SUMMARY OF DATA TO BE USED IN ECONOMIC MODELING Prepared for James Covington, III Engineering an Analysis Division Office of Water U. S Environmental Protection Agency 401 M Street, SW Washington, DC 20460 Prepared by Eastern Research Group, Inc. 110 Hartwell Avenue Lexington, MA 02421 March 2000 2 SUMMARY OF DATA TO BE USED IN ECONOMIC MODELING 1.0 Introduction EPA is developing a methodology to examine the economic and financial impacts of the syntheticbased drilling fluids ( SBF) guidelines on deepwater oil and gas projects in response to comments from industry that these projects are vastly different from the projects analyzed as part of the Offshore Oil and Gas Effluent Guidelines economic analysis. At proposal, EPA relied on the results of that latter analysis showing Gulf of Mexico projects to be only minimally affected by even the most stringent drilling waste option ( the zero discharge option). Because of the unique nature of deepwater projects and because of their greater distance from shore, industry believes deepwater projects need to be evaluated for economic impacts resulting from options considered for the rule.

EPA is thus developing a computer model similar to the one used for the Offshore rulemaking ( U. S. EPA, 1993), and also nearly identical to the one developed for the Main Pass operations in the Gulf of Mexico investigated during the Coastal Oil and Gas Effluent Guidelines rulemaking ( see U. S. EPA,

1996). This model uses a discounted cash flow approach to determine whether a regulatory action would have impacts on production, project life, net present value, or other potentially measurable impacts. The major differences of this model compared to the Main Pass model are the inputs. EPA collected information on projects in the deep water Gulf of Mexico from industry and others to develop the appropriate parameters for model deepwater projects, including production figures, produced water treatment costs, other operating and maintenance ( O& M) costs, project construction costs, wellhead oil and gas prices, and other information. This information will be used in two versions of the financial model one for existing projects ( the BAT model) and one for new projects ( the NSPS model). The collected data are available in Section III. G. 2 of the Rulemaking Record.

The following sections present the general data requirements for modeling deepwater projects 3 ( Section 2), the specific projects that will be used for modeling impacts on deepwater projects, along with summaries of data collected that characterize the financial conditions at these projects ( Section 3),

construction timing assumptions that will be made for projects expected to be built in the future ( for use in the NSPS model version see Section 4), and an estimate of capital and operating costs incurred in the baseline, given data collected and assumptions provided by industry ( see Section 5). The last section ( Section 6) discusses some preliminary observations that can be made about the potential for impacts on deepwater projects prior to the actual running of the financial model.

2.0 Data Inputs Required by the Deepwater Oil and Gas Financial Model To model the baseline and postcompliance financial situation in the deepwater Gulf of Mexico,

EPA needs a variety of information that characterizes deepwater oil and gas projects. Table 1 shows the data required for input to the model, the source of the data, and any assumptions associated with the data.

Some of these assumptions, particularly the assumptions on baseline operating costs, may be subject to change, based on discussions with industry.

Table 1: Data Needs, Assumptions, and Sources of Data for the Oil and Gas Financial Model.

Parameter Comment Lease cost From MMS data ( MMS, 1999a). See Table 2.

Number of wells drilled to date From MMS data ( MMS, 1999d). See Table 4.

Structure characteristics ( e. g., type of platform) From MMS data ( Regg, 1999). See Table 2.

Project timing ( number of years between leasing and exploratory drilling, between exploration and delineation, between delineation and development, and between development and operation) From MMS data. See Table 3 for data and sources of data.

Geophysical and Geological Costs $ 500,000 per lease ( Parker, 1999a).

Drilling costs $ 20 million for platform based development wells, $ 30 million for subsea wells, $ 25 million for exploratory wells. Sidetracks should be one half the cost of a regular borehole ( Parker, 1999b; 2000b).

Incremental drilling costs ( or savings) Provided by EPA's engineering contractor ( McIntyre, 2000). Parameter Comment 4 Platform ( additional infrastructure) cost $ 8/ BOE original proved reserves for small project, $ 7/ BOE for medium project and $ 5/ BOE for large project. Pipeline costs are assumed to be $ 500,000 per foot with a $ 13 million initial cost for small diameter pipelines and $ 750,000 per foot with a $ 35 million initial cost for large diameter pipelines ( Parker 2000b). Pipeline lengths were obtained from MMS ( MMS, 2000. See Table 4.

Rate of installation of development wells Data from MMS ( MMS, 1999d), with projections depending on past history and size of reserve. Reserve size will be allowed to vary up to 3 times its conservative, original proved size to accommodate reasonable worst case estimates of numbers of wells drilled in each project postcompliance.

Peak production rate Using MMS data on production ( MMS, 1999b) for the most recently installed wells in a project ( generally those which began production in 1998), EPA estimated the peak production rate of wells at each project. See Table 2.

Current existing production Data from MMS ( MMS, 1999b). See Table 2.

Production decline rates The Offshore EIA assumes 15 percent per year declines after a year at peak production for all well types. EPA will continue to use this assumption. Note that production overall at a project will not decline at 15 percent per year until the last development well is installed.

Operation & maintenance costs ( excluding variable costs of produced water treatment & discharge) $ 2/ BOE of production for small projects, $ 1.75/ BOE for medium projects and $ 1.50/ BOE for large projects ( Parker, 2000a).

Initial produced water production Data from MMS ( MMS, 1999b). See Table 2.

O& M costs for produced water ( per bbl) 50 cents per bbl of produced water ( Parker, 2000b).

Marginal corporate tax rates The Offshore EIA used 34 percent, which EPA will continue to use.

Severance taxes The Offshore EIA used no severance tax in federal waters, which is still the case.

Royalty rate Royalty rates for each lease have been obtained from MMS ( MMS, 1999a). They are generally 12.5 to 16.7 percent. These are maximum rates, and they can be adjusted downward. EPA will assume that maximum rates will be applied, however. See Table 2. Parameter Comment 5 Depreciation The Offshore EIA used the modified accelerated cost recovery system. EPA will continue to use this depreciation schedule.

Basis for depreciation The Offshore EIA used 100 percent of total capitalized costs. EPA will continue using this value.

Capitalized costs The Offshore EIA assumed intangible drilling costs are expensed, that IDCs represent 60 percent of the cost of production wells and their infrastructure, that integrated producers can expense 70 percent of IDCs ( 42 percent of well drilling costs) and independents can expense 100 percent ( 60 percent of well drilling costs), with the remainder capitalized and treated as depreciable assets.

Inflation rate EPA is using 3 percent.

Depletion Allowance For independents, 15 percent percentage depletion on up to 1,000 barrels of oil equivalent ( BOE) is assumed. For majors EPA will use cost basis depletion, which the tax code defines as ( leasehold costs adjusted for inflation minus depreciation minus salvage [ assumed 0]) times ( barrels of oil produced that year divided by recoverable reserves remaining at the beginning of the year [ includes number produced that year]).

Real discount rate OMB suggests the use of a 7 percent real discount rate for economic analyses. EPA will use 7 percent.

Wellhead price of oil and gas Based on the past 10 years of average wellhead prices for Federal Offshore oil and gas ( API, 1999), and assuming a $ 2/ bbl reduction from average wellhead oil prices and a 10 percent reduction from average wellhead gas prices to reflect greater transport distances associated with the deepwater fields ( Parker, 1999a), EPA is using $ 15/ bbl for oil and $ 1.80/ Mcf for gas. EPA will perform sensitivity analyses on lower and higher oil and gas prices as well.

3.0 Model Projects EPA investigated a number of deepwater projects for use as model projects. These projects included all currently operating projects, as well as a number that should come on line shortly. Over 30 projects fit this description. From these initial projects, EPA selected as many as possible to use in 6 modeling deepwater projects. Data availability was the primary criterion used in selecting the model projects. EPA selected all deepwater projects for analysis that operated in 1998 and that had original proved reserves data available in public documents. The most recent publicly available documents on proved reserves are those provided by MMS on their website, and these documents are current through December 31, 1996 ( MMS, 1999e). Proved reserves are used to distinguish the relative size of projects,

since the indication of the ultimate size of a project is reserves, not necessarily the current production ( new projects that have not completed the maximum number of wells that would be productive at any one time would end up classified as smaller than they will eventually become). Size of project is important, since results will be reported over a group of projects ( i. e, results for small, medium, and large projects) rather than project by project. Size of reserves also allows EPA to determine how many wells might be drilled at a project over time.

Using the data availability criterion, EPA reduced the number of projects that can be modeled to twenty. One project did not operate in 1998, and the others either have not yet started producing, or are so new that original proved reserves had not been calculated for them in December 1996. The twenty projects include four small projects ( original proved reserves of 10 million BOE or less, eight medium size projects ( original proved reserves approximately between 10 million and 100 million BOE), and eight large projects ( original proved reserves over 100 million BOE). These twenty projects will be used to model existing deepwater projects under BAT options. EPA further limited the number of projects to 15 for NSPS modeling purposes. The five projects removed ( Lena, Alabaster, Cognac, Bullwinkle, and Pompano) are either too old or their technologies are too dated for the purposes of projecting what future projects will look like ( Parker, 2000b).

Table 2 shows each of the projects that are used in the BAT model, along with the publicly available data associated with them ( production figures for 1998, number of leases associated with the field that are held by the primary operator, lease bid price in 1998 dollars, royalty rates, and type of project [ e. g., subsea, tension leg platform, or fixed platform]), among other information.

4.0 Timing Assumptions for NSPS Models 7 The timing of the project construction is important data in the NSPS model. Table 3 presents the information obtained from various MMS databases that allow the timing assumptions for NSPS projects to be made. Data for the 15 NSPS model projects include the platform construction date, the year of first production, the first lease year, the discovery date, the delineation date ( inferred from when the next exploratory wells were drilled after the discovery well), beginning of construction date ( generally inferred from date of first development well drilling or pipeline construction permit date), and beginning of production date ( generally the earliest production date seen for any well in the project). In a few cases the years between construction and production were reduced from 5 years to 4 years ( see notes to Table 9 Table 3. Timing Data and Assumptions for NSPS Projects Project Name Lease Year Discovery Date Delineation Date Beginning Construction Date Platform Completion Date 1st Production Date # Years Lease to Discovery # Years Discovery to Delineation # Years Delineation to Construction # Years Construction to Production Shasta ` 80 ` 81 ` 83 ` 94  ` 95 1 2 11 1 Diamond ` 84 ` 93 ` 93 ` 93  ` 93 9 0 0 0 VK862 ` 91 ` 95 ` 95 ` 95  ` 95 4 0 0 0 Rocky ` 93 ` 96  ` 96  ` 96 3 0 0 0 Zinc ` 74 ` 79 ` 79 ` 92  ` 93 5 0 13 1 Neptune ` 83 ` 88 ` 89 ` 94 ` 96 ` 97 5 1 5 3 Popeye ` 83 ` 85 ` 85 ` 94  ` 96 2 0 9 2 Jolliet ` 80 ` 82 ` 82 ` 87 ` 89 ` 90 2 0 5 3 Cooper ` 84 ` 90 ` 90 ` 90 ` 95 ` 95 6 0 0 5 Amberjack ` 83 ` 84 ` 87 ` 91 ` 91 ` 91 1 3 2 2 Mars ` 85 ` 92 ` 89 ` 91 ` 96 ` 96 4 0 3 4 Tahoe ` 84 ` 85 ` 85 ` 89  ` 94 1 0 4 5 Mensa ` 83 ` 87 ` 87 ` 96  ` 97 4 0 9 1 Auger ` 84 ` 87 ` 87 ` 90 ` 94 ` 94 3 0 3 4 Ram Powell ` 84 ` 85 ` 86 ` 97 ` 97 ` 97 1 1 6 5 Notes: Years between construction and production counted for Zinc and Popeye from pipeline application dates ( 1992 and 1994, respectively). Ram Powell and Amberjack show no years between 1st development well drilled and platform completion date, so the difference between delineation date and first development well drilled is split to estimate the length of the construction phase. Mars has a discovery date of 1992, but the discovery well was drilled in 1989 and thus 1989 is assumed the actual discovery year for computing the time between discovery and delineation.

Sources: MMS, 1999a; MMS, 1999b; MMS, 1999d; MMS, 1999f; and MMS, 2000. 11 3) due to the way the model is constructed ( up to 4 years of construction time are hardwired into the model). This change should have little to no effect on model results.

5.0 Model Project Costs Table 4 presents the cost information provided by the industry working group ( Parker, 1999a,

1999b, and 2000) used with the data extracted from MMS. The first column of Table 4 uses the total barrels of oil equivalent produced in 1998 ( See Table 2) to compute annual operating costs, assuming these costs are $ 2.00/ BOE for small, $ 1.75/ BOE for medium and $ 1.50/ BOE for large projects. The O& M cost for produced water treatment is computed as $ 0.50 times the total annual volume of water shown in Table 2 ( the model will vary this cost over time, since water production can increase over time). Costs of drilling wells are assumptions provided by industry as shown in Table 1 ( Parker, 1999b). The well counts in table 2 are then broken down by development, sidetrack, and exploratory designations. When numbers of wells times appropriate well costs are computed, the result can be seen in the column entitled Total Well Cost To Date. Platform cost uses the Original Proved Reserves reported in Table 2 times the assumed $ 7/ BOE for medium projects and $ 5/ BOE for large projects ( Parker, 1999b) ( note: small projects are subsea completions and thus do not have platform costs associated with them). Pipeline length is obtained from MMS ( 2000). Pipeline costs are provided by industry ( Parker, 2000b). In addition, the following assumptions are used in computing the costs of pipelines:

If several pipelines were installed on or about the same day at a project ( e. g., one gas pipeline and one oil pipeline), one fixed pipeline setup cost is assumed to apply and the total miles of all pipelines times the appropriate per mile cost is used ( depending on size reported see below).

All pipelines with dimensions of 14" or less are assumed small. Those over 14" are considered large.

Pipelines labeled " UMB" are umbilical lines ( electrical cables, etc.), which may have an additional cost, but these tend to be very small ( 3 inches). Costs were not computed for these lines.

Costs for proposed pipelines that have an approval date similar to other active pipelines, but that did not go into service at the same time are not estimated because it is assumed that the operator would have installed a proposed pipeline at the time the others were installed to save set up costs, but since they did not, it is assumed the operators changed their minds about installing that 12 pipeline. Also not estimated were costs for any pipelines that had a " cancel" code, but costs for any pipelines no longer in use or removed are estimated.

One setup cost and one set of mileage costs are assumed for one project with pipelines within pipelines. There are six 4" pipelines within a 28" pipeline, all in a 3 mile stretch. The 18" cost of setup and pipeline cost per mile were used.

Costs for very short pipelines ( e. g., under 100 feet) were ignored.

Costs are assigned to the project regardless of who the pipeline operator is ( in some cases the project operator is not the pipeline operator).

Using all of these assumptions, the total pipeline cost is computed.

Costs of leases are shown in Table 2, and are used for computing the total project development costs in last column of Table 4. Note that projects not assigned a total investment cost to date are those that will not be used in the NSPS modeling.

6.0 Preliminary Observations Based on the data collected to date and the assumptions provided by industry, the following observations are made.

Zero discharge of drilling waste will cost an additional $ 151,420 for each deepwater exploratory well and $ 125,020 for each deepwater development well ( McIntyre, 2000). Industry has provided baseline costs of drilling deepwater wells of $ 20 to $ 30 million for deepwater development wells and $ 25 million for deepwater exploratory wells. Zero discharge costs thus are only about 0.6 percent of baseline drilling costs. Furthermore, a typical ( median) small project currently ( 1998) produces revenues of about $ 13.0 million per year ( based on an assumed $ 15/ bbl of oil and $ 1.80 per Mcf of gas), a typical medium project produces revenues of about $ 51.8 million per year, and a large project currently produces revenues of about $ 214.8 million per year ( see Table 4 for estimated revenues). Zero discharge costs per year ( assuming approximately 2 wells per year are added at all but the small projects, which are assumed to add one every other year for this exercise) are no more than 0.5 percent of average current project annual revenues for each size group. 13 Furthermore, because well drilling is not an operating cost ( which drives operating earnings and thus affects shut in decisions), lifetime production will only be affected if the net present value of the project is positive in the baseline and negative in the postcompliance scenario. If this happens, the project either is assumed to shut in ( or never be built) as a response to the rule, or stop drilling wells, if it appears that the revenues from those wells are unlikely to cover the incremental costs of drilling the wells postcompliance. Thus except for very marginal projects, or for projects near the end of their economic lives ( with a very small remaining earnings stream), EPA does not expect these costs to drive the net present value of most projects negative. However, because averages can obscure the effects at the most vulnerable projects, EPA will be looking closely at the potential for option costs to cause any measurable impacts at projects that do conform to the parameters of the average project using the financial model.

Although model outputs will be reported in the aggregate by project size, each individual project will be represented in the model inputs to allow EPA to identify impacts more precisely.

The projects likeliest to show some potential for impact under the zero discharge scenario are the smallest projects ( both existing and new, if the existing projects continue to drill), the oldest existing projects ( such as Lena and Cognac, which have produced over 80 percent of their original proved reserves as of 1996), or very marginal projects. Because any project could be marginal when all the factors are accounted for, even the relatively small cost of the SBF rule under the zero discharge scenario could have an impact on one or more projects, although, at this time, EPA believes this possibility is small. Under the discharge options, however, any costs are so small ( ranging from a cost savings of $ 53,000 per well to a cost of about $ 8,000 per well [ McIntyre, 2000] that it is unlikely these costs would have any measurable impacts on deepwater projects. Nevertheless, EPA will model these regulatory options as well.

REFERENCES American Petroleum Institute ( API), 1999. Basic Petroleum Data Book. Petroleum Industry Statistics. January, 1999.

McIntyre, Jamie, 2000. Personal communication between Anne Jones, Eastern Research Group and Jamie McIntyre, Pechan Avanti, February 1, 2000.

MMS, 1999a. www. gomr/ mms. gov/ homepg/ pubinfo/ freeascii/ leasing/ freelease. html. " Lease Data," ASCII file, downloaded 9/ 30/ 99. 14 MMS, 1999b. www. gomr/ mms. gov/ homepg/ pubinfo/ freeascii/ product/ freeproduct. html. " Production for 1998." ASCII file, downloaded 9/ 27/ 99.

MMS, 1999c. www. gomr/ mms. gov/ homepg/ pubinfo/ freeascii/ geologic/ freegeol. html. " Field Names Master List Appendix B and Appendix C." ASCII files, downloaded 10/ 25/ 99.

MMS, 1999d. www. gomr/ mms. gov/ homepg/ pubinfo/ freeascii/ well/ freewell. html. " Borehole." ASCII file, downloaded 9/ 1/ 99.

MMS, 1999e. www. gomr/ mms. gov/ homepg/ pubinfo/ freeascii/ geologic/ estimated1996. html, " 96_ his. zip." " Reserve History for Proved Fields by Field and Year, December 31, 1996.

MMS, 1999f. www. gomr/ mms. gov/ homepg/ pubinfo/ freeascii/ platform/ freeplat. html. " Platform Masters." ASCII file, downloaded December 15, 1999.

MMS, 2000. www. gomr/ mms. gov/ homepg/ pubinfo/ pdfindex. html. " Segment List in Comes From Order." PDF file, February 3, 2000.

Parker, Michael, 1999a. Personal communication between Michael Parker, Exxon, and EPA, December 7, 1999.

Parker, Michael, 1999b. Personal communication between Michael Parker, Exxon, and EPA, December 20, 1999.

Parker, Michael, 2000a. Personal communication between Michael Parker, Exxon, and EPA, January 3, 2000.

Parker, Michael, 2000b. Personal communication between Michael Parker, Exxon, and EPA, February 2, 2000.

Regg, James, 1999. " Deepwater Production and Discoveries," MMS, August 4, 1999.

U. S. EPA, 1993. Economic Impact Analysis of Final Effluent Limitations Guidelines and Standards of Performance for the Offshore Oil and Gas Industry. EPA 821 R 93 004, January, 1993.

U. S. EPA, 1996. Economic Impact Analysis of Final Effluent Limitations Guidelines and Standards for the Coastal Subcategory of the Oil and Gas Extraction Point Source Category, EPA 821 R 96 022, October, 1996.


[Federal Register Volume 80, Number 50 (Monday, March 16, 2015)]
[Notices]
[Pages 13525-13526]
[FR Doc No: 2015-05864]

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[FR Doc. 2015-05864 Filed 3-13-15; 8:45 am]
 BILLING CODE 6717-01-P


Administration – suggestions that were incorporated in the version
dated May 2007. The current version of the paper reflects minor
revisions made to address additional comments received subsequent to the
distribution of the paper in the docket to EPA’s proposed amendments
to the SPCC rule in October 2007.”

The paper was drafted in response to claims by DOE regarding the
characteristics of production facilities, discharges from these
facilities and the composition of produced water.  The paper represents
an overview of publicly available data including data from DOE and their
website.

XIV.G.vi  Lack of Context to Spill Volumes

COMMENT

“Using data from the National Reporting Center (NRC), the Abt Report
concludes that the number of incidents from 2000 through 2005
‘…remained relatively constant during the six-year period, with an
average of 501 incidents per year.’ Similarly, the average release was
approximately 548,000 gallons per year. How do these incidents relate to
the scope of oil that the industry manages yearly? Using EPA’s
assessment of the number of onshore facilities of 166,000, 500 releases
represent 0.30 percent of the operations. From a volumetric standpoint,
548,000 gallons is about 13,050 barrels. Based on information in ‘IPAA
Oil & Gas Producing Industry in Your State’ and the National Ocean
Economics Program, onshore production of oil and natural gas liquids in
2004 totaled about 2,001,000,000 barrels. The oil spill volumetric loss
was approximately 0.00065 percent of the total volume produced.” [210]

RESPONSE

To address the concern that there is insufficient context to assess the
relative scale of the volume, EPA has added a new Section 2.3.5,
“Significance of Oil Discharge Frequency and Volume” to summarize
the findings and provide additional context for the annual spill volume.
In addition to relating the volume discharged to the total production of
crude oil from onshore fields, the paragraph also provides information
on the effects that such discharges may have on the local environment,
drawing on examples from past discharges from production facilities
reported by EPA Regions. Additionally, the section summarizes available
information on the costs of responding and cleaning oil discharges,
including reference to Section 5 (“Oil Spill Cleanup and Remediation
Costs”).

XIV.H	Produced Water Storage Containers

XIV.H.i	 General

Issue: In the December 5, 2008 amendments, EPA finalized two
alternatives for produced water containers at oil production facilities.
Under the first alternative, EPA exempted certain produced water
containers at oil production facilities from the requirements of the
SPCC rule if a PE certified, as part of the SPCC Plan, that based on the
efficiency of the oil/water separation technology used, the contents of
a produced water container, if completely discharged, would not contain
oil in amounts that may be harmful, as described in 40 CFR part 110; the
capacity of the exempted containers would not count towards the facility
aggregate oil storage capacity. Under the second alternative, for those
produced water containers that are not eligible for the exemption, the
facility owner/operator could comply with general secondary containment
requirements and conduct visual inspections, maintenance and corrective
action, in lieu of sized secondary containment, if a PE described in the
Plan and certified that a practice was established that was designed to
remove the amount of free-phase oil from the produced water container on
a scheduled and routine basis.

COMMENT

Support

Support for exemption (first alternative).  Several comments supported
the exemption of produced water containers and wet gas production
facilities under §112.9(c)(6)(i) of the rule. (211, 220, 226, 227)

Support for exemption from sized secondary containment with additional
measures (second alternative). One comment supported the alternative
option at §112.9(c)(6)(ii) for non-exempt produced water containers
because “it also protects the environment while allowing flexibility
for the regulated community.” (211)  Several other comments stated
that produced water containers located at oil production facilities
should be subject to the wastewater treatment exemption to the same
extent as similar facilities in other industrial sectors. (195, 210,
244)

Exempt produced water from SPCC requirements. Several comments stated
that produced water should not be regulated under this rule. (209, 210,
223, 240)  One comment stated that regulation of produced water is
outside of the SPCC rule’s jurisdiction. (209)

No PE certification for exemption. Two comments suggested (209, 227)
that an exempt produced water container should not have to be certified
by a Professional Engineer because “the cost of complying with SPCC
requirements for these tanks far outweighs whatever minimal benefit may
be gained by imposing these requirements.” (227)

Oppose

Oppose. Several comments opposed the exemption of produced water tanks
from the sized secondary containment rule. (188, 192, 197, 202, 206,
207, 208, 215, 239) “This implies that the agency has historically
taken a container by container based approach for applicability, this is
untrue, the EPA has required that an operator determine if their
‘facility’ poses a threat of discharge, not a specific container.
EPA provides no explanation why a produced water container should be
allowed to be exempted out the rule, when all along the applicability
determination was facility based not container based. The lack of
rationale and record should be the basis for removing this provision for
produced water container.” (206)  “Even though it is unlikely that
most produced water containers can meet the requirement not to discharge
oil in a harmful quantity to navigable waters, should a separation
system at a facility be efficient enough to prevent such a discharge,
then it would not be regulated under the SPCC Rule of 1973 or the rule
of 2002. Therefore the exemption proposed in this amendment is
superfluous and confusing. There is also a higher potential for abuse of
the exemption and PE's could be placed under unwarranted pressure to
make certifications they doubt a facility owner or operator can
maintain.” (202) “… production sector is the only sector showing
an increasing trend in frequency of spills. Common sense suggests
reducing requirements including no or inadequate secondary containment
would only magnify the problem.” (192) “EPA has always said an oil
with anything else is an ‘oil.’ So [neither] a produced water tank
which is just water with no sheen, nor oil content which would violate
water quality standards, was [n]ever regulated. So this exemption is not
needed and has no scientific basis. It just makes it more confusing
about which tanks are regulated and which are not.” (215)

Produced water containers should be fully regulated as bulk containers.
Many comments stated that produced water containers should be fully
regulated under this rule and the relief withdrawn. (202, 203, 207, 215,
218) Some felt that the section on produced water is confusing and
unnecessary. (202, 203) “EPA should eliminate these rule provisions
for produced water containers because the rationale for the relief…is
flawed.” (207) One comment stated that very few PEs would risk their
licenses by certifying produced water containers to not have oil, and as
such, this provision should be withdrawn. (205)

Other Oil Mixtures.  One comment questioned why EPA would regulate
agricultural mixes (e.g. pesticides) more strictly than produced water
when “produced water containers commonly have oil and these containers
may be of much greater capacity than crude oil tanks or pesticide
containers.” (202)

Inefficiency of Separation and Treatment.  One comment noted, generally,
that “separation systems typically in use at onshore oil production
facilities tend to be very inefficient.” (202)

RESPONSE

The Agency is amending the December 2008 rule to remove all rule
elements associated with the exemption for produced water containers.
However, the Agency is retaining the alternative option for produced
water containers to comply with general secondary containment and
additional oil spill prevention measures including a PE-certified
program to remove free-phase oil from the surface of the produced water
container in lieu of the sized secondary containment requirements.

Alternative Option for Secondary Containment.  EPA acknowledges comments
that expressed general support for, as well as opposition to, the
alternatives for produced water containers finalized in the December
2008 notice (73 FR 74236, December 5, 2008). Good general secondary
containment practices can be successfully implemented in lieu of sized
secondary containment, if such practices are designed by a PE in
consideration of site-specific factors and in combination with
additional oil spill prevention practices. The Agency acknowledges that
owners and operators of produced water containers may use a process to
remove free-phase oil on a regular scheduled basis.  To address this,
the Agency is retaining the option for owners and operators of produced
water containers to comply with alternative measures in lieu of sized
secondary containment when a PE describes in the Plan and certifies a
procedure or process to remove free-phase oil (e.g., a skimming program)
has been established and the facility complies with general secondary
containment requirements; visual inspection; corrective action or
repairs to the container; and prompt removal or actions to
stabilize/remediate oil discharges from produced water containers.

Furthermore, the Agency acknowledges that skimming operations at
produced water containers may operate similarly to separation operations
at flow-through process vessels when free phase oil is being removed or
recovered from them on a regular basis. Therefore, including the
additional compliance measures for produced water containers with
procedures to minimize the amount of free-phase oil, including
remediation and inspections, is appropriate and consistent with
alternative compliance options provided for other bulk storage
containers (i.e. flow-through process vessels) which separate oil and
water mixtures.  As with flow-through process vessels at oil production
facilities, EPA remains concerned that these produced water containers
operate at unattended, often remotely located facilities, and has added
the additional provisions for maintenance, inspection, and remediation
to maintain environmental protection. The Agency agrees with comments
that expressed concern regarding the threat of discharges from produced
water containers. Oil may be present not only in free-phase, but also in
other forms, such as in a dissolved phase, emulsion or sludge at the
bottom of the produced water container. EPA is addressing these concerns
by retaining the additional spill prevention measures in addition to
general secondary containment for these containers.

Removal of Exemption for Produced Water Containers.  After reviewing
comments and relevant facts, the Agency is maintaining its position on
produced water as stated in the 2002 final rule (July 17, 2002, 67 FR
47068).

Several comments supported an exemption of produced water containers
from SPCC regulation. These comments stated that produced water
containers should not be subject to the rule. Most of the comments
received focused on the composition of the produced water mixture and
noted that produced water generally contains varying quantities of oil.
While none of the comments offered detailed information on the amount of
free-phase oil measured in produced water containers as requested by
EPA, they generally confirm that the presence of oil in produced water
is not exceptional, but rather is expected as a matter of regular
operations. Oil may be recovered even after the produced water has
undergone several separations at the onshore production facility, prior
to reinjection of the produced water into the geological formation.
Comments support observations by Agency personnel during inspections
that produced water containers have an oil layer floating on top of the
water. One comment indicated that produced water contains about 0.1
percent oil, but did not indicate whether this fraction represents oil
dissolved or suspended in the produced water mixture and whether
produced water containers may accumulate additional oil as a free-phase
layer. Information received by the Agency from other sources, which are
summarized in the EPA document Considerations for the Regulation of
Onshore Oil Exploration and Production Facilities Under the Spill
Prevention, Control, and Countermeasures Regulation, May 30, 2007
(EPA-HQ-OPA-2007-0584-0015) , indicates that while the fraction of oil
dissolved or suspended within the aqueous phase may be low, additional
oil is often found as a free-phase layer floating at the surface of the
produced water container. In the event of a discharge, the aqueous phase
of the produced water mixture may serve to carry the oil farther
overland and into waters than cases where crude oil alone is discharged.

The Agency agrees with comments that a fluid containing no oil is not
subject to SPCC requirements. A container that does not hold oil is not
regulated under the SPCC rule; therefore, a specific exemption for a
produced water container that holds no oil is unnecessary. However, EPA
echoes comments by noting that generally, produced water containers may
contain oil in sufficient quantity to cause a harmful discharge. In
fact, the Agency received no specific information on whether there are
unique characteristics to differentiate produced water containers from
other bulk storage containers found at onshore oil production
facilities, and none that warrant differentiated treatment.

The Agency received no additional data on the efficiency of separators
typically found at onshore oil production facilities or comments on how
the separation efficiency may vary over time. The Agency agrees that
residence time is a key factor in achieving separation of the crude oil
from other well fluids. Many oil production facilities rely on
gravitational separation and long retention times to separate the crude
oil. Based on information reviewed by the Agency, included in the docket
in EPA documents titled Considerations for the Regulation of Onshore Oil
Exploration and Production Facilities Under the Spill Prevention,
Control, and Countermeasures Regulation, May 30, 2007
(EPA-HQ-OPA-2007-0584-0015) and Summary of DOE Comments and Response,
June 6, 2008 (EPA-HQ-OPA-2007-0584-0175), separation equipment found at
onshore oil production facilities are not perfectly efficient at
separating oil from the produced fluids and residual oil may remain with
the produced water and further separate in the quiescent conditions
present in the produced water container. Furthermore, separation
equipment can become less efficient with age and use, thus allowing more
oil into a produced water container. It is therefore common for a layer
of oil to accumulate in a produced water container. Good general
secondary containment practices can be successfully implemented in lieu
of sized secondary containment, if such practices are designed by a PE
in consideration of site-specific factors and in combination with
additional oil spill prevention practices.  The Agency acknowledges that
owners and operators of produced water containers may use a process to
remove free-phase oil on a regular scheduled basis.  To address this,
the Agency is retaining the option for owners and operators of produced
water containers to comply with alternative measures in lieu of sized
secondary containment when a PE describes in the Plan and certifies a
procedure or process to remove free-phase oil (e.g., a skimming program)
has been established and the facility complies with general secondary
containment requirements; visual inspection; corrective action or
repairs to the container; and prompt removal or actions to
stabilize/remediate oil discharges from produced water containers.

EPA does not agree with comments stating that produced water containers
located at oil production facilities should be subject to the wastewater
treatment exemption to the same extent as similar facilities in other
industrial sectors. In the 2002 amendments (67 FR 47068) the Agency
stated that production facilities are normally unattended and therefore
lack constant human oversight and inspection. Produced water generated
by the production process normally contains saline which is an oil
contaminant.  In the case of a discharge, the oil as well as the saline
could aggravate environmental conditions.  Additionally, the goal of an
oil production, oil recovery, or oil recycling facility is to maximize
the production or recovery of oil while eliminating impurities in the
oil, including water.  The goal of a wastewater treatment facility is to
purify water.

Neither an oil production facility nor an oil recovery or oil recycling
facility treats water; they treat oil. For purposes of this exemption,
produced water is not considered wastewater, and treatment of produced
water is not considered wastewater treatment. Therefore, a facility that
stores, treats, or otherwise uses produced water remains subject to the
rule. At oil drilling, oil production, oil recycling, or oil recovery
facilities, treatment units subject to the rule include open oil pits or
ponds associated with oil production operations, oil/water separators
(gun barrels), and heater/treater units. Open oil pits or ponds function
as another form of bulk storage container and are not used for
wastewater treatment. Open oil pits or ponds also pose numerous
environmental risks to birds and other wildlife.

In some cases produced water containers are used as part of the
separation process. In the preamble of the 2008 rule, EPA stated that
produced water containers are similar to flow through-process equipment
when they are used as separators (71 FR 74288, December 5, 2008).
However, one comment pointed out that produced water containers are
typically atmospheric storage tanks, whereas, process vessels have a
pressure rating above atmospheric. EPA agrees with the comment and
acknowledges that produced water containers are typically used as
storage containers at the end of the separation process. Produced water
containers are bulk storage containers and therefore are subject to the
bulk storage container requirements under §112.9(c).

EPA agrees with comments arguing that spill data show that produced
water containers are a common source of oil discharges from onshore oil
production facilities. The Agency’s analysis of spill notification
data compiled by the National Response Center (NRC) for the period of
2000 through 2005, for example, identified 314 oil discharges described
as having originated from tanks, including over a quarter specifically
described as involving produced water containers, compared to 20 percent
from crude oil stock tanks (the remaining 55 percent involved tanks
holding unspecified fluids). The Agency believes that additional
discharges may have been reported to State and local authorities.

Produced water containers may be equally or even more likely to fail
than other containers in the tank battery. Information reviewed by the
Agency and presented in an EPA paper titled Considerations for the
Regulation of Onshore Oil Exploration and Production Facilities Under
the Spill Prevention, Control, and Countermeasures Regulation, May 30,
2007 (EPA-HQ-OPA-2007-0584-0015) showed corrosion as a common cause of
oil and produced water discharges at onshore oil production facilities.
The higher salt content of produced water fluids as compared to crude
oil may lead to the increased corrosion rate of metallic components of
the produced water storage system. The oil production process is
configured to send continuously flowing and treated well fluids to the
storage containers, with the produced water containers often located at
the end of that process. The Agency’s review of the circumstances of
past oil discharges reported to the NRC shows that produced water
containers often receive the additional well fluids when treatment
equipment or appurtenances fail or when a pumper’s scheduled visit is
delayed, thereby increasing the amount of oil entering the produced
water container and the risk that the container will overflow. Finally,
the primary responsibility of the lease pumper or lease operator is to
maximize oil production. Incentives and daily activities therefore
naturally focus on crude oil stock tanks, which hold the marketable
product, rather than the produced water containers.

Produced water can cause harm to surface waters, flora, fauna, and other
sensitive resources and ecosystems. As described in Considerations for
the Regulation of Onshore Oil Exploration and Production Facilities
Under the Spill Prevention, Control, and Countermeasure Regulation
(EPA-HQ-OPA-2007-0584-0015) and Summary of DOE Comments and Response,
June 6, 2008 (EPA-HQ-OPA-2007-0584-0175), the impacts of produced water
discharges are similar to the impacts observed following other oil
discharges. Additionally, the co-location of oil production facilities
with other land users, including farmers and ranchers, raises additional
concern over potential contamination of water resources that are
essential to agricultural production. One comment indicated concern that
produced water could contaminate surface waterways, groundwater and
drinking water; kills fish, birds, and wildlife; and cause severe health
effects in humans and impact wildlife habitats.  The comment also noted
that it takes only a small amount of oil to affect a large area of land
or water. EPA agrees with this comment. Under 40 CFR part 110, a
discharge of oil in such quantities as “may be harmful” is defined
as one that may violate applicable water quality standards; or cause a
film or sheen upon or discoloration of the surface of the water or
adjoining shorelines; or cause a sludge or emulsion to be deposited
beneath the surface of the water or upon adjoining shorelines. In the
Federal Register notice published when EPA provided revisions to 40 CFR
part 110, EPA stated that “[e]vidence from reviews of laboratory
studies further demonstrates that very small amounts of oil, e.g., less
than 1 mg/L (1 ppm) can have lethal and sub-lethal effects on a wide
variety of organisms.”  (52 FR 10716, April 2, 1987).  Therefore, even
if a produced water container has a very small amount of oil, the
container still holds the potential to cause harm.  Based on these facts
EPA recognizes the point made by a comment questioning the inequity of
regulating oil water mixtures contained in agricultural mixes (e.g.
pesticides) more strictly than produced water when “produced water
containers commonly have oil and these containers may be of much greater
capacity than crude oil tanks or pesticide containers.”

Furthermore, EPA agrees with comments that the exemption for produced
water containers predicated on a container-based approach is
inconsistent with the determination of applicability of the oil
pollution prevention regulation which is based on a facility-wide
determination.

XV.H.ii  Production Issue Paper as it Related to December 2008 Produced
Water Container Amendments

Issue: Several comments referenced the Production Issue Paper when
questioning the approaches proposed in the 2007 Notice of Proposed
Rulemaking.

Production sector shows no decrease in spill frequency.  “The Oklahoma
Corporation Commission data shows no decrease in the frequency of spills
or average volume of spills despite the fact that crude oil production
has decreased by 32% in that state.  It also shows that spills of up to
300,000 gallons occur in one year alone in that one state.  So the NRC
data showing an average spill volume of 548,000 for the entire nation
seems vastly underestimated.”  [192]  “EPA should not even consider
reducing requirements for a major industry group which has such a large
number and volume of spills as identified in the Docket
EPA-HQ-OPA-2007-0584-0015. Accordingly, the production sector is the
only sector showing an increasing trend in frequency of spills. Common
sense suggests reducing requirements including no or inadequate
secondary containment would only magnify the problem. The ERC data shows
that production activities account for 1/3 of the volume of spills by
all industry sectors and 1/5 of the frequency of spills.” [192]

Production issue paper supports withdrawal of December 2008 Final
Amendments, particularly produced water.  “Cost of the changes and so
called rationale in these amendments directly contradicts previous
statements in EPA rule making (for example that regarding produced
water). There is no scientific basis nor other valid data in the docket
to support these changes. Most of the real data in papers in the docket
support the opposite of what the rule is trying to do…The Agency needs
to look at what impact these proposals will have on the environment and
waters of the United States which are already in peril. All of these
rule amendments should be reviewed again and most should be withdrawn
permanently, especially regarding any reduction of secondary containment
and integrity testing or inspection requirements.”[239]

RESPONSE

The Agency is amending the December 2008 rule to remove the rule
amendment associated with the exemption of certain produced water
containers.  EPA agrees that information received by the Agency from
other sources, which are summarized in the EPA document Considerations
for the Regulation of Onshore Oil Exploration and Production Facilities
Under the Spill Prevention, Control, and Countermeasures Regulation, May
30, 2007, (EPA-HQ-OPA-2007-0584-0015) supports this action in addition
to the other rationale described above. The production paper was drafted
in response to claims by DOE regarding the characteristics of production
facilities, discharges from these facilities and the composition of
produced water.  The paper represents an overview of publicly available
data including data from DOE and their website. EPA has updated this
paper to address comments and concerns received during the comment
period, as discussed below. These updates do not change the underlying
substance of the report, which describes the characteristics of
production facilities.

XIV.I	Clarification of the Definition of “Permanently Closed”
Containers

Issue: EPA did not take any further regulatory action to address this
issue.  The SPCC rule exempts from applicability and from capacity
threshold determinations any oil storage container that is
“permanently closed.”

COMMENT

 [No comments were submitted on this topic.]

XIV.J	Oil and Natural Gas Pipeline Facilities

Issue: The final rule makes no change in these provisions and is not
otherwise intended to impose new requirements on DOT-regulated oil and
natural gas pipelines. Rather, by granting new flexibility in
delineating facility boundaries, the final rule should reduce
uncertainty and minimize, where appropriate, overlapping regulation.

COMMENT

General support.  Several comments supported EPA and DOT in committing
to a revision of the 1971 MOU. (220, 226)

Incorporate a primary function test in agreement to determine
jurisdiction.  “Prior to the Administration Change, it was our
understanding that EPA and PHMSA were developing a new letter of
agreement incorporating a primary function test to determine
jurisdiction. The goal of this new agreement would be to eliminate gaps
and overlaps in the separate spill prevention regulations. API fully
supports this goal and would like to work with the agencies to provide
any information needed to complete this agreement to both agencies’
satisfaction.” (220)

RESPONSE

Several comments expressed support for the 2007 rule proposal in which
EPA and DOT committed to a revision of the 1971 MOU.  As stated in the
2008 final rule, EPA will continue to collaborate with DOT to work on
guidance for pipeline operators, where appropriate and where the
regulatory requirements are substantially equivalent to the extent
possible with respect to environmental protection.

EPA is committing to work with DOT to address confusion within the
regulated community. Under the 1971 Memorandum of Understanding (MOU)
between EPA and DOT (36 FR 24080, November 24, 1971) (See Appendix A of
part 112), transportation-related activities regulated by DOT and
non-transportation-related activities regulated by EPA are defined.
Based on the 1971 MOU, EPA has jurisdiction over
non-transportation-related facilities.

Equipment, operations, and facilities are subject to DOT jurisdiction
when they are engaged in activities subject to DOT jurisdiction. If
those facilities are also engaged in activities subject to EPA
jurisdiction (such facilities are considered a “complex”), such
activities would subject the equipment, operation, or facility to EPA
jurisdiction. “Complex” is defined in §112.2 as a “facility
possessing a combination of transportation-related and
non-transportation-related components that is subject to the
jurisdiction of more than one Federal agency under section 311(j) of the
Clean Water Act.” This definition was promulgated in 1994 (59 FR
34070, July 1, 1994) when EPA first required certain facility owners and
operators to prepare FRPs to respond to a worst-case discharge of oil
and to a substantial threat of such a discharge.  During the development
of the FRP rule, EPA and other Federal agencies with jurisdiction under
OPA and E.O. 12777 (including DOT) met to create an implementation
strategy that minimized duplication wherever practicable and recognized
State oil pollution prevention and response programs. One of the
critical outgrowths of these efforts was the development of a definition
for, and a consistent approach to regulate “complexes.” The
jurisdiction over a component of a complex is determined by the activity
involving that component. An activity at one time might subject a
facility to one agency’s jurisdiction, while a different activity at
the same facility using the same structure, container or equipment might
subject the facility to the jurisdiction of another agency for a
different purpose.

The Agency is concerned that the ‘‘primary function test’’
approach described in comments may circumvent the meaning of the term
“complex.”  EPA will continue work to improve guidance to address
regulatory jurisdiction at “complex” facilities. Owners and
operators have questioned how to determine whether a container (e.g., a
breakout tank), an activity (e.g., drag reducing agent storage/injection
or other transfer activities) or a facility (e.g., a terminal or a
pipeline facility) is considered “transportation-related” or
“non-transportation-related,” and, subsequently, whether DOT and/or
EPA regulatory requirements apply.  To clarify jurisdiction,
particularly regarding jurisdiction over breakout tanks and activities
at certain facilities, in February 2000, EPA and DOT signed a joint
memorandum regarding, “Jurisdiction over Breakout Tanks/Bulk Storage
Tanks (Containers) at Transportation-Related and
Non-Transportation-Related Facilities” (February 4, 2000). Industry
has raised questions and concerns about duplicative jurisdiction in the
joint memorandum and for other oil storage containers and activities not
specifically addressed by it.  EPA will continue to work with DOT/PHMSA
to provide such clarification and to minimize dual regulation, where
appropriate, and where the regulatory requirements are substantially
equivalent to the extent possible with respect to environmental
protection.XV. Manmade Structures

Issue: EPA stated that it is appropriate for a facility owner or
operator to consider man-made structure to determine how to comply with
the SPCC rule.  Given the clarifications provided in the preamble
discussion of the 2008 proposal, further regulatory action is not needed
to address this issue.

COMMENT

General support. One comment supported the clarifications regarding the
consideration of manmade features to meet the secondary containment
requirements and integrity testing requirements of the rule. (231)

RESPONSE

EPA agrees with the comment that supported the clarifications on
man-made structures and therefore maintains its position on this
clarification.

XVI.	Underground Emergency Diesel Generator Tanks

at Nuclear Power Stations

Issue: EPA exempted underground oil storage tanks including below-grade
vaulted tanks deferred under 40 CFR 280 that supply emergency diesel
generators at nuclear power generation facilities and that are subject
to design criteria under the Nuclear Regulatory Commission regulations.
This exemption includes both tanks that are completely buried and tanks
that are below-grade and vaulted.

COMMENT

Support

General Support.  Several comments generally supported the amendments in
order to avoid dual regulation by EPA and NRC. (211, 238, 247, 253, 255,
256, 257, 259, 260, 261, 262, 263, 264, 265, 268, 269)

RESPONSE

The Agency agrees with comments supporting the exemption for underground
oil storage tanks including below-grade vaulted tanks deferred under 40
CFR 280 that supply emergency diesel generators at nuclear power
generation facilities and that are subject to design criteria under the
Nuclear Regulatory Commission regulations. EPA is making a technical
correction to amend the provision at §112.1(d)(4) and clarify that this
exemption applies to “any underground oil storage tanks including
below-grade vaulted tanks, deferred under 40 CFR part 280, as originally
promulgated, that supply emergency diesel generators at a nuclear power
generation facility licensed by the Nuclear Regulatory Commission,
provided that such a tank is subject to any Nuclear Regulatory
Commission provision regarding design and quality criteria, including
but not limited to 10 CFR part 50.” (Emphasis added to show modified
wording.) This technical correction should make this provision easier to
understand.Wind Turbines

Issue:  The Agency addressed the applicability of the rule to wind
turbines and finds that wind turbines meet the definition of oil-filled
operational equipment.  Thus, owners or operators of this equipment can
take advantage of the alternative compliance option provided for this
type of equipment, to the extent that the wind turbines meet the oil
storage capacity threshold in the rule.

COMMENT

General support.  Several comments generally supported this amendment.
(247, 253, 255, 256, 257, 259, 260, 261, 262, 263)

RESPONSE

The Agency agrees with comments supporting this clarification.  EPA
maintains its position on this clarification.XVIII. Delay of the
Effective Date of the Rule

Issue: On January 29, 2009, in accordance with the January 20, 2009,
White House memorandum entitled "Regulatory Review" and the Office of
Management and Budget memorandum entitled, "Implementation of Memorandum
Concerning Regulatory Review," EPA delayed by 60 days the effective date
of the final rule that amends the Spill Prevention, Control, and
Countermeasure (SPCC) regulations promulgated in the Federal Register on
December 5, 2008. This action delayed the effective date of the
amendments to April 4, 2009.  EPA requested public comment on the delay
of the effective date.

COMMENTS

Support

General support. Several comments supported making the rule effective on
April 4, 2009. (200, 214, 222, 232, 233)

Oppose

Delaying date may result in harm. One comment stated that delaying the
effective date of the rule any further may result in environmental harm,
and unnecessary compliance confusion and costs. (232)

No justification to delay further. Several comments stated that there is
no reason or justification to further delay the effective date of the
rule. (214, 222)

Alternative Approaches Suggested

Rule should be reviewed further before becoming effective. “The rule
was obviously rushed through to provide changes to the regulation which
benefit industry, not the environment…Either withdraw the entire rule
permanently or extend the effective date indefinitely until each
proposal can be carefully reconsidered and acted upon without unbiased
pressure from special interests.” (239)

Uncertainty of applicability should allow for more time. “The
uncertainty surrounding the applicability of the SPCC regulations to
natural gas pipeline facilities makes it difficult to adequately and
efficiently prepare SPCC plans… It would not be unreasonable to extend
the effective date for natural gas pipeline facilities to a year after
the finalization of the EPA/DOT jurisdictional issues.” (242)

RESPONSE

The Agency agrees with the comments that support delay of the effective
date.  In accordance with the January 20, 2009 White House memorandum
entitled, “Regulatory Review,” and the memorandum from the Office of
Management and Budget entitled “Implementation of Memorandum
Concerning Regulatory Review” (M-09-08, January 21, 2009 OMB
memorandum),   SEQ CHAPTER \h \r 1   SEQ CHAPTER \h \r 1 the effective
date of the December 2008 rulemaking was delayed for 60 days, from
February 3, 2009 to April 4, 2009 (These memorandums are available for
review in the docket for this rulemaking.) The Agency took this action
to ensure that the rule properly reflected consideration of all relevant
facts. Accordingly, EPA requested public comment on the delay of the
effective date and its duration, and on the multiple regulatory
amendments contained in the final rule (74 FR 5900, February 3, 2009).
On April 1, 2009, the Agency further delayed the effective date of the
December 2008 rulemaking until January 14, 2010 (74 FR 14736). The
Agency took this action to allow sufficient time to address the comments
received on the February 3, 2009 notice.

While the delay to January 14, 2010 was needed to allow time to
adequately address the concerns raised about the December 2008 rule, the
Agency disagrees with comments that suggested an indefinite delay, or a
delay contingent on resolution of EPA/DOT jurisdictional issues.  The
jurisdictional issues are broader than this action and do not justify a
delay of the effective date. Additionally, many gas and liquid pipeline
facilities are complexes that store oil as part of a non-transportation
related activity and meet the rule’s eligibility requirements, and
therefore have already been subject to the SPCC requirements.  A
majority of December 2008 rule provided regulatory relief so a further
delay of the effective date is not needed.  EPA and DOT will continue to
address jurisdictional concerns outside the regulatory process.  It is
appropriate to now have a date certain for facilities to be able to take
full advantage of the flexibility and compliance options offered in the
SPCC rule amendments, including the December 2008 rule.  EPA will
continue to work with DOT to minimize dual regulation, where
appropriate, and where the regulatory requirements are substantially
equivalent with respect to environmental protection. XIX. Further Delay
of the Effective Date of the Rule

Issue: On April 1, 2009, EPA published a notice in the Federal Register
delaying the effective date of the December 5, 2008 amendments from
April 4, 2009 to January 14, 2010.  EPA also requested comment on
whether a further extension of the effective date may be warranted.

COMMENTS

Support

Extend effective date to 2013.  One comment urged EPA to extend the
effective date of the amendments for oil production facilities to a date
no earlier than November 20, 2013, the date previously proposed by EPA
for qualified facilities. The comment cites justification for this
extension based on rationale provided by EPA in an earlier rulemaking:
“The proposed dates will allow this sector ample time to make changes
to their facilities and to their SPCC Plans necessary to comply with the
revised requirements. This extension will also provide the Agency with
sufficient time to initiate work with relevant trade associations, the
Interstate Oil and Gas Compact Commission and the Department of Energy
on outreach and compliance assistance tools to help qualified oil
production facilities to develop their self-certified Plans.” (73 FR
72019, November 26, 2008). (251)

Oppose

Most amendments were not controversial, so effective date should not be
delayed any further.  Several comments opposed any further delay beyond
January 14, 2010 since most, if not all of the December 5, 2008
amendments, were noncontroversial and generated few adverse comments.
(252, 255)

Further delay would make compliance impossible based on the current July
1, 2009 compliance date.  Several comments pointed out that the new
effective date (and any later date) is too close to the current
compliance date to allow regulated facilities to effectively understand
and comply with the new rule.  (247, 253, 255, 256, 257, 259, 260, 261,
262, 263, 267)

Alternative Approaches Suggested

Allow at least the many non-controversial portions of the December 5,
2008 SPCC final rule to become effective immediately. (254, 252)

RESPONSE

At this time the Agency is not considering a further delay in the
effective date of January 14, 2010.  Most of the provisions in the
December 2008 action were non-controversial and the Agency is making
minor or no change to many provisions.  Publication of the current
action is expected approximately one year in advance of the current
compliance date of November 10, 2010.  The Agency never proposed an
effective date November 20, 2013, as one commenter indicated.  However,
EPA recognizes that because of the changes in this action, and
specifically provisions that have been removed from the December 2008
amendments, facilities may need additional time to comply with the SPCC
amendments. Because of the uncertainty surrounding the final amendments
to the December 5, 2008 rule and the delay of the effective date, the
Agency will propose to extend the compliance date.

 The Interstate Oil and Gas Compact Commission estimates that there are
422,255 marginal oil wells as of January 1, 2007. (IOGCC Marginal Wells:
2007 Report)

 EPA has updated this paper to address comments and concerns received
during the comment period. These updates do not change the underlying
substance of the report, which describes the characteristics of
production facilities. This updated version of the paper has been
included in the docket for this rulemaking.

 See Interstate Oil and Gas Compact Commission, 2006: “Marginal Wells:
Fuels for Economic Growth”, p. 4 (defining “stripper wells” as
wells that produce 10 barrels of oil per day or less).

 Berton J. Fisher and Kerry L. Sublette. Environmental Releases from
Exploration and Production Operations and Oklahoma: Type, Volume,
Causes, and Prevention, in Environmental Geosciences, V. 12, No. 2 (June
2005), pp. 89-99.

 Since the publication of the notice of proposed rulemaking for which
this document provides a summary of public comment, the Agency has
further delayed the effective date to January 14, 2010.

 PAGE

 PAGE   1


[Federal Register Volume 83, Number 7 (Wednesday, January 10, 2018)]
[Notices]
[Page 1254]
[FR Doc No: 2018-00278]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

Combined Notice of Filings #1

    Take notice that the Commission received the following electric
rate filings:

    Docket Numbers: ER18-594-000.
    Applicants: Southwest Power Pool, Inc.
    Description: Sec.  205(d) Rate Filing: 3371 KAMO Electric and GRDA
Interconnection Agreement to be effective 1/1/2018.
    Filed Date: 1/3/18.
    Accession Number: 20180103-5141.
    Comments Due: 5 p.m. ET 1/24/18.

    Docket Numbers: ER18-595-000.
    Applicants: Aurora Generation, LLC, Rockford Power, LLC, Rockford
Power II, LLC.
    Description: Request for Limited Waiver of Aurora Generation, LLC,
et al.
    Filed Date: 1/3/18.
    Accession Number: 20180103-5189.
    Comments Due: 5 p.m. ET 1/17/18.

    Docket Numbers: ER18-596-000.
    Applicants: Springdale Energy, LLC, Helix Ironwood, LLC.
    Description: Request for Limited Waiver of Springdale Energy, LLC
and Helix Ironwood, LLC.
    Filed Date: 1/3/18.
    Accession Number: 20180103-5192.
    Comments Due: 5 p.m. ET 1/17/18.

    Take notice that the Commission received the following qualifying
facility filings:

    Docket Numbers: QF18-454-000.
    Applicants: Otsego Paper Inc.
    Description: Form 556 of Otsego Paper Inc. under QF18-454.
    Filed Date: 1/3/18.
    Accession Number: 20180103-5179.
    Comments Due: None Applicable.

    The filings are accessible in the Commission's eLibrary system by
clicking on the links or querying the docket number.
    Any person desiring to intervene or protest in any of the above
proceedings must file in accordance with Rules 211 and 214 of the
Commission's Regulations (18 CFR 385.211 and 385.214) on or before 5:00
p.m. Eastern time on the specified comment date. Protests may be
considered, but intervention is necessary to become a party to the
proceeding.
    eFiling is encouraged. More detailed information relating to filing
requirements, interventions, protests, service, and qualifying
facilities filings can be found at: http://www.ferc.gov/docs-filing/efiling/filing-req.pdf. For other information, call<PHONE_NUMBER>
(toll free). For TTY, call<PHONE_NUMBER>.

    Dated: January 4, 2018.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
[FR Doc. 2018-00278 Filed 1-9-18; 8:45 am]
 BILLING CODE 6717-01-P


[Federal Register Volume 78, Number 32 (Friday, February 15, 2013)]
[Rules and Regulations]
[Page 11092]
[FR Doc No: 2013-3755]

=======================================================================
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LABOR DEPARTMENT

Occupational Safety and Health Administration

29 CFR Part 1926

Safety and Health Regulations for Construction

CFR Correction

    In Title 29 of the Code of Federal Regulations, Part 1926, revised
as of July 1, 2012, on page 225, in Sec.  1926.152, paragraph (c)(16)
is added to read as follows:

Sec.  1926.251  Rigging equipment for material handling.

* * * * *
    (c) * * *
    (16) Wire rope slings shall have permanently affixed, legible
identification markings stating size, rated capacity for the type(s) of
hitch(es) used and the angle upon which it is based, and the number of
legs if more than one.
* * * * *
[FR Doc. 2013-3755 Filed 2-14-13; 8:45 am]
BILLING CODE 1505-01-D


[Federal Register Volume 77, Number 5 (Monday, January 9, 2012)]
[Notices]
[Pages 1111-1114]
[FR Doc No: 2012-111]

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SECURITIES AND EXCHANGE COMMISSION

[Release No. 34-66086; File No. SR-Phlx-2011-181]

Self-Regulatory Organizations; NASDAQ OMX PHLX LLC; Notice of
Filing and Immediate Effectiveness of Proposed Rule Change To Access
Service Fees

January 3, 2012.
    Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934
(``Act''),\1\ and Rule 19b-4 thereunder,\2\ notice is hereby given that
on December 21, 2011, NASDAQ OMX PHLX LLC (``Phlx'' or ``Exchange'')
filed with the Securities and Exchange Commission (``SEC'' or
``Commission'') the proposed rule change as described in Items I, II,
and III, below, which Items have been prepared by the Exchange. The
Commission is publishing this notice to solicit comments on the
proposed rule change from interested persons.
---------------------------------------------------------------------------

    \1\ 15 U.S.C. 78s(b)(1).
    \2\ 17 CFR 240.19b-4.
---------------------------------------------------------------------------

I. Self-Regulatory Organization's Statement of the Terms of Substance
of the Proposed Rule Change

    The Exchange proposes to amend the following Access Service Fees:
(i) the Trading/Administrative Booths and

Market Maker Trading Space Fee; (ii) the Specialist Post Fee; and (iii)
the Floor Facility Fee. The Exchange proposes to delete the following
Access Service Fees: (i) the Shelf Space on Equity Option Trading Floor
Fee; and (ii) Kiosk Construction Fee.
    While changes to the Fee Schedule pursuant to this proposal are
effective upon filing, the Exchange has designated these changes to be
operative on January 3, 2012.
    The text of the proposed rule change is available on the Exchange's
Web site at http://nasdaqtrader.com/micro.aspx?id=PHLXfilings, at the
principal office of the Exchange, and at the Commission's Public
Reference Room.

II. Self-Regulatory Organization's Statement of the Purpose of, and
Statutory Basis for, the Proposed Rule Change

    In its filing with the Commission, the Exchange included statements
concerning the purpose of and basis for the proposed rule change and
discussed any comments it received on the proposed rule change. The
text of these statements may be examined at the places specified in
Item IV below. The Exchange has prepared summaries, set forth in
sections A, B, and C below, of the most significant aspects of such
statements.

A. Self-Regulatory Organization's Statement of the Purpose of, and the
Statutory Basis for, the Proposed Rule Change

1. Purpose
    The purpose of the proposed rule change is amend the following
Access Service Fees: (i) the Trading/Administrative Booths and Market
Maker Trading Space Fee; (ii) Specialist Post Fee and (iii) Floor
Facility Fee to keep pace with rising overhead costs associated with
maintaining the trading floor. In addition, the Exchange proposes to
delete the Shelf Space on Equity Option Trading Floor Fee and the Kiosk
Construction Fee because these fees are not relevant and the Exchange
has absorbed such costs, respectively. Each fee will be described below
separately.

Trading/Administrative Booths and Market Maker Trading Space Fee

    The Exchange is proposing to amend the name of the ``Trading/
Administrative Booths and Market Maker Trading Space'' Fee to the
``Trading/Administrative Booths'' Fee. The Trading Post/Booth space is
physical space on the Exchange's trading floor, which space typically
is used by floor brokers and clearing firms. The Exchange is proposing
changes to the Floor Facility Fees, described in more detail below, and
therefore is amending the name of the Trading/Administrative Booths and
Market Maker Trading Space Fee to reflect the changes described below.
Registered Options Traders \3\ and SQTs \4\ would be assessed the Floor
Facility Fee, instead of this fee. Any floor participant may elect to
obtain a booth on the Exchange's trading floor. The Exchange is not
proposing to amend the fee rate of the Trading/Administrative Booths
Fee.
---------------------------------------------------------------------------

    \3\ A Registered Options Trader (``ROT'') includes a Streaming
Quote Trader (``SQT''), a Remote Streaming Quote Trader (``RSQT'')
and a Non-SQT, which by definition is neither a SQT or a RSQT. A
Registered Option Trader is defined in Exchange Rule 1014(b) as a
regular member or a foreign currency options participant of the
Exchange located on the trading floor who has received permission
from the Exchange to trade in options for his own account. See
Exchange Rule 1014 (b)(i) and (ii).
    \4\ An SQT is defined in Exchange Rule 1014(b)(ii)(A) as an ROT
who has received permission from the Exchange to generate and submit
option quotations electronically in options to which such SQT is
assigned.
---------------------------------------------------------------------------

Specialist Post Fee

    The Exchange proposes to amend the current fee structure for a
Specialist Post and instead assess a $3,000 fee for such a post.
Currently, Specialist Post Fees vary with the size of the post.
Specialist units are assessed a Specialist Post Fee of $1,125 per month
for a quarter post and $4,500 per month for a full post with a maximum
fee of $4,500 per month. The Exchange proposes modifying the fee
structure for a Specialist Post to assess the fee equally to all
Specialist units. Each individual Specialist would also be assessed a
Floor Facility Fee, as described below, which costs together (the
Specialist Post Fee and the Floor Facility Fee) would assist the
Exchange in recouping increasing occupancy costs, such as electricity
usage due to the increase of member computers on the trading floor. The
Exchange believes that the $3,000 Specialist Post Fee is consistent
with costs incurred by the Exchange for the usage of space on the
Exchange's trading floor \5\ by Specialists.
---------------------------------------------------------------------------

    \5\ There are some Specialist units that currently pay a $1,125
Specialist Post Fee that would experience an increased fee with the
proposed $3,000 fee rate, however these Specialist units comprise
less than two percent of the Specialist Units.
---------------------------------------------------------------------------

Floor Facility Fee

    The Exchange proposes to increase the Floor Facility Fee from $200
per month to $300 per month. Currently, the Floor Facility Fee is
applicable to floor members that are not currently assessed fees
related to the usage of a Trading/Administrative Booths and Market
Maker Trading Space Fee. The Floor Facility Fee is intended to fairly
allocate costs attendant to providing members with services necessary
to the conduct of business on the floor of the Exchange. The Exchange
proposes to increase this fee to offset the increased costs of
operating a trading floor facility. In addition to increasing this fee,
the Exchange proposes to apply the Floor Facility Fee to ROTs, SQTs and
individual Specialists \6\ located on the Exchange's trading floor.
Today, a ROT and SQT are assessed the Trading/Administrative Booths and
Market Maker Trading Space Fee and an individual Specialist is not
assessed such a fee. The Exchange also proposes to remove the qualifier
that the Floor Facility Fee is applicable to floor members that are not
currently assessed fees related to the usage of a Trading/
Administrative Booth or Market Maker Trading Space. Rather, ROTs, SQTs
and individual Specialists on the Exchange's trading floor would be
assessed a Floor Facility Fee. If a ROT or SQT also determined to
acquire a Trading/Administrative Booth, they would also be assessed
that fee as well. Each individual Specialist would be assessed this fee
and the Specialist unit would be assessed the Specialist Post Fee. In
the instance that an individual Specialist is also an SQT, that member
will only pay a $300 Floor Facility Fee per month; that Specialist
would not be assessed the fee for each capacity.
---------------------------------------------------------------------------

    \6\ A Specialist is an Exchange member who is registered as an
options specialist pursuant to Rule 1020(a). A Specialist Unit would
be assessed the Specialist Post Fee and the individual Specialist
would be assessed the Floor Facility Fee.
---------------------------------------------------------------------------

Shelf Space on Equity Option Trading Floor

    The Exchange maintained various fees on its Fee Schedule relating
to XLE, the Exchange's equity trading system. The Exchange ceased
operation of the technology used to operate XLE on October 24, 2008 and
filed a proposal to amend the administration and enforcement of certain
rules.\7\ The Exchange also filed to delete XLE Fee Schedule and
references to XLE fees

from the Fee Schedule.\8\ The Shelf Space on Equity Option Trading
Floor Fee should have been deleted along with the other XLE fees. This
fee inadvertently remained on the Fee Schedule. The Exchange proposes
to delete this outdated fee.
---------------------------------------------------------------------------

    \7\ See Securities Exchange Act Release No. 58613 (September 22,
2008), 73 FR 57181 (October 1, 2008) (SR-Phlx-2008-65). The Exchange
later filed to delete various Rules relating to XLE. See Securities
Exchange Act Release No. 64338 (April 25, 2011), 76 FR 24069 (April
29, 2011) (SR-Phlx-2011-13).
    \8\ See Securities Exchange Act Release No. 59030 (December 1,
2008), 73 FR 74548 (December 8, 2008) (SR-Phlx-2008-80).
---------------------------------------------------------------------------

Kiosk Construction Fee

    The Exchange proposes to amend the Fee Schedule to eliminate the
Kiosk \9\ Construction Fee. This fee was adopted in 2002 to require
individual Specialists and Specialist units to pay for the cost of
construction of a kiosk if the Specialist unit initiates the
construction request.\10\ The Exchange has not assessed this fee since
approximately 2008. The Exchange has determined to absorb this cost in
the few circumstances that it believes any construction would be
necessary going forward. The Exchange proposes to eliminate the Kiosk
Construction Fee.
---------------------------------------------------------------------------

    \9\ A kiosk is an open, flat surface that contains computer
terminals and allows the Specialist units to face the trading crowd.
    \10\ See Securities Exchange Act Release No. 458470 (April 20,
2002), 67 FR 30409 (May 6, 2002) (SR-Phlx-2002-30).
---------------------------------------------------------------------------

    While changes to the Fee Schedule pursuant to this proposal are
effective upon filing, the Exchange has designated these changes to be
operative on January 3, 2012.
2. Statutory Basis
    The Exchange believes that its proposal to amend its Fee Schedule
is consistent with Section 6(b) of the Act \11\ in general, and
furthers the objectives of Section 6(b)(4) of the Act \12\ in
particular, in that it is an equitable allocation of reasonable fees
and other charges among Exchange members.
---------------------------------------------------------------------------

    \11\ 15 U.S.C. 78f(b).
    \12\ 15 U.S.C. 78f(b)(4).
---------------------------------------------------------------------------

    The Exchange believes that it is reasonable to amend its Trading/
Administrative Booths Fee to eliminate the requirement that a market
maker, which includes a ROT and a SQT in this case, pay the $300
monthly fee. The Exchange also believes that it is reasonable to apply
the Floor Facility Fees to ROTs, SQTs and individual Specialists and
increase that fee to $300. Finally, the Exchange believes that it is
reasonable to assess all Specialist Units a Specialist Post Fee of
$3,000 instead of a fee based on the size of the post. The revenue from
these fees would assist the Exchange in defraying the occupancy costs
of maintaining the trading floor. The Exchange also believes that it is
reasonable to assess ROTs and SQTs the Floor Facility Fee instead of
the newly named ``Trading/Administrative Booths'' Fee in order that
market makers retain their own fee category. There is no impact in
terms of the amount such ROTS and SQTs will be assessed because both
fees, the Trading/Administrative Booths Fee and the Floor Facility Fee,
will be $300. Finally, the Exchange believes that removing the
qualifier that the Floor Facility Fee is applicable to floor members
that are not currently assessed fees related to the usage of a Trading/
Administrative Booth is reasonable because these fees are meant to
apply to different types of market participants. In the event that a
ROT or SQT determined that they would also require a booth, the
Exchange believes that the use of the booth should be a separate fee
from the Facility Fee.
    The Exchange also believes that the fee amendments to the newly
named Trading/Administrative Booths Fee, Specialist Post Fee and Floor
Facility Fees are equitable and not unfairly discriminatory because the
Specialist Post Fees are higher because Specialists generate higher
occupancy costs from electricity usage and other facility usage as
compared to other floor participants. The Specialist Post Fee combined
with the Floor Facility Fee would allow the Exchange to cover such
costs as cleaning, HVAC and general maintenance. All other floor
members would be assessed the Floor Facility Fee of $300 per month to
conduct business on the Exchange's trading floor. The Exchange believes
these fees are indicative of the costs attributable to each category of
participant. In addition, the amendment to the Specialist Post Fee
would cause all Specialist units to be uniformly assessed the same fee.
All individual Specialists would also be uniformly assessed a $300
Floor Facility Fee, which would be equal to the Trading/Administrative
Booths Fee paid by floor brokers and clearing firms, also $300 per
month. Only a small number of Specialist units would pay a higher cost
for Specialist Posts. When combining the Specialist Post Fee and Floor
Facility Fee some Specialists units/Specialists would experience a
higher fee overall, which fees are consistent with increased costs to
maintain the Exchange's trading floor. Other Specialist units/
Specialists would experience a lower fee overall. Finally, the Exchange
believes that removing the qualifier that the Floor Facility Fee is
applicable to floor members that are not currently assessed fees
related to the usage of a Trading/Administrative Booth is equitable and
not unfairly discriminatory because all members would be billed equally
for each service based on their participation and requests for space.
    The Exchange believes that eliminating the outdated Shelf Space on
Equity Option Trading Floor Fee is reasonable, equitable and not
unfairly discriminatory because there is no longer an equity trading
floor and the fee inadvertently remained on the Fee Schedule after the
shutdown of XLE. Similarly, the Exchange believes that eliminating the
Kiosk Construction Fee is reasonable, equitable and not unfairly
discriminatory because the Exchange has recently not received any
requests for construction and has determined to absorb such costs in
the future if such construction is necessary. By eliminating this fee,
no member on the Exchange's trading floor would be assessed for such a
cost.

B. Self-Regulatory Organization's Statement on Burden on Competition

    The Exchange does not believe that the proposed rule change will
impose any burden on competition not necessary or appropriate in
furtherance of the purposes of the Act.

C. Self-Regulatory Organization's Statement on Comments on the Proposed
Rule Change Received From Members, Participants, or Others

    No written comments were either solicited or received.

III. Date of Effectiveness of the Proposed Rule Change and Timing for
Commission Action

    The foregoing rule change has become effective pursuant to Section
19(b)(3)(A)(ii) of the Act.\13\ At any time within 60 days of the
filing of the proposed rule change, the Commission summarily may
temporarily suspend such rule change if it appears to the Commission
that such action is necessary or appropriate in the public interest,
for the protection of investors, or otherwise in furtherance of the
purposes of the Act. If the Commission takes such action, the
Commission shall institute proceedings to determine whether the
proposed rule should be approved or disapproved.
---------------------------------------------------------------------------

    \13\ 15 U.S.C. 78s(b)(3)(A)(ii).
---------------------------------------------------------------------------

IV. Solicitation of Comments

    Interested persons are invited to submit written data, views, and
arguments concerning the foregoing, including whether the proposed rule
change is consistent with the Act. Comments may be submitted by any of
the following methods:

Electronic Comments

     Use the Commission's Internet comment form (http://www.sec.gov/rules/sro.shtml); or
     Send an email to<EMAIL_ADDRESS>Please include
File No. SR-Phlx-2011-181 on the subject line.

Paper Comments

     Send paper comments in triplicate to Elizabeth M. Murphy,
Secretary, Securities and Exchange Commission, 100 F Street NE.,
Washington, DC 20549-1090.

All submissions should refer to File No. SR-Phlx-2011-181. This file
number should be included on the subject line if email is used. To help
the Commission process and review your comments more efficiently,
please use only one method. The Commission will post all comments on
the Commission's Internet Web site (http://www.sec.gov/rules/sro.shtml). Copies of the submission, all subsequent amendments, all
written statements with respect to the proposed rule change that are
filed with the Commission, and all written communications relating to
the proposed rule change between the Commission and any person, other
than those that may be withheld from the public in accordance with the
provisions of 5 U.S.C. 552, will be available for Web site viewing and
printing in the Commission's Public Reference Room, 100 F Street NE.,
Washington, DC 20549, on official business days between the hours of 10
a.m. and 3 p.m. Copies of such filing also will be available for
inspection and copying at the principal office of the Exchange. All
comments received will be posted without change; the Commission does
not edit personal identifying information from submissions. You should
submit only information that you wish to make available publicly. All
submissions should refer to File No. SR-Phlx-2011-181 and should be
submitted on or before January 30, 2012.

    For the Commission, by the Division of Trading and Markets,
pursuant to delegated authority.\14\
Kevin M. O'Neill,
Deputy Secretary.
---------------------------------------------------------------------------

    \14\ 17 CFR 200.30-3(a)(12).
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[FR Doc. 2012-111 Filed 1-6-12; 8:45 am]
BILLING CODE 8011-01-P