may hold in any one state and that the oil shale lease acreage would not
count toward acreage limitations associated with oil and gas leases.
Another 50,000 acres may be held on acquired lands. Since the provisions
in this section relating to maximum acreage holdings are statutory, the
BLM does not have the authority to revise the requirements in this
section.

COMMENT: Yet another example of a premature, ill thought out rule, which
has further opened the door to huge land grabs and speculation. Given
that all Colorado BLM RDD lessee's will process less than 2 acres of
their five separate 160 acre tracts, and only 16 acres in Utah at
commercial scale operation---what was the big rush to open up commercial
leasing for up to 100,000 acres per state, or a total of 300,000 acres
for CO, WY, and UT with what could be upwards of 300 billion barrels of
recoverable oil worth \$30 trillion---far more than the entire Saudi
Arabia oil reserves? How many acres of acquired land bearing oil shale
are there in each of the states of Wyoming, Utah, and Colorado? If there
are over 50,000 acres then the real total acreage lease limitation per
entity is 100,000 acres. The quantity of non-acquired oil shale bearing
acreage and acquired oil shale bearing acreage needs to be delineated.
What are the anti trust implications here---John D. Rockefeller would
have a hay day.

And yet with this rule the BLM is making it next to impossible for small
developers to gain access to 1-2 acre parcels to conduct development
work on oil shale technology leading to commercial demonstration.

Subpart 3902 **---Qualification Requirements**

Section 3902.10---**Who may hold leases.**

AR: (a) The following entities may hold leases or interests therein: (1)
Citizens of the United States; (2) Associations (including partnerships
and trusts) of such citizens; and (3) Corporations organized under the
laws of the United States or of any state or territory thereof. (b)
Citizens of a foreign country may only hold interest in leases through
stock ownership, stock holding, or stock control in such domestic
corporations. Foreign citizens may hold stock in United States
corporations that hold leases if the Secretary has not determined that
laws, customs, or regulations of their country deny similar privileges
to citizens or corporations of the United States. (c) A minor may not
hold a lease. A legal guardian or trustee of a minor may hold a lease.
(d) An entity must be in compliance with Section 2(a)(2)(A) of the Act
in order to hold a lease. If the BLM erroneously issues a lease to an
entity that is in violation of Section 2(a)(2)(A) of the Act, the BLM
will void the lease.

COMMENT: What precludes foreign big oil, and foreign entities, such as a
foreign country, wealthy individual foreigner, or a group of wealthy
individual foreigners, who may or may not have the interest of the USA
at heart from obtaining a huge interest in a commercial oil shale lease
by setting up a US corporation in the US and owning most of the stock?
Their only restriction is that they allow US citizens to own stock in
the foreign parent corporation who has set up a US subsidiary
corporation in the US. Foreign interests can always own the controlling
interest, while allowing US citizens/corporations to purchase minority
interests. This includes countries such as China, Russia, Venezuela,
Iran, and North Korea as well as their, or others', individual citizens
or groups of citizens. Corporate entities that already exist within the
US in this regard include Shell Exploration and Production (Royal Dutch
Shell), CITGO (Venezuela), Luke Oil (Russia). and Motiva (Saudi
Arabia/Royal Dutch Shell). Motiva (foreign controlled) with its new
expansion will soon own and operate the largest single refinery in the
United States.

Section 3902.21

Section 3902.22

Section 3902.23

Section 3902.24

Section 3902.25

Section 3902.26

Section 3902.27

Section 3902.28

Section 3902.29

Subpart 3903

Section 3903.20

Section 3903.30

Section 3903.40---**Rentals**

AR: (a) The rental rate for oil shale leases is \$2.00 per acre, or
fraction thereof, payable in advance of the lease year. Rentals paid for
any 1 year are credited against any production royalties accruing for
that year.

DR, pg 42930: Section 3903.40 would incorporate the requirement of
Section 369(j) of the EP Act that the annual rental rate for an oil
shale lease would be \$2.00 per acre. Since the statute sets the rental
rate, the BLM has no discretion to revise it.

COMMENT: No adjustment is made here for thickness, overburden depth,
quality of the oil shale, etc. Therefore there is no correlation between
the rental rate and the value of the resource per acre. The Energy
Policy Act must be changed so that the rental rate is coupled to
resource thickness, overburden depth, and quality of oil, etc. For the
thickest and highest quality reserves this payment is meaningless
compared to the value of the reserves---and won't even be paid if there
is any meaningful payment of production royalties.

AR Section 3903.51\--**Minimum production and payments in lieu of
production.**

AR: (a) Each lease must have a minimum annual production amount of shale
oil or make a payment in lieu of production for any particular lease
year, beginning with the 10th lease year.

\(b\) The payment in lieu of annual production is established in the
lease and will not be less than \$4 per acre or fraction thereof per
year, payable in advance. Production royalty payments will be credited
to payments in lieu of annual production for that year only.

DR, pg 42928: **Minimum Production Requirement**---The BLM specifically
asked in the ANPR for suggestions from the public about what the minimum
production requirement should be to assist us in determining lease
production requirements for an industry that has yet to be successfully
established. A discussion of the public comments we received on minimum
production requirements can be found in section 3903.51 of this proposed
rule.

DR, pg 42930: Section 3903.51 would address the minimal annual
production requirement that would apply to every lease. It also would
discuss payments in lieu of production beginning with **the 10^th^ lease
year**. The BLM would determine the payment in lieu of annual
production, but in no case would it be less than \$4 per acre. Payments
in lieu of production are not unique to this proposed rule. They are a
requirement of other BLM mineral leasing regulations and the BLM
believes they provide an incentive to maintain production. Setting the
payment in lieu of production at no less than \$4 per acre should be an
adequate payment to the Federal government to justify allowing the
lessee to continue holding a lease absent production, but should not be
high enough to cause the lessee to relinquish the lease. A payment in
lieu of production of \$4 per acre for the maximum lease size of 5,760
acres equals a payment of \$23,040 per year.

In response to the ANPR, the BLM received comments expressing various
ideas concerning minimum production amounts and requirements. The
comments are summarized as follows:

\(1\) Minimum production should be 1,000 barrels a day;

\(2\) Minimum production should be based on the viability of the
operation;

\(3\) Minimum production levels should be based on resource potential
and production levels identified in the plan of development;

\(4\) Minimum royalties should be assessed at the end of the primary
term;

\(5\) Minimum production should be based on a percentage of the
projected resource base; and

\(6\) There should not be a minimum production requirement.

We agree with several of the commenter's suggestions. **The suggestions
to base minimum production on the approved plan of development and the
specifics of the operation were incorporated into proposed sections
3930.30(c) and 3930.30(d).** The suggestions related to defining the
minimum production on a percentage of the resource base were not
incorporated into the proposed rule because of the difficulties
associated with defining the recoverable resource, the variables
associated with the different development technologies, and the
differing kerogen content of the shales. We consider the suggestion that
identified 1,000 barrels a day as the correct minimum production
requirement too inflexible a standard because it does not allow for
differences in shale quality and differences in extraction technology.

Reference (c) & (d) of AR: **sections 3930.30(c) and 3930.30(d)
immediately below and referred to above.**

\(c\) Operators must maintain minimum annual production every year after
the 10th lease year or pay in lieu of production according to the lease
terms.

\(d\) Each lease will provide for minimum production. **The minimum**
**production requirement stated in the** **lease must be met by the end
of the 10^th^ lease year and will be based on the BLM's estimate of the
extraction technology to be used, the recoverable resources on the
lease, expected life of the operation, and other factors the BLM
considers.**

COMMENT: The minimum production suggestion of 1000 barrels/day was
provided separately by not one commenter but two, Wyoming Governor Dave
Freudenthal and also by Brent Fryer. Any commercial oil shale
lease/project that cannot consistently produce 1000 barrels/day of raw
shale oil after 10 years of is tying up a national resource which is not
in the best interests of the nation. There clearly needs to be a minimum
production floor to make it clear that this is not acceptable.

COMMENT: **\$4/acre per year after 10 years.** Given the fact that the
maximum size single lease cannot exceed 9 sections (5760 acres) and
given the fact that this much land may hold well over 9 billion barrels
of Fischer Assay raw shale oil plus Tosco Assay raw gas, which when
processed into marketable products could easily be worth \$1-2 trillion
dollars, \$23,040/year is clearly not a fair return to US citizens based
on the time value of money of the asset that is not being produced after
a lease has been let. The payment in lieu of production should be based
on the thickness, overburden depth, and quality of the oil shale, and in
addition should be based on the lost value to the U.S. economy, as well
as royalties, etc., and the time value of money of that asset that is
not being produced. The payment is only required after 10 years after
the lease is initiated before the minimum production, payment in lieu of
production goes into effect. This is excessive time and encourages
speculation.

COMMENT Referring to the following statement (a): DR, pg 42930, from
above: The suggestions to base minimum production on the approved plan
of development and the specifics of the operation were incorporated into
proposed sections 3930.30(c) and 3930.30(d).

Does not equal the following statement (b):

AR from above: The minimum production requirement stated in the lease
must be met by the end of the 10^th^ lease year and **will be based on
the BLM's estimate of the extraction technology to be used, the
recoverable resources on the lease, expected life of the operation, and
other factors the BLM considers.**

Reference from above AR, pg 42958**[: Production means]{.underline}**:
(1) The extraction of shale oil, shale gas, or shale oil by products
through surface retorting or in situ recovery methods; or (2) The
severing of oil shale rock through surface or underground mining
methods.

As noted above these are two vastly different definitions of
"production", which are further, complicated with two different
definitions of "minimum production." In addition if the production is
shale oil or shale gas is this raw shale oil and raw shale gas or
hydrotreated oil and processed gas?

COMMENT: Combined effect of 10 year grace period, \$4/acre per year if
minimum production not met, definition of production means extraction of
shale oil, shale gas, or shale oil by products---or severing of oil
shale rock through mining, and inconsistent and meaningless statements
on minimum production is problematic since: (1) no differentiation on
\$4 payment between poor acreage and excellent acreage; (2) excessive
grace period encourages speculation; (3) no clear cut practical lower
floor for minimum required production; and, (4) not clear who defines
the "minimum production"---BLM or lessee in his plan of operations; and
(5) two definitions of production---rock or hydrocarbon products with no
distinction between the raw oil/gas products and the downstream
processed products. Further, any commercial lessee that can't
consistently produce a minimum of 1000 barrels/day of raw shale oil
after five years (not ten) should be extinguished. Without achieving
this level of production within 5 years, that lessee clearly does not
have the best interests of the US citizen at heart---and deserves no
support since he has no chance of ever developing either technology nor
an oil shale industry.

Section 3903.52 \--**Production Royalties (and Point of
Determination?)**

AR: **Option 1**

**§ 3903.52 Production royalties.**

\(a\) The lessee must pay royalties on all products of oil shale that
are sold from or transported off of the lease. (b) The royalty rate for
the products of oil shale is 5 percent of the amount or value of
production.

**Option 2**

**§ 3903.52 Production royalties.**

\(a\) The lessee must pay royalties on the amount or value of all
products of oil shale that are sold from or transported off of the
lease. (b) The standard royalty rate for the products of oil shale is
12.5 percent of the amount or value of production. (c) For any lease
that begins production of oil shale within 12 years of issuance of the
first commercial oil shale lease issued under subpart 3925 or subpart
3926, the royalty rate is 5 percent of the amount or value of production
on the first 30 million barrels of oil equivalent produced from that oil
shale lease.

COMMENT: Option 3 is discussed in DR, but not even mentioned in AR?
"Production of oil shale" means what?---production of rock? What would
DOI/BLM do with 5% of the "amount" of mined rock?

COMMENT: Here again we have the issue of what are the "products". Do we
use "all products sold or transported" off the lease as specified in
options 1 & 2. Or do we use the definition of "production" in Section
3900.2. and if from there what does shale oil by-products include? Does
it include surplus electricity and process steam generated from an
energy efficient and self sufficient process? What about shale gas
by-products such as sulfur and ammonia? Are the products raw shale oil,
hydrotreated shale oil, or the gasoline, diesel, and jet fuel finished
products?

DR pg 42934 The BLM also received 5 comments specific to the royalty
point of determination. Two of the comments suggested that royalty
should be determined ''at the point at which the oil product exits a
process facility in a marketable state.'' One comment suggested that
''the point of royalty determination be at the earliest point of liquid
or gaseous product marketability.'' Another comment suggested that ''the
oil produced should be measured at the point at which the oil product
exits a processing facility in a marketable state.'' The last comment
did not provide a specific suggestion; rather, it stated that the BLM
''must set the royalty rate and point of royalty determination with
reference to the economic cost of emissions that would be created from
developing, and then burning, the oil shale resource.'' After a careful
evaluation of these comments and consultation with the MMS, under the
proposed rule the royalty would be assessed on all products of oil shale
that are sold from or transported off of the lease. This proposed point
of royalty determination is similar to points of royalty determination
for other Interior Department minerals programs.

COMMENT: Reference the above DR, pg 42934 "**under** **the proposed rule
the royalty would be assessed on all products of oil shale that are sold
from or transported off of the lease." This proposed point of royalty
determination is similar to points of royalty determination for other
Interior Department minerals programs."** One interpretation is that any
oil shale rock and any derived product, that crosses the lease boundary
must pay the production royalty. Another interpretation is that any
product that crosses the lease boundary, or that is subsequently sold,
must pay the production royalty at the point of sale. If only rock
crosses the boundary, then the royalty paid would be small since the
rock per ton, or per unit of kerogen, is small since little value has
been added up to this point. If finished jet fuel, kerosene, and
gasoline and pipeline quality gas, and surplus produced electricity and
process steam cross the lease boundary and is subsequently sold at the
retail level from a large integrated oil/gas company then the royalty
paid will be orders of magnitude larger for the same total rock resource
considered.

COMMENT: "first commercial oil shale lease" must be "first USA Federal
commercial oil shale lease" to differentiate from private or state first
commercial oil shale leases.

COMMENT: Assuming a "product" value of \$100/barrel we have 30x106
barrels x\$100/barrel\*(.125-.05) = \$215x10^6^ in royalty relief per
lease. Therefore an "entity" can either nominate say 9 sections for one
lease (maximum allowed in any one lease) and obtain one relief of
\$215x10^6.^ Or alternatively for the same total 9 sections of land,
nominate 36 separate ¼ sections (the minimum allowed in any one lease),
and obtain 36 times this or a total of \$7.740 billion in royalty relief
assuming there is 30 million barrels recoverable from each ¼ section

DR, pg 42928: **Royalty Rate and Point of Royalty
Determination**---Section 369(o) of the EP Act does not prescribe a
royalty rate, but does provide that the royalty rate for oil shale
should encourage development of the resource and should ensure a fair
return to the United States. The ANPR comments received were extremely
varied and recommended a wide range of royalty rates. Discussion of the
ANPR royalty comments can be found in the discussion of section 3903.52
of this rule.

DR, pg 42931 In the ANPR, the BLM solicited public input on the royalty
rate and point of royalty determination. The BLM's purpose for
requesting comments was to solicit ideas on these royalty issues for a
resource that has little or no history of commercial development

There were approximately thirty-one entities that provided comments
through the ANPR process that were specific to royalty rate and royalty
point of determination.

\\

DR, pg 42934 Other Royalty Issues

The BLM also received 5 comments specific to the royalty point of
determination. Two of the comments suggested that royalty should be
determined ''at the point at which the oil product exits a process
facility in a marketable state.'' One comment suggested that ''the point
of royalty determination be at the earliest point of liquid or gaseous
product marketability.'' Another comment suggested that ''the oil
produced should be measured at the point at which the oil product exits
a processing facility in a marketable state.'' The last comment did not
provide a specific suggestion; rather, it stated that the BLM ''must set
the royalty rate and point of royalty determination with reference to
the economic cost of emissions that would be created from developing,
and then burning, the oil shale resource.'' After a careful evaluation
of these comment sand consultation with the MMS, under the proposed rule
the royalty would be assessed on all products of oil shale that are sold
from or transported off of the lease. This proposed point of royalty
determination is similar to points of royalty determination for other
Interior Department minerals programs.

COMMENT: Where's the point of determination in the AR? Is the point of
determination where the "products" are sold from the lease, and/or where
the products are transported off the lease---i.e. across the lease
boundary? There is only one place it is even mentioned and that is in
the DR. Also how is the point of determination connected to "production"
and what is the definition of "production" and "products"? Is the
definition of "production" and the products extracted, or the severing
of the rock, both the products upon which production royalties are
applied---and also the point of determination?

Reference from above AR, pg 42958**[: Production means]{.underline}**:
(1) The extraction of shale oil, shale gas, or shale oil by-products
through surface retorting or in situ recovery methods; or (2) The
severing of oil shale rock through surface or underground mining
methods.

COMMENT: Two vastly different definitions of "production". One product
is shale oil, shale gas, or shale oil by-products, the other is oil
shale rock. The first product description does not differentiate between
raw shale oil and raw shale gas, and downstream hydrotreated oil and
processed/separated gas. Shale gas by-products are not mentioned, nor is
the char for processes which do not consume it for pyrolysis heat.

DR pg 42930: Section 3903.52---Royalty Rates on Oil Shale Production

Section 3903.52 would establish a **royalty rate for all products that
are sold from or transported off of the lease area.**

COMMENT: Is this the only discussion or statement that implies the point
of royalty determination? Also the word "area" used in the DR is not
included in the AR.

DR pg 42930: The BLM recognizes that encouraging oil shale development
**presents some unique challenges compared to BLM's traditional role**
in managing conventional oil and gas operations. We received a wide
range of comments presenting alternative royalty approaches as part of
the ANPR process, and we address those comments below. However, while we
have narrowed the range of options based on the ANPR comments, we have
not yet settled on a single royalty rate for this proposed rule.
Instead, we are presenting two royalty rate alternatives in the proposed
rule (as outlined later in this section), and requesting public comment
on those specific alternatives. In addition, we are considering a third
alternative, a sliding scale royalty rate (also outlined in this
preamble), and we are seeking public comment on the appropriate
parameters for the sliding scale royalty rate should the BLM choose to
adopt this alternative. We anticipate adopting one of these
alternatives, or variations on one of these alternatives, at the final
rule stage.

COMMENT: What in the resultant proposed rules is unique? There should be
rules that incorporate oil shale's uniqueness, but I could not uncover a
thing. Although there are many technology, economic, environmental, and
legal unique issues, they are not addressed or contained within these
rule.

DR pg 42930-1: EP Act (Section 369(o)) directs the agency to establish
royalties and other payments for oil shale leases that ''shall---

\(1\) Encourage development of the oil shale and tar sands resources;
and

\(2\) Ensure a fair return to the United States.''

The market demand for oil shale resources based on the price of
competing sources (e.g., crude oil) of similar end products is expected
to provide the primary incentive for future oil shale development.
Additional encouragement for development may be provided through the
royalty terms employed for oil shale relative to conventional oil and
gas royalty terms, but we recognize that such incentives must be
balanced against the objective of providing a fair return to taxpayers
for the sale of these resources. Through the ANPR process, the BLM
initially examined a wide range of royalty options, including:

\(1\) 12.5 percent royalty rate on the first marketable product:

\(2\) 12.5 percent royalty rate on the value of the mined oil shale
rock, as proposed in 1983;

\(3\) 8 percent royalty rate on products sold for 10 years with optional
increases of 1 percent per year up to a maximum of 12.5 percent, similar
to the rates established by the State of Utah in 1980;

\(4\) Initial 2 percent royalty to encourage production and a 5 percent
maximum upon establishment of Infrastructure;

\(5\) Sliding scale royalty rate tied to timeframes up to a maximum of
12.5 percent;

\(6\) Sliding scale royalty rate tied to production amounts up to a
maximum of 12.5 percent;

\(7\) Sliding scale royalty rate with royalty rates tied to the price of
crude oil;

\(8\) Royalty rate of 1 percent of gross profit before payout and
royalty rate of 25 percent net profit after payout--- (Canadian oil
sands model);

\(9\) Royalty based on cents per ton as proposed in the 1973 oil shale
prototype program; and

\(10\) Royalty based on British Thermal Unit (Btu) content as compared
to crude oil.

In evaluating an appropriate royalty rate system for oil shale that
would meet the dual EP Act objectives of encouraging development and
ensuring a fair return to the government, the BLM also reviewed other
Federal royalty rates for Federal minerals set by statute and under
existing regulations administered by Department of the Interior bureaus,
and royalty rates applied to oil shale production in other countries.

The royalty rates for other Federal energy minerals vary. Specifically,
current royalty rates for Federal energy minerals under Department of
the Interior leasing programs include:

\(1\) Onshore oil and gas (12.5 percent);

\(2\) Offshore oil and gas (16.67 percent), Gulf of Mexico Region (18.75
percent);

\(3\) Underground coal (8 percent);

\(4\) Surface coal (12.5 percent) and

\(5\) Geothermal (for new leases: 1.75 percent for the first 10 years
and 3.5 percent thereafter.

For leases issued prior to the EP Act, 10 percent on net proceeds after
deductions). Many of these programs allow for royalty rate relief under
certain circumstances.

The BLM also looked at royalty applications for oil shale and similar
unconventional fuels in other countries, including:

\(1\) For oil sands, Canada applies a royalty rate of 1 percent of the
gross revenue before payout (before companies have recouped investment
costs) with a 25 percent net profit royalty rate applied after payout;

\(2\) Australia has a 10 percent gross royalty on the value of the shale
oil produced;

\(3\) Brazil applies a 3 percent gross royalty rate;

\(4\) Estonia does not have a royalty; and

\(5\) No information on a royalty rate for shale oil produced in China
was available.

It should be noted that Canada produces oil from oil sands, not oil
shale. **The oil in the sands is the same as crude oil**, but dispersed
in sand. Extraction and processing is more expensive than for
conventional crude oil production, but less expensive than is
anticipated for oil shale. Canadian operators have never reached the
payout point due to the continued capital expenditures in new equipment,
so to date, Canada has received a 1 percent royalty on oil sands
production.

COMMENT: The "oil" in oil or tar sands is not the same as petroleum---it
is bitumen. Should "Canada produces oil from oil sands, not oil shale"
read as follows: "Canada produces oil from oil sands, not oil from oil
shale"?

DR pg 42931: Australian **operations are using the Alberta Taciuk
Process**, which is the same type of technology currently used by the
Oil Shale Exploration Company (OSEC) in Utah. Despite their 10 percent
royalty rate, the Australian oil shale project (the Stuart Project) was
heavily subsidized by the Australian government through other means (tax
incentives). Even the government subsidies could not sustain oil shale
operations in Australia. The last three operators went into bankruptcy
after brief operations. Suncor, the founder of the Stuart Project and a
successful developer of the Canadian tar sands, exited the Australian
oil shale business after losing approximately one hundred million
dollars.1 For its Utah demonstration project, OSEC is also expected to
test the Petrosix horizontal retort process, which is currently being
used by Petrobras, Brazil, for oil shale operations.

COMMENT: The Australians are not using the Taciuk Process---the
equipment is being dismantled and that which is obsolete is being sold
by the receivers of the bankrupt project. Ziffs' Queensland Energy
Resources (receiver of the bankrupt SPP project) has abandoned the
Taciuk and have now opted for the "New Paraho" process which they call
Paraho II. If the Australian operators went bankrupt under a 10% royalty
rate on the value of the oil shale produced, why is 12.5% being
considered in the US, particularly given that one of the BLM RDD lessees
proposed to use the same Taciuk process as the Australians?

How can OSEC's lease allow the use of the Petrosix process when this
statement is included in the OSEC EA based on the exclusive use of the
Taciuk process:

**"After comparing the ATP system with other advanced surface retorts,
OSEC became confident that the ATP system was the most advanced, proven
system and that the other surface retorts were not sufficiently advanced
to meet the needs of the RD&D Project.** **OSEC feels the ATP system is
the best choice for the current RD&D program and that it has the
greatest potential for advancing to a full commercial scale retort;
therefore, the other retorts were not included in proposed RD&D project
and were eliminated from further analysis." Based on OSEC's web site
that appears to be their intention:**

### <http://www.oilshaleexplorationcompany.com/tech.asp>

### "After careful study, OSEC currently intends to use the Petrosix process (a patented retort process) as the technology to process the mined oil shale into shale oil at the White River Mine."

One additional question, who were the last three operators who went into
bankruptcy on the Australian project?

DR pg 42931: Australia and Brazil are the only other known countries
that are producing or have produced oil shale **using the same
technologies as in the U.S**. Oil shale developmental efforts in China
and Estonia are owned by their respective governments. Because no other
country has yet achieved successful commercial oil shale operations and
because of the wide variety of oversight and revenue structures employed
in each country, the BLM's review of these systems did not identify a
useful model for a royalty system to be used for oil shale development
on Federal lands in the U.S.

COMMENT: The Taciuk has never been used within the US for shale oil
production, neither has the Petrosix. It is misleading to imply that
these processes are in use in the US on US oil shale. The Paraho II,
with exception of a small amount of US oil shale, has been used recently
to process test a significant amount of Australian Shale.

DR pg 42931: In the ANPR, the BLM solicited public input on the royalty
rate and point of royalty determination. The BLM's purpose for
requesting comments was to solicit ideas on these royalty issues for a
resource that has little or no history of commercial development.

There were approximately thirty-one entities that provided comments
through the ANPR process that were specific to royalty rate and royalty
point of determination. The comments suggested royalty rates that ranged
from a royalty rate of zero to a royalty rate of 12.5 percent. Of the
royalty-related comments, three suggested that the royalty be set at
12.5 percent, the same rate as in BLM's oil and gas program, while some
comments described a 12.5 percent royalty rate as unreasonable. It is
contemplated that the primary products produced from oil shale will
compete directly with those from onshore oil and gas production, which
has a 12.5 percent royalty rate. However, the BLM recognizes that the
nature of potential oil shale operations differs from that of
conventional oil and gas operations and that these differences may
suggest the need for a royalty system other than the traditional flat
rate of 12.5 percent used for conventional onshore oil and gas
operations.

COMMENT: Does the word "primary" mean largest quantity, or the first
product of the process---i.e. raw shale oil and raw gas. Does product
mean raw shale oil and raw gas, hydrotreated oil and processed/separated
gas, or diesel, jet fuel, and gasoline and pipeline quality gas?

DR pg 42931: In determining the royalty rate for oil shale, it should be
noted that there is a significant difference between oil shale mineral
deposits and a conventional crude oil reservoir. As discussed in the
Background section of this preamble, oil shale is a marlstone that
contains no oil, but kerogen, that needs to be refined and converted to
synthetic crude oil.

COMMENT: We are not refining kerogen. First kerogen is pyrolyzed into
raw shale oil, raw shale gas and char. Next raw shale oil is
hydrotreated and raw gas is processed/separated. From **[AR: Synthetic
Petroleum]{.underline}** *Synthetic petroleum* means synthetic crude oil
manufactured from shale oil and suitable for use as a refinery feedstock
and for petrochemical production.

DR pg 42931: Currently, proposed processes to extract kerogen from an
oil shale deposit are also considerably different, as well as labor and
capital intensive. Oil shale is a solid rock that must be mined or
treated in place to release the kerogen. Two of these processes are
discussed in the Background section of this preamble.

COMMENT: We are not extracting kerogen, nor are we releasing the kerogen
when we pyrolyze kerogen. We are decomposing the kerogen via pyrolysis
into raw shale oil, raw shale gas and char.

DR pg 42931: Seven of the comments recommended that a ''very low royalty
rate'' be established until after companies have recouped the costs of
their investments (debt service and capital investment). Many among the
seven recommended that a 1 percent royalty rate be the starting point,
and they used the Canadian oil sands royalty scheme as an example. As
discussed above, the BLM looked at royalty applications for oil shale
and similar unconventional fuels in other countries. The Canadian tar
sand model presents two challenges. First, because of the continual
infusion of capital to acquire new equipment the payout point is never
being reached.

COMMENT: The Canadian government has obviously encouraged the
development of tar or oil sands. However, they obviously are not
returning a fair return to Canadian citizens, and who is going to pay
for the massive environmental water and soil contamination environmental
mess being left behind. Will it simply become a sacrificial zone forever
leaching and leaking toxic contaminants into the soil and surface/ground
water??

DR pg 42932: Secondly, because of the complexity of determining when
payout may occur, such a royalty scheme is subject to easy manipulation
and higher administrative costs. Therefore, the BLM considered the
investment payout scheme as inconsistent with the premise of ''a fair
return'' to the taxpayers as mandated in EP Act.

COMMENT: How does it follow that "complexity" is inconsistent with "a
fair return"? 1% is inconsistent with a fair return---essentially the
lessee's in Canada are essentially paying nothing for the resource. On
the other hand US oil shale must compete with Canadian Tar Sands---else
it will not be successful. If and when the Canadian projects reach
payout the lease will pay 25% of net profits. At that time, for the
purpose of the royalty, the profits will be market price for products
minus the cost of production. The cost of production will include only
operating costs since the capital will have been paid off. The Canadian
system could work for the US oil shale industry by eliminating the 1%
rate until payout, and switching to a sliding scale of net profits over
the project life, where net profits equal market price minus the total
costs of production including not only operating costs but amortization
of the capital investment.

DR pg 42932: Three of the ANPR comments recommended that ''royalties
must be high enough'' to support local communities and infrastructure;
however, these comments did not provide specific royalty rates. Oil
shale royalties are not designated for community and infrastructure
support, but by statute are required to be split between the Federal
Treasury and the states (30 U.S.C. 191). Presumably states could choose
to direct a portion of the royalty revenues they receive to local
community and infrastructure support, but that would be a state choice,
and for the purposes of this rulemaking, these comments were not
considered because they assume a use of royalty revenues not available
under current law.

Three comments suggested that royalties should not be charged on
hydrocarbons unavoidably lost or used on the lease for the benefit of
the lease, but did not directly address the royalty rate issue.

COMMENT: Hydrocarbons lost or used on the lease for the benefit of the
lease are discussed nowhere but here in the DR or AR. It is implied in
Options 1 and 2 that royalties are only charged for products sold from
or transported off the lease---but no where does it specifically say,
for this option, anything about hydrocarbons lost or used on the lease
for the benefit of the lease---or what "benefit of the lease" means.
Nowhere is the proposal discussed by Royal Dutch Shell to receive a
royalty credit for electricity brought on the lease for the benefit of
the lease. This atrocious waste of high availability energy in the form
of electricity for use as process heat should result in a monetary
penalty to the lessee---not a royalty credit to the lessee. Any process
that heats with electricity should be banned as a matter of Federal
Energy Policy as a fundamental violation of the Second Law of
Thermodynamics, elementary engineering, energy efficiency, energy self
sufficiency, and energy conservation.. What about excessive hydrocarbons
loss by poor processes such as the RDS ICP process where 40% of the
kerogen is lost as char, and no use is made of the char except to
contaminate ground water? Rather than no royalty for this waste of
hydrocarbons, there should be a waste or squandering charge plus a huge
environmental bond required of the lessee---or better yet such processes
should be banned as a matter of Federal Energy Policy.

If Fischer Assay is required for the raw shale oil production, Tosco
Assay is required for the raw shale gas production, and char is required
to be utilized for all pyrolysis heat then there will be no unavoidable
hydrocarbon lost. Char used for pyrolysis heat for the benefit of the
lease should be royalty free to further encourage and assure its
utilization, and eliminate it as a potential massive source for
contamination of both ground and surface water.

DR pg 42932 One comment suggested the royalty be ''based on the material
as it exists naturally in the land, and as it is removed from the
land.'' This comment seems to suggest that royalty should be based on
mined raw shale. While the BLM acknowledges the inherent differences
between an oil shale deposit and other deposits from which similar
products can be produced, this suggestion was not considered because
there is no known value for raw oil shale since there is no oil shale
industry or an established market for raw oil shale. However, it should
be noted that in 1983 the BLM proposed a rule to establish a royalty
rate equivalent to12.5 percent of the value of oil shale after mining or
resource extraction and before processing, as determined by the BLM. The
1983 proposed rule was published on February 11, 1983 (48 FR 6510). The
1983 proposed rule provided that ''the derivation methodology for this
value shall be announced prior to the solicitation of bids.'' The
proposed rule further stated that ''the royalty rate shall, to the
extent practicable, not be levied on any value added by the production
process after the point of resource extraction.'' It would be
unreasonable to adopt such a proposal today, due to the changes in
extraction methodology (in situ versus ex situ). It would also be
challenging to develop a fair and transparent process to calculate the
royalty equivalent in today's economic environment, and no values were
assigned to the mined or unprocessed rock and tonnage in the 1983
proposed rule. As noted, the 1983 proposed rule deferred the
determination of those parameters to a later date.

COMMENT: The issue here is accommodated with a kerogen based royalty
system as discussed in a separate section. Kerogen has no value without
technology to convert it into hydrotreated oil and processed gas.
Technology, no matter how effective, to pyrolyze the kerogen and convert
it into hydrotreated oil and processed gas has no value if the owner has
no access to the kerogen. The challenge is to develop a leasing monetary
system where US citizens and the developers of technology/projects
receive a fair share or return, for: (1) the resource; and (2) the risk
and investment of money, time and intellect into the development of both
technology and projects. Besides a fair return it behooves both parties
to insure technological processes are required to be energy efficient,
energy self sufficient, resource recovery effective, and environmentally
benign as possible. Coming up with that system requires production cost
information, and accommodation of changes in both production costs and
product market prices over time. Both the US citizen, and the
lessee/developer, should share in the difference between the time
varying product price and the production cost---i.e. the net proceeds.

DR pg 42932 In addition to ANPR comments received on royalty rates, the
BLM looked at an initial 2 percent royalty to encourage production and a
maximum 5 percent rate upon establishment of infrastructure. This method
recognizes the high costs involved in producing shale oil. However, we
dismissed this approach because of the difficulty involved in
determining when necessary infrastructure is in place.

The BLM also considered the 8 percent royalty rate established by the
State of Utah for state oil shale leases. It was determined that this
rate represents the historic base royalty rate for solid fuel minerals
on the State of Utah School and Institutional Trust Lands Administration
lands---including asphaltic sands, uranium, and coal. To date, none of
the state leases in Utah have been developed. Based on these facts, the
BLM determined that there is not currently a sufficient basis for simply
adopting the State of Utah's royalty rate for oil shale on Federal
lands.

After examining the basis for setting rates, as suggested in the ANPR
comments, the BLM determined that a flat 12.5 percent royalty rate for
all future production may not allow oil shale to become competitive with
traditional oil and gas development and therefore could be viewed as
inconsistent with the requirements of EP Act. The BLM has decided to
consider other alternatives in this proposed rule that may provide some
additional incentive beyond that of a flat 12.5 percent royalty rate
while also meeting the EP Act objective of providing a fair return to
taxpayers.

COMMENT: There's one way to find out if 12.5% is too high. Put parcels
up for bid based on the 12.5% royalty and see if there are any takers.
12.5% may be way too low for new conventional onshore petroleum given
the current price for crude. The issue for conventional petroleum is
more one of access than it is of royalty rates. There is also a common
thread of BLM's unwillingness to take on developing a royalty system
that has any complexity or requires any effort. Given the value of the
resource, and its strategic importance, as a tax paying citizen who has
taken on a much bigger challenge than royalty formulas---i.e. developing
a new effective oil shale process---I think a little effort on
complexity on the part of DOI/BLM is warranted.

DR pg 42932 **[Royalty Rate Alternatives Proposed for Further
Consideration]{.underline}**

As noted previously, we are not proposing a single royalty system in the
proposed rule. Based on the information the BLM has reviewed to date and
considering the unique challenge of trying to set a royalty rate on oil
shale production in light of the many uncertainties regarding the
economics and technology of a potential future oil shale industry, we
are instead presenting two different royalty rate alternatives in the
proposed rule text:

1\. A flat 5 percent royalty rate; and

2\. A 5 percent royalty rate on a specific volume of initial production
beginning within a prescribed time frame, with a 12.5 percent rate
applied thereafter.

In addition, we are seeking comment on the appropriate parameters for a
third option: A two-three tiered sliding scale royalty based on the
market price of competing products (e.g., crude oil and natural gas). A
further explanation of each of these proposals is presented below. We
are requesting the public to comment on these specific options.

DR pg 42932: **[Option 1. Flat 5 Percent Royalty]{.underline}**

Flat 5 Percent Royalty Although mitigated somewhat by the much greater
geographic concentration of oil shale resources, there is a significant
difference between the energy value of oil shale and crude oil. On a
per-pound basis, very high quality oil shale rock generates 4,300 Btu,
coal generates an average of 10,600 Btu, while crude oil generates
19,000 Btu. Even wood has more heating capacity than oil shale rock,
generating an average of 6,500 Btu. Applying the relative Btu value of
oil shale to crude oil would result in a 2.6 percent royalty for oil
shale. Using the same comparison to the royalty rate for underground
coal would result in a 3.2 percent royalty rate for oil shale. In other
words, it would require almost 5 times as much oil shale to produce the
Btu value of crude oil and more than 2 times as much oil shale to
produce the equivalent Btu value of coal.

COMMENT: This approach is based on 48 gallon per ton oil shale. Lower
more realistic grades would result in even lower royalty rates. The
approach is meaningless since the oil shale resource is not coal and its
not petroleum or natural gas. The real resource is kerogen and it's
worthless unless pyrolyzed and converted to raw shale oil and raw shale
gas. The raw shale oil is also worthless unless hydrotreated to remove
the nitrogen so that it is refinery acceptable feedstock. The underlying
value of the kerogen is that it has a chemical energy heating value of
about 16,000 BTU/lb and can be converted directly to oil and gas by
pyrolysis. Comparison of royalty rates based on heating value ignores
the production costs to obtain a useful product and the product
price---and is therefore a meaningless distraction The real monetary
value of kerogen is tied to the net proceeds between the market price of
products and the production costs, and the technical and economic
effectiveness of the process used to convert the kerogen into marketable
products.

DR pg 42932 The BLM looked at royalty rates on leases issued under
Interior's 1973 Prototype Leasing Program. The prototype leases provided
for royalties of \$.12 per ton for oil shale with a quality of 30
gallons of oil per ton (30 g/t) with the addition of \$.01 for every
increase in gallon per ton of oil shale. In 1973, the average price of a
barrel of oil was \$3.89. At \$.24 per ton of 42 g/t or one barrel/ton
of oil shale, the royalty per barrel of oil would have been 5 percent.
This rate is similar to the rate derived by comparing production costs
to royalty rates as recommended by these proposed regulations.

COMMENT: The above royalty calculation of 5% has an arithmetic error:
\$.24/barrel divided by \$3.89/barrel =6.2% royalty not 5%, for 42 g/t
oil shale. What's the royalty rate for 10 gpt oil shale? If this is part
of the Option 1 basis then perhaps Option 1 should be 6%, not 5%. What
about inefficient processes which only produce 50% of Fischer Assay on
the oil. If they are charged royalty on the rock input to the process
then they pay one value, if the are charged a royalty on the raw shale
oil produced then they are charged a different value (one half in this
case compared to a 100% Fischer Assay process).

Is the proposed Option 1 rate of 5% based on the above 1973 calculated
rate with an arithmetic error, or is it derived immediately below, by
comparing production costs to royalty rates as recommended by these
proposed regulations. The below approach approximates 5% by using an
average value of (6.5+3.75)/2 = 5.125?

DR pg 42932-3: The BLM also estimated what royalty rates for shale oil
might be, based on comparisons of production costs for similar products.
The cost of removing oil from shale rock is currently estimated to be
two to three times higher than the current cost of producing
conventional crude oil from onshore operations. The current estimated
production cost for shale oil ranges from about \$37.75--\$65.21 a
barrel. The production cost for conventional onshore crude is
approximately \$19.50 a barrel.2 The table below compares the estimated
cost of shale oil production for different technologies with the
estimated cost of current onshore U.S. conventional oil production. The
table also estimates what royalty rates for oil shale production might
be, for the different production methods, compared to a 12.5 percent
royalty rate for conventional oil production, if the higher anticipated
production costs for oil shale are taken into account.

Technology Estimated shale Royalty calculation based on difference in
production Adjusted

oil production cost of a barrel of conventional oil versus shale oil
royalty for

costs per barrel shale oil

(percent)

Surface mining \...\...\...\...\...\...\...\...\... \$44.24
\$19.50/\$44.24 = 44.07% ⋅ 12.5% = 5.5 \...\...\...\...\....
\...\...\...\...\..... 5 .5

Underground mining \...\...\...\...\...\..... 54.00 \$19.50/\$54 =
36.11% ⋅ 12.5% = 4.51\...\...\...\...\...\...\...\...\...\...\.... 4 .5

Fracturing and heating in place \....65.21 \$19.50/\$65.21 = 29.90%
⋅ 12.5% = 3.75\...\...\...\...\...\...\...\...\...\...\... 3 .75

Heating only in place \...\...\...\...\...\.... 37.75 \$19.50/\$37.75 =
51.65% ⋅ 12.5% = 6.46% \...\...\... \...\...\...\...\...\.... 6 .5

Adjusting royalty rates based on higher anticipated production cost for
oil from oil shale is not a new concept and is similar to the situation
in the coal program where underground coal operations compete with
surface coal operations, which have lower production costs. Congress
addressed this disparity in production costs by allowing for different
royalty rates for coal mined underground versus coal mined at the
surface.

Please specifically comment on whether or not the anticipated costs of
producing oil shale should be considered in establishing the royalty
rate for all oil shale products and whether the BLM has chosen
appropriate reference points for this production cost comparison.

Therefore, one alternative that considers the decreased energy content
and increased production costs, while encouraging production and
ensuring an appropriate return to the government is to set a flat
royalty rate of 5%. This alternative assumes that oil shale will
continue to be more expensive to produce for many years when compared to
new conventional oil.

COMMENT: The above production cost based royalty approach assumes
royalties should be inversely proportional to production costs. It also
assumes an average onshore petroleum production cost of \$19.50 per
barrel. It assumes shale oil production costs of \$37.75-65.21/barrel.
The cost of the next marginal barrel of conventional onshore US
production is obviously going to be much more than \$19.50, or the
market would soon become flooded with US oil. This is further
complicated by a more important issue than production costs of
conventional petroleum world wide and that is "access" to the resource.
It is not stated whether the shale oil production costs are for raw
shale oil or downstream hydrotreated oil suitable for refinery
acceptance. At best the values are a WAG (Wild Ass Guess). To tie oil
shale production royalties---all production---to a royalty rate
developed on this basis is nothing short of ludicrous. Further, the rate
varies from 3. 75 to 6.5 with only the average being roughly 5%.
Furthermore it is stated above that this 5% considers the decreased
energy value and increased production cost of oil shale. Yet the 1973
rock based royalty is the only approach that arrived at 5% and it is in
fact in error and should be 6.2% as a result of an arithmetic error.

Bottom line is the 5% value is also a WAG based on arithmetic errors,
faulty production costs, and faulty reasoning. The 1973 rock based
royalty with a modifier for oil shale quality is really a kerogen based
royalty approach and is in fact a fundamentally more sound approach
provided corrections are made for production costs and product prices.

RDS is recommending an 8% rate at market prices above \$100/barrel. If
the main oil shale developer in this world is RDS and they are happy
with 8%, why is the BLM offering a rate that is 3% less than this---i.e.
5%?

Inversely proportioning royalty to production costs should result in a
variable rate depending on the production method and its related costs.
This creates one problem, under this scheme as production costs for oil
shale go down, royalty rates go up. This does not encourage the
development of more economic methods of production.

DR pg **42933 Option 2. A 5 Percent Royalty on Initial Production, With
12.5 Percent Thereafter**

This alternative would provide a reduced royalty rate of 5% as a
temporary incentive for early production of oil shale (similar to
royalty incentives offered to spur initial Outer Continental Shelf (OCS)
deepwater production), but with the standard 12.5% onshore oil and gas
royalty rate applying to all oil shale production after a set timeframe
and a set amount of production has taken place. Like the other royalty
options, this option would require oil shale lessees to pay royalties on
the amount or value of all products of oil shale that are sold from or
transported off of the lease. This section would explain that the
standard royalty rate for the products of oil shale is 12.5 percent of
the amount or value of production. However, under this option, for
leases that begin production of oil shale within 12 years of the
issuance of the first oil shale commercial lease, the royalty rate would
be 5 percent of the amount or value of production on the first 30
million barrels of oil equivalent produced.

COMMENT: The minerals management service (MMS) failed to include price
thresholds in 1998-99 OCS lease royalties. What good are leasing rules
if the MMS fails to incorporate them in the leases?

DR pg 42933 The advantage of this alternative over a flat 5% royalty
(Option 1) is that it provides a better return to taxpayers on later
production if oil prices remain high and oil shale production becomes
competitive with new conventional oil projects. At \$60/barrel, this
would amount to roughly \$1.8 billion in production allowed per lease at
the lower 5% royalty rate, providing roughly a \$135 million in savings
per lease compared to using the standard onshore oil and gas royalty
rate of 12.5%.

COMMENT: A better return to "taxpayers" occurs on later production
irrespective of oil prices remaining high---the illogical conclusion
does not follow. At \$60/barrel and 30 million barrels the amounts given
above are not "roughly" but "exactly". All US citizens are equal owners
of the US federal oil shale reserve---they are not necessarily all
taxpayers.

DR pg 42933 One potential downside to this alternative is that offering
royalty incentives without regard to oil prices increases the likelihood
that, if oil prices remain high, the government will sacrifice revenue
without affecting actual oil shale development. For example, at
\$120/barrel, the savings would be worth \$270 million, even though oil
shale operations would be more profitable than at oil prices of \$60/
barrel.

Therefore, we are also requesting comment on whether, if this proposal
were adopted in the final rule, the temporary 5% royalty on initial
production should also be conditioned on crude oil and natural gas
prices (similar to OCS deepwater royalty incentives) and if so, what oil
and gas price level would trigger payment at the higher 12.5% rate if
prices exceeded the threshold. We would also like comments on the 12
year timeframe for reduced royalty

COMMENT: The 5% and 12.5% royalty values of Option 2 have no rational
basis for their magnitude. The only rationale is a lower royalty for a
certain amount of early production to be used as an initial incentive.
Adding a price threshold trigger to create an earlier royalty increase
trigger ignores the need to also consider production costs and
production cost increases which generally increase as the price of
energy increases. Oil prices discussed throughout the subject FRN have
also been exceeded by wide margins in the world market during the last
year and although volatile, the trend will be relentlessly upwards.
Furthermore there is no distinction made between heavy high sulfur
petroleum and light sweet crude in terms of the "market price for oil",
nor between the cost and market price for raw shale oil, hydrotreated
shale oil, or finished gasoline, diesel, and jet fuel products. Also,
the concept of a maximum royalty plateau where royalties cease to
increase irrespective of the market price of products is without
foundation---even for conventional petroleum and natural gas---let alone
oil shale products.

DR pg 42933 **Option 3. Sliding Scale Royalty Based on the Market Price
of Oil**

Two comments suggested a sliding scale royalty format. One comment
specifically suggested a sliding scale royalty scheme based on a royalty
schedule that varies with the price of conventional crude, as follows:

At \$10 per barrel of conventional crude, the royalty rate should be
zero; At \$15 per barrel, royalty should be 0.25 percent and should
increase by 0.25 percent for every \$5 per barrel increase up to \$35
per barrel;

At \$40 per barrel, the royalty rate should be 2 percent and should
increase by 0.5 percent for every \$5 per barrel increase in the price
of conventional crude oil until the price of conventional crude reaches
\$100 per barrel; and

At \$100 per barrel, royalty rate should be 8 percent and should remain
at 8 percent at prices above \$100 per barrel.

COMMENT: The price of crude has risen to a high of \$147/barrel and is
temporarily at about \$100 today. The foreseeable royalty rate based on
this approach would be a flat 8%, with no increases if crude went to
\$200/barrel, or even higher. Plateau royalty rates above a certain
threshold or benchmark price will not produce a fair return to US
citizens. Its interesting to note that the proponent of the approach,
Royal Dutch Shell viewed by some as the most advanced oil shale
developer---or poster child---wants or is willing to settle for a
royalty as high as 8%, while the BLM has promoted Option 1 which is a 5%
flat rate---or 3% less. Whose side is BLM on---the US citizen, or RDS's.

DR pg 42933 Another comment suggested two approaches to calculating
royalty. The first part of the comment suggested that a simple way to
accomplish royalty rates would be to index the value of barrels of oil
equivalent to some percentage of NYMEX futures (say, 30 day average
front month) prices. The commenter suggested that the index should be
some fraction of the price, such as 50 to 65 percent. In the second part
of the comment, the commenter suggested that, as an alternative to
indexing, the BLM use a sliding royalty rate that is calculated on the
difference between product price and the highest cost production in the
industry. The commenter cautioned that ''there need to be provisions
that deferred portions of the royalty do not reduce mineral lease
payments to the States, if an escalating royalty rate is used.''

COMMENT: Royalty based on the net proceeds or difference between the
product price and the highest cost production in the industry provides
incentive to the lowest cost producer since the lowest cost producer's
net profit after royalty payments will be significantly higher than the
highest cost producer. What is not clear is when the net proceeds go up
does the royalty rate go up also on a sliding scale? As product prices
go up, the US citizen should share in a larger share of production, but
as a lessee reduces the costs of production he should be rewarded with a
larger share of production as an incentive to reduce costs. Although the
lessee has a direct primary incentive, for a fixed royalty rate, to
reduce costs and thereby increase net proceeds, he should obtain a
secondary incentive via royalty rate reduction on a sliding scale to
further reduce production costs. The structure of the royalty formula
should be such that when net proceeds increase, both the lessee's and
the US Citizen's, total net monetary return increases but the share
received by each should be adjusted such that production cost reductions
are encouraged. Under this formula an increase in net proceeds would
increase total net monetary return to both the lessee and the US
Citizen, but as only product price increases will the share increase for
the US Citizen, and as only production costs decrease the share will
increase for the lessee. When simultaneous increases or decreases occur
in both product prices and production costs with increases or decreases
in net proceeds the formula will adjust both the net monetary returns to
each party and also the share of production---i.e. royalty rate.

DR pg 42934: The BLM, in consultation with the MMS, evaluated these
variable royalty options, but decided that as presented, they would be
highly complex, and therefore, cumbersome to administer. With price
volatility in the crude oil market, an intricate sliding scale royalty
scheme could make enforcing compliance very difficult for the MMS. In
addition, there is uncertainty about the types of products that would be
derived from oil shale refining. Royalties based on oil shale quality
would also be difficult for the BLM to administer when attempting to
verify production quantities. For instance, if oil shale is extracted in
an under ground heating system, it would be extremely difficult for the
BLM to determine how much oil or other product came from a particular
volume or area of in-place oil shale.

COMMENT: A simple easy to administer royalty system for oil shale will
not promote oil shale development or return fair monetary value to the
US Citizen. If there is uncertainty about the types of products that
would be derived, then how can a product based royalty system even be
defined or rational rates in terms of magnitude be conceived? No mention
is made of commenters proposing royalty rates based on oil shale
quality---yet it is mentioned here. Sooner or later the BLM is going to
have to determine how much shale of what quality is in a given lease
area, and how much product and of what quality is produced and what
those products are to insure there is no unnecessary waste and that the
US citizen is maximizing his return from this national resource---no
matter how difficult it is to administer. The lessee is also going to
have to do the same thing. That is unless there is no accountability on
the part of the DOI/ BLM/MMS nor the lessee. In that case anything goes
and the 19980-9 OCS fiasco can be repeated in grand style.

The recent gifts, drugs, sex scandal within the MMS demonstrates that
the MMS has no trouble generating complex corrupt schemes requiring the
expenditure of 2 years and 5.3 \$ million by the DOI's Inspector
General's Office to investigate. However, when it comes to developing a
well based system for encouraging oil shale development simultaneous
with securing a fair return for the US Citizen their work as evidenced
by the subject rules is riddled with pleas for a simple non complex
approach that is easy to administer. The DOI/BLM seems to have forgotten
the old proverb of what happens when employees have things to simple and
have time on their hands---"and idle mind is the devils workshop".

DR pg 42934 While the BLM and MMS are concerned about the complexity of
administering some of the proposed sliding scale royalty proposals, we
recognize that there is some merit to the sliding scale concept, and in
a simpler form, a sliding scale royalty may prove useful in meeting the
dual goals of encouraging production and ensuring a fair return to
taxpayers from future oil shale development.

COMMENT: This search by the BLM for a simple royalty system is like the
search for the Holy Grail. It's miss guided and will not prove useful in
meeting the dual goals of encouraging oil shale development and
production and ensuring a fair return to US citizens from future oil
shale development.

DR pg 42934 One of the concerns that has been expressed regarding oil
shale development is that potential oil shale developers may be
reluctant to make the large upfront investments required for commercial
operations if they believe there is a chance that crude oil prices might
drop in the future below the point at which oil shale production would
be profitable (i.e., competitive with new conventional oil production).
A sliding scale royalty system could allow the government to at least
partially mitigate this development risk by providing for a lower
royalty rate if crude oil prices fall below a certain price threshold.
The basic concept is that in return for the government accepting a
greater share of the price risk that an operator faces when prices are
low (in the form of a lower royalty), the government would receive a
greater share of the rewards (through a higher royalty) when prices are
high.

The BLM has not decided on the specific parameters of a sliding scale
royalty system, but is considering a simplified, two- or three-tiered
system based on the current royalty rates already in effect for
conventional fuel minerals and with a 5 percent royalty rate (Option 1)
representing the first tier. The applicable royalty rate would be
determined based on market prices of competing products (e.g., crude oil
and natural gas) over a certain time period. If prices remain below a
certain point during the applicable period, the royalty rate on oil
shale products would be 5percent for that period. If prices are above
that range for the period, a higher royalty would be charged. In a three
tiered system, a third royalty rate would apply if prices rise above a
second price threshold during the applicable period.

COMMENT; what's the need for a discontinuous discrete tiered sliding
scale? What's wrong with a continuously changing royalty rate with no
upper bound or plateau? Although there will be short term volatility in
energy prices, the trend will be relentlessly upwards. Lessees and
DOI/BLM/MMS personnel betting on lower long term energy prices have
neither the interest nor the pocket books of the US Citizen or
stockholders in mind.

DR pg 42934 The BLM seeks comment on the specific parameters that could
be applied to a sliding scale royalty system, should the BLM choose to
adopt such a system in the final rule. More specifically, the BLM would
like feedback on the following questions:

1\. Should a sliding scale system include two or three tiers? Assuming a
5 percent royalty for the first tier, what would be appropriate royalty
rates for the second and/or third tiers?

2\. What are appropriate price thresholds to apply to each tier? Should
the thresholds be fixed (in real dollar terms), or should they float
relative to a published index?

3\. Should the sliding scale apply to all products, or should nonfuel
products pay a traditional flat rate?

4\. Are there other ways to simplify a sliding scale royalty to reduce
the administrative costs for BLM, MMS, and producers?

Under a sliding scale system, if prices fall below the lower range,
producers would have a ''safety net'' in the form of the lower 5%
royalty rate. Whether or not the lower royalty kicks in at some point,
simply having it in place provides some added certainty for investors
that would help encourage oil shale production. In return for this
''safety net'' that conventional oil and gas producers do not enjoy, oil
shale producers would be required to pay a higher royalty rate(s) when
crude oil and/or natural gas prices are high (and where oil shale is
expected to be substantially more profitable).

There are a couple of advantages of this alternative. It reduces the
risk for oil shale operators that oil prices might fall below the point
that continued oil shale production would be economic. However, it also
ensures an improved return to the government if prices remain within one
of the higher expected ranges at which oil shale may be profitable. One
disadvantage is that taxpayers accept a greater risk of lower returns if
prices fall and remain well below the lowest threshold. However, with
the lowest royalty rate step set at 5 percent, this risk is no greater
than under a flat 5 percent royalty system (Option #1).

COMMENT: The above argument is repetitive but is still all bunk. Oil
shale development is not going to hinge on whether the royalty rate is
5% or 12.5% or some simplistic sliding scale in between based on product
prices. If an oil shale project is going to operate in such a narrow
profitability range that the magnitude and range of royalty payments
proposed is going to determine survival or bankruptcy, then the normal
volatility in energy prices will ultimately result in bankruptcy. Has
the BLM considered the fact that commercial oil shale development may
never be successful for the simple reason the total cost of production
including capital recovery may always exceed the product price? This may
be the hard facts since as crude oil and other energy prices increase so
do all of the materials costs that directly impact capital costs, as
well as do operation costs. In that case a royalty rate of 0% and bonus
bids of zero will not get the job done. At that point if we want oil
shale development we are talking about tax payer subsidy---and subsidies
always end in disaster---sooner or later. If the oil shale industry
cannot operate without subsidies it should not be encouraged or allowed
in our capitalistic free market system.

DR pg 42934: **Other Royalty Issues**

DR pg 42935 Finally, it is important to note that the proposed rule
allows the Federal Government to readjust royalty rates on leases after
the first 20-year term. Currently, there is no oil shale industry and
the oil shale extractive technology is still in its rudimentary stages;
as such, commercial oil shale production does not exist anywhere in the
world. As research and development of oil shale technology progresses,
the BLM will have adequate time to reexamine and readjust royalty rates
for oil shale production, either up or down. Please specifically comment
on the time necessary to develop an oil shale industry.

COMMENT: Now's the time to get it right---not 20 years from now. The US
needs a kerogen based payment system (let's not call it bonus bids and
royalties) as described elsewhere which is based on production costs,
product prices, oil shale quality in terms of kerogen content, over
burden depth, and thickness. The payment to the US citizens from the
lessee needs to be adjustable to provide incentives for energy
efficiency of the process, energy self sufficiency, resource recovery
effectiveness and environmental impact---and for variations in net
proceeds (market price minus production costs.).

DR pg 42935 The BLM is proposing alternatives for the royalty rate and
the products on which the royalties will be collected. The BLM
anticipates selecting one of these alternatives, or based on public
comment and further analysis, variations on these alternatives in the
final rule in order to provide predictability for the industry and ease
of administration both for the United States and for payers. However,
the Department is not proposing corresponding MMS valuation regulations
at this time. Because the oil shale industry is still in the research
and development phase, it would be speculative to predict whether the
industry as it matures would predominantly sell from its leases mined
solid oil shale, shale oil, synthetic petroleum, shale gas, natural gas,
or products in several different forms or stages of processing. It is
also difficult to predict whether or when multi-buyer/multi-seller
markets would develop that would provide FMV pricing for products of oil
shale. Therefore, the MMS will promulgate royalty valuation regulations
before oil shale leases are required to begin paying production
royalties under this rule.

COMMENT: What are the products on which the royalties will be
collected---the BLM has never specifically stated what they are? Are the
products listed in sentence 4 of the above paragraph the products: i.e.
"predominantly sell from its leases mined solid oil shale, shale oil,
synthetic petroleum, shale gas, natural gas, or products in several
different forms or stages of processing." In this one paragraph the BLM
has essentially undone all of the royalty, point of determination, and
production and/or product arguments, rules, etc. of the subject FRN and
dumped it onto MMS to handle at some future date. Consistent with the
PEIS, the DOI/BLM is in contempt of congress and the requirements of the
EP Act in regard to commercial leasing rules in both content and
delivery schedule..

DR pg 42935 To the extent possible, the MMS will ensure that any oil
shale valuation regulation is consistent with other valuation
regulations and will incorporate principles of simplicity, early
certainty, and reduced administrative costs in the oil shale valuation
regulations it promulgates. For example, the MMS could promulgate
regulations similar to the current Federal oil valuation regulation to
value crude oil produced from oil shale. Under this regulation, the
value of oil sold at arm's-length would be based on gross proceeds less
allowable costs of transporting oil to the point of sale. The value of
oil not sold at arm's length would be based on a market index price or
the affiliate's arm's-length resale price. In both arm's-length and
non-arm's-length situations, the regulations provide for adjustments for
location, quality, and transportation allowances. Further, lessees also
can petition for alternate valuation agreements that are situation
specific when regulatory provisions do not apply.

COMMENT: What's the product again, what's the point of determination, is
their an adjustment for processing costs, etc., etc.? If the BLM has to
determine gross proceeds how much harder is to get the production costs?

DR pg 42935 Royalties would not be payable on potentially valuable
minerals or inorganic matter that are not sold or transported off the
lease for commercial purposes. Those materials would be considered
waste, and would be subject to management and reclamation requirements
as provided in the lease or in an approved plan of development. The
Department seeks comments on what future royalty valuation regulations
need to contain. In particular, the Department is seeking comments on
the potential types of oil shale products, the most equitable and
practical point and method to determine the value on which to apply the
royalty rate, and whether there are or should be opportunities to
determine value by market proxy or indices. The Department also seeks
comments on alternative approaches to valuation and royalty rates.

COMMENT: Again, what are the products, point of determination, etc, and
what about products utilized on site, what about char?

DR pg 42935: In the economic analysis for this rule, the BLM analyzed
the royalty implications of a range of royalty rates. Specifically, the
BLM conducted a simulation-based analysis to estimate the revenue,
profit, and royalty implication of a production scenario 3 using three
discount rates (7 percent, 3 percent, and 20 percent), three world crude
oil price projections (EIA's 2007 reference, high, and low price
projections 4), and six different royalty rates (1 percent, 3 percent, 5
percent, 7 percent, 9 percent, and 12.5 percent). The likelihood of a
company, in the face of numerous technological challenges, having the
incentive to develop Federal oil shale reserves and experiencing
economic success will depend on a number of factors. However, because
the simulated scenario analysis is based on a given production scenario
and set production costs, the analysis did not assist in determining the
project(s) economic viability due to the royalty rate applied. The
analysis did, however, clearly identify world oil price as a critical
variable determining a project's economic viability. Under EIA's 2007
low oil price projection all operations are assumed to be uneconomic
based on the set production costs used in the analysis of the rule.

COMMENT: Why couldn't this analysis determine, for the parameters
assumed, the financial break even or viability royalty rate? It was able
to determine for all the parameters assumed that the low oil price
projection would result in bankruptcy apparently for all royalty rates
assumed. Why were set production costs assumed---they will not be set
even for a new project, let alone one started several years later? This
analysis was essentially worthless if that's all it produced.

**Section 3903.53 Overriding royalties**

Section 3903.54--- **Waiver, suspension, or reduction of rental or
payments in lieu of production, or reduction of royalty, or waiver of
royalty in the first 5 years of the lease.**

**AR:** (a) In order **to encourage the maximum economic recovery
(MER)** of the leased mineral(s), and in the interest of conservation,
whenever the BLM determines it is necessary to promote development or
finds that leases cannot be successfully operated under the lease terms,
the BLM may waive, suspend, or reduce the rental or payment in lieu of
production, reduce the rate of royalty, or in the first 5 years of the
lease, waive the royalty.

DR pg 42935: Section 3903.54 would contain the requirements for filing
an application for waiver, suspension, or reduction of rental or payment
in lieu of production, or a reduction in royalty, or waiver of royalty
in the first 5 years of the lease. As with the BLM's other mineral
leasing programs, this section is intended to encourage the maximum
ultimate recovery of the mineral(s) under lease.

COMMENT: "Whenever" means the rate of royalty can be reduced at any
time---to zero, apparently. How is that different than "waiving" the
royalty? However, waiving can only occur in the first 5 years---which is
not "whenever". If there is no production occurring and none is required
before 10 years what's the need to do anything on the payment in lieu of
production? After that if the annual \$4/acre payment for non
production, or the royalties proposed in these rules, are going to
effect MER, or the viability of the project, it is so marginal that the
lease should be extinguished.

COMMENT: Maximum ultimate recovery of the kerogen means not only
pyrolyzing the maximum amount of kerogen on the lease, but achieving the
maximum amount of useful high quality products. This can only be done if
there are meaningful technological process requirements that must be met
to qualify for a commercial lease. These are discussed elsewhere in this
document, but boil down to energy efficiency, self sufficiency,
effective resource recovery, and requirements for Fischer and Tosco
Assay on oil and gas recovery.

Section **3903.60 Late payment or underpayment charges.**

Subpart 3904\-- **Bonds and Trust Funds**

Section 3904.10\--**Bonding requirements**

AR: (a) **Prior to issuing a lease** or exploration license, the **BLM
requires** exploration license or **lease bonds for each lease** or
exploration license **that covers all liabilities**, **other than
reclamation, that may arise under the lease** or license. The bond must
cover all record title owners, operating rights owners, operators, and
any person who conducts operations or is responsible for payments under
a lease or license. (b) **Before the BLM will approve a plan of**
**development, the lessee must provide to the proper BLM office a
reclamation bond to cover all costs the BLM estimates will be necessary
to cover reclamation.**

COMMENT: Explain what liabilities the lease bond covers. That it is
supposed to cover everything but reclamation is not an adequate
explanation. It implies that it covers the listed individuals relative
to their responsibilities to make the proper lease payments. Is this
correct? Why is a bond needed for that---if the lessee doesn't make the
proper lease payments, and on time, the lease is extinguished? Does this
insure the BLM against pass through liabilities/litigation that are
levied against the lessee?

Section 3904.11 When **to file bonds**.

AR: File the lease bond prior to lease issuance, file the reclamation
bond prior to the plan of development approval, and file the exploration
bond prior to exploration license issuance.

COMMENT: Is the lease bond filed after lease award or as part of the
application for a lease? Is the plan of development filed after lease
award and before filing the reclamation bond?

Section 3904.12

Section 2904.13---**Acceptable forms of bonds**.

AR: (a) The BLM will accept either a personal bond or a surety bond.
Personal bonds are pledges of any of the following: (1) Cash; (2)
Cashier's check; (3) Certified check; or (4) Negotiable U.S. Treasury
bonds equal in value to the bond amount. Treasury bonds must give the
Secretary authority to sell the securities in the case of failure to
comply with the conditions and obligations of the exploration license or
lease. (b) Surety bonds must be issued by qualified surety companies
approved by the Department of the Treasury. A list of qualified sureties
is available at any BLM state office.

COMMENT: Requirement (14) for the BLM's RDD program application required
a statement from a Surety of the amount for which the applicant
qualifies under the Surety's underwriting criteria. Federal regulations,
including the above section, allow either a personal bond or a surety
bond. There is no legal requirement for one or the other of the two
bonding options. Surety bonding is neither practical nor affordable for
entrepreneurs, whereas personal bonding is. My BLM RDD application was
rejected for only one reason---I supplied financial institution
statements of my net worth to provide a basis of my bondability amount
under personal bonding provisions, which was viewed as acceptable by
local BLM representatives---this was later rejected by the BLM's
interdisciplinary review team. Why isn't the BLM requiring the surety
statement for commercial leasing---or for that matter a statement of
financial capability?

No lease bond was required for the RDD program, just a reclamation bond.
Total inconsistency here between the BLM RDD program bonding and
financial capacity requirements and those of commercial leasing.

Section 3904.14\--**Individual lease, exploration** **license, and
reclamation bonds.**

AR: (a) The BLM will determine individual lease bond amounts on a
case-by-case basis. The minimum lease bond amount is \$25,000. (b) The
BLM will determine reclamation bond and exploration license bond amounts
on a case-by-case basis when it approves a plan of development or
exploration plan. The reclamation or exploration license bond must be
sufficient to cover the estimated cost of site reclamation.

COMMENT: How will the bond face value be estimated, for example for long
term clean up of underground water systems such as that integral to
RDS's ICP process?? The cost and time estimates to clean up
contamination of groundwater at the Hanford Nuclear Reservation on a 4
acre site at depths ranging from 180-400 feet is \$174 million over 125
years of cleanup operation. The major contaminant in this case is not
nuclear, but chemical contamination from carbon tetrachloride. This
amounts to about \$40 million per acre. This approaches a significant
fraction of the value of finished products per acre for the oil shale in
the thickest and richest portion of the Piceance basin.

Section 3904.15

Section 3904.20

Section 3904.40\--**Long-term water treatment trust** **funds.**

AR: (a) The BLM may require the operator or lessee to establish a trust
fund or other funding mechanism to ensure the continuation of long-term
treatment to achieve water quality standards and for other long-term,
post-mining maintenance requirements. The funding must be adequate to
provide for the construction, long-term operation, maintenance, or
replacement of any treatment facilities and infrastructure, for as long
as the treatment and facilities are needed after mine closure. The BLM
may identify the need for a trust fund or other funding mechanism during
plan review or later. (b) In determining whether a trust fund will be
required, the BLM will consider the following factors: (1) The
anticipated post-mining obligations (PMO) that are identified in the
environmental document or approved plan of development; (2) Whether
there is a reasonable degree of certainty that the treatment will be
required based on accepted scientific evidence or models; (3) The
determination that the financial responsibility for those obligations
rests with the operator; and (4) Whether it is feasible, practical, or
desirable to require separate or expanded reclamation bonds for those
anticipated long-term PMOs.

COMMENT: Spent shale that has not been de-charred and is left
underground will be certain to contaminate underground water aquifers
for centuries to come. The cost of cleaning it up, will, like the above
mentioned current Hanford Nuclear Site, be prohibitive in both cost and
time, and like Hanford will become a sacrificial zone---but not an
isolated one since it will forever leak and leach contaminants into the
groundwater which in turn will drain into the White, Green, and Colorado
river drainage systems. An eternal unsolvable mess to which no price tag
is large enough nor no bond, or trust fund, is big enough---it's simply
too late after it occurs such as the Hanford Nuclear Reservation where
both chemical and nuclear contamination will forever leak and leach into
the Columbia River drainage system. The only solution is to prevent it
from occurring in the first place by making it a matter of national
energy policy that oil shale technologies that do not de-char spent
shale are banned from operating in the USA---and those who also produce
more char than the Fischer Assay are doubly barred. Note the RDS ICP
process is one of these, reducing 40% of the kerogen to char, left
underground to contaminate forever. Where the cost of cleanup, if at all
even possible, would be more than the finished energy products secured
from the kerogen reserve.

Royal Dutch Shell proposed in their ANPR comments that the BLM use the
same bonding as for the BLM RDD leases which they state is sufficient to
cover the costs associated with restoration of the leased lands. Shell
opposes a more extensive bonding requirement that would cover
catastrophic events or extraordinary circumstances. Underground water
contamination by residual char is equivalent to a catastrophic
event---yet Shell never mentions it.

Subpart 3905

Section 3905.10

Part 3910---**Oil** **Shale Exploration Licenses**

Subpart 3910---**Exploration Licenses**

Section 3910.21

Section 3910.22

Section 3910.23

Section 3910.31\-- **Filing of an application for an exploration
license.**

AR: An exploration license application may cover no more than 25,000
acres in a reasonably compact area and entirely within one state. An
application for an exploration license covering more than 25,000 acres
must include justification for an exception to the normal acreage
limitation.

DR, pg 42937: Section 3910.31 would identify specific requirements for
filing an application for an exploration license. Mirroring the coal
regulations, this section would establish an acreage limit of 25,000
acres as the maximum size allowable for an exploration license.

COMMENT: What's the purpose of this? The maximum allowed lease acreage
is 50,000 acres/state and another 50,000 acres of acquired land per
state. The limits should be the same for an exploration license.

Section 3910.32

Section 3910.40

Section 3910.41

Section 3910.42

Section 3910.44

Section 3910.50

Part 3920

Subpart 3921 **Pre-Sale Activities**

COMMENT: Note that BLM RDD preference lease conversions are not subject
to this Section, 3921, nor 3922.40, and 3924 :

**Refer to** AR**, pg 42967: 3926.10 Conversion of an R, D and D lease
to a commercial lease.**

\(a\) Applications to convert R, D and D leases, including preference
right areas, into commercial leases, are subject to the regulations at
parts 3900 and 3910, this part, and part 3930, except for lease sale
procedures at subparts 3921 and 3924 and **§ 3922.40**.

Refer to AR, pg 42967: The conversion application must include: (3) A
bid payment no less than specified in § 3923.10 of this chapter and
equal to the FMV of the lease;

COMMENT: So: how is the FMV for the conversion of a BLM RDD lease
arrived at? The BLM has no recipe for the conversion, nor for the
commercial leases. There are no meaningful comparable sales, and the BLM
has no reliable production costs to determine meaningful net income
either.

Section 3921.10

Section 3921.20

**§ 3921.20 Compliance with the National Environmental Policy Act.**
Before the BLM will offer a tract for competitive lease sale under
subpart 3924 of this chapter, the BLM must prepare a NEPA analysis of
the proposed lease area under 40 CFR parts 1500 through 1508 either
separately or in conjunction with a land use planning action.

COMMENT: Who pays for the NEPA analysis---the nominators? Must there
always be nominators, or can the BLM offer tracts without their first
being nominated?

Section 3921.30

Section 3921.40

Section 3921.50

AR: **§ 3921.50 Determining the geographic area for receiving
applications to lease.** After analyzing expressions of leasing interest
received under § 3921.30 of this chapter and complying with the
procedures at § 3921.40 of this chapter, the BLM State Director may
determine a geographic area for receiving applications to lease. The BLM
may also include additional geographic areas available for lease in
addition to lands identified in expressions of interest to lease.

DR,pg 42938 Section 3921.50 would explain that after analyzing
expressions of leasing interest, the BLM would determine a geographic
area for receiving applications to lease. This section would also
explain that the BLM may add lands to those areas identified by the
public in the expressions of leasing interest

COMMENT: An applicant may apply for the minimum lease size of 160 acres,
but after delineation the size could and will be increased by the BLM
such that when the lease sale occurs the parcels offered will be way
beyond the bonus bid capacity of a small entrepreneur---particularly in
a competitive arena with big oil and wealthy speculators.

Section 3921.60

Subpart 3922

Section 3922.10\--**Application processing fee.**

AR: (a) An applicant nominating or applying for a tract for competitive
leasing must pay a cost recovery or processing fee that the BLM will
determine on a case-by-case basis as described in § 3000.11 of this
chapter and as modified by the following provisions.

\(b\) The cost recovery process for a competitive oil shale lease is as
follows:

\(1\) The applicant nominating the tract for competitive leasing must
pay the fee before the BLM will process the application and publish a
notice of competitive lease sale;

\(2\) The BLM will publish a sale notice no later than 30 days before
the proposed sale. The BLM will include in the sale notice a statement
of the total cost recovery fee paid to the BLM by the applicant, up to
30 calendar days before the sale;

\(3\) Before the lease is issued:

\(i\) The successful bidder, if someone other than the applicant, must
pay to the BLM the cost recovery amount specified in the sale notice,
including the cost of the NEPA analysis; and

\(ii\) The successful bidder must pay all processing costs the BLM
incurs after the date of the sale notice;

\(4\) If the successful bidder is someone other than the applicant, the
BLM will refund to the applicant the amount paid under paragraph (b)(1)
of this section;

\(5\) If there is no successful bidder, the applicant is responsible for
all processing fees; and

\(6\) If the successful bidder is someone other than the applicant,
within 30 calendar days after the lease sale, the successful bidder must
file an application in accordance with § 3922.20 of this chapter.

COMMENT: When is the NEPA analysis conducted, after the nomination, but
before the lease sale?? Who pays for the NEPA conducted after the
nomination but before the lease sale? It's implied that the nominator
does, otherwise why would 3(i) differentiate between the nominator and
the non nominator. If the nominator has not paid for the NEPA then 3(i)
says he will never have to pay. If there is no successful bidder, then
the applicant is responsible for all processing fees---in this case the
applicant is the nominator.

Section 3922.20---**Application contents**

AR: .A lease application must be filed by any party seeking to obtain a
lease. Lease applications must be filed in the proper BLM state office.
No specific form of application is required, but the application must
include information necessary to evaluate the impacts of issuing the
proposed lease or leases on the human environment. Except as otherwise
requested by the BLM, the application must include, but is not limited
to, the following:

\(a\) Name, address, and telephone number of applicant, and a
qualification statement, as required by subpart 3902 of part 3900 of
this chapter;

\(b\) A delineation of the proposed lease area or areas, the surface
ownership (if other than the United States) of those areas, a
description of the quality, thickness, and depth of the oil shale and of
any other resources the applicant proposes to extract, and environmental
data necessary to assess impacts from the proposed development; and

\(c\) A description of the proposed extraction method, including
personnel requirements, production levels, and transportation methods,
including:

\(1\) A description of the mining, retorting, or in situ mining or
processing technology that the operator would use and whether the
proposed development technology is substantially identical to a
technology or method currently in use to produce marketable commodities
from oil shale deposits;

\(2\) An estimate of the maximum surface area of the lease area that
will be disturbed or be undergoing reclamation at any one time;

\(3\) A description of the source and quantities of water to be used and
of the water treatment and disposal methods necessary to meet applicable
water quality standards;

\(6\) A description of how the proposed lease development would comply
with all applicable statutes and regulations governing management of
chemicals and disposal of solid waste. If the proposed lease development
would include disposal of wastes on the lease site, include a
description of measures to be used to prevent the contamination of soil
and of surface and ground water.

\(11\) A discussion of proposed measures to mitigate any adverse impacts
to the environment and to nearby communities;

\(12\) A brief description of the reclamation methods that will be used;

\(13\) Any other information that shows that the application meets the
requirements of this subpart or that the applicant believes would assist
the BLM in analyzing the impacts of the proposed development;

COMMENT: Given the lack of any meaningful process technology
qualification requirements for what is the above information
need---apparently for NEPA analysis and little else.

Section 3922.30

Section 3922.40

Subpart 3923

Section 3923.10\--**Minimum bid.**

AR: The BLM will not accept any bid that is less than the FMV. In no
case may the minimum bid be less than \$1,000 per acre.

DR,pg 42940 In the rule, the BLM is proposing to establish a minimum
acceptable bonus bid for Federal oil shale leases. The amount is not a
reflection of FMV, but is intended to establish a floor value to **limit
or dissuade nuisance bids**. The proposed rule requires a minimum
acceptable bonus bid of \$1,000 per acre. The assumption is that such an
amount will not exceed FMV or be a deterrent to companies interested in
bidding for the lease tracts. At the same time, the BLM has requested
further comments on the value proposed. As per comments on specific
values, the proposed rule does not attempt to establish actual FMV for
future Federal oil shale leases. Values received in the 1970's may not
be an accurate indicator for future values.

R48(in yellow color) RDS COMMENT: The minimum acceptable lease bonus bid
for an oil shale lease shall be \$1,0000 per acre.

COMMENT: How is the FMV to be established by BLM after the bids are
received for the commercial leases, and further more how is the FMV
going to be established for conversion of the BLM RDD leases?
\$1000/acre is very onerous for small entrepreneurs particularly when
combined with the minimum lease size of 160 acres. For development
purposes only 1-2 acres of mineral rights are needed and for no more
than 5 years maximum. This minimum bid value and minimum acreage
limitations combined with big oils ability to outbid small
entrepreneurs, and the likelihood that BLM will not put any 160 acre
tracts up for lease bid essentially seals the fate of small
entrepreneurs ever being able to access federal oil shale for
demonstration of commercial viability of their technology.

DR, pg 42949 The ability to obtain an exploration License and/or to
compete for a commercial oil shale lease is not affected by the size of
the company. Exploration licenses require a nominal filing fee (\$295
per filing) and have no minimum acreage. Leases have minimum tract
acreage of 160 acres; lease processing costs are paid by the successful
bidder; and bonus bids may be deferred over a 5-year period. These
aspects of the proposed licensing and leasing procedures allow small
entities to better compete for Federal oil shale licenses and leases
with larger, well capitalized companies. As required by the EP Act, all
royalties, rentals, bonus bids, and other payments proposed in this rule
are to encourage development of the oil shale resources while ensuring a
fair return to the government. The proposed regulatory provisions,
including filing fees, rentals, and production royalties, will not have
a significant economic impact on lessees or operators, regardless of the
firm's size. Therefore, the BLM has determined that under the RFA this
proposed rule would not have a significant economic impact on a
substantial number of small entities.

COMMENT: The above conclusions are blatantly false.!! With these rules
there is no way a small entrepreneur can complete with big oil and
wealthy speculators.

See Section 3024.1 for further comments.

**Subpart 3924---Lease Sale Procedures**

COMMENT: BLM RDD preference lease conversions are not subject to 3921,
3922.40, and 3924 :

**Refer to** AR**, pg 42967: 3926.10 Conversion of an R, D and D lease
to a commercial lease.**

\(a\) Applications to convert R, D and D leases, including preference
right areas, into commercial leases, are subject to the regulations at
parts 3900 and 3910, this part, and part 3930, except for lease sale
procedures at subparts 3921 and 3924 and **§ 3922.40**.

Refer to AR, pg 42967: The conversion application must include: (3) A
bid payment no less than specified in § 3923.10 of this chapter and
equal to the FMV of the lease;

COMMENT: So: how is the FMV for the conversion of a BLM RDD lease
arrived at?

AR: **3924.5 Notice of sale.** Section 3924.5 (b) The notice of the sale
will: (1) List the time and place of sale, the bidding method, and the
legal land descriptions of the tracts being offered; (2) Specify where a
detailed statement of lease terms, conditions, and stipulations may be
obtained; (3) Specify the royalty rate and the amount of the annual
rental; (4) Specify that, prior to lease issuance, the successful bidder
for a particular lease must pay the identified cost recovery amount,
including the bidder's proportionate share of the total cost of the NEPA
analysis and of publication of the notice;

COMMENT: NEPA, what is the bidders proportionate cost of the NEPA
analysis? This implies that the nominator does not have to pay the
pre-sale NEPA costs, even if he is the successful bidder. Compare this
to Section 3922.10

Section 3924.10\-- **Lease sale procedures and receipt of bids.**

AR: (d) After the sale, the BLM will convene a sale panel to determine:

\(1\) If the high bid was submitted in compliance with the terms of the
notice of sale and these regulations;

\(2\) If the high bid reflects the FMV of the tract; and

\(3\) Whether the high bidder is qualified to hold the lease.

\(e\) The BLM may reject any or all bids regardless of the amount
offered, and will not accept any bid that is less than the FMV. The BLM
will notify in writing the high bidder whose bid has been rejected and
include a statement of reasons for the rejection.

\(f\) The BLM may offer the lease to the next highest qualified bidder
if the successful bidder fails to execute the lease or for any reason is
disqualified from receiving the lease.

DR: pg, 42939-40: Section 3924.10 would detail competitive lease sale
procedures, including receipt and opening of sealed bids, submission of
the one-fifth of the amount of the bonus bid, requirements for future
submission of remaining installments of the bonus bid, and post sale
procedures for determining the successful bidder. This section would
also address the actions of the sale panel in determining whether or not
to accept the high bid, including a FMV determination. This section is
similar to the BLM's competitive leasing regulations for coal and
non-energy leasable minerals. The BLM is proposing to adopt this process
because it has been successful in these other mineral leasing programs
and because we believe this process is appropriate for oil shale
leasing.

The BLM will rely on the appraisal process to estimate the fair market
value (FMV) for commercial oil shale leases under the proposed
regulations. An appraisal is an unbiased estimate of the value of
property. The appraisal process is a systematic approach to property
valuation. It consists of defining data requirements, assembling the
best available data, and applying an appropriate appraisal method. The
principles of property valuation are presented in the Uniform Appraisal
Standards for Federal Land Acquisitions and in The Appraisal of Real
Estate. The term ''fair market value'' is defined in the Uniform
Appraisal Standards for Federal Land Acquisitions as the amount in cash,
or on terms reasonably equivalent to cash, for which in all probability
the property would be sold by a knowledgeable owner willing, but not
obligated, to sell to a knowledgeable purchaser who desired, but is not
obligated, to buy.

In ascertaining that figure, consideration should be given to all
matters that might be brought forward and substantial weight given in
bargaining by persons of ordinary prudence. Factors that will affect the
market value of an oil shale lease include the lease terms which
encompass rental and royalty obligations. The bonus bid for the lease
must be equal or greater than the lease FMV.

There are three methodologies generally used in appraising real
property: the comparable sales approach, income approach, and
replacement cost approach. Normally, the replacement cost approach is
not applied to appraisals involving property such as mineral leases.

In the comparable sales approach, the value of a property is estimated
from prior sales of comparable properties. The basis for estimation is
that the market would impute value to the subject property in the same
manner that it determines value of comparable competitive properties.
When reliable comparable sales data are available, it generally is
assumed that the comparable sales approach will provide the best
indication of value.

In the income approach, the value assigned to the property is derived
from the present worth of future net income benefits. If sufficiently
similar sales are not available, the FMV determination will generally
rely on the income approach.

The FMV determination follows a preexisting valuation standard, which
utilizes the circumstances of place, time, the existence of comparable
precedents, and the evaluation principles of each involved party. In
determining the FMV under this rule, our determination would be based on
comparison with identical or similar past, actual, or expected services
and goods relating to oil shale. It is the Section 102(a) of FLPMA (43
U.S.C. 1701(a)(9)) and Section 369(o)(2) of the EP Act, that the United
States receive FMV for the issuance of Federal mineral leases.

In the ANPR, the BLM solicited public input on the process for bid
adequacy evaluation and minimum acceptable lease bonus bid. The BLM's
purpose for requesting comments on the FMV it should receive for lease
tracts was to solicit ideas on how FMV would be determined for a
resource that has little or no history of comparable sales.

The public comments received were primarily concerned with the need to
receive an appropriate value for the lease. The BLM received comments
from 6 entities related to this question, specifically mentioning that:
a FMV determination needs to reflect private sector valuations;
competitive bidding should establish a lease's FMV; the process for
establishing FMV should be modeled after the Federal coal leasing
program; bonus payments are needed to stop speculation; and sealed
bidding ensures the most competitive bonus bid. The comments also posed
arguments for and against using a minimum acceptable bonus bid. In
addition, the BLM received comments that bonus bids should be high and
suggested that the 1974 bonus bid amounts pertaining to 4 oil shale
leases that were offered in Colorado and Utah, with bonus bids that
ranged from \$74 million to \$210 million, were indicative of expected
bonus bid amounts.

In response to the ANPR comments and other considerations, the BLM
proposes to establish oil shale lease FMV using a process similar to
that used in the Federal coal leasing program. This proposed process
relies on the appraisal process in an attempt to estimate the market
value for those leases. As such, the proposed process relies on many of
the procedures used in private sector valuations, and where available,
will rely on private sector transactions to establish the market value
for Federal oil shale leases. The Federal coal leasing program and this
proposed rule, utilize competitive bidding, specifically sealed bidding,
for determining who receives the lease.

In the rule, the BLM is proposing to establish a minimum acceptable
bonus bid for Federal oil shale leases. The amount is not a reflection
of FMV, but is intended to establish a floor value to limit or dissuade
nuisance bids. The proposed rule requires a minimum acceptable bonus bid
of \$1,000 per acre. The assumption is that such an amount will not
exceed FMV or be a deterrent to companies interested in bidding for the
lease tracts. At the same time, the BLM has requested further comments
on the value proposed. As per comments on specific values, the proposed
rule does not attempt to establish actual FMV for future Federal oil
shale leases. Values received in the 1970's may not be an accurate
indicator for future values.

COMMENT: The BLM's method for determining FMV is to use private sector
oil shale mineral right sales to establish FMV for Federal oil shale
leases. What will it use when they find there are non available---or
there are non similar in terms of oil shale quality, thickness, and
overburden depth? When the first approach fails, the above states the
BLM will use the net proceeds or net income method for which the BLM has
no meaningful production cost data. What about bonus bids for Utah State
Trust Lands? Will it use the net income approach when there are no
comparable sale data? Where will it get its total production cost
estimates and forward energy prices to determine the net income?

COMMENT: . The minimum acceptable bonus bid is \$1000/acre. Its intent
is to limit or dissuade nuisance bids. The BLM states this amount will
not exceed FMV or be a deterrent to companies interested in bidding for
the lease tracts. What's the difference between "companies", "nuisance
bidders" and small business, or individual entrepreneurs? When you
combine the 160 acre minimum tract size with a minimum bonus bid of
\$1000/acre, and further combine that with the "delineation" process
which is almost certain to increase a nominators applied for acreage
from 160 acres on upwards toward the maximum allowed of 9 sections, and
then add in big oil's ability to out bid the small guy---the BLMS's
assumption that the combined effect will not be a deterrent for small
companies or individual entrepreneurs interested in bidding on lease
tracts is totally wrong. From both the DOI/BLM's and big oils viewpoint
based on their comments, small business and individual entrepreneurs are
simply nuisances that need to be cleared from the oligopolies field of
illusory competition.

**Subpart 3925---Award of Lease**

Section 3925.10\--**Award of lease.**

AR: (a) The lease will be awarded to the highest qualified bidder whose
bid exceeds the minimum bid, except as provided in § 3924.10 of this
chapter

.(b) Within 60 calendar days after receipt of the lease forms, the
successful bidder must sign all copies and return them to the proper BLM
office. The successful bidder must also submit the necessary lease bond
(see subpart 3904 of this chapter), the first year's rental, any unpaid
cost recovery fees, including costs associated with the NEPA analysis,
and the bidder's proportionate share of the cost of publication of the
sale notice. The BLM may, upon written request, grant an extension of
time to submit the items under this paragraph.

\(e\) If the successful bidder was not an applicant under § 3922.20 of
this chapter, the successful bidder must submit an application and the
BLM may require additional NEPA analysis of the successful bidder's
proposed operations.

COMMENT: NEPA, the non nominator bid winner may have to do additional
NEPA. What (e) must say is that if the successful bidder was not the
original nominator then he must submit an application under 3922.20. The
nominator must already have been required to do this---although 3922.10
does not explicitly say a nominator must apply under 3922.20, it says an
applicant must. BLM must clear up this confusion between "nominators",
"original applicants" and "applicants". In addition it is not clear when
the nominator pays for the NEPA, and whether what, and if, he pays
depends on being the successful bidder when the lease sale occurs.

**Subpart 3926---Conversion of Preference Right for Research,
Demonstration, and Development (R, D and D) Leases**

Section 3926.10\--**Conversion of an R, D and D lease to a commercial
lease.**

AR**, pg 42967**: (a) Applications to convert R, D and D leases,
including preference right areas, into commercial leases, are subject to
the regulations at parts 3900 and 3910, this part, and part 3930, except
for lease sale procedures at subparts 3921 and 3924 and § 3922.40.

\(b\) A lessee of an R, D and D lease must apply for the conversion of
the R, D and D lease to a commercial lease no later than 90 calendar
days after the commencement of production in commercial quantities.

The conversion application must include:

\(1\) Documentation that there has been commercial quantities of oil
shale produced from the lease, including the narrative required by the
R, D and D leases;

\(2\) Documentation that the lessee consulted with state and local
officials to develop a plan for mitigating the socioeconomic impacts of
commercial development on communities and infrastructure;

\(3\) A bid payment no less than specified in § 3923.10 of this chapter
and equal to the FMV of the lease; and

\(4\) Bonding as required by § 3904.14 of this chapter.

\(c\) The lessee of an R, D and D lease has the exclusive right to
acquire any and all portions of the preference right area designated in
the R, D and D lease up to a total of 5,120 acres in the lease. The BLM
will approve the conversion application, in whole or in part, if it
determines that:

\(1\) There have been commercial quantities of shale oil produced from
the lease;

\(2\) The bid payment for the lease met or exceeded FMV;

\(3\) The lessee consulted with state and local officials to develop a
plan for mitigating the socioeconomic impacts of commercial development
on communities and infrastructure;

\(4\) The bond is consistent with § 3904.14 of this chapter; and

\(5\) Commercial scale operations can be conducted, subject to
mitigation measures to be specified in stipulations or regulations,
without unacceptable environmental consequences.

\(d\) The commercial lease must contain terms consistent with the
regulations in parts 3900 and 3910, this part, and part 3930 and
stipulations developed through appropriate NEPA analysis.

*DR: pg, 42940 ,Subpart 3926---Conversion of Preference Right for
Research, Demonstration, and Development Leases* Section 3926.10 would
provide application procedures or requirements to convert R, D and D
leases and preference rights acreages to commercial leases. Under this
section, a lessee of any of the R, D and D lease would be required to
apply for conversion to a commercial lease no later than 90 days after
the BLM determines that commencement of production in commercial
quantities had occurred. As stated in Section 23 of the R, D and D
leases (issued in response to the BLM's call for nominations of parcels
for R, D and D leasing (70 FR 33753 and 33754, June 9, 2005) R, D and D
lessees can acquire contiguous acreage of the remaining preference right
lease area up to a total of 5,120 acres. In order to acquire the
contiguous acreage and convert to a commercial lease, the lessee would
**be required to demonstrate to the BLM that the technology tested in
the original lease would have the ability to produce shale oil in
commercial quantities**. In addition, the lessee, as required in R, D
and D leases, would be required to submit to the BLM:

\(1\) Documentation that there have been commercial quantities of oil
shale produced from the lease, including the narrative required by
Section 23 of R, D and D leases;

\(2\) Documentation that the lessee consulted with state and local
officials to develop a plan for mitigating the socioeconomic impacts of
commercial development on communities and infrastructure;

\(3\) A bid payment no less than that specified in section 3923.10 and
equal to the FMV of the lease; and

\(4\) Bonding as required by section 3904.14.

COMMENT: Commercial quantities in the BLM RDD program FRN Section 1,
Definitions is defined as: (b) "Commercial Quantities" quantities
sufficient to provide a positive return after all costs of production
have been met, including the amortized costs of capital investment. And
in the RDD FRN Section 23 (a) Upon documenting to the satisfaction of
the authorized officer that it has produced commercial quantities of
shale oil from the lease, the Lessee has the exclusive right to convert
the research and development lease acreage to a commercial leas and
acquire any or all portions of the remaining preference lease area up to
a total of 5120 contiguous acres upon:

So this definition in the RDD FRN is somewhat different than in the
Commercial Rules FRN. The RDD FRN requires actual commercial production
and showing of a profit from that production. But this may be 10
barrels/day if you can show on paper that it's profitable. The
Commercial Rules FRN only requires that you produce enough shale oil
that you can show via extrapolation that an expanded operation would be
profitable.

*DR: pg, 42941:* The BLM would approve the conversion application, in
whole or in part, if it determined that:

\(1\) There have been commercial quantities produced from the lease;

\(2\) The bid payment for the lease met or exceeded FMV;

\(3\) The lessee consulted with state and local officials to develop a
plan for mitigating the socioeconomic impacts of commercial development
on communities and infrastructure;

\(4\) The bond provided is consistent with section 3904.14; and

\(5\) Commercial scale operations can be conducted, subject to
mitigation measures to be specified in stipulations or regulations,
without unacceptable environmental consequences.

COMMENT: To this discussion must be added direct extractions from the BM
RDD leasing program, **Federal Register** (70 FR/Number 110, starting on
pg 33753), regarding applicants qualification requirements of being in
possession of a innovative, new, and today's process technology and
having technological capacity.

[The purpose of the BLM RDD program]{.underline}: 

 

page. 33753 SUMMARY: The BLM solicits the nomination of parcels to be
leased for research, development and demonstration of oil shale recovery
technologies in Colorado, Utah, and Wyoming. 

 

pg. 33754 The BLM is soliciting for nomination parcels to be leased for
research, development and demonstration of oil shale recovery
technologies.

 

[Innovative technologies\--as in new\--as in old bankrupt Taciuk and
post world war II Petrosix?]{.underline}

[ ]{.underline}

pg. 33754 BLM believes this effort will significantly enhance the
collective knowledge regarding the viability of innovative technologies
for oil shale development on a commercial scale.

 

[Where\'s the \"rigorous\" technological and environmental
oversight\--given the technology of the processes selected by BLM RDD
and the environmental fiasco of the RDS ICP process?]{.underline}

 

The BLM intends to ensure that a commercial oil shale development
program demands rigorous technological and environmental oversight,
requires the best available practices to minimize impacts, and ensures
that states and local communities have the opportunity to be involved in
the development of a commercial program.

 

[Yesterday\'s technologies or \"today\'s\" technology.]{.underline}

 

pg. 33754 The BLM oil shale program design allows tracts of land up to
160 acres to be used to demonstrate the economic feasibility of today's
technologies over a period of ten years.

 

COMMENT: [Let's see, if we can just finally settle on what the
applicant\'s technology is before the 10 year lease expires, and also
demo commercial viability\--bang!!!\--they get the 8 section prize.  
What was the technology defined in the original lease?]{.underline}

 

pg. 33754 Applicants may also identify up to an additional contiguous
4960 acres which the applicant requests BLM to reserve for a preference
right lease to be awarded following: (1) The demonstration that the
applicant's technology tested in the original lease of up to 160 acres
has the ability to produce shale oil in commercial quantities;

 

COMMENT: [The selection was a farce\--none of the selected technologies
(outside maybe Chevron\'s who has also jumped off to something different
than the application/EA) meets any of the below criteria]{.underline}.

 

pg. 33754 The review will consider the potential of proposals to advance
knowledge of effective technology, economic viability and the means of
managing the environmental effects of oil shale development. BLM also
would conduct NEPA analysis of the environmental effects of a proposal
prior to the award of a research, development and demonstration lease.

 

COMMENT: [Let's look at the actual applications, EA\'s, and plans of
development.  I\'ve never seen the applications but I have reviewed the
Colorado EA\'s and plans of development, and the Utah EA\--but OSEC has
never delivered a plan of development.]{.underline}

 

pg. 33755 (5) A narrative description of the proposed methodology for
recovering oil from oil shale, including a description of all equipment
and facilities needed to support the proposed technology.

 

COMMENT: [Did OSEC possess the Taciuk technology, did they have the
experience to advance any technology?  Well yes, sure, they advanced the
Taciuk technology so far it was shoved clear up into the clouds
and right out of the picture.  Maybe they had a license to use the
Taciuk technology when they made the application\--but what experience
did they have other than a few consultants who were basically
geologists/consultants not oil shale pyrolysis experts.   And what about
possessing Petrosix \--at the time of the application???]{.underline}

 

pg. 33758 Therefore, to address the issues raised in comments, the
criteria for lessee qualification will be based on possession of
technology and the experience to advance such technology, while
protecting the environment (land, air, water, cultural, biological,
visual, and other resources) and utilizing best management practices to
minimize impacts during the life of the project.

 

COMMENT:Yes, we have to look at the documentation.

 

pg. 33758 Supporting documentation for applicant qualification should
include but is not limited to the description of the technology to be
used including the results of laboratory and/or field tests, a plan of
operations, proof of investment capacity, and partnership(s).

 

COMMENT: That word \"new\" keeps cropping up here.

 

pg. 33758 One of the principal reasons to offer small research and
development leases before issuing commercial leases for oil shale is to
obtain a better understanding of the environmental effects of the new
technologies and the effectiveness of various mitigation measures.

COMMENT:  [Speculation, who said that nasty word?  EGL sells 80% before
they\'ve made a drop of oil, and OSEC sells off 40% after they make a
few barrels of oil in Canada with Taciuk and jettison the Taciuk for
Petrosix.  And as for the making of a mess, well Royal Dutch Shell has a
well known legacy of leaving messes\--i.e. Africa as of late.
 ]{.underline}

pg. 33758 Criteria To Qualify a Company or an Individual To Acquire an
R&D Lease. Some comments asked that the R&D leasing program not be used
as a license for (land) speculation. One comment urged that the intent
of the R&D program be made very clear by moving the last sentence on
page A-- 2 of the Federal Register Notice to the top of the page. The
sentence reads as follows: ''The intent of the leases is to further the
development of technologies for the economic production of oil shale.''
Several comments suggested that a potential lessee should demonstrate or
possess technological experience, research capability, financial
strength, and the ability to satisfy bonding requirements. Some
suggested that among the above requirements, that BLM should not issue
leases to companies or individuals that cannot clean up their mess or
that have a history of regulatory non-compliance. A few comments
suggested that only applicants with environmentally friendly projects be
considered.

 

COMMENT: And from ExxonMobil\'s comments on the ANPR:

 

R48(in yellow color) It is recognized that Interior has indicated to
limited parties that a preferential right to obtain a lease will be part
of a commercial leasing program. Others who were excluded from the
opportunity to obtain such a preferential right as well as those who
elected not to participate in the program should be given the
opportunity to obtain oil shale leases in and equitable process that
does not provide an undue advantage to those who are issued a RDD lease.
Thus preferential rights should not be obtained on the 2005 RDD
nominated acreage unless the prospective lessee uses the technology that
was proposed, tested and commercialize on the associated RDD tract.
Technologies developed and demonstrated to be commercial on another RDD
tract or not identified in the application for the applicable RDD tract
should not be used to gain a preferential right.

 

COMMENT: Sounds like my old employer done had a premonition about some
folks applying with one technology, then using the old  sea shell game
of bait and switch, to come up with another technology, then another and
another.   Well, big oil Exxon seems to want to put an end to those kind
of shenanigans.

COMMENT: If technology different from the technology tested in the
original lease is used then no conversion is possible. If technology is
demonstrated on the BLM RDD lease that was not proposed in the BLM RDD
application then no conversion is possible, and furthermore, that
technology not proposed shouldn't have been allowed to be demonstrated
on the BLM RDD lease either. From above: "In order to acquire the
contiguous acreage and convert to a commercial lease, the lessee would
be required to demonstrate to the BLM **that the technology tested in
the original lease** would have the ability to produce shale oil in
commercial quantities."

COMMENT: How is FMV determined? The same way as for a commercial lease.
BLM does not have a means for doing this.

Subpart 3927\-- **Lease Terms**

Section 3927.10

Section 3927.20\-- **Lease size.**

AR: The maximum size of an oil shale lease is 5,760 acres and the
minimum size of an oil shale lease is 160 acres.

*DR: pg, 42928:* **Small Tract Leasing**---In the ANPR the BLM requested
comments on whether there should be small tract leasing or leasing small
acreages of land for oil shale development. A discussion of the public
comments we received on small tract leasing can be found in section
3927.20 of this proposed rule.

*DR: pg, 42941:* Although the EP Act does not establish a minimum lease
size, in keeping with the size restrictions of the oil shale R, D and D
leases, section 3927.20 would also establish 160 acres as the minimum
size of an oil shale lease. The BLM received several comments relating
to whether the BLM's commercial oil shale leasing regulations should
include provisions for small tract leasing, all of which generally were
in favor of making small lease tracts available. One comment suggested
that smaller tracts would be particularly appropriate in the early years
of the commercial leasing program in light of new technologies, and it
recommended a minimum tract size of 1,280 acres. Recommendations
relating to a minimum tract size stated in other comments ranged from
over 320 acres to one square mile. Two comments suggested that there
should be restrictions for small tract leasing. Of those comments, one
commenter stated that small tract leasing should not be a mechanism to
thwart potential development. Another commenter recommended that small
tracts should only be allowed in cases where ''the tracts have been
orphaned, in between larger leases, basin edge or other fee owned
lands.'' Although section 3927.20 would not formally establish small
tract leasing, the 160-acre minimum lease size set by this section would
provide a lessee the opportunity to develop relatively small-scale
leasehold, identical to the lease size authorized under the BLM's oil
shale R, D and D program. Thus, rather than the BLM incorporating small
tract leasing as a separate component of the commercial oil shale
leasing program, establishing a minimum lease size of 160 acres provides
an opportunity for a lessee to utilize a preferred technology on a
relatively small tract that is consistent with the size of existing R, D
and D leases. For this reason, the BLM did not adopt ANPR comments that
recommended a larger minimum lease size. With respect to the comment
expressing concern that small tract leasing could thwart potential
development and the comment recommending that small tract leasing should
be allowed only in limited situations as stated above, it is the policy
of the BLM, when delineating tracts to be offered through competitive
lease sale, to make efforts to ensure that the configuration of any
small acreage tracts would likely promote development of oil shale. The
BLM believes that configuration of tracts in this manner would not
impede development on any existing oil shale leases located in the
vicinity of smaller tracts. As is the case in other BLM mineral leasing
programs, the tract delineation process for a competitive lease sale
includes the gathering of detailed information on tracts and conducting
various analyses. Because the steps customarily included in the tract
delineation process are designed to promote or encourage development of
mineral resources, the BLM maintains that establishing a minimum lease
size of 160 acres will not thwart potential development of oil shale
resources. Likewise, the competitive leasing process and the required
minimum bonus bids would discourage speculation.

One comment endorsing small tract leasing also recommended that a small
tract lease should include a preference right for additional adjoining
acreage. The BLM is not adopting this recommendation since it maintains
that the concept of a preference right for the future leasing of
additional acreage---a key component of the R, D and D leasing
program---is not a necessary provision in a commercial leasing program
in light of lease modification provisions under proposed subpart 3932.
In the event that a lessee of a small tract has interest in obtaining
additional acreage adjacent to its lease, under the proposed rule the
lessee could apply for a lease modification to include Federal lands
adjacent to the lease, but not to exceed the maximum lease size (see
section 3932.10).

DR pg 42934: The BLM received three ANPR comments relating to the oil
shale research, development, and demonstration (R, D and D) program. One
comment encouraged the BLM to ''continue the existing BLM R, D and D
leasing program for access to oil shale for companies wishing to test
unproven technologies.'' Another comment suggested that the BLM ''should
let several 'boutique' small companies with large R, D and D budgets to
develop a small number of sites,'' on the condition that those companies
''would have to agree to allow their findings to be shared.'' The last
comment specifically requested that the ''commercial leasing regulations
make clear that the BLM will not hold a commercial lease sale for
Federal oil shale resources until successful technologies have been
developed and demonstrated on R, D and D leases.'' These proposed
regulations do not address the first comment. The Secretary has
discretion under the EP Act to offer additional tracts for R, D and D
leasing. These regulations do not decide whether additional R, D and D
leasing is necessary. Although the BLM could require that proprietary
information be made public as a condition of further R, D and D leasing,
we believe that the industry would not be interested in leasing under
such conditions.

DR pg 42935: Furthermore, as previously explained, these regulations do
not address any new R, D and D leases. The BLM could not incorporate the
third comment, because it suggested a limitation that is inconsistent
with the terms of the EP Act. Sections 369(c) and 369(e) of the EP Act
authorize the commercial leasing of oil shale following promulgation of
regulations and consultation with interested parties without the
limitations sought by the comment.

DR, pg 42949 The ability to obtain an exploration License and/or to
compete for a commercial oil shale lease is not affected by the size of
the company. Exploration licenses require a nominal filing fee (\$295
per filing) and have no minimum acreage. Leases have minimum tract
acreage of 160 acres; lease processing costs are paid by the successful
bidder; and bonus bids may be deferred over a 5-year period. These
aspects of the proposed licensing and leasing procedures allow small
entities to better compete for Federal oil shale licenses and leases
with larger, well capitalized companies. As required by the EP Act, all
royalties, rentals, bonus bids, and other payments proposed in this rule
are to encourage development of the oil shale resources while ensuring a
fair return to the government. The proposed regulatory provisions,
including filing fees, rentals, and production royalties, will not have
a significant economic impact on lessees or operators, regardless of the
firm's size. Therefore, the BLM has determined that under the RFA this
proposed rule would not have a significant economic impact on a
substantial number of small entities.

COMMENT: With these rules there is no way a small entrepreneur can
complete with big oil. The above ignores the up front processing fees
that a nominator has to pay as part of the application process, and then
comes the NEPA costs.  \$1000/acre is very onerous for small
entrepreneurs particularly when combined with the minimum lease size of
160 acres. For development purposes only 1-2 acres of mineral rights are
needed and for no more than 5 years maximum. This minimum bid value and
minimum acreage limitations combined with big oils ability to outbid
small entrepreneurs, and the likelihood that BLM will not put any 160
acre tracts up for lease bid essentially seals the fate of small
entrepreneurs ever being able to access federal oil shale for
demonstration of commercial viability of their technology. Statements
made about the effect of these proposed rules on small entities (small
business and entrepreneurs) being able to compete are just blatantly
false.

See Section 3024.1 for further comments.

COMMENT: The defacto position of the BLM is that no additional BLM RDD
leases will be let. A small oil shale developer will not be able to
bonus bid compete with big oil and wealthy speculators to obtain even
the minimum size lease of 160 acres---particularly after "delineation"
when the lease size will increase up to the maximum of 9 sections.

COMMENT: The position taken by the BLM that small tract lease coupling
to a preference lease is not necessary since additional acreage can be
obtained by the small tract lessee through lease modification via
Section 3932.10 is not credible. Additional acreage through lease
modification can only be obtained if there are no competitors interested
in the adjoining tract.

The reader is referred to the following Section 3932.20:

> AR: **§ 3932.20 Lease modification land availability criteria.** (a)
> The BLM may grant a lease modification if: (1) There is no competitive
> interest in the lands covered by the modification application; (2) The
> lands covered by the modification application cannot be reasonably
> developed as part of another independent federally-approved operation;
>
> COMMENT: The argument made that lease modification of small tracts is
> the equivalent of a preference lease are simply false. There is no
> requirement for "no competitive interest" in the BLM RDD preference
> leases.

COMMENT: EP Act not required for authorization as stated
above---otherwise the BLM RDD would have been not authorized under the
then current legislation.

COMMENT: The minimum acceptable bonus bid is \$1000/acre. Its intent is
to limit or dissuade nuisance bids. The BLM states this amount will not
exceed FMV or be a deterrent to companies interested in bidding for the
lease tracts. What's the difference between "companies", "nuisance
bidders" and small business, or individual entrepreneurs? When you
combine the 160 acre minimum tract size with a minimum bonus bid of
\$1000/acre, and further combine that with the "delineation" process
which is almost certain to increase a nominators applied for acreage
from 160 acres on upwards toward the maximum allowed of 9 sections, and
then add in big oil's ability to out bid the small guy---the BLMS's
assumption that the combined effect will not be a deterrent for small
companies or individual entrepreneurs interested in bidding on lease
tracts is totally wrong.

COMMENT: **[SMALL RDD TRACTS: RDD Program Lessee Pyrolysis Target Zone
Plan Area Verses 160 acre Tract Plan Area;.]{.underline}**

Small RDD mineral right lease tracts in most cases need be no larger
than 1-2 acres---maximum as validated by the actual target oil shale
extraction zones that will be pyrolyzed/processed in the BLM RDD program
as discussed further below. If larger surface areas are needed for
infrastructure, process equipment that can be handled with a surface
lease---severed from the minerals rights below. Even RDS's ICP ice
freeze wall could be handled under a surface lease, since the surface
interest is more than the right to the surface of the land, it is all
underground rights that are not included in the mineral interest.

The discussion above really deals with how much land and/or oil shale
does an oil shale developer need to make the jump from where he is, to
where he\'s trying to get\--a commercial operation.   And what has the
DOI/BLM offered up for RDD and what are they offering up for commercial,
and what have you got to do to access it?   The first answer is\--not
much oil shale.  The second answer is\--DOI/BLM is making it incredibly
difficult for small guys like me\--and for that matter even large guys
like Exxon, and they are giving away huge dollar values to entities that
in no way shape or form deserve any of it.

For the last 25 years you couldn\'t get a single rock from the BLM for
RDD purposes.   On November 22, 2004 in an obscure Federal Register
Notice they asked for comments the adequacy of a 40 acre lease for
successful demonstration of oil shale technology.  On June 9, 2005 they
offered up to 160 acres with a preference lease totaling 5120 acres (the
Minerals Leasing Act Limit at that time for the entire USA for one
entity).   As a result of comments received due to the November 22, 2005
notice recommending 40-1280 acres, the BLM \"determined\" that the RDD
lease acreage should be increased from 40 to 160 acres and they stated
that this was large enough to accommodate any RDD activity that can be
envisioned including construction of ancillary surface facilities.   On
August 8, 2005 Bush signed the Energy Policy Act which increased the
maximum leased acreage from 5120 acres total per US per entity to 50,000
acres per state per entity.   There was no announcement by the BLM that
the EP Act had retroactively changed the rules for the BLM RDD program,
however, and leaves unexplained Royal Dutch Shells 2 applications the
day of the BLM RDD program announcement and their award of 3 separate
leases.   The Proposed Rule for Commercial leasing now sets the minimum
lease size at 160 acres, and the Minerals Leasing Act now sets the
maximum single lease size to 5760 acres. 

What is the size of the areas to be pyrolyzed by the 3 Colorado in-situ
BLM RDD lessees? Answer:

RDS\--1/3-1/2 acre target zones, one each for the 3 separate
leases.   EGL\--approximately 2 acres.  CVX\--less than .1 acres.   What
is the maximum plan area to be mined by OSEC in Utah\--approximately 16
acres and this is for essentially a commercial operation equivalent to
the Aussie plant and for a period of 2 years.  For each of these the
thickness of the target zone of oil shale is quite different.

If so little oil shale is actually proposed to be used, why then was 160
acres needed?   The in-situ guys will immediately respond with\--we need
it for above ground infrastructure, etc..  Above ground infrastructure
and processing equipment can be totally handled with a surface use
lease\--the BLM didn\'t need to give the Colorado in-situ guys  more
than a couple of acres of minerals lease\--period.   Even RDS\'s freeze
wall requires no minerals lease rights.   Further, even OSEC\'s mining
of about 16 plan view acres does not need 160 acres of mineral
rights\--that would have taken them 20 years to mine out and their lease
is only for 10 years.   Of the 160 acre tract I applied for\--well, the
stock pile already mined at the White Mine would have easily got me to
the commercial scale demonstration.  If that weren\'t going to be
available I asked for a tract known as the Greek Corrals a few miles
away which had an outcrop where I would have opened up a 5 acre mine,
the maximum size allowed under Utah State mining regulations for a
\"small mine\".     Bottom line\--the 160 acres was an oil shale land
grab worth about a \$75 billion just for the 3 RDS RDD
tracts\--and about 2.4 \$trillion if you include their preference
leases.

 

Who then put out the 40 acre tract size feeler?  Who wanted 40-1280
acres?  Who and why did the BLM settle on 160 acres for the RDD
program?   Who pushed for the maximum single lease size of 5760 acres
now part of the new Minerals Leasing Act?   Who pushed for the 50,000
acres total per state now also part of the MLA?   Who\'s pushing for the
160 minimum lease size in the Commercial Rules?   Who\'s pushing for the
other acreage qualifications in the Commercial Rules?   Of the 48
comments the BLM received on the Commercial Rules ANPR  who pushed for
what? The 48 comments are quite interesting, I\'ve reviewed them all.  
Of the 32 comments received on the November 22, 2004 BLM notice (40
acres proposed for RDD) who pushed for what in their comments on the
proposed commercial rules\--comments due September 22, 2008?

Much smaller mineral leases with appropriate above ground surface leases
could have, and should have, been offered by the BLM for RDD.   No
preference leases should have been offered.   No commercial leases
should be made to any entity who does not possess demonstrated
technology at commercial scale\--and demonstrated to be energy
efficient, energy self sufficient, resource recovery efficient, and
environmental impact minimized.

The proposed rules fall short when it comes to putting together oil
shale leasing programs that will result in sound technology development
and maximum return to the citizens of the US from this incredibly
valuable resource. The essentially exclude small entities with superior
technology from access to either more BLM RDD leases, or small
commercial leases.

COMMENT: **[PACE AND SIZE OF COMMERCIAL LEASING]{.underline}**

How much oil shale should the DOI/BLM put up for lease over time for
commercial operations?   The answer is\--they already have leased enough
to provide 1/4 of the total national liquid fuel and chemical feedstock
needs (petroleum + condensate) for the next 24 years of production
starting right now.   They have leased out 6x160 acres of RDD land which
contains roughly 1.5 billion barrels Fischer assay oil plus a
significant quantity of gas.   They have preference leases obligated for
a total of 6x8 = 48 sections, or about 48 billion barrels of shale oil. 
US consumption of liquids is running at about 20-22 million barrels per
day, or roughly 8 billion barrels/year.  1/4th of 8 billion barrels per
year is 2 billion barrels/year.   Therefore at this rate we have about
24 years of production all ready given away to two big oil organizations
and two small organizations who by their recent sale offs actions appear
to be more speculators than oil shale developers.   Note the RDD leases
are only for 10 years, and proposed commercial lease period is for 20
years.   So without extensions, there are all kinds of complications if
more land is put up for lease.   Such as, if more is leased and more oil
is produced than is needed, the price collapses, etc., etc. and so on.

 

So what\'s the big rush to put commercial leasing rules in place?

 

What\'s the big rush given the Reagan, Bush Sr., Clinton, Bush/Cheney
did absolutely nothing on the development of oil shale for 25 years,
then all of the sudden we start the ball rolling with obscure notices in
the Federal Register November 22, 2004, BLM RDD June 9, 2005 with a 3
month application window, etc., etc..?

 

The BLM/DOI should have started with leases or some other
legal/regulatory instrument to make surface land available for
infrastructure, process equipment, whatever on a surface right
basis\--coupled with very small mineral right leases of the order of 1-2
acres (or sale of pre-mined shale in the case of the White Mine
stockpile) on an as needed basis\--but based on the requirement that the
applicant has a process of merit worth testing.  That oil shale process
must be energy efficient, energy self sufficient, resource recovery
effective, and minimum environmental impact.   This must be validated by
actual tests and/or mathematical engineering analysis to support the
claim.   In no case should the amount of oil shale, or mineral right
lease exceed the quantity of shale proposed for the target in-situ
process zone, or mining zone to be removed and processed above ground
for both RDD purposes, semi-scale commercial, and initial commercial
operations. 

 

Under full blown commercial operations how much oil shale should be
leased each year for a reasonable commercial production rate.    Well
that depends on the thickness and quality of the shale, and the desired
production rate, and the total real cost of production.   It also
depends on national strategic needs, world oil prices, etc.   For
starters consider a production rate of 2 billion barrels per year, or
1/4 of US production.   For the best stuff in the Piceance basis that
translates to about 2 sections of land per year.   Three more lease
sales equivalent to the BLM RDD program preference leases, plus the
current preference leases, (a total of 192 sections, or would carry the
US to 2108.   That\'s roughly a square 14 miles on each side.

 

This little bit of reasoning exposes the fact that the DOI/BLM has not
thought out a rational program for meaningful long term development.  
Its simply been a knee jerk reaction motivated by Royal Dutch Shell and
a few others with political connections to a few key Republican
politicians, and likely also some key Democrats.  It got initiated that
way, and now other folks including snake oil salesmen have joined the
fray.   The way the thing is currently rolling big oil will nominate
land they want, it will go up for bid, and big oil and big speculators
will make sure they put out the largest bonus bids and they will tie it
all up.    There is nothing to stop this from happening in the next few
years\--there will be no paced leasing based on US liquids needs,
impacts on the world oil market, strategic interests of the US,
effective resource recovery, and energy efficiency and self
sufficiency.  Development of advanced effective oil shale technology
will not be encouraged---since none is required. There isn\'t a single
requirement in the commercial rules that even requires a bidder to have
any technology whatsoever to obtain a lease.  Let alone a technology
that is energy efficient, energy self sufficient, resource recovery
effective, or environmentally characterized my minimum impact. 

  

All things considered, unless the Chevron in situ EA described process,
modified appropriately to produce Black Box Pyrolysis Process II
performance, can be actually demonstrated as a workable in-situ process,
the only way to obtain maximum resource recovery is one big strip mine
for the Piceance Basin with the above ground Black Box Pyrolysis Process
I required for maximum energy efficiency, and energy self
sufficiency.    The same would be true for the Uintah and Wyoming
basins.  Environmental mitigation would require massive reclamation
combined with massive water storage projects to leave the target zone
more useful and environmentally acceptable than it currently is.   This
would have to be done on the basis of a National Oil Trust with the work
conducted on the basis of contracts to private industry\--but the
federal government would control the operation much like the TVA or the
BPA\--sound like socialism.    As I recall Exxon had such great
delusions of grandeur with strip mines, but probably no meaningful
cleanup afterwards.   They were going to get water from the Missouri
River however.  The reader is challenged to come up with a better
scheme\--because the current one the DOI/BLM has underway is worse than
Tea Pot Dome.

AR Section 3927.30\--**Lease duration.**

AR: Leases issue for a period of 20 years and continue as long as there
is annual minimum production or as long as there are payments in lieu of
production

COMMENT: The lease could therefore go on forever after 20 years until
the minimum production stops, the lease runs out of resource, or the
payments in lieu of production are not made. Even with no production
throughout the first 20 years the penalties for lack of due diligence a
very small compared to the value of the resource being held from
production. See also Section 3930.40.

Section 3927.40

Section 3927.50\--**Diligent development.**

AR:Oil shale lessees must meet:

\(a\) Diligent development milestones;

\(b\) Annual minimum production requirements or payments in lieu of
production starting the 10th lease year, except when the BLM determines
that operations under the lease are interrupted by strikes, the
elements, or causes not attributable to the lessee. Market conditions
are not considered a valid reason to waive or suspend the requirements
for annual minimum production. The BLM will determine the annual
production requirements based on the extraction technology to be used
and on the BLM's estimate of the recoverable resources on the lease,
expected life of the operation, and other factors.

COMMENT: Nothing on process energy efficiency, self sufficiency,
effective resource recovery. Market conditions can result in suspension
of minimum annual production and all that a lessee has to do in any
event is pay the in lieu of production fee. See Section 3930.30 for
Diligent Development Milestones that must be met.

Subpart 3930---**Management of Oil Shale Exploration Licenses and
Leases**

Section 3930.10\--**General performance standards.**

AR: The operator/lessee must comply with the following performance
standards concerning exploration, development, and production:

\(a\) All operations must be conducted to achieve Maximum Economic
Recovery;

\(b\) Operations must be conducted under an approved plan of development
or exploration plan;

\(c\) The operator/lessee must diligently develop the lease and must
comply with the diligence development milestones and production
requirements at § 3930.30 of this chapter;

\(d\) The operator/lessee must notify the BLM promptly if operations
encounter unexpected wells or drill holes that could adversely affect
the recovery of shale oil or other minerals producible under an oil
shale lease during mining operations, and must not take any action that
would disturb such wells or drill holes without the BLM's prior
approval;

\(e\) The operator/lessee must conduct operations to:

\(1\) Prevent waste and conserve the recoverable oil shale reserves and
other resources;

\(2\) Prevent damage to or degradation of oil shale formations;

\(3\) Ensure that other resources are protected upon abandonment of
operations; and

\(f\) The operator must save topsoil for use in final reclamation after
the reshaping of disturbed areas has been completed.

COMMENT: Where else is prevention of waste, conservation of reserves,
and MER called for? Where are energy efficiency, energy self
sufficiency, and effective resource recovery required if at all???
Diligent Development Milestones are discussed in Section 3930.30. There
are no teeth in these rules, quantitative or otherwise.

Section 3930.11\--**Performance standards for** **exploration and in
situ operations.**

AR: The operator/lessee must adhere to the following standards for all
exploration and in situ drilling operations:

\(a\) At the end of exploration operations, all drill holes must be
capped with at least 5 feet of cement and plugged with a permanent
plugging material that is unaffected by water and hydrocarbon gases and
will prevent the migration of gases and water in the drill hole under
normal hole pressures. For holes drilled deeper than stripping limits,
the operator/lessee, using cement or other suitable plugging material
the BLM approves in advance, must plug

the hole through the thickness of the oil shale bed(s) or mineral
deposit(s) and through aquifers for a distance of at least 50 feet above
and below the oil shale bed(s) or mineral deposit(s) and aquifers, or to
the bottom of the drill hole. The BLM may approve a lesser cap or plug.
Capping and plugging must be managed to prevent water pollution and the
mixing of ground and surface waters and to ensure the safety of people,
livestock, and wildlife;

\(b\) The operator/lessee must retain for 1 year all drill and
geophysical logs. The operator must also make such logs available for
inspection or analysis by the BLM. The BLM may require the
operator/lessee to retain representative samples of drill cores for 1
year;

\(c\) The operator/lessee may, after the BLM's written approval, use
drill holes as surveillance wells for the purpose of monitoring the
effects of subsequent operations on the quantity, quality, or pressure
of ground water or mine gases; and

\(d\) The operator/lessee may, after written approval from the BLM and
the surface owner, convert drill holes to water wells. When granting
such approvals, the BLM will include a transfer to the surface owner of
responsibility for any liability, including eventual plugging,
reclamation, and abandonment.

COMMENT: Where for in situ processes/operations are all the big ticket
issues on energy efficiency, energy self sufficiency, maximum resource
recovery, and environmental impact required. Where are the specific
requirements regarding surface scalping and wholesale crapping up of
ground water and unproven mitigation schemes for cleaning it up after
the fact? There are none.

Section 3930.12\--**Performance standards for** **underground mining.**

AR: (a) Underground mining operations must be conducted in a manner to
prevent the waste of oil shale, to conserve recoverable oil shale
reserves, and to protect other resources. The BLM must approve in
writing permanent abandonment and operations that render oil shale
inaccessible.

\(b\) The operator/lessee must adopt mining methods that ensure the
proper recovery of recoverable oil shale reserves.

\(c\) Operators/lessees must adopt measures consistent with known
technology to prevent or, where the mining method used requires
subsidence, control subsidence, maximize mine stability, and maintain
the value and use of surface lands. If the plan of development indicates
that pillars will not be removed and controlled subsidence is not part
of the plan of development, the POD must show that pillars of adequate
dimensions will be left for surface stability, considering the thickness
and strength of the oil shale beds and the strata above and immediately
below the mined interval.

\(d\) The lessee/operator must have the BLM's approval to temporarily
abandon a mine or portions thereof.

\(e\) The operator/lessee must have the BLM's prior approval to mine any
recoverable oil shale reserves or drive any underground workings within
50 feet of any of the outer boundary lines of the federally-leased or
federally licensed land. The BLM may approve operations closer to the
boundary after taking into consideration state and Federal environmental
laws and regulations.

\(f\) The lessee/operator must have the BLM's prior approval before
drilling any lateral holes within 50 feet of any outside boundary.

\(g\) Either the operator/lessee or the BLM may initiate the proposal to
mine oil shale in a barrier pillar if the oil shale in adjoining lands
has been mined out. The lessee/operator of the Federal oil shale must
enter into an agreement with the owner of the oil shale in those
adjacent lands prior to mining the oil shale remaining in the Federal
barrier pillars (which otherwise may be lost).

\(h\) The BLM must approve final abandonment of a mining area.

COMMENT: Where for underground mining processes/operations are all the
big ticket issues on energy efficiency, energy self sufficiency, maximum
resource recovery, and environmental impact? There are none.

Section 3930.13\--**Performance standards for surface mines.**

AR: (a) Pit widths for each oil shale seam must be engineered and
designed to eliminate or minimize the amount of oil shale fender to be
left as a permanent pillar on the spoil side of the pit.

\(b\) Considering mine economics and oil shale quality, the amount of
oil shale wasted in each pit must be minimal.

\(c\) The BLM must approve the final abandonment of a mining area.

\(d\) The BLM must approve the conditions under which surface mines, or
portions thereof, will be temporarily abandoned, under the regulations
in this part.

\(e\) The operator/lessee may, in the interest of conservation, mine oil
shale up to the Federal lease or license boundary line, provided that
the mining:

\(1\) Complies with existing state and Federal mining, environmental,
reclamation, and safety laws and rules; and

\(2\) Does not conflict with the rights of adjacent surface owners.

\(f\) The operator must save topsoil for final application after the
reshaping of disturbed areas has been completed.

COMMENT: If surface or strip mining is used none of the oil shale should
be wasted. Only continuous mining should be considered which means no
fenders whatsoever. Where for surface mining processes/operations are
all the big ticket issues on energy efficiency, energy self sufficiency,
maximum resource recovery, and environmental impact? There are none.

Section 3930.20\--**Operations.**

AR: (a) *Maximum Economic Recovery (MER).* All mining and in situ
development and production operations must be conducted in a manner to
yield the MER of the oil shale deposits, consistent with the protection
and use of other natural resources, the protection and preservation of
the environment, including, land, water, and air, and with due regard
for the safety of miners and the public. All shafts, main exits, and
passageways, and overlying beds or mineral deposits that at a future
date may be of economic importance must be protected by adequate pillars
in the deposit being worked or by such other means as the BLM approves.

\(c\) *Statutory compliance.* Operators must comply with applicable
Federal and state law, including, but not limited to the following:

\(1\) Clean Air Act (42 U.S.C. 1857 *et seq.*);

\(2\) Federal Water Pollution Control Act, as amended (30 U.S.C. 1151
*et seq.*);

\(3\) Solid Waste Disposal Act as amended by the Resource Conservation
and Recovery Act (42 U.S.C. 6901 *et seq.*);

\(d\) Resource protection. The following additional resource protection
provisions apply to oil shale operations:

\(1\) Operators must comply with applicable Federal and state standards
for the disposal and treatment of solid wastes.

COMMENT: Refer to discussion section on Definitions for more discussion
of MER. Where are the technology qualification requirements on all the
big ticket issues of energy efficiency, energy self sufficiency, maximum
resource recovery, and environmental impact needed to ever achieve MER?
Where are the specifics of prohibiting residual charred spent shale,
thereby preventing the contamination of both surface and underground
water systems? There are none.

Section 3930.30\--**Diligent development milestones.**

**AR:** (a) Operators must diligently develop the oil shale resources
consistent with the terms and conditions of the lease, plan of
development, and these regulations. If the operator does not maintain or
comply with diligent development milestones, the BLM may initiate lease
cancellation. In order to be considered diligently developing the lease,
the lessee/operator must comply with the following diligence milestones:

> \(1\) Milestone 1. Within 2 years of the lease issuance date, submit
> to the proper BLM office an initial plan of development that meets the
> requirements of subpart 3931. The operator must revise the plan of
> development following subpart 3931 of this part, if the BLM determines
> that the initial plan of development is unacceptable;
>
> \(2\) Milestone 2. Within 3 years of the lease issuance date, submit a
> final plan of development. The BLM may, based on circumstances beyond
> the control of the lessee or operator, or on the complexity of the
> plan of development, grant a 1 year extension to the lessee or
> operator to submit a complete plan of development;
>
> \(3\) Milestone 3. Within 2 years after the BLM approves the final
> plan of development, apply for all required Federal and state permits
> and licenses;
>
> \(4\) Milestone 4. Before the end of the 7th year after lease
> issuance, begin infrastructure installation, as required by the BLM
> approved plan of development; and

\(5\) Milestone 5. Before the end of the 10th year after lease issuance,
begin oil shale production.

\(b\) Operators may apply for additional time to complete a milestone.
The BLM may grant additional time for completing a milestone if the
operator provides documentation that shows to the BLM's satisfaction
that achieving the milestone by the deadline is not possible for reasons
that are beyond the control of the operator.

\(c\) Operators must maintain minimum annual production every year after
the 10th lease year or pay in lieu of production according to the lease
terms.

\(d\) Each lease will provide for minimum production. The minimum
production requirement stated in the lease must be met by the end of the
10^th^ lease year and will be based on the BLM's estimate of the
extraction technology to be used, the recoverable resources on the
lease, expected life of the operation, and other factors the BLM
considers.

\(e\) Each lease will provide for payment in lieu of the minimum
production for any particular year starting the 10th lease year.
Payments in lieu of production in year 10 of the lease satisfies
Milestone 5 in paragraph (a)(5) of this section.

COMMENT More than liberal diligent development milestones. Ten years to
produce oil should be cut to five years.

Section 3930.40\--**Penalties for missing diligence milestones.**

AR: The BLM will assess a penalty of \$50 for each acre in the lease for
each missed diligence milestone each year until the operator or lessee
complies with § 3930.30(a) of this chapter. For example: If the operator
does not submit the required plan of development within 2 years of lease
issuance (the first milestone), the BLM will assess the operator an
additional \$50 per acre penalty each year until the milestone is met.
If the operator does not meet the second milestone (apply for all
required permits and licenses by 2 years after the BLM approves the plan
of development), the BLM will assess the operator \$50 per acre penalty
per year resulting in a total penalty of \$100 per acre, per year. If
the operator does not begin production by the end of the initial lease
term, or make payments in lieu thereof, the BLM may initiate lease
cancellation procedures (see §§ 3934.21 and 3934.22 of this part).

COMMENT Penalty not dependent on quality, thickness, or overburden depth
of the resource. \$50/acre per year is nothing for big oil for the best
resources in the Piceance Basin worth over \$100 million per acre in
finished products. Big oil can therefore carry the lease for 20 years
and beyond to perpetuity with no production, and without meeting a
single milestone for a maximum cost of \$250/acre per year diligence
penalty, \$4/acre lack of minimum production, a \$2/acre rental fee for
a total of \$256/acre starting after year 10 of the lease. Before year
10 the maximum missed milestone payments would be after 2 years,
\$50/acre, after 3 years \$100/acre, after 5 years \$150/acre, after 7
years \$200/acre. This is nothing for a resource end product value of
the order of \$100 million. A price increase in oil of .025 cents/barrel
would cover the total penalty. How about a price increase of
\$100/barrel---well that ultimately results in another \$100 million of
revenue to the lessee.

The DOI/BLM has made sure the hurdles for entrée into the oil shale
development industry are much too high for the small guy, and not even
noticeable to the big guys to not only enter---but to tie up the entire
resource without breaking a sweat.

Subpart 3931 **\--Plans of Development and Exploration Plans**

Section 3931.10\--**Exploration plans and plans of development for
mining and in situ operations.**

AR: (a) The plan of development must provide for reasonable protection
and reclamation of the environment and the protection and diligent
development of the oil shale resources in the lease. (b) The operator
must submit to the proper BLM office an exploration plan or plan of
development describing in detail the proposed exploration, testing,
development, or mining operations to be conducted. Exploration plans or
plans of development must be consistent with the requirements of the
lease or exploration license and protect non mineral resources and
provide for the reclamation of the lands affected by the operations on
Federal lease(s) or exploration license(s). All plans of development and
exploration plans must be submitted to the proper BLM office. (c) The
lessee or operator must submit 3 copies of the plan of development to
the proper BLM office or submit it in an acceptable electronic format.
Contact the proper BLM office for detailed information on submitting
copies electronically (see § 3931.40 for submission of exploration
plans). (d) The BLM will consult with any other Federal, state, or local
agencies involved and review the plan. If the BLM denies the plan, it
will indicate what additional information is necessary to complete the
application. (e) All development and exploration activities must comply
with the BLM approved plan of development or exploration plan. (f)
Activities under § 3931.40 of this subpart, other than casual use, may
not begin until the BLM approves an exploration plan or plan of
development.

COMMENT Where are the lessee's descriptions of BLM's lessee
qualification requirements for the technology involved on energy
efficiency, energy self sufficiency, effective resource recovery, and
environmental impact? Answer, there none.

Section 3931.11\--**Content of plan of development.**

AR: The plan of development must contain, at a minimum, the following:

\(a\) Names, addresses, and telephone numbers of those responsible for
operations to be conducted under the approved plan and to whom notices
and orders are to be delivered, names and addresses of Federal oil shale
lessees and corresponding Federal lease serial numbers, and names and
addresses of surface and mineral owners of record, if other than the
United States;

\(b\) A general description of geologic conditions and mineral resources
within the area where mining is to be conducted, including appropriate
maps;

\(c\) A copy of a suitable map or aerial photograph showing the
topography, the area covered by each lease, the name and location of
major topographic and cultural features;

\(d\) A statement of proposed methods of operation and development,
including the following items as appropriate:

\(1\) A description detailing the extraction technology to be used;

\(2\) The equipment to be used in development and extraction;

\(3\) The proposed access roads;

\(4\) The size, location, and schematics of all structures, facilities,
and lined or unlined pits to be built;

\(5\) The stripping ratios, development sequence, and schedule;

\(6\) The number of acres in the Federal lease(s) or license(s) to be
affected;

> \(7\) Comprehensive well design and procedure for drilling, casing,
> cementing, testing, stimulation, cleanup, completion, and production,
> for all drilled well types, including those used for heating,
> freezing, and disposal;

\(8\) A description of the methods and means to protect and monitor all
aquifers;

\(9\) Surveyed well location plats or project-wide well location plats;

> \(10\) A description of the measurement and handling of produced
> fluids, including the anticipated production rates and estimated
> recovery factors; and
>
> \(11\) A description/discussion of the controls that the operator will
> use to protect the public, including identification of:
>
> \(i\) Essential operations, personnel, and health and safety
> precautions;
>
> \(ii\) Programs and plans for noxious gas control (hydrogen sulfide,
> ammonia, etc.);
>
> \(iii\) Well control procedures;
>
> \(iv\) Temporary abandonment procedures; and
>
> \(v\) Plans to address spills, leaks, venting, and flaring;

\(e\) An estimate of the quantity and quality of the oil shale
resources;

\(f\) An explanation of how MER of the resource will be achieved for
each Federal lease;

\(g\) Appropriate maps and cross sections showing:

\(1\) Federal lease boundaries and serial numbers; (2) Surface ownership
and boundaries; (3) Locations of any existing and abandoned mines and
existing oil and gas well (including well bore trajectories) and water
well locations, including well bore trajectories; (4) Typical geological
structure cross sections; (5) Location of shafts or mining entries,
strip pits, waste dumps, retort facilities, and surface facilities; (6)
Typical mining or in situ development sequence, with appropriate
time-frames;

\(h\) A narrative addressing the environmental aspects of the proposed
mine or in situ operation, including at a minimum, the following:

\(1\) An estimate of the quantity of water to be used and pollutants
that may enter any receiving waters;

> \(2\) A design for the necessary impoundment, treatment, control, or
> injection of all produced water, runoff water, and drainage from
> workings; and
>
> \(3\) A description of measures to be taken to prevent or control
> fire, soil erosion, subsidence, pollution of surface and ground water,
> pollution of air, damage to fish or wildlife or other natural
> resources, and hazards to public health and safety;

\(i\) A reclamation plan and schedule for all Federal lease(s) or
exploration license(s) that details all reclamation activities necessary
to fulfill the requirements of § 3931.20;

\(j\) The method of abandonment of operations on Federal lease(s) and
exploration license(s) proposed to protect the un mined recoverable
reserves and other resources, including: (1) The method proposed to fill
in, fence, or close all surface openings that are hazardous to people or
animals; and (2) For in situ operations, a description of the method and
materials to be used to plug all abandoned development or production
wells; and

\(k\) Any additional information that the BLM determines is necessary
for analysis or approval of the plan of development.

OMMENT Where are the lessee's qualification requirement descriptions on
energy efficiency, energy self sufficiency, effective resource recovery,
and environmental impact. Answer: lessee is not required to have any.

Section 3931.20\--**Reclamation.**

AR: (a) The operator or lessee must restore the disturbed lands to their
pre-mining or pre-exploration use or to a BLM determined higher use.

\(b\) The operator must reclaim the area disturbed by taking reasonable
measures to prevent or control onsite and offsite damage to lands and
resources.

\(c\) Reclamation includes, but is not limited to: (1) Measures to
control erosion, landslides, and water runoff; (2) Measures to isolate,
remove, or control toxic materials; (3) Reshaping the area disturbed,
application of the topsoil, and re-vegetation of disturbed areas,
**[where reasonably practicable]{.underline}**; and (4) Rehabilitation
of fisheries and wildlife habitat. (d) The operator or lessee must
substantially fill in, fence, protect, or close all surface openings,
subsidence holes, surface excavations, or workings which are a hazard to
people or animals. These protected areas must be maintained in a secure
condition during the term of the lease or exploration license. During
reclamation, but before abandonment of operations, all openings,
including water discharge points, must be closed to the BLM's
satisfaction. For in situ operations, all drilled holes must be plugged
and abandoned, as required by the approved plan.

\(e\) The operator or lessee must reclaim or protect surface areas no
longer needed for operations as contemporaneously as possible as
required by the approved plan.

COMMENT: Taking reasonable measures? Where reasonably practicable? Who
decides. There's nothing on in-situ---plug the holes and "abandoned" and
walk away. Incredible reclamation requirements. What about RDS's
scalping and ground water crap up approach---what are the requirements??
Compliance with (a) is not assured in (b) through (e).

Where's the DOI/BLM leadership here requiring that the land and water be
left better than the lessee found it. Where's some consideration and
requirement for dual benefits---not only energy production, but for
example some massive water storage and beneficial land improvement
projects resulting from the massive amount of soil that must be moved
and reclaimed---not only for surface and underground mining, but also
for the total land scalping required for RDS's ICP process? Answer:
there is none.

Section 3931.30

Section 3931.40

Section 3931.41

Section 3931.50

Section 3931.60

**AR § 3931.70 Production maps and production reports.**

Pg, 42972 (f) For in situ development operations, the lessee or operator
must submit a map showing all surface installations, including
pipelines, meter locations, or other points of measurement **necessary
for production verification a**s part of your plan of development. All
maps must be modified as necessary for adequate representation of
existing operations

COMMENT: The BLM and the lessee both need a complete map of kerogen as a
function of quality, thickness, and overburden. In addition a complete
map of the fraction of kerogen to be impacted, ultimately processed,
wasted, and left behind should be required as a function of quality,
thickness, and overburden. Without this complete accounting of the
resource, the effectiveness of its utilization can never be obtained.

Section 3931.80

Section 3931.100

Subpart 3932

Section 3932.10

Section 3932.20

Section 3932.30

Section 3932.40

Subpart 3933

Section 3933.10

\\AR: **§ 3932.20 Lease modification land availability criteria.** (a)
The BLM may grant a lease modification if: (1) There is no competitive
interest in the lands covered by the modification application; (2) The
lands covered by the modification application cannot be reasonably
developed as part of another independent federally-approved operation;

COMMENT: The argument made that lease modification of small tracts is
the equivalent of a preference lease are simply false. There is no
requirement for "no competitive interest" in the BLM RDD preference
leases.

Section 3933.31

Section 3933.32

Section 3933.40

Section 3933.51

Section 3933.52

Section 3933.60

Section 3933.70

Subpart 3934

Section 3934.10

Section 3934.21

Section 3934.22

Section 3934.30

Section 3934.40

Section 3934.50

Subpart 3935\--**Production and Sale** **Records**

Section 3935.10 **Accounting records.**

AR: (a) Operators or lessees must maintain records that provide an
accurate account of, or include all: (1) Oil shale mined; (2) Oil shale
put through the processing plant and retort; (3) Mineral products
produced and sold; (4) Shale oil products, shale gas, and shale oil
by-products sold; and (5) Shale oil products and by-products that are
consumed on-lease for the beneficial use of the lease. (b) The records
must include relevant quality analyses of oil shale mined or processed
and of all products including synthetic petroleum, shale oil, shale gas,
and shale oil by-products sold. (c) Production and sale records must be
made available for the BLM's examination during regular business hours.

COMMENT: The BLM and the lessee both need a complete map of kerogen as a
function of quality, thickness, and overburden. In addition a complete
map of the fraction of kerogen to be impacted, ultimately processed,
wasted, and left behind should be required as a function of quality,
thickness, and overburden. Without this a complete accounting of the
resource and the effectiveness of its utilization can never be obtained.
In addition to production records, the DOI/BLM must have a complete
breakdown of production costs records. Given this information a kerogen
based annual payment system can be devised as discussed in a following
section, and recommended in the Summary section of this document.

Subpart 3936\--**Inspection and** **Enforcement**

Section 3936.10\-- **Inspection of underground and surface operations
and facilities.**

AR: Operators, licensees, or lessees must allow the BLM, at any time,
either day or night, to inspect or investigate underground and surface
mining or exploration operations to determine compliance with lease or
license terms and conditions, compliance with the approved exploration
or development plan, and to verify production.

COMMENT: Inspection or examination of the design or operating conditions
of proprietary oil shale process are not needed and should not be
required. Feed into the process and product and other effluents leaving
the process should be required to made available for accounting purposes
and environmental compliance---but there is no need whatsoever for the
DOI/BLM to access the design and operating condition
information---either documentation or the working equipment.

Section 3936.20

Section 3936.30

Section 3936.40

**[C.5 IV. Procedural Matters]{.underline}**

*Executive Order 12866, Regulatory Planning and Review*

DR, pg 42945 (4) This rule does not raise novel legal or policy issues.
As stated earlier in this preamble, the legal and policy issues
addressed by this rule are already dealt with in a similar manner in
other BLM regulations currently in effect, therefore they are not novel.

DR, pg 42946 Please comment on the uncertainty surrounding the quantity
and quality of recoverable oil shale, specifically as it relates to
potential production of shale oil.

DR, pg 42946 Please specifically comment on the state of technology
necessary to recover or produce oil from shale and the associated
production costs.

DR, pg 42947 In addition to the emissions associated with the operations
themselves, extraction of oil from shale could consume immense
quantities of electricity. This would necessitate the building of new
power plants, which could further contribute air emissions. Impacts

DR, pg 42947 Before oil shale development could occur, additional
project-specific NEPA analyses would be performed at two points in time:
(1) Prior to leasing; and (2) Prior to plan of development approval.

DR, pg 42948 The bonus is the amount paid by the successful high bidder
when a parcel is offered for lease. By statute the parcel must be leased
for fair market value. At this juncture there is no practical way to
generate a meaningful estimate of the potential bonus bids or fair
market values for potential lease parcels.

DR, pg 42948 *Clarity of the Regulations* Executive Order 12866 requires
each agency to write regulations that are simple and easy to understand.

*Small Business Regulatory Enforcement Fairness Act (SBREFA).*

DR, pg 42949 (3) Does not have significant adverse effects on
competition, employment, investment, productivity, innovation, or the
ability of U.S.-based enterprises to compete with foreign-based
enterprises.

Executive Order 13272 reinforces executive intent that agencies give
serious attention to impacts on small entities and develop regulatory
alternatives to reduce the regulatory burden on small entities. To meet
these requirements, the agency must either conduct a regulatory
flexibility analysis or certify that the final rule will not have ''a
significant economic impact on a substantial number of small entities.''

DR, pg 42949 *Regulatory Flexibility Act* Congress enacted the
Regulatory Flexibility Act of 1980 (RFA), as amended, 5 U.S.C. 601--612,
to ensure that Government regulations do not unnecessarily or
disproportionately burden small entities. The RFA requires a regulatory
flexibility analysis if a rule would have a significant economic impact,
either detrimental or beneficial, on a substantial number of small
entities. The RFA establishes an analytical process for determining how
public policy goals can best be achieved without erecting barriers to
competition, stifling innovation, or imposing undue burdens on small
entities. Executive Order 13272 reinforces executive intent that
agencies give serious attention to impacts on small entities and develop
regulatory alternatives to reduce the regulatory burden on small
entities. To meet these requirements, the agency must either conduct a
regulatory flexibility analysis or certify that the final rule will not
have ''a significant economic impact on a substantial number of small
entities.' However, the number of firms, large or small, involved in oil
shale development on Federal lands would likely remain quite limited.
Given the likely size of the industry that may eventually be involved in
the leasing and development of Federal oil shale resources, it is
reasonable to conclude that this rule would not significantly impact a
''substantial number of small

entities.''

As proposed, commercial oil shale leases would primarily rely on a
process of leasing parcels nominated by industry. The BLM may also
choose to offer certain lands for lease. All leases would be offered
competitively. The BLM would not collect an application or nomination
fee; however, the successful high bidder would be required to pay
certain costs associated with the BLM offering the tract for lease, in
addition to the bonus bid. At the time of lease sale, the high bidder
would be required to submit a payment of one fifth of the amount of the
bonus bid. Leases would also be subject to a \$2.00 per acre rental

DR, pg 42949 The ability to obtain an exploration License and/or to
compete for a commercial oil shale lease is not affected by the size of
the company. Exploration licenses require a nominal filing fee (\$295
per filing) and have no minimum acreage. Leases have minimum tract
acreage of 160 acres; lease processing costs are paid by the successful
bidder; and bonus bids may be deferred over a 5-year period. These
aspects of the proposed licensing and leasing procedures allow small
entities to better compete for Federal oil shale licenses and leases
with larger, well capitalized companies. As required by the EP Act, all
royalties, rentals, bonus bids, and other payments proposed in this rule
are to encourage development of the oil shale resources while ensuring a
fair return to the government. The proposed regulatory provisions,
including filing fees, rentals, and production royalties, will not have
a significant economic impact on lessees or operators, regardless of the
firm's size.

Therefore, the BLM has determined that under the RFA this proposed rule
would not have a significant economic impact on a substantial number of
small entities.

COMMENT: With these conclusions and resultant rules there is no way a
small entrepreneur can complete with big oil. The conclusions reached
above are blatantly false and the DOI/BLM has not complied with the
above orders and acts in presenting and analyzing the facts relevant to
the impact of these proposed rules on small entities---small business,
individuals, and entrepreneurs.. The DOI/BLM has made sure the hurdles
for entrée into the oil shale development industry are much too high for
the small guy, and not even noticeable to the big guys to not only
enter---but to tie up the entire resource without breaking a sweat.

COMMENT: The statement that "this rule does not raise novel legal or
policy issues" is ludicrous. Development of the oil shale industry, if
it ever occurs, will be novel including the leasing, the technology, the
economics, and the environmental impact and the legal issues surround
each of these. That's why the DOI/BLM has struggled with the
"definitions", the bases, and developing a coherent and fundamentally
well based set of leasing rules---and has not been able to finalize such
things as royalty rates and fair market value. It's why they have not
included technological qualification requirements of energy efficiency,
energy self sufficiency, effective resource recovery, and minimal
environmental impact. Requirements for the BLM RDD leasing program are
substantially different than for the commercial leasing rules---and they
shouldn't be, particularly in terms of requiring possession of
new/advanced process technology. and demonstration of commercial
viability before obtaining a commercial lease.

COMMENT: Even the clarity of the rules and related preamble discussion
is very poor---primarily because there is not a fundamentally sound
basis for the rules proposed.

COMMENT: The statement "Leases have minimum tract acreage of 160 acres;
lease processing costs are paid by the successful bidder; and bonus bids
may be deferred over a 5-year period." leaves the impression that a
small entity has no costs until he becomes the successful bidder. This
is totally untrue, the nominator is required to pay the processing costs
at the time of the nomination application---and also pay for NEPA costs
incurred prior to the lease sale---although both will be reimbursed if
the nominator is not the successful bidder.

**[D 48 commenters]{.underline}**

**[D. 1 Summary of 48 commenters---Developers vrs
Non-Developers]{.underline}**

Discussion of 48 comments received on the ANPR announced in August 25,
2006 Federal Register.

A summary of my review of the 48 ANPR commenters is provided below in
cryptic outline form. The review focuses on organizations and
individuals who are oil shale technology developers, oil shale owners,
and project developers. Of particular interest are the combined
technology/project developers who are in it for the long haul---the
serious ones. There are other organizations/individuals out there
involved in oil shale technology development but there commitment is
unclear since they have not actively participated in the BLM RDD
program, or making comments on the PEIS, or ANPR. Some of these can be
found in the profiles section of the recently issued DOE 2008 version of
the Secure Fuels for America report. There is one very serious project
developer who typically doesn't show up on any lists and that is the
Ziff brothers who took receivership of the bankrupt Australian SPP
project. They are proposing to develop a \$14 billion project on the
ashes of the defunct SPP project but have run into serious road block
actions by the New Australian federal government.

Acronyms used for a few of the organizations/individuals follow.

API=American Petroleum Institute

BCF = Brent C. Fryer

COP=ConocoPhillips

CVX= ChevronTexaco

NPI-Energy NPI

OSEC=Oil Shale Exploration Corporation

RDS= Royal Dutch Shell

XOM= ExxonMobil

A breakdown of organizations/individuals in terms of success/rejection
on the BLM RDD program and whether they responded or not to the ANPR is
provided below.

2 BLM RDD successful applicants responded: EGL and RDS

2 BLM RDD successful applicants did not respond: CVX and OSEC

3 BLM RDD rejected applicants responded: BCF, XOM, Anadarko

2 RDD developers who did not apply for BLM RDD, but responded: Red Leaf
(Ecoshale), COP

11 BLM RDD applicants who were rejected and did not respond: Utah :OTEC,
Western Energy Partners, Argyle Energy, Syntec Energy, Mountain West
Energy, Great Western Energy, American Oil Productions; Colorado:
Natural Soda, Independent Energy Partners, Kennecott Exploration,
Phoenix-Wyoming.

2 Individuals who were part of organizations that applied for a BLM RDD
lease who responded as individuals, not as prior organization BLM RDD
applicants: Bunger (Western Energy Partners, now with Red Leaf) , Byron
Merrill (Oil Tech, Millenium Synfuels, Ambre)

1 Developer who neither applied for the BLM RDD nor responded---Enshale
(Gold Buillion)

Of these how many are pushing for commercial leasing: RDS, EGL, OSEC,Red
Leaf, Anadarko

Of these how many want more BLM RDD leases: BCF, Bunger, CVX, XOM, Red
Leaf

Of these how many want commercial leasing only after demonstration of
technology: XOM, CVX, BCF .

Of these how many want commercial leasing only for those who have the
wherewithal, money, technology, project experience, etc.: XOM, RDS, COP

Of the 48 responses how many were direct duplications in one way or
another, or simply additional comments by the same person: answer is 17

2- COP: same letter sent by two different individuals.

2- XOM: same letter sent by two different individuals

2- Utah State: two letters from same person, additional comments

2-Red Leaf: two identical letters from same person

2-Raney: two letters from same person, additional comments+ 1 letter had
same comments as the RDS +2 comments.

2- API, NPI: same letter with two different organization cover letters.

4- RDS, + 3 other individuals (note comments in one of the Raney letters
are contained in the RDS or +2 letters) : Exact same sentences, same
words in re-arranged paragraph---an amazing coincidence.

2---Two different Individuals: same letter, reformatted. (Ryan, Norah)

In effect, there were not 48 separate responses, but only essentially 39
different ones. Of these only only 8 are serious oil shale
technology/project developers since Bunger now is part of the Red Leaf
organization, and Oil Tech, Millennium Synfuels, Ambre/Byron Merrill are
apparently no longer active in serious oil shale development. The 8 are
BCF, XOM,CVX,RDS,OSEC,EGL,Red Leaf, and Gold Buillion. One has to
question the seriousness of the 2 BLM RDD lessee's who didn't to respond
to the ANPR---CVX and OTEC. In addition how serious is the Enshale (Gold
Buillion) organization who neither applied for a BLM RDD lease, nor,
responded to the ANPR.

CVX made it known in their response on the PEIS that they do not support
commercial leasing until research leading to demonstration of commercial
viability is achieved. XOM has made no statements that they are in any
big rush to initiate commercial leasing either. OSEC on the other hand
has been pushing, with strong Republican support, to get commercial
leasing underway now---taking a position that they are going to use
technology that has already demonstrated commerciality. First saying
that for the Taciuk process, and in July abandoning that process, and
switching to Petrosix. OSEC has now sold up to 40% of their oil shale
operations to Petrobras and Mitsuii. RDS has been pushing hard for
commercial leasing, but withdrew their Colorado state licensing
applications over a year ago which is inconsistent with their push for
commercial rules. EGL has sold 80% of their oil shale operations to IDT
a floundering telecommunications company.

Of the 39 separate responses, 32 are not oil shale developers. Although
their responses are of interest, without technology/project developers
who are in for the long haul, oil shale development will go nowhere.
Therefore my comments are focused on them---the so called
"technology/project developers".

But let's consider **13 developer organizations and/or individuals and
their responses/non responses**. These include the five BLM RDD
applicants developers/responders and 2 developers/ non responders, and 2
non applicants but who responded to the ANPR, two individuals who are
developers and were associated with BLM RDD applicants but who now are
associated with other organizations, or organizations with a different
name. One other non BLM RDD applicant organization that made no comments
is also listed since they are a known developer having leased Utah State
Trust Lands. Two of the applicant/non responders did provide comments
relevant to leasing in their comments on the PEIS.

The following is presented in cryptic form to summarize my conclusions
on the respondents' positions.

**[D.2 Two BLM RDD applicants/lessees/ANPR comments (RDS,
EGL)]{.underline}**

1\. RDS \--\$1000/acre minimum acceptable bonus bid. \$2500/acre BLM RDD
preference lease conversion fee (i.e. bonus bid/fair market value).
25,000 acres maximum lease consolidation limit. 640 acre minimum lease
size. The Recoverable Oil Shale Resources shall be determined by
multiplying the technically and economically recoverable oil shale
resources by 40%. 35% of royalties may be offset to purchase either
electricity or fuel used to generate electricity used to remove or
process oil shale. Royalty rate on oil would be .05%x(price of crude oil
-\$10) between \$10-\$30/barrel. Thereafter the royalty rate would be
.1%x(market price of crude-\$30)+!%. At market prices above \$100 the
royalty rate would be fixed at 8%. The royalty rate on natural gas
production would be .5%x(natural gas price-\$2) up to a market prices of
\$15. Above \$15 the royalty rate would be fixed at 6.5%. %. Products
produced on the lease, but used on the lease to remove or process
minerals on the leased are royalty free. If royalties are imposed on
products used on the lease to produce electricity, then the royalty
percentages must be reduced by at lease 35% to avoid royalties too high
to support a sustainable shale development program. No lessee may be
awarded more than 3 leases in anyone year.

Shell is concerned that speculators may unreasonably interfere with
legitimate developers and impede real competition. (b) promote a level
playing field amongst oil shale producers, rather than penalizing more
efficient producers. Proposal does not generally call for any costs to
be deducted from the index price before applying the royalty rate. The
sole exception is imported electricity. Net proceeds royalty mechanism
would favor less efficient oil shale production techniques and
technologies. More efficient techniques and technologies can (b) help
recover the maximum amount of oil shale reasonably possible out of each
acre of federal land. First oil shale development is speculative. Need a
substantial minimum bid to deter speculation.

Shell states that no 1 entity should be allowed more than 3 oil shale
leases in any one year.

The BLM is proposing a flat 5% royalty as Option 1, while RDS is willing
to live with 8%. BLM is offering a federal government/US citizen rate of
5% and big oil is willing to accept 3% higher at 8%\--doesn't sound like
BLM is bartering for a fair deal for the US citizen.

Substantial bonus bids focuses development on richer resources.
Diligence: Plan of Operations 3 years after lease execution. 20 years
before any production required. This is diligence? Whose speculating
under a 20 year no production scenario?

Check this out. Compare electricity costs, 35% of royalties offset to
buy electricity, and a 35% reduction in royalties if electricity not
offset. What if cost of electricity not as great as 35% of the
royalties.

COMMENT: Oil over \$100 now, has been nearly \$150, natural gas at about
\$9 and has been near \$15, therefore this would set the royalty rates
at 8% for oil and gas at 6.5% for how long? Well the resource
efficiently developed may last for 200 years. Its ludicrous to propose
this sliding scale based on todays dollars, and today's prices. In 20
years this will result in a windfall for the lessee and a scam worse
than the offshore drilling mess of 1998/99. How can Shell operate at a
12.5% royalty if they require a royalty no higher than 8% and a 35%
reduction in royalty for imported electricity, which results in an
equivalent 5.2% royalty?

2\. EGL (Now 80% IDT)

BLM needs a fresh look, should not simply model leasing program after
exiting mineral leasing programs. Should not base leasing on competitive
biding with award to highest bidder. Large energy and mining companies
could easily out-bid smaller competitors. That would block access by
smaller companies who have the technology but not the deep pockets.
Diligence provisions won't solve the problem. By the time diligence
provisions would have any effect the smaller competitors will have long
disappeared. Or after diligence requirements extinguish a lease, the
small company will be out-bid when the lease is re-offered. EGL
recommends a negotiated bonus. EGL supports managing leasing process
based on well publicized qualifying and selection criteria, including
the technology that will be used. Lease acreage would be provided to the
extent the developer demonstrates the capability to develop the
resource. Lessees could not obtain lease acreage beyond what BLM thinks
they reasonably can develop in the future. No minimum production when
commercial production is unproven. BLM should only establish work
requirements and milestones. Royalty, 2% 1-10 years, 4% 11-15 years, and
6% thereafter. New commercial leases should be 6% from the beginning.
Point of determination should be first marketable product\-- MMS must
determine at what point/product that is, and whether there are
allowances for transport and processing. 20 year lease term. Lease
production used on or for the benefit of the lease not subject to
royalty.

COMMENT: For the same royalty rate, the royalty paid on the value of
finished products would be significantly different than for raw shale
oil and raw shale gas. No consideration of fair return to US citizen if
product prices escalate significantly. RDS requires no production before
20 years, therefore if none were produced, the royalty rate under the
EGl proposal would be 6%.

The BLM is proposing a flat 5% royalty as Option 1, while EGL, a BLM RDD
lessee, is willing to live with 6%. BLM is offering a federal
government/US citizen rate of 5% and small entrepreneur organization who
sold out to failing telecommunications company, IDT, is willing to
accept 1% higher at 6%\--doesn't sound like BLM is bartering for a fair
deal for the US citizen.

**[D.3 Three BLM RDD applicants/rejected/ANPR comments
(BCF,XOM,Anadarko)]{.underline}**

3\. BCF

The defacto position of the DOI/BLM on future RDD leases is that the
current program meets the requirements of EPA2005 and therefore there
will be no more RDD leases. Need a kerogen based payment system based on
the net proceeds.

4\. XOM

Royalty rates should be determined at the point the oil shale
hydrocarbons are capable of being processed in a traditional facility.
This must mean hydrotreated shale oil to be refinery acceptable, and
separated/processed shale gas to be pipeline acceptable. 10 year lease
with 5 year extension for technology development. All capable parties
with technical breadth to develop technology, engineering capacity to
undertake a long-term development, and capability to handle financial
risk associated with a capital intensive project which may not be
commercially successful shale have the opportunity to obtain oil shale
leases. Award of leases should be based on a combination of demonstrated
technology development capability and proposed work programs to progress
technology to commercialization. An equitable, transparent, and
science-base regulatory process will be needed to ensure reasonable
decision making to create a stable investment and operating climate.

R48(in yellow color) It is recognized that Interior has indicated to
limited parties that a preferential right to obtain a lease will be part
of a commercial leasing program. Others who were excluded from the
opportunity to obtain such a preferential right as well as those who
elected not to participate in the program should be given the
opportunity to obtain oil shale leases in and equitable process that
does not provide an undue advantage to those who are issued a RDD lease.
Thus preferential rights should not be obtained on the 2005 RDD
nominated acreage unless the prospective lessee uses the technology that
was proposed, tested and commercialize on the associated RDD tract.
Technologies developed and demonstrated to be commercial on another RDD
tract or not identified in the application for the applicable RDD tract
should not be used to gain a preferential right.

R48(in yellow color) All preferential right acreage nominated in
association with the application for a RDD tract should be available for
leasing by any party. If a party, as well as a preferential right
holder, desires to lease a particular tract burdened with a preferential
right, Interior should consider factors other than monetary
consideration in its evaluation as to who will receive the tract and
whether a preferential right party will be able to obtain it to the
exclusion of the other party. Other factors should include the ability
to maximize recovery of the shale oil along with other minerals that may
be present as well as the environmental disturbance necessary to
accomplish recovery using a particular technology. A time limit should
be established following which a preferential right is extinguished if
commerciality of a particular technology has not been demonstrated.

Minimum tract size should be 1280 acres (2 sections).

Fair market value is impossible to be made at this time. At this stage
in the technology development, lease award should take into account the
following:

(1) Demonstrated technology development capability

(2) Work programs to progress technology to commercial application

(3) Bonus

Greater weight should be given to the first two.

Diligence: nothing specific

Royalty: costs of transport and upgrader processing should be allowed as
deductions for purposes of royalty determination. Nothing specific on
royalty rates.

From the PEIS Comments:

> No urgency is expressed on the part of ExxonMobil for commercial
> leasing regulations.

Exxon/Mobil (XOM) Comment ID: OSTSD52818 (PEIS comments)

RPEIS (in purple color): We believe a commercial oil shale and tar sand
leasing program is in the best interest of the nation in contributing to
meeting the country's energy needs. We also support the process for the
environmental analysis of oil shale and tar sand lands leasing.

We support the BLM in its efforts to develop a commercial leasing
program and the government's recent efforts to make Federal lands
available for oil shale research. [We urge the BLM to recognize in any
leasing program that there is a need for ongoing opportunities to
develop and test new technologies on a phased basis to avoid precluding
the development of new and potentially better ideas for the recovery of
shale oil.]{.underline}

We note that in our specific comments that both Alternative A and
Alternative C will, [we believe, effectively limit competition in the
oil shale development sector to the companies that currently have RD&D
leases.]{.underline} [This will preclude development and testing of
alternative technologies having the potential for improved total
resource recovery and minimization of other impacts.]{.underline}

We urge that the DPEIS reflect the high probability of mineral
co-development in the future and afford, through the envisioned leasing
program, opportunity for these types of technologies to be tested. [This
is best accomplished through further leasing similar in scope and detail
to the BLM's previous RD&D leasing action.]{.underline}

COMMENT: XOM wants more BLM RDD leases, preference rights, and
commercial viability demonstrations as a qualification for a commercial
lease.

COMMENT: The above describes a "preferential right"?? This sounds like
the approach of BLM asking for expressions of interest, then asking for
nomination/applications, the holding a lease sale where someone other
than the nominator is the successful bidder. Sounds like XOM wants a new
definition of preference rights.

COMMENT: Where is the actual technology that XOM has developed---not
just capability to do so? At the 2006 Oil Shale Symposium XOM presented
test results from the ElectroFrac process---total oil production was a
meager .15 milliliters---how many drops is that? Where is XOM's
demonstrated capability/work programs given the Colony/Tosco process
fiasco.

5\. Anadarko

Note Anadarko is an oil shale mineral rights owner, but is not an oil
shale technology developer.

Royalty rates: 1% on all production, then increase to 12.5% on net
revenues after all start-up costs, RDD costs, and allowance for a return
on capital.

No minimum production initially, afterwards impose a minimum production
requirement.

Small tract leasing should not be allowed.

COMMENT: Anadarko wants commercial development, commercialized
technology, but doesn't want small lease tracts which will in fact be
the best engine for developing advanced commercial technology.

**[D.4 Two BLM RDD applicants/lessees/ no ANPR comments---but leasing
relevant comments made on PEIS (CVX, OSEC)]{.underline}**

6\. CVX---No ANPR comments, but advocated more RDD leasing and no
commercial leasing until technology proven in their PEIS comments.

Chevron stated that they don't support commercial leasing until there is
a clear demonstration of the technology. Chevron encourages the BLM to
consider expanding the RD&D leasing program

Chevron/Texaco (CVX) Comment ID: OSTSD52876 (PEIS comments)

**Chevron's View on Commercial Leasing Program**

RPEIS (in purple color): [Chevron believes that a full scale commercial
leasing program should not proceed at this time without clear
demonstration of commercial technologies.]{.underline} The BLM's
original intent in issuing RD&D leases was to help accomplish this task.
The RD&D program helps to insure that oil shale technologies can operate
at economically sustainable and environmentally responsible levels prior
to full-scale commercial leasing. [To that end, Chevron encourages the
BLM to consider expanding the RD&D leasing program.]{.underline}

Chevron, however, does support discussions on developing a path forward
for eventual commercial leasing. It is important that discussions take
place now to help develop the proposed rules and regulations around the
eventual issuance of these leases.

**Chevron Agrees with the BLM's Recommended Alternative B**

RPEIS (in purple color): Programmatic Alternative A does not allow for
the eventual issuance of commercial leases. Chevron recommends
clarification on the description of Alternative A. [This alternative
essentially limits development to the existing RD&D leases which have
been granted.]{.underline} However, according the BLM leases, the lessee
" ...shall have the exclusive right to acquire any or all portions of
the preference lease area for inclusion in the commercial lease, up to a
total of 5,120 contiguous acres..." The BLM needs to clarify whether or
not their intent was to include the contiguous acres which are already
part of the approved lease programs.

7\. OSEC (Now up to 40% Petrobras and Mitsuii)

OSEC did not respond to the ANPR request for comments.

In their PEIS comments they discussed the need to clarify and insure
that their BLM RDD preference lease rights are in tact as they
understood them.

**[D. 5 Two Non-BLM RDD applicants/ANPR comments (Red Leaf,
COP)]{.underline}**

8\. Red Leaf (Ecoshale, Dana/Bunger)

Royalty of 1% up until debt service and capital investment has been
repaid. Follow the Canadian plan.

No royalty on production and use of fuels on site.

From the PEIS comments:

Red Leaf Resources recommends that BLM initiate further RD&D programs
beyond the five oil shale projects on public lands in Colorado and Utah,
stating, RD&D should be considered as a fundamental aspect of BLM's land
management options for oil shale.

9\. COP\--

Royalty should be levied at the point where the first marketable product
is produced. Royalty should commence only after full recovery of RDD,
capital and operating costs. COP supports BLM considering the Canadian
oil sands model. The highest bonus bid should not be the sole criteria
for winning bid selection. Qualified bidders should have a combination
of technical, financial, and project management expertise and experience
and a solid record of environmental and social responsibility. The
applicant's ability to transport, upgrade and refine the shale oil
product is also an important consideration. The leasing of small tracts
should only be allowed in cases where tracts have been orphaned.

**[D. 6 Two Individuals Associated with BLM RDD applicant
organizations/ANPR Comments (Bunger,Merrill)]{.underline}**

10\. Bunger, Energy Technology and Engineering (Now associated with
Redleaf/Ecoshale) ( Was associated with Western Energy Partners as
applicant BLM RDD applicant)

Royalty per barrel of oil equivalent should be less than that paid for
oil and gas since it is more costly to produce. Point of determination
should be the earliest point of market determination. This point will be
the raw shale oil. Oil shale resources consumed on site should be exempt
from royalty because this will strongly encourage energy
self-sufficiency. Royalty could be based on a fraction of NYMEX. An
alternative to indexing would be to employ a sliding royalty rate that
is calculated on the difference between the product price and the
highest-cost production in the industry. A third royalty option is to
use the Canadian oil sands model. Should be small tract leasing with
preference rights, not unlike BLM RDD leasing program.

11\. Byron Merrill (associated with OTEC---bought by Millennium
Synfuels, now owned by Ambre Energy in Australia)

Royalty should be on the material as it exists naturally in the land,
and as it is removed from the land.

Makes a comparison of BTU content as follows:

Coal: 8,100-13,000 BTU/lb

Oil Shale: 4300 BTU/lb

Crude oil: 19,000 BTU/lb

Wood: 4,500-8500 BTU/lb.

**[D. 7 Two Other Developer Organizations (Enshale,OTEC)]{.underline}**

12\. Enshale (Parent Company is Gold Buillion)---No comments, but a
significant holder of Utah Trust Lands Oil Shale Leases.---no ANPR
comments.

13\. OTEC, Millennium Synfuels, Ambre Energy\-\--apparently currently
pursuing coal processing, Jack Savage, Byron Merrill,. Romit
Bhattacharya. No ANPR comments, not currently prosecuting an oil shale
agenda.

**[D. 8 Summary of 13 Developer's Comments, Recommendations, Relative to
Actual Proposed Rule---BLM Acceptance, Rejection, or Inconclusive BLM
Position.]{.underline}**

There was precious little incorporated into the commercial leasing rules
based on the 48 comments provided, even when considering the 13
technology/project developer's responses, except for a few critical
issues and combinations of different parts of the total rules package
that result in exclusion of small entities.. Respondent proposals
included, although not in exact proposed form, are RDS's proposals for
time before minimum production requirements kick in, minimum bonus bid,
and exclusion of small entities via the combination of minimum lease
size, minimum bonus bid, delineation of nominated 160 acre tracts up to
larger sizes, and competitive bonus bidding---and no requirements of
commercial viability or process technology qualification requirements..
Some important parts of the rules which incorporated, or rejected
proposals from respondents, included the following issues:

1.  Minimum production

2.  Royalties

3.  Minimum bonus bid

4.  Conversion of BLM RDD preference rights to commercial leases

5.  Minimum lease size

6.  Content of Plan of Development---Technology Qualification
    Requirements and Financial Capacity Requirements

7.  Long term water treatment trust funds.

**[1. Minimum Production]{.underline}**

AR Section 3903.51\--**Minimum production and payments in lieu of
production.**

AR: (a) Each lease must have a minimum annual production amount of shale
oil or make a payment in lieu of production for any particular lease
year, beginning with the 10th lease year.

COMMENT:

Minimum production by technology/project developer:

RDS=20 years after lease initiation production of ¼% of recoverable
resource.

EGL=no minimum production requirement.

BCF=1000 barrels/day---any commercial lease that cannot reach and
maintain this level of production should be extinguished.

XOM=no specifics on minimum production.

Anadarko=.no comment in ANPR response.

CVX= no response to ANPR

OSEC= no response to ANPR

Red Leaf= no comment in ANPR response

COP=should be based on plan of development. Production at low levels
would be non economic.

Bunger=nothing specific or quantitative.

Merrill=no comment in ANPR response.

Enshale=no response to ANPR

OTEC=no response to ANPR

COMMENT: The minimum production suggestion of 1000 barrels/day was
provided separately by not one commenter but two, Wyoming Governor Dave
Freudenthal and also by Brent Fryer. Any commercial oil shale
lease/project that cannot consistently produce 1000 barrels/day of raw
shale oil after 10 years of is tying up a national resource which is not
in the best interests of the nation. There clearly needs to be a minimum
production floor to make it clear that this is not acceptable. RDS's
proposal of no minimum production required until after 20 years of lease
tenure is almost equivalent to the BLM's proposal when you consider that
no production is required under the proposed rules for perpetuity, if
the diligence, rentals, and payments in lieu of production
fees/penalties of \$256/acre are paid. This is a small annual payment
for a resource that could be worth as much as \$100 million per acre.

**[2. Royalties]{.underline}**

AR: **Option 1**

**§ 3903.52 Production royalties.**

\(a\) The lessee must pay royalties on all products of oil shale that
are sold from or transported off of the lease. (b) The royalty rate for
the products of oil shale is 5 percent of the amount or value of
production.

**Option 2**

**§ 3903.52 Production royalties.**

\(a\) The lessee must pay royalties on the amount or value of all
products of oil shale that are sold from or transported off of the
lease. (b) The standard royalty rate for the products of oil shale is
12.5 percent of the amount or value of production. (c) For any lease
that begins production of oil shale within 12 years of issuance of the
first commercial oil shale lease issued under subpart 3925 or subpart
3926, the royalty rate is 5 percent of the amount or value of production
on the first 30 million barrels of oil equivalent produced from that oil
shale lease.

COMMENT:

Royalties by Bid by technology/project developer:

RDS= royalty 8% @ 100\$/barrel with a 35% reduction for electricity
equivalent to a 5.2% royalty.

EGL= initially royalty 6% after 15 years of lease tenure, with
additional leases at 6% from beginning of production.

BCF=Need a kerogen based payment system that includes kerogen quality,
thickness, and overburden thickness coupled with net proceeds (product
prices minus production costs).

XOM=no quantitative rates provided.

Anadarko=1% until all costs recovered then 12.5%.

CVX= no response to ANPR

OSEC= no response to ANPR

Red Leaf=1% until all costs recovered then \_\_\_\_\_, no values
provided after payout.

COP= no quantitative royalty rates provided.

Bunger=no quantitative royalty rates provided.

Merrill=royalty rate based on value of kerogen in the ground.

Enshale=no response to ANPR

OTEC=no response to ANPR

COMMENT: BLM's Option 1, flat 5%, is essentially the same as the sliding
scale RDS recommendation with a royalty rebated for imported electricity
of 35% which results in 5.2% for \$100/barrel oil. Although the RDS
proposal has a sliding scale based on oil price, the royalty rate
plateaus above \$100/barrel at 8% before the royalty rebate for imported
electricity of 35%.

**[3. Minimum Bonus Bid]{.underline}**

Section 3923.10\--**Minimum bid.**

AR: The BLM will not accept any bid that is less than the FMV. In no
case may the minimum bid be less than \$1,000 per acre.

COMMENT: Minimum Bonus Bid by technology/project developer:

RDS=The minimum acceptable lease bonus bid for an oil shale leases shale
be \$1000/acre.

EGL= non competitive bonus bid leasing, rather managed leasing with
negotiated bonus and qualifying criteria.

BCF=no minimum bonus bid, but required technology qualifications.

XOM=lease awards based on demonstrated technology development
capability, work programs, and bonus with greater weight given to first
two.

Anadarko=bonus bids should be low enough to allow operates access but
high enough to discourage speculators.

CVX=no ANPR response.

OSEC=no ANPR response.

Red Leaf=no bonus bid comments in their ANPR response.

COP=highest bonus bid should not be the sole criteria for winning bid
criteria, technical, financial, and management qualifications should
also be required.

Bunger=bonus bids should be left to the market place.

Merrill=no comment ANPR response.

Enshale=no response to ANPR

OTEC=no response to ANPR

COMMENT: BLM has accepted RDS's recommendation almost verbatim. RDS
obtained their 3 separate 160 acre tracts for a \$2000 application fee,
free and clear of bonus bids and any pre-commercial royalties. Now they
want to shut the door on small entrepreneurs gaining access to federal
reserves by imposing this minimum bid hurdle and the BLM has agreed.

**[4. Conversion of BLM RDD preference rights to a Commercial
Lease]{.underline}**

Section 3926.10\--**Conversion of an R, D and D lease to a commercial
lease.**

AR: The conversion application must include:

\(1\) Documentation that there has been commercial quantities of oil
shale produced from the lease, including the narrative required by the
R, D and D leases;

*DR: pg, 42940:* **be required to demonstrate to the BLM that the
technology tested in the original lease would have the ability to
produce shale oil in commercial quantities**

COMMENT:

Conversion of an RDD preference right to commercial lease based on
process technology originally proposed---response by technology/project
developer:

RDS= no comment in ANPR response

EGL= no comment in ANPR response

BCF=The BLM RDD program require commercial demonstration of the process
technology originally proposed in the application.

XOM:=Thus preferential rights should not be obtained on the 2005 RDD
nominated acreage unless the prospective lessee **uses the technology
that was proposed, tested and commercialize**d on the associated RDD
tract. Technologies developed and demonstrated to be commercial on
another RDD tract or not identified in the application for the
applicable RDD tract should not be used to gain a preferential right.

Anadarko=.

CVX== In PEIS comments "Chevron believes that a full scale commercial
leasing program should not proceed at this time without clear
demonstration of commercial technologies." This implies they would
require commercial demonstration prior to lease award.

OSEC= no response to ANPR

Red Leaf= = no comment in ANPR response

COP= no comment in ANPR response.

Bunger= no comment in ANPR response.

Merrill=no comment in ANPR response.

Enshale=no response to ANPR

OTEC=no response to ANPR

COMMENT: The BLM RDD leasing program and rules essentially states what
XOM is proposing---that the technology proposed in the application must
be the one commercially demonstrated on the BLM RDD tract---not some
technology switched to later. However, the switch by OSEC from Taciuk to
Petrosix has not thus far extinguished OSEC's BLM RDD lease.

**[5. Minimum Lease Size]{.underline}**

Section 3927.20\-- **Lease size.**

AR: The maximum size of an oil shale lease is 5,760 acres and the
minimum size of an oil shale lease is 160 acres.

COMMENT:

Minimum acreage limit by technology/project developer:

RDS=640 acres

EGL= min/max size would depend on lessee's capability to develop the
resource

BCF=continue BLM RDD program, 160 acres. If BLM starts over, 1-2 acres
adequate as demonstrated by pyrolysis target zones of RDD program
lessees.

XOM=1280 acres

Anadarko=small tract leasing should not be allowed.

CVX=expand BLM RDD leasing program, 160 acres (response in PEIS not
ANPR)

OSEC= no response to ANPR.

Red Leaf=BLM should initiate further RDD leasing programs, 160 acres.

COP= no small tracts except for orphaned tracts.

Bunger=should be small tracts with preference rights, not unlike BLM RDD
program, 160 acres.

Merrill=no comment on small tracts in ANPR response.

Enshale=no response to ANPR

OTEC=no response to ANPR

The BLM used 160 acres to be consistent with BLM RDD program---but when
you add in \$1000/acre minimum bonus bid, BLM delineation which will
result in tracts up to 5760 acres, not 160 acres, plus competitive bonus
bidding award of small tracts will be out of reach of small entities. 3
of the above 4 big oil companies do not want small tracts to be made
available for leasing.

**[6. Content of Plan of Development---Technology Qualification
Requirements and Financial Capacity Requirements]{.underline}**

AR: **§ 3931.11 Content of plan of development.**

\(d\) A statement of proposed methods of operation and development,
including the following items as appropriate:

\(1\) A description detailing the extraction technology to be used;

\(2\) The equipment to be used in development and extraction;

COMMENT:

Content of plan of development by technology/project developer in terms
of qualification requirements for a priori commercial viability and
process technology:

RDS= no comments on commercial viability or process technology
requirements in ANPR response.

EGL= no comments on commercial viability or process technology
requirements in ANPR response.

BCF=must demonstrate a priori commercial viability and meet specific
process technology requirements.

XOM=lease award should be based n demonstrated technology development
capability---but nothing on specifics of demonstrated commercial
viability or specific process technology requirements.

Anadarko= no comments on commercial viability or process technology
requirements in ANPR response.

CVX= In PEIS comments "Chevron believes that a full scale commercial
leasing program should not proceed at this time without clear
demonstration of commercial technologies." This implies they would
require commercial demonstration prior to lease award.

OSEC=no response to ANPR.

Red Leaf=no comments on commercial viability or process technology
requirements in ANPR response.

COP=bidders should have a combination of technical, economic, and
management expertise and experience---nothing specific.

Bunger= no comments on commercial viability or process technology
requirements in ANPR response.

Merrill= no comments on commercial viability or process technology
requirements in ANPR response.

Enshale=no response to ANPR

OTEC=no response to ANPR

COMMENT: In the BLM proposed rules there are no real requirement for
aprior commercial demonstration of the technology, nor any technical
requirements on the technology in terms of energy efficiency, self
sufficiency, effective resource recovery, environmental impact.

**[7. Long term water treatment trust funds]{.underline}**

Section 3904.40\--**Long-term water treatment trust** **funds.**

AR: (a) The BLM may require the operator or lessee to establish a trust
fund or other funding mechanism to ensure the continuation of long-term
treatment to achieve water quality standards and for other long-term,
post-mining maintenance requirements. The funding must be adequate to
provide for the construction, long-term operation, maintenance, or
replacement of any treatment facilities and infrastructure, for as long
as the treatment and facilities are needed after mine closure. The BLM
may identify the need for a trust fund or other funding mechanism during
plan review or later. (b) In determining whether a trust fund will be
required, the BLM will consider the following factors: (1) The
anticipated post-mining obligations (PMO) that are identified in the
environmental document or approved plan of development; (2) Whether
there is a reasonable degree of certainty that the treatment will be
required based on accepted scientific evidence or models; (3) The
determination that the financial responsibility for those obligations
rests with the operator; and (4) Whether it is feasible, practical, or
desirable to require separate or expanded reclamation bonds for those
anticipated long-term PMOs.

COMMENT: Long term water treatment funds by technology/project
developer:

RDS=.Shell opposes a more extensive bonding requirement that would cover
catastrophic events or extraordinary circumstances.

EGL= bonding should be handled on a case by case basis.

BCF=detailed the problems of inefficient processes that produce
excessive residual char, do not use the char for pyrolysis heat, and
leave it above or below ground as a source of contamination of centuries
of natural underground and surface water systems. There is no trust fund
or bonding mechanism large enough to cover such environmental disasters.

XOM=nothing in ANPR response on long term water treatment trust funds.

Anadarko= nothing in ANPR response on long term water treatment trust
funds.

CVX= no response to ANPR

OSEC= no response to ANPR

Red Leaf= nothing in ANPR comments.

COP= nothing in ANPR response on long term water treatment trust funds.

Bunger=no comment in ANPR comments.

Merrill=no comment in ANPR response.

Enshale=no response to ANPR

OTEC=no response to ANPR

COMMENT: Spent shale that has not been de-charred and is left
underground will be certain to contaminate underground water aquifers
for centuries to come. The cost of cleaning it up, will, like the above
mentioned current Hanford Nuclear Site, be prohibitive in both cost and
time, and like Hanford will become a sacrificial zone---but not an
isolated one since it will forever leak and leach contaminants into the
groundwater which in turn will drain into the White, Green, and Colorado
river drainage systems. An eternal unsolvable mess to which no price tag
is large enough nor no bond, or trust fund, is big enough---it's simply
too late after it occurs such as the Hanford Nuclear Reservation where
both chemical and nuclear contamination will forever leak and leach into
the Columbia River drainage system. The only solution is to prevent it
from occurring in the first place by making it a matter of national
energy policy that oil shale technologies that do not de-char spent
shale are banned from operating in the USA---and those who also produce
more char than the Fischer Assay are doubly barred. Note the RDS ICP
process is one of these, reducing 40% of the kerogen to char, left
underground to contaminate forever. Where the cost of cleanup, if at all
even possible, would be more than the finished energy products secured
from the kerogen reserve.

Shell proposed in their ANPR comments that the BLM use the same bonding
as for the BLM RDD leases which they state is sufficient to cover the
costs associated with restoration of the leased lands. Shell opposes a
more extensive bonding requirement that would cover catastrophic events
or extraordinary circumstances. Underground water contamination by
residual char is equivalent to a catastrophic event---yet Shell never
mentions it.

**[E. 32 Commenters on BLM RDD Leasing Terms]{.underline}**

COMMENT: Copies of the 32 comments were requested from BLM on August 7,
2008. At this writing they had not yet been received so no evaluation
could be provided.

**[F.]{.underline} Recommended Changes to Rule and BLM's Approach to Oil
Shale Development**

**[F1. General statement on the premature nature, and in-applicability
of attempting to use, prior rules for mining and oil/gas production, for
the leasing of oil shale, and of ever finding a very simple system that
is easy to administer..]{.underline}**

Attempting to cast oil shale leasing rules in concrete at this point in
time will have undesirable intended consequences, and many unintended
consequences. This is obvious in spite of the fact that Congress via the
Energy Policy Act of 2005 mandated that commercial leasing rules be put
in place by August 24, 2007. This was to be preceded by a PEIS mandated
to be finalized February 8, 2007. A draft "PEIS" was made available for
public comment---but is not a "PEIS" as mandated by congress---rather it
is a Land Use Plan. This is further compounded by the Democratic oil
shale moratorium The Salazar/Udall moratorium expires October 1, 2008
and they want to extend it into 2009. Given this state of affairs the
mandates of congress are meaningless---therefore, the DOI/BLM should
start over and try to get it right.

Preceding the subject rules, the BLM requested public comments via the
ANPR on August 25, 2006 with an extended comment deadline of October 25,
2006. During this comment time window light sweet crude ranged from
\$60-70/barrel and had never exceeded \$75/barrel. Recently crude
approached \$150/barrel and is now around \$100/barrel, while natural
gas has approached \$15/MMBTU and is now around \$7-8/MMBTU. In the
proposed rules an attempt is made to reference royalty rates, etc. to
assumed onshore US production costs of \$19.50/barrel, and oil shale
production cost estimates of \$37.75-65.21/barrel. This is meaningless.
First the marginal cost of finding and producing the next barrel of oil
onshore in the US is clearly going to be much more that
\$19.50/barrel---or there wouldn't be a current supply problem given the
current spread between the current \$100-150/barrel price and the
\$19.50/barrel production cost referenced. As far as the marginal cost
of production of the next barrel of conventional petroleum is
concerned---it's more a question of access to the resource rather than
the cost of production. Second, there's more than mere so called
"production" costs involved here---both in the US and world wide---it's
a question of access to oil reserves. Attempts by commenters and the BLM
to come up with a sliding scale royalty rate also demonstrate the result
of this ill thought out, pre-mature, and tied to oil/gas/coal rules,
production costs, and price approach. For example, RDS proposed a
sliding royalty rate tied to crude and gas prices, with the rate peaking
and remaining constant at 8% for oil above \$100/barrel and at 8% for
natural gas above \$18/MMBTU. How could the citizens of the USA obtain a
fair return under such a royalty system when crude hits
\$200/barrel---even assuming 8% were a fair return at \$100/barrel? If
the price goes beyond \$100/barrel, why should the royalty rate stay
fixed at 8%? Obviously when the RDS comments were generated 2 years ago
they never thought it possible that crude would approach the recent
\$150/barrel price.

It should be noted that foreign oil exporting nations have moved away
from royalties and bonus bid approaches to fixed price contracts for
services rendered. There is no "sharing" of production, particularly at
fixed royalty rates as the price of crude goes higher. This is true even
in Iraq where the new government has stated there will be "no sharing".

Its been 159 years since one of the first oil wells was drilled in
Titusville, PA. Federal leasing of oil/gas resources has been involved
in only a fraction of this time period. Peak oil production in the US
peaked in the early 1970's and since than has been cut in half. Over the
159 years of oil/gas production in the US the system of royalties and
bonus payments that has evolved has hopefully produced effective
development of these resources---and produced a fair return for the US
citizens. Classical exceptions include failure of the Minerals
Management Service to include price thresholds in deepwater leases
entered into during 1998 and 1999.

Effective oil shale development could result in meeting total US current
oil consumption for 100-200 years, or partial consumption for twice that
long. Much more production for a much longer period of time than
conventional petroleum in the US will ever see. Given the volatile but
certain long term future rise in crude oil and natural gas prices (and
production and access costs), the casting in concrete of an ill thought
out leasing system will have unintended consequences and be an
unfortunate legacy US citizens can ill afford. A leasing system that
will promote the development of oil shale and provide a maximum total
benefit including a fair total monetary return to the US citizen must
include the following considerations:

(1) Requires technology that is:

    A.  Energy efficient

    B.  Energy self sufficient

    C.  Maximizes total resource recovery

    D.  Achieves Fischer Assay Raw Oil recovery and TOSCO Assay Raw Gas
        recovery

    E.  Minimizes ultimate environmental impact

    F.  Cost effective

(2) Includes consideration of current and future market prices for
    ultimate, intermediate, and raw fuel products and non-fuel products
    including, but not limited to, excess electricity and/or process
    steam production.

(3) Includes consideration of total production costs for ultimate,
    intermediate, and raw fuel products and non-fuel products including
    but not limited to excess electricity and/or process steam
    production

(4) Includes incentives for technological development directed towards
    improving technology relative to (1) A-F.

(5) Provides access to small RDD tracts with incentives such as
    preference leases for larger tracts to allow oil shale developers an
    opportunity to demonstrate (1) A-F.

The challenge is to device a leasing system with monetary payments (not
necessarily bonus bids and royalties) and other requirement that will
simultaneously achieve the above. Small tract leasing is one of the few
means to bring about advanced technology which incorporates (1) above.
Trying to achieve any one, or most of the above, without all of them
will result in unintended consequences. The DOI/BLM/MMS wants a simple
leasing system easy to administer. This will not happen via the untimely
knee jerk reaction currently underway as a result of the ill conceived
Energy Policy Act of 2005 and political pressure. It will take time, and
any rules put in place must be flexible enough to accommodate change
required by experience until the above goals are met. To achieve the
above the DOI/BLM/MMS must put their mission ahead of the ease of
accomplishing their mission.

**[F2 Royalty Options 1, 2, & 3]{.underline}**

Rule proposed Royalty Options 1, 2, & 3 simply won't promote development
and provide a fair return to US citizens. Option 1---flat 5% of
production will not provide a fair return to US citizens under high
oil/gas prices and low production costs---items (2) and (3) above.
Neither does it incorporate items (1) and (4) above. Option 2, 12.5% of
production, except 5% of production for the first 30 million barrels of
oil equivalent production occurring within 12 years of issue of the
first BLM commercial lease. Other than a higher royalty payment, the
same as onshore oil/gas, this approach has the same effect as Option 1.
Option 3, a sliding scale based on a market price of competing products,
with 2 or 3 tier price thresholds based on current royalty rates (12.5%
for highest tier) with a 5% rate for the first tier. This option ignores
(1) and (4) and also (3) above---in addition it ignores the question of
will tier 3, 12.5%, be too high, or too low to both promote
development---and simultaneously provide a fair return to US citizens.

**F3 Fundamental Basis needed to simultaneously meet the goals of
optimizing the encouragement of oil shale development and providing the
maximum benefit including total fair monetary return to US citizens.**

The subject proposed rules are flawed because they lack a meaningful
fundamental basis. To develop that basis a few facts must be recognized,
and from these facts a rational set of rules can be developed that can
meet the above stated goal.. These are facts are:

> \(1\) The primary value of oil shale is the solid hydrocarbon,
> kerogen, contained within the oil shale. The mineral rock without the
> kerogen has little value. The value of the kerogen is that it has a
> chemical energy heating value of about 16,000 BTU/lb of kerogen (not
> per pound of rock), and, therefore approaches the heating value of
> crude oil.

(1) Kerogen has no value without technology to convert it into
    hydrotreated oil and processed gas. Technology, no matter how
    effective, to pyrolyze the kerogen and convert it into hydrotreated
    oil and processed gas has no value if the owner has no access to the
    kerogen.

(2) Heating the kerogen up to 900 F over a heating period of 1 hour in
    either the Fischer Assay or TOSCO Assay laboratory tests will
    pyrolyze the kerogen and convert the kerogen on an energy basis to
    raw shale oil (81%), raw shale gas (8%), and residual char (11%) and
    on a mass basis to raw shale oil (68%), raw shale gas (11%), and
    residual char (21%). Since there is no known practical process for
    directly extracting the kerogen from the oil shale, pyrolysis is
    conducted to decompose the kerogen into raw shale oil, raw gas, and
    residual char by heating the rock containing the kerogen. (Some
    developers such as Chevron are seeking ways to do carryout direct
    kerogen extraction using solvents such as supercritical CO~2~). The
    Fischer Assay/TOSCO Assay laboratory tests are the standard assays
    used to determine the reference assay in terms of the gallons of raw
    shale oil, and standard cubic feet of raw shale gas, that can be
    obtained from a ton of raw oil shale. Actual processes proposed for
    development or commercial use may produce significantly lower net
    quantities of oil and or gas, and much more char.

(3) The Fischer Assay/TOSCO Assay process returns nearly the maximum
    amount of raw oil, a minimum quantity of char, and the minimum
    balance of high BTU/ft^3^ hydrocarbon and other gases due to its
    short heating period to a temperature adequate to cause pyrolysis in
    a very short period of time. More than the standard assay raw shale
    oil might be produced by simultaneously hydrotreating to convert
    more of the kerogen, and heavy liquid ends, into light oil but the
    gains, even if achievable, would likely be quite small. Processes
    involving slower heat up rates, and therefore longer heat up times,
    albeit to a lower pyrolysis temperature, will typically produce much
    less raw shale oil (up to a 50% reduction), more raw gas, and much
    more char. This is due to the kinetics involved which result in
    coking of the oil produced. In addition for some processes much of
    the primary oil/gas product may be required to provide the pyrolysis
    heat---thus reducing net production. Even furthermore, some
    processes may choose or require expensive and energy inefficient
    offsite energy (such as electricity) to be imported to the process
    for pyrolysis heat inherently making the process less economic, as
    well as less energy efficient and totally non energy self
    sufficient.

(4) The residual char left on the spent oil shale after pyrolysis has
    limited value/utility other than within the pyrolysis process
    itself, and if not removed could become a potential for massive
    environmental impact There is however, adequate chemical energy in
    the char to provide enough pyrolysis heat such that energy self
    sufficiency can be achieved, and its use will significantly improve
    the net energy efficiency of a process. A well engineered pyrolysis
    process can be energy efficient, and may be able to produce surplus
    electricity and process steam in addition to the Fischer Assay/TOSCO
    assay quantities of oil and gas. This can be achieved technically
    across all quality grades of oil shale.

(5) There are however going to be oil shale quality economic limits
    which will be reached as shale quality decreases wherein the cost of
    the amount of rock that must be processed will exceed the value of
    the resultant quantity of oil/gas produced from that rock. In
    addition to quality, the thickness and overburden depth will also
    factor into defining the economic limits

(6) In addition to the quality of the oil shale, the amount of
    overburden present, and the thickness of the oil shale must be
    factored into valuing the kerogen within the oil shale.

(7) The maximum total benefit to US citizens, including fair monetary
    return must consider all the kerogen in the national oil shale
    resource. Evaluation of the total benefit must include strategic
    value, total monetary value paid by all lessees, and the economic
    value to the US economy of producing this product internally rather
    than importing it from foreign sources. Evaluation of total monetary
    fair return must include the sum of both royalties and bonus bids
    and incorporates the time value of money. .

Based on these facts, what must leasing rules contain to meet the
required objectives?

(1) The total fair monetary market value of the kerogen must be
    incorporated into the combined sum of payments (preferably not bonus
    bids and royalties), money time valued, over the life of the
    amortized payments.

(2) The total fair market value must include the value of each pound of
    kerogen in the lease hold, corrected or discounted, to account for
    quality, depth of overburden, and thickness.

(3) The total fair market monetary value must incorporate both the
    market price of the products as well as the cost of
    production---i.e. the net proceeds. The cost of production must
    consider both the least cost producer and the highest cost producer.

(4) Lease awards must be made to the competitor who will ultimately
    produce the maximum quantity of raw shale oil and minimum quantity
    of residual char from the lease hold, and who will return to the US
    Citizen the maximum sum of bonus bid and total integrated royalty
    payments including consideration of the time value of money.

(5) Commercial lease applicants must have a specific technology that
    will be applied to the lease hold, and have demonstrated commercial
    viability of that technology.

(6) Application technologies must be capable of approaching
    Fischer/TOSCO assay recovery of raw shale oil and raw shale gas. The
    technology must utilize the residual char energy as a pyrolysis heat
    source to achieve energy self sufficiency. Consuming product raw
    shale oil or raw shale gas to achieve energy self sufficiency should
    not be allowed. The technology must be energy efficient and energy
    self sufficient and include recovery of spent shale stored thermal
    energy. Environmental impact must be minimized.

(7) DOI/BLM and the applicant must both determine the total quantity of
    kerogen present, its quality, depth of overburden, and thickness.
    The applicant must define what kerogen fractions will be processed
    as a function of quality, thickness, and overburden depth, what will
    not be processed, wasted, and left behind and possibly what will be
    processed on a contingency basis.

(8) Diligence must compare applicant's commitments to actual production
    results and affected kerogen resource. Non compliance must result in
    extinguishing the lease.

(9) The total fair monetary market value of the kerogen must be
    incorporated into the combined sum of payments (preferably not bonus
    bids and royalties), money time valued, over the life of the
    amortized payments.

These fundamental rules will eliminate the speculators, hygraders, those
who have no technology, and those whose technologies are not in the best
interests of the United States. It will maximize resource recovery,
energy efficiency, and energy self sufficiency, and monetary return to
both the US citizen and lessee, both in terms of how much kerogen gets
processed as well as the maximum production from that which is
processed. The maximum monetary value and other benefits such as
strategic value and net US economic value will result. The incentive to
developers goes to the developer with the best technology---he gets the
lease---provided he's willing to live with a reasonable return. If
developer with worse technology out bonus bids the reasonable return
developer, then that developer with worse technology, is going to loose
his shirt: first because his production costs will be higher, and second
he won't be able to perform on diligence and his lease will be
extinguished.

Requiring demonstration of technology commercial viability (items (4-6)
above) means that RDD on new technologies must be conducted and
demonstrated to be functional, reliable, and cost effective to be
profitable. In addition its technical effectiveness (item (6) above)
must be demonstrated. This means that additional BLM RDD tracts/leases
must be made available. These tracts need not be large---with 1-2 acres
of mineral rights being adequate, with an outcrop being preferred for
most above ground processes. If large surface areas are needed for above
ground equipment (for above ground, or in-situ processes) this can be
handled with a surface lease. This demonstration will eliminate most if
not all of the technology viability uncertainty---and therefore most of
the need for delays in due diligence, issues of minimum production,
royalty relief, and so on. . It will also minimize waste by minimizing
the volume of process target zones in case things go wrong.

**[F4 Amortized kerogen based annual payment approach rather than bonus
bids and royalties.]{.underline}**

A lease payment system must consider the following facts. Kerogen has no
value without technology to convert it into hydrotreated oil and
processed gas. Technology, no matter how effective, to pyrolyze the
kerogen and convert it into hydrotreated oil and processed gas has no
value if the owner has no access to the kerogen. The challenge is to
develop a leasing monetary system where US citizens and the developers
of technology/projects receive a fair share or return, for: (1) the
resource; and (2) the risk and investment of money, time and intellect
into the development of both technology and projects. Besides a fair
return, it behooves both parties to insure technological processes are
required to be energy efficient, energy self sufficient, resource
recovery effective, and environmentally benign as possible. Coming up
with that system requires production cost information, and accommodation
of changes in both production costs and product market prices over time.
Both the US citizen, and the lessee/developer, should share in the
difference between the time varying product price and the production
cost---i.e. the net proceeds. As the net proceeds increase the share
split must address which of the parties deserves, if either is deserving
of a large share. In order to benefit both parties, incentives should be
present to reduce production costs. This kerogen based payment system
meets the challenge---the BLM's proposed rules do not.

Properly done bonuses and royalty payments on production could be
eliminated entirely, and replaced with an initial lock-in payment plus
annual payments amortized out over the planned project life based on the
value of the kerogen in the ground as described in the following
elements:

1.  Royalties and Bonus Bids should be eliminated and replaced with a
    competitive annual payment from the lessee to the Federal government
    that would be determined and work as outlined below based on the
    value of the kerogen in the ground, and net proceeds (time varying
    market price of products minus time varying production costs). In
    some regards this is similar to the Canadian Tar Sands system but
    with a different approach that eliminates the problems therein.

2.  Annual payments over the life of the resource would start at the end
    of the first year of production. A front end or down payment would
    be required to lock the lessee in at the time of bid award, and this
    would be credited towards the annual payments, with time value
    considered.

3.  The kerogen quantity in the leasehold would be defined and agreed to
    both by the BLM and lessee as a function of quality, thickness, and
    overburden depth.

4.  The lessee's competitive bid would be an offering to process given
    fractional amounts of the kerogen by quality, depth, and overburden
    thickness of the leasehold based on the total available kerogen
    resource. The lessee's bid would also offer to produce a given
    quantity of definable marketable products, at a given production
    cost at the start of production, and to return a given share of the
    products or value thereof to the Federal government based on product
    prices at the start of production. Cost of production would include
    capital recovery. This would be the base annual payment. The lessee
    could competitively offer to modify the share to the Federal
    government if product prices increased or decreased, and make a
    similar offer if production costs increased or decreased. The fair
    thing to do would be for the lessee to increase the share to the
    Federal government if product prices increase, and decrease the
    share if he were able to decrease production costs. Now once the BLM
    has all the bidders proposals in hand based on these bidder
    requirements the BLM can determine which bidder will return the most
    benefit to the US citizen based on the following:

    i.  Of the total tonnage of kerogen in the ground and as a function
        of quality, thickness, and overburden depth what fraction will
        be processed, left behind, and wasted

    ii. What will be the total integrated production, products, and
        value of those products

    iii. What will be the total production costs

    iv. How will the share of production are split as production costs
        are reduced or product prices increase.

    v.  What is the total value of the production and the Federal
        governments share

    vi. What is the magnitude and severity of the environmental impact

    vii. What is the quantitative and qualitative value/benefits of the
         dual outcomes of energy production and water storage or surface
         utilization through beneficial reclamation

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14. The bidder/lessee will be locked into his minimum offered kerogen
    impacted schedule as his minimum annual payments will be based on
    that. Impacted kerogen includes processed, left behind and
    unprocessed, and wasted kerogen by what ever cause. If he impacts
    more he will pay more. If he impacts less than the base, he will pay
    for the base. If he produces more products for a reduced total
    production costs, for the same share, he gets a larger total return.
    If his formula for sharing is based on his share increasing as his
    production costs decreases, then he gets an even larger return. The
    bidder has to figure out what payment formula produces his maximum
    net proceeds and also those of the US government---in competition
    with other bidders.

15. This lessee payment system relies on competition setting the most
    attractive benefit terms for the US citizen for the kerogen resource
    development incorporating effectiveness of resource recovery, and
    technical and economic effectiveness of the process technology. The
    bidder with the most effective technology and resource recovery, who
    offers dual benefits, can also offer the best benefits to the
    federal government---a win, win developmental approach. If a bidder
    with the best technology in terms of both effectiveness and
    economics, but fails to offer the US citizen a fair or maximum
    return, could be beat out by a bidder with somewhat worse technology
    but who is willing to give the US citizen more total return.

16. This system essentially eliminates issues of what the 'product" is,
    what "production" is, achieving and enforcing MER, and trying to
    figure out a royalty and bonus bid that provides a fair return to
    the US citizen---both at the start of the lease and as production
    costs and product prices change with time. It eliminates issues
    associated with due diligence, minimum production, and penalties.

17. Although the proposed competitively determined lease payment system
    will be argued to be to complex it requires no more information up
    front or later from the lessee, and it requires no more information
    which the BLM must ultimately develop, or obtain from the lessee,
    than that which is required by the proposed BLM leasing systems
    accounting rules. It will be argued that production costs are not
    required---well the internal revenue service requires both
    production and cost data to determine net income and therefore the
    lessee must provide this to the government ultimately in any event.

18. A lease payment system must consider the following facts. Kerogen
    has no value without technology to convert it into hydrotreated oil
    and processed gas. Technology, no matter how effective, to pyrolyze
    the kerogen and convert it into hydrotreated oil and processed gas
    has no value if the owner has no access to the kerogen. The
    challenge is to develop a leasing monetary system where US citizens
    and the developers of technology/projects receive a fair share or
    return, for: (1) the resource; and (2) the risk and investment of
    money, time and intellect into the development of both technology
    and projects. Besides a fair return, it behooves both parties to
    insure technological processes are required to be energy efficient,
    energy self sufficient, resource recovery effective, and
    environmentally benign as possible. Coming up with that system
    requires production cost information, and accommodation of changes
    in both production costs and product market prices over time. Both
    the US citizen, and the lessee/developer, should share in the
    difference between the time varying product price and the production
    cost---i.e. the net proceeds. As the net proceeds increase the share
    split must address which of the parties deserves, if either is
    deserving of a large share. In order to benefit both parties,
    incentives should be present to reduce production costs.

This eliminates many issues:

(1) No need to define what the products are or the point of
    determination. That's up to the lessee to figure out, and he will
    soon figure out that he needs to maximize raw shale oil production,
    and minimize char production for each pound of kerogen in the ground
    and for each pound of kerogen processed, and utilize the raw shale
    gas for downstream hydrotreating.

(2) No need for most quantitative accountability on products since it's
    up to the lessee to maximize the total quantity of the most high
    value products.

(3) No need to figure out a royalty rate formula since the total fair
    return to the US citizen is incorporated in the amortized bonus
    payments based on the competitive value of the total quantity of
    kerogen in the ground/leasehold. No need to figure out whether the
    royalty rate is too high or too low to encourage developers to go
    forward. No need to tie the royalty rate to product price, net
    proceeds, etc. since there would be no royalty rate. In fact the
    definition of a royalty is: a share of production free of the costs
    of production.

(4) no need to determine maximum economic recovery, once the lessee has
    paid the competitive value for all the kerogen involved it will
    behoove him to recover and process as much as is economically
    recoverable. If competitor "A" cannot economically recover as much
    as "B" he will not be able to bonus bid as much, and therefore will
    not get the lease.

There is a need to insure that the annual rate of kerogen pyrolyzed,
consumed, or effected in any way is at, or less than, the planned rate,
and therefore that amortized bonus payments are at or higher than the
value of that kerogen. In other words it must be determined that actual
consumption does not exceed the planned payments. It will be argued that
determining the total amount of kerogen in a lease hold is too difficult
to determine. It will also be argued that determining how much has been
utilized wasted, or left behind each year will also be too
difficult---particularly for in-situ operations.

The counter argument is that under the subject proposed rules the same
determination must be made to come up with a fair market value, and to
also determine that unavoidable waste is not occurring. The subject
proposed rules obscure getting to the issue of total net fair return to
the US citizen since it is the sum of the bonus bid plus the royalties
collected over the period of operation. Total royalties paid under the
proposed rules will depend on the total resource recovered/impacted,
recovery efficiency, and process efficiency. The only mechanism to
obtain maximum resource recovery is the "waste" clause---which is
adversarial at best---no incentive to lessee. On the contrary the
amortized kerogen bonus bid approach requires a fixed payment every year
and a fixed total payment, and therefore incentivizes the lessee to
recover the maximum amount of resource and process it as efficiently as
possible.

An amortized kerogen bonus bid payment could also be tied or adjusted to
either product prices, net proceeds, or both. An applicant could offer
various types of kerogen bonus bid payment structures with their
attendant risks and hedge benefits and the DOI/BLM could award leases
based on the most attractive competitive offering

**[F5 A market price and/or net proceeds approach---intended and
unintended consequences]{.underline}**

A net proceeds approach, some with a sliding scale, was discussed by
several commenters. One suggested the net proceeds be based on the
difference between the product price and highest cost production in the
industry (i.e. the marginal producer). This provides a competitive
advantage for the cost effective producer, which should be the
case---but may not encourage (1) A-E. The highest cost producer may have
the best technology in regards to (1) A-E. He may produce more high
quality oil and gas, he may use less energy doing it, he may totally
energy self sufficient, and have the lease environmental impact. Under
this scenario he would have the same royalty rate as the lowest cost
producer---but his royalty payments from the same resource would be much
larger since he producer more total product of higher quality, used no
external energy and was energy self sufficient thus reducing total net
national energy consumption, and had lower environmental impact. It is
clear that a fair return of both money and other less quantifiable
"returns/benefits" to the US citizen will not be obtained in this case.

**[F6 Bonus Bids and Royalties---intended and unintended
consequences]{.underline}**.

Bonus Bids and Royalties are the two means whereby a fair return to US
citizens is supposedly achieved. If royalties are too high to achieve a
profit based on known mature technology and production costs then no one
will bid on the lease offering. Presumably if the royalty rate is too
low, competitors will offer bonus bids such that when the bonus bid is
added to the costs of production plus royalties, they can still make a
reasonable profit. It could also be argued that processes which
incorporate (1) A-E would also be the most cost effective, and therefore
a competitor with that type of technology could offer a higher bonus
bid, and still make a profit. **This may not be the case as now
discussed**. A competitors technology may exploit a hygrading technology
approach whereby he does none of (1) A-E, He produces less net product
from the resource, he is not energy efficient, nor energy self
sufficient, he does not produce Fischer Assay oil or TOSCO assay gas,
and he has a large environmental impact---but his cost per unit of net
product for (which may also be of lower quality) may be lower. It could
also be higher, and he could make less profit. What does the US citizen
receive? He may get a higher bonus bid, but he gets fewer royalties, and
his total return will be less. Besides the simple bottom line dollars
received, there are other used economic, environmental, and strategic
losses. Less total high quality oil and gas produced from a given oil
shale resource will have a net negative impact on the US economy and the
world at large---first the reduced total dollar amount and its
integrated effect, second is the reduction in the quantity of oil/gas
available, and third is the strategic and trade/balance of payments
impacts.

Nothing in the proposed rules incorporates (1) A-F. The proposed rules
simply boil down to highest bonus bid wins\-\--good technology,
development of better technology, and Joe Citizen have a high
probability of losing.

**[F7 Summary of Status of BLM Oil Shale RDD Program, PEIS, & Commercial
Rules]{.underline}**

There never was a need for the BLM RDD 160 acre tract size for RDD, nor
the 40 acre tracts initially proposed. The five 160 acre Colorado RDD
tracts will pyrolyze only .1-2 acres per tract as target zones. All
surface tract needs for infrastructure and even underground freeze
walls, etc. could have been met with surface leases with severed
minerals rights. The Utah RDD lease will pyrolyze only about 16 acres at
essentially commercial scale.

Although the commercial rules have a minimum lease tract size of 160
acres, obtaining such a tract by a small entity will prove impossible.
First the minimum bonus bid is \$1000/acre, second parcels must be
competed for with big oil and wealthy speculators which will increase
the bonus bid way above the minimum, and thirdly, after a small entity
nominates a 160 acre parcel, it must pass through the BLM delineation
process which will increase the tract size offered for sale possibly up
to the maximum allowed of 5760 acres. The required bonus bid to obtain
the smallest tract possible, although the minimum would be \$160,000,
may well be orders of magnitude more than that thereby eliminating small
entities from competition.

20 Nominations---not 19 (See also Randall's comments).

3 to RDS, 24 sections, 24 billion barrels, 2.4 \$ trillion

EGL and OSEC have sold out majority or large fractions of operations.

OSEC and CVX have switched technologies

RDS has withdrew Colorado State Licensing Applications, scaled back
development.

CVX has switched from EA described hot gas heating pyrolysis to
supercritical carbon dioxide dissolution.

OSEC produced a few hundred barrels of oil from Utah shale at Taciuk
pilot plant in Canada.

RDS, CVX, and EGL have produced no oil under the program.

Not significant results for a program started in November 22,
2004---almost 4 years ago

Final PEIS issued. It is not a PEIS as mandated by the EP Act, rather a
land use plan. Per the EP Act, commercial rules cannot be issued until a
real PEIS is issued.

The commercial rules are pretty much a give away to big oil and wealthy
speculators. Onerous barriers erected against small entrepreneur/oil
shale technology developers gaining access to federal oil shale.

**[F8 Where is the value of new technology---proven intellectual
property factored in here---and in particular encouragement to develop
such---and rewards there from??]{.underline}**

A national cook-off of oil shale technology would open the opportunity
up for individuals and organizations to develop intellectual property
and be rewarded for that technology---to the benefit of the nation as a
whole.

The DOI/BLM Bush/Cheney administration (which I voted for twice)
wittingly or unwittingly has structured the federal oil shale
development program such that it provides a blank check for big oil and
wealthy speculators, and even smaller organizations that have strong
political connections particularly within the Republican party---and
closes the door for individuals and small business to develop technology
with merit for the benefit of the nation.