 1 316b Phase II Cost Module 1.0 Submerged Passive Intakes The modules described in this section involve submerged passive intakes, and address both adding technologies to the inlet of existing submerged intakes and converting shoreline based intakes ( e. g., shoreline intakes with traveling screens) to submerged offshore intakes with added passive inlet technologies. The passive inlet technologies that are considered include passive screens and velocity caps. All intakes relocated from shore based to submerged offshore are assumed to employ either a velocity cap or passive screens. The module discussing velocity caps begins in section 3.0.

1.1 Relocated Shore based Intake to Submerged Near shore and Offshore with Fine Mesh Passive Screens at Inlet This section contains three sections. The first section discusses the selection and deriviation of cost input values. This discussion includes: passive screen technology selection, selection of flow values, intake configurations, connecting walls, and connecting pipes. The second section discusses cost development for: screen construction materials, connecting walls, pipe manifolds, airburst systems, indirect costs, nuclear facilities, O& M costs, construction relatred downtime. The third section presents a discussion of the applicability of this cost module.

1.1.1 Selection/ Deriviation of Cost Input Values Passive Screen Technology Selection Passive screens come in one of three general configurations: flat panel, cylindrical, and cylindrical T type. Only passive screens constructed of welded wedgewire were considered due to the improved performance of wedgewire with respect to debris. After discussion with vendors concerning the attributes and prevalence of the various passive screen technology configurations, EPA selected the T screen configuration as the most versatile with respect to a variety of local intake waterbody attributes. The most important screen attribute was the requirement for screen placement. Both cylindrical and T screens allow for placement of the screens extending into the waterbody, which allows for debris to migrate away from the screens once dislodged. T screens produce greater flow per screen unit and thus were chosen because they are more practical in multi screen installations. Due to the potential for build up and plugging by debris, passive screens are usually installed with an airburst backwash system. This system includes a compressor, an accumulator ( aka receiver), controls, a distributor and air piping that directs a burst of air into each screen. The air burst produces a rapid backflow through the screen; this air induced turbulence dislodges accumulated debris, which then drifts away from the screen unit. Vendors claimed ( although with minimal or no supporting data) that only very stagnant water with a high debris load or very shallow water (< 2 ft deep) would prevent use of this screen technology. Areas with low water velocities would simply require more frequent airburst backwashes, and few facilites are constrained by water depths as shalllow as 2 feet..  2 SCREEN SIZE CAPACIT Y SLOT SCREEN LENGTH AIRBURST PIPE DIAMETER SCREEN OUTLET DIAMETER SCREEN WEIGHT GPM MM FT INCHES INCHES LBS T24 2,500 1.78 6.3 2 18 375 T36 5,700 1.78 9.3 3 30 1,050 T48 10,000 1.78 13.3 4 36 1,600 T60 15,800 1.78 16.6 6 42 2,500 T72 22,700 1.78 19.8 8 48 4,300 T84 31,000 1.78 22.9 10 60 6,000 T96 40,750 1.78 26.4 12 72 NA * Source: Johnson Screen  Brochure 2002  High Capacity Screen at 50% Open Area PASSIVE T SCREEN DESIGN SPECIFICATIONS While there are waterbodies with levels of debris low enough to preclude installation of an airburst system, EPA has chosen to include an airburst backwash system with each T screen installation as a prudent precaution. The capital cost of the airburst backwash system is a substantial component, particularly in offshore applications, because of the need to install a separate air supply pipe from the shoreline air supply to each screen or group of smaller screens. Thus, the assumption that airburst backwash systems are needed in all applications is considered as part of an overall cost approach that increases projected capital costs to the industry to develop a high side cost estimate.

T screens ranging in diameter from 2 feet ( T24) to 8 feet ( T96), in one foot intervals, are used in the analysis. The costs provided are for screens with a slot size of approximately 1.75 mm. The design flow values used for each size screen correspond to wedgewire T screens with a through screen velocity of 0.5 fps. Table 1 1 presents design specifications for the wedgewire T screens costed.

TABLE 1 1 Selection of Flow Values The flow values used in the development of cost equations range from a design flow of 2,500 gpm ( which is the design flow for the smallest screen ( T24) for which costs were obtained) to a flow of 163,000 gpm ( which is equivalent to the design flow of four T96 screens). The higher flow was chosen because it was equal to the flow in a 10 foot diameter pipe at a pipe velocity of just 4.6 fps. A 10 foot diameter pipe was chosen as the largest size for individual pipes because this size was within the range of sizes that are capable of being installed using the technology assumed in the cost model. Additionally, the need to spread out the multiple screens across the bottom is facilitated by multiple pipes. One result of this decision is that for facilities with design flows significantly greater than 163,000 gpm, the total costs are based on dividing the intake into multiple units and summing the costs of each.

Intake Configuration  3 The scenarios evaluated in this analysis are based on retrofit construction in which the new passive screens are connected to the existing intake by newly installed pipes, while the existing intake pumps and pump wells remain intact and functional. The cost scenario also retains the existing screen wells and bays, since in most cases they are connected directly to the pump wells. Facilities may retain the existing traveling screens as a backup, but the retention of functioning traveling screens is not necessary. No operating costs are considered for the existing screens since they are not needed. Even if they are retained, there should be almost no debris to collect on their surfaces. Thus, they would only need to be operated on an infrequent basis to ensure they remain functional.

The new passive screens are placed along the bottom of the waterway in front of the existing intake and connected to the existing intake with pipes that are laid either directly on or buried below the stream bed. The key components of the retrofit are: the transition connection to the existing intake, the connecting pipe or pipes ( a. k. a. manifold or header), the passive screens or velocity cap located at the pipe inlet, and if passive screens are used, the backwash system.

At most of the T screen retrofit installations, particularly those requiring more than one screen, the installation of passive T screens will likely require relocating the intake to a near shore location or to a submerged location farther offshore, depending on the screen spacing, water depth, and other requirements. An exception would be smaller flow intakes where the screen could be connected directly to the front of the intake with a minimal pipe length ( e. g., half screen diameter). Other considerations that may make locating farther offshore necessary or desirable include: the availability of cooler water, lower levels of debris, and fewer aquatic organisms for placements outside the littoral zone. As such, costs have been developed for a series of distances from the shoreline.

In retrofits where flow requirements do not increase, EPA has found existing pumps and pump wells can be, and have been, retained as part of the new system. The cost scenarios assume flow volumes do not increase. Thus, using existing pumps and pump wells is both feasible and economically prudent. There are, however, two concerns regarding the use of existing pumps and pump wells. One is the degree of additional head loss associated with the new pipes and screens. The second is the intake downtime needed to complete the installation and connection of the new passive screen system or velocity cap. The downtime considerations are discussed later in a separate section.

The additional head losses associated with the passive screen retrofit scenario described here include the frictional losses in the connecting pipes and the losses through the screen surface. If the new connecting pipe velocities are kept low ( e. g., 5 fps is used in this analysis), then the head loss in the extension pipe should remain low enough to allow the existing pumps to function properly in most instances. For example, a 48 inch diameter pipe at a flow of 2,800 gpm ( average velocity of 4.96 fps) will have a head loss of 2.31 feet of water per 1,000 foot pipe length ( Shaw and Loomis 1970). The new passive screens will contribute an additional 0.5 to 0.75 feet of water to this head loss, which will further increase when the screen is clogged by debris ( Screen Services 2002). In fact, the rate at which this screen head loss increases due to debris build up will dictate the frequency of use of the air backwash. Pump wells are generally equipped with alarms that warn of low water levels due to increased head loss through the intake. If the screen becomes plugged to the point where backwash fails to maintain the necessary water level in the pump well, the pump flow rate must be reduced.  4 This reduction may result in a derating or shut down of the associated generating unit. Lower than normal surface water levels may exacerbate this problem.

In terms of required dimensions for installation, Table 1 1 shows screen length is just over three times the diameter and each screen requires a minimum clearance of one half diameter on all sides except the ends. Thus, an 8 foot diameter screen will require a minimum water depth of 16 feet at the screen location ( four feet above, four feet below, and eight feet for the screen itself). It is recommended that T screens be oriented such that the long axis is parallel to the waterbody flow direction. T screens can be arranged in an end to end configuration if necessary. However, using a greater separation above the minimum will facilitate dispersion of the released accumulated debris during screen backwashes.

In the retrofit scenario described here, screen size and number are based on using a single screen with the screen size increasing with increasing design flows. When flow exceeds the capacity of a single T96 screen, multiple T96 screens are used. This retrofit scenario also assumes the selected screen location has a minimum water depth equal to or greater than the values shown in Table 1 2.

TABLE 1 2 MINIMUM DEPTH AT SCREEN LOCATION FOR SINGLE SCREEN SCENARIO Flow Screen Size Minimum Depth 2,500 gpm T24 4 ft 5,700 gpm T36 6 ft 10,000 gpm T48 8 ft 15,800 gpm T60 10 ft 22,700 gpm T72 12 ft 31,000 gpm T84 14 ft 40,750 gpm T96 16 ft > 40,750 gpm Multiple T96 16 ft In certain instances water depth or other considerations will require using a greater number of smaller diameter screens. For these cases the same size header pipe can be used, but the intake will require either more branched piping or multiple connections along the header pipe.

Connecting Wall The retrofit of passive T screen technology where the existing pump well and pumps are retained will require a means of connecting the new screen pipes to the pump well. Pump wells that are an  5 integral part of shoreline intakes ( often the case) will require installing a wall in front of the existing intake pump well or screen bays. This wall serves to block the existing intake opening and to connect the T screen pipe( s) to the existing intake pump wells. In the proposed cost scenario, the T screen pipe( s) can be attached directly to holes passing through the wall at the bottom.

Two different types of construction have been used in past retrofits or have been proposed in feasibility studies. In one, a wall constructed of steel plates is attached to and covers the front of each intake bay or pump well, such that one or more connecting pipes feed water into each screen bay or pump well individually. In this scenario, a single steel plate or several interlocking plates are affixed to the front of the screen bays by divers, and the T screen pipe manifolds are then attached to flanged fittings welded at the bottom of the plate( s). For smaller flow intakes that require a single screen, this may be the best configuration since the screen can be attached directly to the front of the intake minimizing the intrusion of the retrofit operation into the waterway.

In the second scenario, an interlocking sheet pile wall is installed in the waterbody directly in front of, and running the length of, the existing intake. Individual screen manifold pipe( s) are attached to holes cut in the bottom along the length of the sheet pile wall. In this case, a common plenum between the sheet pile wall and the existing intake runs the length of the intake. This configuration provides the best performance from an operational standpoint because it allows for flow balancing between the screen/ pump bays and the individual manifold pipes. If there are no concerns with obstructing the waterway, the sheet pile wall can be placed far enough out so that the portion of the wall parallel to the intake can be installed first along with the pipes and screens that extend further offshore. In this case, the plenum ends are left open so that the intake can remain functional until the offshore construction is completed. At that point, the intake must shut down to install the final end portions of the wall, the air piping connection to the air supply, and make final connections of the manifold pipes. EPA is not aware of any existing retrofits where this construction technique has been used. However, it has been proposed in a feasibility study where a new, larger intake was to be constructed offshore ( see discussion in Construction Downtime Section).

Costs were developed for this module based on the second scenario described above. These costs are assumed equal or greater than costs for steel plate( s) affixed to the existing intake opening, and therefore inclusive of either approach. This assumption is based on the use of a greater amount of steel material for sheet piles ( which is offset somewhat by the fabrication cost for the steel plates), the use of similarly sized heavy equipment ( pile driver versus crane), and similar diver costs for constructing pipe connections and reinforcements in the sheet pile wall versus installing plates. Costs were developed for both freshwater environments and, with the inclusion a cost factor for coating the steel with a corrosion resistant material, for saltwater environments.

Connecting Pipes The design ( length and configuration) of the connecting pipes ( also referred to as pipe manifold or header) is partly dictated by intake flow and water depth. A review of the pipe diameter and design flow data submitted to EPA by facilities with submerged offshore intakes indicates intake pipe velocities at design flow were typically around 5 fps. Note that a minimum of 2.5 to 3 fps is recommended to prevent deposition of sediment and sand in the pipe ( Metcalf & Eddy 1972). Also,  6 calculations based on vendor data concerning screen attachment flange size and design flow data resulted in pipe velocities ranging from 3.2 to 4.5 fps for the nominal size pipe connection. EPA has elected to size the connecting pipes based on a typical design pipe velocity of 5 fps.

Even at 5 fps, the piping requirements are substantial. For example, if the existing intake has traveling screens with a high velocity ( e. g., 2.5 fps through screen velocity), then the cross sectional area of the intake pipe needed to provide the same flow would be approximately one third of the existing screen area ( assuming existing screen open area is 69%). Given the above assumptions, an existing intake with a 10 foot wide traveling screen and a 20 foot water depth would require a 9.4 foot diameter pipe and be connected to at least four 8 foot diameter T screens ( T96). The flow rate for this hypothetical intake screen would be 155,000 gpm.

For small volume flows ( 40,750 gpm or less   see Table 1 2), T screens ( particularly those with a single screen unit) can be installed very close to the existing intake structure, as the upstream or downstream extensions of the screen should not be an issue. In the 10 foot wide by 20 foot deep traveling screen example above, each of the T96 screens required is 26 feet long. For this example, it is possible to place the four T96 screens directly in front of the existing intake connected to a single manifold extending 56 feet ( 2* 8+ 2* 8+ 2* 8+ 8) to the centerline of the last T screen. This is based on a configuration where the manifold has multiple ports ( four in this case) spaced along the top. However, this configuration will experience some flow imbalance between the screens. A better configuration would be a single pipe branching twice in a double " H" arrangement. In this case, the total pipe length would be 62 feet ( 20+ 26+ 2* 8). Therefore, a minimum pipe length of 66 feet ( 20 meters) was selected to cover the pipe installation costs for screens installed close to the intake.

Based on the above discussion, facilities with design flow values requiring multiple manifold pipes ( i. e., > 163,000 gpm) will require the screens to extend even further out. In these cases, costs for a longer pipe size are appropriate. Using a longer pipe allows for individual screens to be spread out laterally and/ or longitudinally. Longer pipes would also tend to provide access to deeper water where larger screens can be used. While using smaller screens allows for operations in shallower water, many more screens would be needed. This configuration covers a greater bottom area and requires more branching and longer, but smaller, pipes. Therefore, with the exception of the lower intake flow facilities, a length of connecting pipe longer than66 feet ( 20 meters) is assumed to be required.

The next assumed pipe length is 410 feet ( 125 meters), based on the PhaseI proposed rule cost estimates. A length of 125 meters was selected in Phase I costing as a reasonable estimate for extending intakes beyond the littoral zone. Additional lengths of 820 feet ( 250 meters) and 1640 feet ( 500 meters) were selected to cover the possible range of intake distances. The longest distance ( 1640 feet) is similar in magnitude to the intake distances reported for many of the Phase II facilities with offshore intakes located on large bodies of water, such as oceans and Great Lakes.

As described in the document Economic and Engineering Analyses of the Proposed Section 316( b) New Facility Rule, Appendix A, submerged intake pipes can be constructed in two ways. One construction uses steel that is concrete lined and coated on the outside with epoxy and a concrete overcoat. The second construction uses prestressed concrete cylinder pipe ( PCCP). Steel is generally used for lake applications; both steel and PCCP are used for riverine applications; PCCP  7 is typically used in ocean applications. A review of the submerged pipe laying costs developed for the Phase I proposed rule showed that the costs of installing steel and PCCP pipe using the conventional method were similar, with steel being somewhat higher in cost. EPA has thus elected to use the Phase I cost methodology for conventional steel pipe as representative of the cost for both steel and concrete pipes installed in all waterbodies. The conventional pipe laying method was selected because it could be performed in front of an existing intake and was least affected by the limitations associated with local topography.

While other methods such as the bottom pull or micro tunneling methods could potentially be used, the bottom pull method requires sufficient space for laying pipe onshore while the micro tunneling method requires that a shaft be drilled near the shoreline, which may be difficult to perform in conjunction with an existing intake. The conventional steel pipe laying cost methodology and assumptions are described in detail in the document Economic and Engineering Analyses of the Proposed Section 316( b) New Facility Rule, Appendix A.

1.1.2 Capital Cost Development Screen Material Construction and Costs Costs were obtained for T screens constructed of three different types of materials: 304 stainless steel, 316 stainless steel, and copper nickel ( CuNi) alloy. In general, screens installed in freshwater are constructed of 304 stainless steel. However, where Zebra Mussels are a problem, CuNi alloys are often used because the leached copper tends to discourage screen biofouling with Zebra mussels. In corrosive environments such as brackish and saltwater, 316 stainless steel is often used. If the corrosive environment is harsh, particularly where oxygen levels are low, CuNi alloys are recommended. Since the T screens are to be placed extending out into the waterway, such low oxygen environments are not expected to be encountered very often.

Based on this information, EPA has chosen to base the cost estimates on utilizing screens made of 304 stainless steel for freshwater environments without Zebra Mussels, CuNi alloy for freshwater environments with the potential for Zebra Mussels and 316 stainless steel for brackish and saltwater environments. Table 1 3 provides a list of states that contain or are adjacent to waterbodies where Zebra Mussels are currently found. The cost for CuNi screens are applied to all freshwater environments located within these states. EPA notes that the screens comprise only a small portion of the total costs, particularly where the design of other components are the same, such as the proposed design scenarios for freshwater environments with Zebra Mussels versus those without.  8 State Name Abbreviation Alabama AL Connecticut CT Illinois IL Indiana IN Iowa IA Kentucky KY Louisiana LA Michigan MI Minnesota MN Mississippi MS Missouri MO New York NY Ohio OH Oklahoma OK Pennsylvania PA Tennessee TN Vermont VT West Virginia WV Wisconsin WI List of States with Freshwater Zebra Mussels as of 2001 TABLE 1 3 Table 1 4 presents the component and total installed costs for the three types of screens. Installation and mobilization costs are based on vendor provided cost estimates for velocity caps, which are comparable to those for T screens. The individual installation cost per screen of $ 35,000 was reduced by 30% for multiple screen installations. Costs for steel fittings are also included. These costs are based on steel fitting costs developed for Phase I and are adjusted for a pipe velocity of 5 fps and converted to 2002 dollars. An additional 5% was added to the total installed screen costs to account for installation of intake protection and warning devices such as pilings, dolphins, buoys, and warning signs. 1 Note that this 50% value was derived by comparing the estimated costs of a sheet pile wall presented in a feasibility study for the Salem Nuclear Plant to the cost estimated for a similarly sized sheet pile wall using the EPA method described here. This factor was intended to cover the cost of items such as walers, bracing and installation costs not included in the Costworks unit cost. The Salem facility costs included bypass gates, which are assumed to be similar in cost to the pipe connections.

 9 SIZE NUMBER OF SCREENS CAPACITY AIR BURST EQUIPMENT SCREEN INSTALL ATION MOBILIZAT ION STEEL FITTING GPM 304SS 316SS CuNi 304SS 316SS CuNi T24 1 2,500 $ 5,800 $ 6,100 $ 8,000 $ 10,450 $ 25,000 $ 15,000 $ 2,624 $ 50,846 $ 51,161 $ 53,156 T36 1 5,700 $ 10,000 $ 11,200 $ 18,000 $ 15,050 $ 25,000 $ 15,000 $ 3,666 $ 56,349 $ 57,609 $ 64,749 T48 1 10,000 $ 17,000 $ 18,800 $ 31,700 $ 22,362 $ 30,000 $ 15,000 $ 5,067 $ 70,421 $ 72,311 $ 85,856 T60 1 15,800 $ 23,000 $ 26,200 $ 44,500 $ 28,112 $ 35,000 $ 15,000 $ 6,964 $ 83,962 $ 87,322 $ 106,537 T72 1 22,700 $ 34,000 $ 39,500 $ 69,700 $ 35,708 $ 35,000 $ 20,000 $ 9,227 $ 103,139 $ 108,914 $ 140,624 T84 1 31,000 $ 45,000 $ 51,900 $ 93,400 $ 43,588 $ 35,000 $ 20,000 $ 11,961 $ 117,560 $ 124,805 $ 168,380 T96 1 40,750 $ 61,000 $ 70,200 $ 124,000 $ 49,338 $ 35,000 $ 25,000 $ 15,189 $ 142,999 $ 152,659 $ 209,149 T96 2 81,500 $ 122,000 $ 140,400 $ 248,000 $ 49,338 $ 49,000 $ 25,000 $ 28,865 $ 236,108 $ 255,428 $ 368,408 T96 3 122,250 $ 183,000 $ 210,600 $ 372,000 $ 49,338 $ 73,500 $ 30,000 $ 42,840 $ 345,807 $ 374,787 $ 544,257 T96 4 163,000 $ 244,000 $ 280,800 $ 496,000 $ 49,338 $ 98,000 $ 30,000 $ 57,113 $ 450,569 $ 489,209 $ 715,169 MATERIAL TOTAL INSTALLED SCREEN COSTS EXCLUDING AIRBURST SYSTEM TABLE 1 4 T SCREEN EQUIPMENT AND INSTALLATION COSTS Connecting Wall Cost Development The cost for the connecting wall that blocks off the existing intake and provides the connection to the screen pipes is based on the cost of an interlocking sheet pile wall constructed directly in front of the existing intake. In general, the costs are mostly a function of the total area of the wall and will vary some with depth. Cost estimates were developed for a range of wall dimensions. The first step was to estimate the nominal length of the existing intake for each of the design flow values shown in Table 1 1. The nominal length was estimated using an assumed water depth and intake velocity. The use of actual depths and intake velocities imparted too many variables for the selected costing methodology. A depth of 20 feet was selected because it was close to both the mean and median intake water depth values reported by Phase II facilities in their Detailed Technical Questionnaires.

The length of the wall was also based on an assumed existing intake, through screen velocity of 1 fps and an existing screen open area of 50%. Most existing coarse screens have an open area of 69%. However, a 50% area was chosen to produce a larger ( i. e., more costly) wall size. Selecting a screen velocity of 1 fps also will overestimate wall length ( and therefore, costs) for existing screen velocities greater than 1 fps. This is the case for most of the facilities ( just under 70% of the Phase II Facilities reported screen velocities of 1 fps or greater). An additional length of 30 to 60 feet ( scaled between 30 feet for 3150 gpm to 60 feet for 182,44 gpm) was added to cover the end portions of the wall and to cover fixed costs for smaller intakes. The costs are based on the following:

° Sheet pile unit cost of $ 24.50/ sq ft ( Costworks 2001) ° An additional 50% of sheet pile cost to cover costs not included in sheet pile unit cost1 ° Total pile length of 45 feet for 20 foot depth including 15 foot penetration and 10 foot extension above water level  10 Design Flow Total Estimated Wall Length Mobilization gpm Ft Freshwater Saltwater 2,500 31 $ 36,600 $ 87,157 $ 103,840 5,700 32 $ 36,600 $ 89,351 $ 106,758 10,000 34 $ 36,600 $ 92,359 $ 110,759 15,800 36 $ 36,600 $ 96,416 $ 116,155 22,700 39 $ 36,600 $ 101,243 $ 122,575 31,000 43 $ 36,600 $ 107,049 $ 130,297 40,750 47 $ 36,600 $ 113,870 $ 139,369 81,500 64 $ 36,600 $ 142,376 $ 177,283 122,250 81 $ 36,600 $ 170,883 $ 215,196 163,000 96 $ 36,600 $ 195,960 $ 248,549 Sheet Pile Wall Costs 20 Ft Water Depth SHEET PILE WALL CAPITAL COSTS ° Mobilization of $ 18,300 for 20 foot depth ( Costworks 2001), added twice ( assuming sheet pile would be installed in two stages to minimize generating unit downtime ( see Downtime discussion) ° An additional cost of 33% for corrosion resistant coating for saltwater environments.

Table 1 5 presents the estimated wall lengths, mobilization costs, and total costs for 20 foot depth for both freshwater and saltwater environments.

TABLE 1 5 Pipe Manifold Cost Development For facilities with design intake flows that are 10% or more greater than 163,000 gpm ( i. e., above 180,000 gpm), multiple intakes are costed and the costs summed. This apoproach leads to probable costing over estimates for both the added length of end sections wall costs.

Pipe costs are developed using the same general methodology as described in Economic and Engineering Analyses of the Proposed Section 316( b) New Facility Rule, Appendix A, but modified based on a design pipe velocity of 5 fps. The pipe laying cost methodology was revised to include: costs for several different pipe lengths were developed. These pipe lengths include: 66 feet ( 20 meters), 410 feet ( 125 meters), 820 feet ( 250 meters), and 1640 feet ( 500 meters). The cost for pipe installation includes an equipment rental component for the pipe laying vessel, support barge, crew, and pipe laying equipment. The Phase I proposed rule Economic and Engineering Analyses document estimates that 500 feet of pipe can be laid in a day under favorable conditions. Equipment rental costs for the longer piping distances were adjusted upward, in single day increments, to limit daily production rates not to exceed 550 feet/ day. For the shorter distance of 66 feet ( 20 meters), the single day pipe laying vessel/ equipment costs were reduced by a factor of 40%. This reduction is  11 based on the assumption that, in most cases, a pipe laying vessel is not needed because installation can be performed via crane located on the shoreline.

Figure 1 1 presents the capital cost curves for the pipe portion only for each of the offshore distance scenarios. The pipe cost development methodology adopted from the Phase I effort used a different set of flow values than are shown in Table 1 1. Therefore, second order, best fit equations were derived from pipe cost data. These equations were applied to the flow values in Table 1 1 to obtain the relevant installed pipe cost component.

An additional equipment component representing the cost of pipe fittings such as tees or elbows are also included. The costs are based on the cost estimates developed for the Phase I proposed rule, adjusted to a pipe velocity of 5 fps and 2002 dollars.

Airburst System Costs Capital costs for airburst equipment sized to backwash each of the T screens were obtained from vendor estimates. These costs included air supply equipment ( compressor, accumulator, distributor) minus the piping to the screens, air supply housing, and utility connections and wiring. Capital costs of the airburst air supply system are shown in Table 1 6. Costs for a housing structure, electrical, and controls were added based on the following:

° electrical costs = 10% of air supply equipment ( BPJ) ° Controls = 5% of air supply equipment ( BPJ) ° Housing = $ 142/ sq ft for area shown in Table 1 6. This cost was based on the $ 130/ sq ft cost used in the Phase I cost for pump housing, adjusted to 2002 dollars.  12 Screen Size Vendor Supplied Equipment Costs Estimated Housing Area Housing Area Housing Costs Electrical Controls Total Airburst Minus Air Piping to Screens sq ft 10% 5% T24 $ 6,000 5x5 25 $ 3,550 $ 600 $ 300 $ 10,450 T36 $ 10,000 5x5 25 $ 3,550 $ 1,000 $ 500 $ 15,050 T48 $ 15,000 6x6 36 $ 5,112 $ 1,500 $ 750 $ 22,362 T60 $ 20,000 6x6 36 $ 5,112 $ 2,000 $ 1,000 $ 28,112 T72 $ 25,000 7x7 49 $ 6,958 $ 2,500 $ 1,250 $ 35,708 T84 $ 30,000 8x8 64 $ 9,088 $ 3,000 $ 1,500 $ 43,588 T96 $ 35,000 8x8 64 $ 9,088 $ 3,500 $ 1,750 $ 49,338 TABLE 1 6 CAPITAL COSTS OF AIRBURST AIR SUPPLY EQUIPMENT The costs of the air supply pipes, or " blow pipes," are calculated for each installation depending on the length of the intake pipe, plus an assumed average distance of 70 feet from the airburst system housing to the intake pipe at the front of the sheet pile wall. Pipe costs are based on this total distance multiplied by a derived unit cost of installed pipe Vendors indicated that the pipes are typically made of schedule 10 stainless steel or high density polyethylene and that material costs are only a portion of the total installed costs. Consistent with the selection of screen materials, EPA chose to assume that the blow pipes are constructed of 304 stainless steel for freshwater and 316 stainless steel for saltwater applications.

The unit costs for the installed blow pipes are based on the installed cost of similar pipe in a structure on land multiplied by an underwater installation factor. This underwater installation factor was derived by reviewing the materials versus total costs for underwater steel pipe installation, which ranged from about 3.2 to 4.5 with values decreasing with increasing pipe size. A review of the materials versus installed on land costs for the smaller diameter stainless steel pipe ( Costworks 2001) found that if the installed on land unit costs are multiplied by 2.0, the resulting materials to totalestimated ( underwater) installed cost ratios fell within a similar range. These costs are considered as over estimating costs somewhat because they include 304 and 316 stainless steel where less costly materials may be used. Also, they do not consider potential savings associated with concurrent installation alongside the much larger water intake pipe.

Blow pipe sizes were provided by vendors for T60 and smaller screens. For larger screens, the blow pipe diameter was derived by calculating pipe diameters ( and rounding up to even pipe sizes) using the same ratio of screen area to blow pipe area calculated for T60 screens. This is based on the assumption that blow pipe air velocities are proportional to the needed air/ water backwash velocities at the screen surface. A separate blow pipe was included for each T screen where multiple screens are included, but only one set of the air supply equipment ( compressor, accumulator, distributor,  13 Design Flow Air Pipe Unit Cost  Schedule 10 304 SS Air Pipe Unit Cost  Schedule 10 316 SS gpm $/ Ft $/ Ft 20 Meters 125 Meters 250 Meters 500 Meters 20 Meters 125 Meters 250 Meters 500 Meters 2,500 $ 55.0 $ 62.0 $ 7,458 $ 26,400 $ 48,950 $ 94,050 $ 8,407 $ 29,760 $ 55,180 $ 106,020 5,700 $ 82.0 $ 98.0 $ 11,119 $ 39,360 $ 72,980 $ 140,220 $ 13,289 $ 47,040 $ 87,220 $ 167,580 10,000 $ 98.0 $ 114.0 $ 13,289 $ 47,040 $ 87,220 $ 167,580 $ 15,458 $ 54,720 $ 101,460 $ 194,940 15,800 $ 154.0 $ 181.0 $ 20,882 $ 73,920 $ 137,060 $ 263,340 $ 24,544 $ 86,880 $ 161,090 $ 309,510 22,700 $ 214.0 $ 268.0 $ 29,018 $ 102,720 $ 190,460 $ 365,940 $ 36,341 $ 128,640 $ 238,520 $ 458,280 31,000 $ 292.0 $ 354.0 $ 39,595 $ 140,160 $ 259,880 $ 499,320 $ 48,002 $ 169,920 $ 315,060 $ 605,340 40,750 $ 362.0 $ 438.0 $ 49,087 $ 173,760 $ 322,180 $ 619,020 $ 59,393 $ 210,240 $ 389,820 $ 748,980 81,500 $ 362.0 $ 438.0 $ 98,174 $ 347,520 $ 644,360 $ 1,238,040 $ 118,786 $ 420,480 $ 779,640 $ 1,497,960 122,250 $ 362.0 $ 438.0 $ 147,262 $ 521,280 $ 966,540 $ 1,857,060 $ 178,178 $ 630,720 $ 1,169,460 $ 2,246,940 163,000 $ 362.0 $ 438.0 $ 196,349 $ 695,040 $ 1,288,720 $ 2,476,080 $ 237,571 $ 840,960 $ 1,559,280 $ 2,995,920 Saltwater Airburst Distribution Installed Pipe Costs Freshwater Airburst Distribution Installed Pipe Costs controls etc.) is included in each installation. The calculated costs for the air supply pipes are shown in Table 1 7.

TABLE 1 7 CAPITAL COSTS OF INSTALLED AIR SUPPLY PIPES Indirect Costs The total calculated capital costs were adjusted to include the following added costs:

° Engineering at 10% of direct capital costs ° Contractor overhead and profit at 15% of direct capital costs ( based on O& P component of installing lift station in Costworks 2001); some direct cost components, e. g., the intake pipe cost and blow pipe cost, already include costs for contractor overhead and profit ° Contingency at 10% of direct capital costs ° Sitework at 10% of direct capital costs; based on sitework component of Fairfax Water Intake costs data, including costs for erosion & sediment control, trash removal, security, dust control, access road improvements, and restoration ( trees, shrubs, seeding & sodding).

Total Capital Costs Table 1 8 presents the total capital costs of the complete system including indirect costs. Figures 1 2, 1 3, and 1 4 present the plotted capital costs in Table 1 8 for freshwater, saltwater, and freshwater with Zebra mussels, respectively. Figures 1 2, 1 3, and 1 4 also present the best fit, second order equations used in estimating compliance costs.  14

Design Flow gpm 304 SS 316 SS CuNi 304 SS 316 SS CuNi 304 SS 316 SS CuNi 304 SS 316 SS CuNi Freshwater Saltwater Zebra Mussels Freshwater Saltwater Zebra Mussels Freshwater Saltwater Zebra Mussels Freshwater Saltwater Zebra Mussels 3,150 $ 226,234 $ 244,261 $ 228,544 $ 317,824 $ 338,262 $ 320,134 $ 484,935 $ 508,243 $ 487,245 $ 708,887 $ 737,935 $ 711,197 7,100 $ 246,433 $ 267,593 $ 254,833 $ 368,265 $ 394,936 $ 376,665 $ 571,913 $ 605,144 $ 580,313 $ 868,212 $ 914,563 $ 876,612 11,400 $ 276,666 $ 299,449 $ 292,101 $ 426,879 $ 455,173 $ 442,314 $ 664,952 $ 699,805 $ 680,387 $ 1,029,380 $ 1,077,354 $ 1,044,815 17,800 $ 313,965 $ 341,187 $ 336,540 $ 517,642 $ 554,163 $ 540,217 $ 820,421 $ 868,012 $ 842,996 $ 1,313,330 $ 1,383,061 $ 1,335,905 25,650 $ 362,161 $ 397,272 $ 399,646 $ 628,646 $ 682,354 $ 666,131 $ 1,007,678 $ 1,083,526 $ 1,045,163 $ 1,652,171 $ 1,772,299 $ 1,689,656 34,950 $ 411,364 $ 451,176 $ 462,184 $ 754,958 $ 816,123 $ 805,778 $ 1,227,803 $ 1,314,388 $ 1,278,623 $ 2,059,145 $ 2,196,571 $ 2,109,965 45,600 $ 471,488 $ 518,072 $ 537,638 $ 897,156 $ 969,915 $ 963,306 $ 1,470,358 $ 1,574,277 $ 1,536,508 $ 2,501,955 $ 2,668,193 $ 2,568,105 91,200 $ 707,345 $ 784,421 $ 839,645 $ 1,511,007 $ 1,640,433 $ 1,643,307 $ 2,549,704 $ 2,741,450 $ 2,682,004 $ 4,515,446 $ 4,831,832 $ 4,647,746 136,800 $ 976,111 $ 1,083,680 $ 1,174,561 $ 2,166,086 $ 2,352,178 $ 2,364,536 $ 3,686,913 $ 3,966,485 $ 3,885,363 $ 6,628,388 $ 7,094,920 $ 6,826,838 182,400 $ 1,246,414 $ 1,381,225 $ 1,511,014 $ 2,831,017 $ 3,070,526 $ 3,095,617 $ 4,850,609 $ 5,214,758 $ 5,115,209 $ 8,809,404 $ 9,422,833 $ 9,074,004 Total Costs 500 Meters Offshore Total Costs 20 Meters Offshore Total Costs 125 Meters Offshore Total Costs 250 Meters Offshore TABLE 1 8 TOTAL CAPITAL COSTS OF INSTALLED T SCREEN SYSTEM AT EXISTING SHORELINE BASED INTAKES  15 Nuclear Facilities Construction and material costs tend to be substantially greater for nuclear facilities due to burden of increased security and to the requirements for more robust system design. Rather than performing a detailed evaluation of the differences in capital costs for nuclear facilities, EPA has chosen to apply a simple cost factor based on total costs.

In the Phase I costing effort, EPA used data from an Argonne National Lab study on retrofitting costs of fossil fuel power plants and nuclear power plants. This study reported average, comparative costs of $ 171 for nuclear facilities and $ 108 for fossil fuel facilities, resulting in a 1.58 costing factor. In comparison, recent consultation with a traveling screen vendor, the vendor indicated costing factors in the range of 1.5 2.0 were reasonable for estimating the increase in costs associated with nuclear power plants based on their experience. Because there are likely to be additional security burdens above that experienced when the Argonne Report was generated, EPA has selected 1.8 as a capital costing factor for nuclear facilities. Costs for nuclear facilities are not presented here but can be estimated by multiplying the applicable non nuclear facility costs by the 1.8 costing factor.

O& M Costs O& M cost are based on the sum of costs for annual inspection and cleaning of the intake screens by a dive team and for estimated operating costs for the airburst air supply system. Dive team costs were estimated for a total job duration of one to four days, and are shown in Table 1 9. Dive team cleaning and inspections were costed at once per year for low debris locations and twice per year for high debris locations. The O& M costs for the airburst system are based on power requirements of the air compressor and labor requirements for routine O& M. Vendors cited a backwash frequency per screen from as low as once per week to as high as once per hour. The time needed to recharge the accumulator is about 0.5 hours, but can be as high as 1 hour for those with smaller compressors or accumulators that backwash more than one screen simultaneously.

The Hp rating of the typical size airburst compressor for each screen size was obtained from a vendor and is presented in the table in Attachment A. A vendor stated that several hours per week would be more than enough labor for routine maintenance, so labor is assumed to be two to four hours per week based on roughly half hour daily inspection of the airburst system. However, during seasonal periods of high debris such as leaves in the fall, it may be necessary for someone to man the backwash system 24 hours/ day for several weeks ( Frey 2002). Thus, an additional two to four weeks of 24 hour labor are included for these periods ( two weeks low debris; four weeks high debris).

The O& M cost of the airburst system are based on the following:

° Average backwash frequency in low debris areas is 2 times per day ° Average backwash frequency in high debris areas is 12 times per day ° Time to recharge accumulator is 0.5 hours ° Compressor motor efficiency is 90% ° Cost of electric power consumed is $ 0.04/ Kwh ° Routine inspection and maintenance labor is 3 hours per week for systems up to 182,400 gpm  16 Item Daily Cost* One Time Cost* Total Duration One Day One Day Two Day Three Day Four Day Cost Year 1999 2002 2002 2002 2002 Supervisor $ 575 $ 575 $ 627 $ 1,254 $ 1,880 $ 2,507 Tender $ 200 $ 200 $ 218 $ 436 $ 654 $ 872 Diver $ 375 $ 750 $ 818 $ 1,635 $ 2,453 $ 3,270 Air Packs $ 100 $ 100 $ 109 $ 218 $ 327 $ 436 Boat $ 200 $ 200 $ 218 $ 436 $ 654 $ 872 Mob/ Demob $ 3,000 $ 3,000 $ 3,270 $ 3,270 $ 3,270 $ 3,270 Total $ 4,825 $ 5,260 $ 7,250 $ 9,240 $ 11,230 * Source: Paroby 1999 ( cost adjusted to 2002 dollars). Adjusted Total Installation and Maintenance Diver Team Costs ° O& M labor rate per hour is $ 38.00/ hr. The rate is based on Bureau of Labor Statistics Data using the median labor rates for electrical equipment maintenance technical labor ( SOC 49 2095) and managerial labor ( SOC 11 1021); benefits and other compensation are added using factors based on SIC 29 data for blue collar and white collar labor. The two values were combined into a single rate assuming 90% technical labor and 10% managerial. See Doley 2002 for details.

TABLE 1 9 ESTIMATED COSTS FOR DIVE TEAM TO INSPECT AND CLEAN T SCREENS Attachment A presents the worksheet data used to develop the annual O& M costs, plotted in Figure 1 5. Figure 1 5 also shows the second order equations that were fitted to these data and used to estimate the O& M costs for individual Phase II facilities. As with the capital costs, at facilities where the design flow exceeds the maximum cost model design flow of 163,000 gpm plus 10% ( 180,000 gpm), the design flow are divided and the corresponding costs are summed.

Construction Related Downtime Downtime may be a substantial cost item for retrofits using the existing pump wells and pumps. The proposed EPA retrofit scenario includes a sheet pile wall in front of the existing intake. This scenario is modeled after a proposed scenario presented in a feasibility study for the Salem Nuclear Plant. In this scenario, a sheet pile plenum with bypass gates is constructed 40 feet in front of the existing intake with about twelve 10 foot diameter header pipes connecting the plenum to about 240 T screens. Construction is estimated to take two years, with installation of the sheet pile plenum in the first year. The facility projects the installation of 10 foot header pipes and screens to take nine months and the air backwash piping to take two months. The feasibility study states that Units 1 & 2 would each have to be shutdown for about six months, to install the plenum, and for an additional two months to install the 10 foot header pipe connection to the plenum and to install the air piping. Thus, an estimated total of eight months downtime is estimated for this very large ( near worst case)  17 intake scenario. This scenario was discarded by the facility due to uncertainty about biofouling and debris removal at slack tides. No cost estimates were developed and, therefore no incentive to focus on a system design and a construction sequence that would minimize downtime existed.

In the same feasibility study, a scenario is proposed where a new intake with dual flow traveling screens is installed at a distance of 65 feet offshore inside a cofferdam. In this scenario, a sheet pile plenum wall connects the new intake to the existing shore intake. In this scenario the intake is constructed first; Units 1 & 2 are estimated to be shut down for about one month each to construct and connect the plenum walls to the existing intake.

It would seem that the T screen plenum construction scenario could follow the same approach, i. e., performed while the units are operating. This apporach would result in a much lower downtime, similar to that for the offshore intake, but including consideration for added time for near shore air pipe installation. There are two relevant differences between these scenarios. One is the distance offshore to the T screen piping connection versus the new intake structure ( 40 feet versus 65 feet). The second is that T screens, pipes, and plenum would be installed underwater while the new intake would be constructed behind a coffer dam. Conceivably the offshore portion of the T screen plenum ( excluding the ends) and all pipe and screen installation on the offshore side could be performed without shutting down the intake.

The WH Zimmer plant is one of the few facilities that EPA has identified as actually having converted an existing shoreline intake with traveling screens to submerged offshore T screens. This facility was originally constructed as a nuclear facility but was never completed. In the late 80' s it was converted to a coal fired plant. The original intake was to supply service water and make up water for recirculating wet towers, and had been completed. However, the area in front of the intake was plagued with sediment deposition. A decision was made to abandon the traveling screens and install T screens approximately 50 feet offshore. However, because the facility was not operating at the time of this conversion, there was no monetary incentive to minimize construction time. Actual construction took six to eight months for this intake, with a design flow of about 61,000 gpm ( Frey 2002). The construction method in this case used a steel wall installed in front of the existing intake pump wells.

The WH Zimmer plant engineer was consulted and asked to estimate how long it would take to perform this retrofit particularly with a goal of minimizing generating unit downtime. The estimated downtime was a minimum of seven to nine weeks, assuming mobilization goes smoothly and a tight construction schedule is maintained. A more generous estimate of a total of 12 to 15 weeks was estimated for their facility. This estimate includes five to six weeks for installing piping ( some support pilings can be laid ahead of time), an additional five to six weeks to tie in piping and install the wall, and an additional two to three weeks to clean and dredge the intake area. This last two to three week period was a construction step somewhat unique to the Zimmer plant, especially because the presence of sediment was the driving factor in the decision to convert the system.

Based on the above information, EPA has concluded that a reasonable unit downtime should be in the range of 8 to 12 weeks. It is reasonable to assume that this downtime can be scheduled to coincide with routine generating unit downtime of approximately four weeks or longer, resulting in a total  18 potential lost generation period of four to eight weeks. Rather than select a single downtime for all facilities installing passive screens, EPA chose to apply the 8 to 12 week downtime duration based on variations in project size using design flow as a measure of size. As such, EPA assumed a downtime of 8 weeks for facilities with intake flow volumes of less than 400,000 gpm, 10 weeks for facilities with intake flow volumes greater than 400,000 gpm but less than 800,000 gpm, and 12 weeks for facilities with intake flow volumes greater than 800,000 gpm.

Application General Applicability The following site related conditions may preclude the use of passive T screens or create operational problems:

° Water depths of < 2 feet at screen location; for existing facilities this should not be an issue ° Stagnant waterbodies with high debris load ° Waterbodies with frazil ice in winter.

Frazil ice consists of fine, small, needle like structures or thin, flat, circular plates of ice suspended in water. In rivers and lakes it is formed in supercooled, turbulent water. Remedies for this problem include finding another location such as deeper water that is outside of the turbulent water or creating a provision for periodically applying heated water to the screens. The application of heated water may not be feasible or economically justifiable in many instances.

Some facilities have reported limited success in alleviating frazil ice problems by blowing a small constant stream of air through the screen backwash system ( Whitaker 2002b).

Application of Different Pipe Lengths As noted previously, the shortest pipe length cost scenario ( 20 meters) are assumed to be applicable only to facilities with flows less than 163,000 gpm. Conversely, facilities located on large waterbodies that are subject to wave action and shifting sediment are assumed to install the longest pipe length scenario of 500 meters. Large waterbodies in this instance will include Great Lakes, oceans, and some estuarine/ tidal rivers. The matrix in Table 1 10 will provide some initial guidance. Generally, if the waterbody width is known, the pipe length should not exceed half the width.  19 TABLE 1 10 SELECTION OF APPLICABLE RELOCATION OFFSHORE PIPE LENGTHS BY WATERBODY Freshwater Rivers/ Streams Lakes/ Reservoirs Estuaries/ Tidal Rivers Great Lakes Oceans 20 Meters Flow < 163,000 Flow < 163,000 NA NA NA 125 Meters TBD TBD TBD NA NA 250 Meters TBD TBD TBD TBD NA 500 Meters NA NA TBD TBD ALL TBD: Criteria or selection to be determined; criteria may include design flow, waterbody size ( if readily available).

References Whitaker, J. Hendrick Screen Company. Telephone Contact Report with John Sunda, SAIC, concerning Tscreen cost and design information. August 2, & September 9, 2002a Whitaker, J. Hendrick Screen Company. Email correspondence with John Sunda SAIC concerning Tscreen cost and design information. August 9, 2002b Johnson Screen  Brochure  " High Capacity Surface Water Intake Screen Technical Data."

Petrovs, H. Johnson Screens. Telephone Contact Report Regarding Answers to Passive Screen Vendor Questions.

Screen Services  Brochure  Static Orb, 2002 Shaw, G. V. & Loomis, A. W. Cameron Hydraulic Data. Ingersoll Rand Company. 1970 Frey, R. Cinergy. Telephone Contact Report Regarding Retrofit of Passive T Screens. September 30, 2002.

Doley, T. SAIC Memorandum to the 316b Record regarding Development of Power Plant Intake Maintenance Personnel hourly compensation rate. 2002 R. S. Means. 2001. R. S. Means Cost Works Database, 2001.

Metcalf & Eddy. Wastewater Engineering. Mcgraw Hill Book Company. 1972  20

Scren Size Number of Screens Design Flow Compresso r Power Electric Power Required Low Debris Backwash Frequency High Debris Backwash Frequency Accumulato r recharge time Operating Days Annual Power Required

Low Debris Annual Power Required

High Debris Annual Power Costs

Low Debris* Annual Power Costs

High Debris* Annual Labor Required

Low Debris Annual Labor Cost

Low Debris Annual Labor Required

High Debris gpm Hp Kw at $/ kw = at $/ kw =

Events/ day Events/ day Hrs Days/ yr Kwh Kwh $ 0.04 $ 0.04 Hours Hours T24 1 2,500 2 1.7 2 12 0.5 365 605 3,631 $ 24 $ 145 272 $ 10,336 608 T36 1 5,700 5 4.1 2 12 0.5 365 1,513 9,076 $ 61 $ 363 272 $ 10,336 608 T48 1 10,000 10 8.3 2 12 0.5 365 3,025 18,153 $ 121 $ 726 272 $ 10,336 608 T60 1 15,800 12 9.9 2 12 0.5 365 3,631 21,783 $ 145 $ 871 324 $ 12,312 660 T72 1 22,700 15 12.4 2 12 0.5 365 4,538 27,229 $ 182 $ 1,089 324 $ 12,312 660 T84 1 31,000 20 16.6 2 12 0.5 365 6,051 36,305 $ 242 $ 1,452 324 $ 12,312 660 T96 1 40,750 25 20.7 2 12 0.5 365 7,564 45,382 $ 303 $ 1,815 324 $ 12,312 660 T96 2 81,500 25 20.7 4 24 0.5 365 15,127 90,763 $ 605 $ 3,631 376 $ 14,288 712 T96 3 122,250 25 20.7 6 36 0.5 365 22,691 136,145 $ 908 $ 5,446 376 $ 14,288 712 T96 4 163,000 25 20.7 8 48 0.5 365 30,254 181,527 $ 1,210 $ 7,261 376 $ 14,288 712 ATTACHMENT A O& M DEVELOPMENT DATA  21 Figure 1 1 Capital Costs Conventional Steel Pipe Laying Method At Various Offshore Distances y = 2E 05x 2 + 25.418x + 388636 R 2 = 0.9995 y = 1E 05x 2 + 12.81x + 249598 R 2 = 0.9993 y = 6E 06x 2 + 6.4038x + 125256 R 2 = 0.9992 y = 4E 06x 2 + 1.1221x + 69265 R 2 = 0.9966 $

$ 1,000,000 $ 2,000,000 $ 3,000,000 $ 4,000,000 $ 5,000,000 $ 6,000,000 $ 7,000,000 $ 8,000,000 $ 9,000,000 0 50,000 100,000 150,000 200,000 250,000 300,000 Design Flow gpm Capital Costs 125 Meter 250 Meter 500 Meter 20 Meter  22 Figure 1 2 Capital Costs for Passive Screen Relocation Offshore in Freshwater at Selected Offshore Distances y = 3E 05x 2 + 63.009x + 841363 R 2 = 1 y = 1E 05x 2 + 34.841x + 608473 R 2 = 1 y = 6E 06x 2 + 20.609x + 412534 R 2 = 0.9999 y = 2E 06x 2 + 8.7987x + 318207 R 2 = 0.9996 $ 0 $ 1,000,000 $ 2,000,000 $ 3,000,000 $ 4,000,000 $ 5,000,000 $ 6,000,000 $ 7,000,000 $ 8,000,000 $ 9,000,000 $ 10,000,000 $ 11,000,000 $ 12,000,000 $ 13,000,000 0 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000 180,000 Design Intake Flow ( gpm)

Total Capital Costs 20 Meter 125 Meter 250 Meter 500 Meter  23 Figure 1 3 Capital Costs for Passive Screen Relocation Offshore in Saltwater at Selected Offshore Distances y = 3E 05x 2 + 68.287x + 871178 R 2 = 1 y = 1E 05x 2 + 37.925x + 634921 R 2 = 1 y = 6E 06x 2 + 22.596x + 437299 R 2 = 0.9999 y = 2E 06x 2 + 9.8641x + 341558 R 2 = 0.9997 $ 0 $ 1,000,000 $ 2,000,000 $ 3,000,000 $ 4,000,000 $ 5,000,000 $ 6,000,000 $ 7,000,000 $ 8,000,000 $ 9,000,000 $ 10,000,000 $ 11,000,000 $ 12,000,000 $ 13,000,000 $ 14,000,000 0 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000 180,000 Design Intake Flow ( gpm)

Total Capital Costs 20 Meter 125 Meter 250 Meter 500 Meter  24 Figure 1 4 Capital Costs for Passive Screen Relocation Offshore in Freshwater with Zebra Mussels at Selected Offshore Distances y = 3E 05x 2 + 65.418x + 839278 R 2 = 1 y = 1E 05x 2 + 37.25x + 606388 R 2 = 1 y = 6E 06x 2 + 23.018x + 410449 R 2 = 1 y = 2E 06x 2 + 11.207x + 316122 R 2 = 0.9997 $ 0 $ 1,000,000 $ 2,000,000 $ 3,000,000 $ 4,000,000 $ 5,000,000 $ 6,000,000 $ 7,000,000 $ 8,000,000 $ 9,000,000 $ 10,000,000 $ 11,000,000 $ 12,000,000 $ 13,000,000 0 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000 180,000 Design Intake Flow ( gpm)

Total Capital Costs 20 Meter 125 Meter 250 Meter 500 Meter  25 Figure 1 5 Total O& M Cost for Passive Screen Relocated Offshore with Airburst Backwash y =  5E 07x 2 + 0.1393x + 16582 R 2 = 0.9246 y =  6E 07x 2 + 0.2289x + 35945 R 2 = 0.9531 $ 0 $ 10,000 $ 20,000 $ 30,000 $ 40,000 $ 50,000 $ 60,000 $ 70,000 0 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000 180,000 Design Intake Flow Annual O&

M Costs Low Debris High Debris  26


[Federal Register: January 30, 2008 (Volume 73, Number 20)]
[Notices]
[Page 5607-5609]
[DOCID:fr30ja08-125]

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SECURITIES AND EXCHANGE COMMISSION

[Release No. 34-57188; File No. SR-Amex-2007-70]

Self-Regulatory Organizations; American Stock Exchange LLC; Order
Granting Accelerated Approval of a Proposed Rule Change, as Modified by
Amendment Nos. 1 and 2, Relating to the Listing and Trading of Units of
the United States Heating Oil Fund and the United States Gasoline Fund,
LP

January 23, 2008.

I. Introduction

    On June 29, 2007, the American Stock Exchange LLC (``Amex'' or
``Exchange'') filed with the Securities and Exchange Commission
(``Commission'') a proposed rule change pursuant to Section 19(b)(1) of
the Securities Exchange Act of 1934 (``Act'') \1\ and Rule 19b-4
thereunder \2\ to list and trade units (a ``Unit,'' and collectively,
the ``Units'') of each of the United States Heating Oil Fund, LP
(``USHO'') and the United States Gasoline Fund, LP (``USG'') (each, a
``Partnership,'' and collectively, the ``Partnerships'') pursuant to
Amex Rules 1500-AEMI and 1501 through 1505. On August 16, 2007, the
Exchange submitted Amendment No. 1 to the proposed rule change. On
December 20, 2007, the Exchange submitted Amendment No. 2 to the
proposed rule change. The proposed rule change, as amended, was
published for comment in the Federal Register on January 3, 2008 for a
15-day comment period.\3\ The Commission received no comments regarding
the proposal. This order approves the proposed rule change, as modified
by Amendment Nos. 1 and 2, on an accelerated basis.
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    \1\ 15 U.S.C. 78s(b)(1).
    \2\ 17 CFR 240.19b-4.
    \3\ See Securities Exchange Act Release No. 57042 (December 26,
2007), 73 FR 514 (``Notice'').
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II. Description of Proposal

    The Exchange proposes to list and trade Units issued by USHO and
USG pursuant to Amex Rules 1500-AEMI and 1501 through 1505.\4\ The
Exchange has represented that the Units will conform to the initial and
continued listing criteria under Rule 1502,\5\ specialist prohibitions
under Rule 1503, and the obligations of specialists under Rule 1504.
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    \4\ Amex Rule 1500-AEMI provides for the listing of Partnership
Units, which are defined as securities, that are: (a) issued by a
partnership that invests in any combination of futures contracts,
options on futures contracts, forward contracts, commodities, and/or
securities; and (b) that are issued and redeemed daily in specified
aggregate amounts at net asset value. See Securities Exchange Act
Release No. 53582 (March 31, 2006), 71 FR 17510 (April 6, 2006) (SR-
Amex-2005-127) (approving Amex Rules 1500-AEMI and 1501 through 1505
in conjunction with the listing and trading of Units of the United
States Oil Fund, LP).
    \5\ The Amex stated that it will require a minimum of 100,000
Units to be outstanding at the start of trading and expects that the
initial price of a Unit will be $50.00.
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    Each Unit represents ownership of a fractional undivided beneficial
interest in the net assets of USHO and USG.\6\ The net assets of each
Partnership will consist primarily of investments in futures contracts
for heating oil, gasoline, crude oil, and other petroleum-based fuels
that are traded on the New York Mercantile Exchange (``NYMEX''),
Intercontinental Exchange (``ICE Futures'') or other U.S. and foreign
exchanges (collectively, ``Futures Contracts''). In the case of USHO,
the predominant investments are expected to be based on, or related to,
heating oil. The predominant investments of USG are expected to be
based on, or related to, gasoline.
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    \6\ Each Partnership is a commodity pool that will issue Units
that may be purchased and sold on the Exchange.
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    USHO may also invest in other heating-oil-related investments such
as cash-settled options on Futures Contracts, forward contracts for
heating oil, and over-the-counter (``OTC'') contracts that are based on
the price of heating oil, oil and other petroleum-based fuels, Futures
Contracts, and indices based on the foregoing (collectively, ``Other
Heating Oil Related Investments''). Futures Contracts and Other Heating
Oil Related Investments collectively are referred to as ``Heating Oil
Interests.''
    Similarly, USG may also invest in other gasoline-related
investments such as cash-settled options on Futures Contracts, forward
contracts for gasoline, and OTC transactions based on the price of
gasoline, oil, and other petroleum-based fuels, Futures Contracts, and
indices based on the

foregoing (collectively, ``Other Gasoline-Related Investments'').
Futures Contracts and Other Gasoline-Related Investments collectively
are referred to as ``Gasoline Interests.''
    Each of USHO and USG will invest in Heating Oil Interests and
Gasoline Interests, respectively, to the fullest extent possible
without being leveraged or unable to satisfy its current or potential
margin or collateral obligations. In pursuing this objective, the
primary focus of USHO's and USG's investment manager, Victoria Bay
Asset Management, LLC (``Victoria Bay'' or ``General Partner''), will
be investment in Futures Contracts and the management of Partnership
investments in short-term obligations of the United States of two years
or less (``Treasuries''), and cash and cash equivalents (collectively,
``Cash'') for margining purposes and as collateral. Each Partnership
seeks to track price changes in percentage terms of an underlying
commodity as measured by a benchmark defined to be the price of a
specified futures contract. Each Partnership seeks to track price
changes in percentage terms of an underlying commodity as measured by a
benchmark defined to be the price of a specified futures contract.\7\
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    \7\ A detailed discussion of the underlying benchmark for each
Partnership, dissemination of the values thereof, investment
objective of the Partnership, portfolio investment methodology,
investment techniques, availability of information and key values,
creation and redemption of Units, arbitrage, dividends and
distributions, Amex's initial and continued listing standards, Amex
trading rules and trading halts, information circular to Exchange
members, and other related information regarding the Partnership can
be found in the Notice. See supra note 3.
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    Accordingly, the investment objective of USHO is for the changes in
percentage terms of a Unit's net asset value (``NAV'') to reflect the
changes in percentage terms of a specified price of heating oil (also
known as No. 2 fuel) delivered at the New York harbor, as measured by
the changes in the price of the heating oil futures contract traded on
the NYMEX (the ``Heating Oil Benchmark Futures Contract''), less USHO's
expenses. Similarly, the investment objective of USG is for changes in
percentage terms of a Unit's NAV to reflect the changes in percentage
terms of the price of unleaded gasoline (also known as reformulated
gasoline blendstock for oxygen blending or ``RBOB''), for delivery to
New York harbor, as measured by the changes in the price of a specified
unleaded gasoline futures contract traded on the NYMEX (the ``Gasoline
Benchmark Futures Contract''), less USG's expenses. The Heating Oil
Benchmark Futures Contract and Gasoline Benchmark Futures Contract
employed are, in each case, the near month expiration contract, except
when the near month contract is within two weeks of expiration, in
which case it will invest in the next expiration month.\8\
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    \8\ The Heating Oil Benchmark Futures Contract and Gasoline
Benchmark Futures Contract will be changed or ``rolled'' over a
four-day period by selling the near month contract that expires the
following month.
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    The General Partner will attempt to place USHO's trades in Heating
Oil Interests and otherwise manage USHO's investments so that ``A''
will be within plus/minus 10% of ``B'', where:
     A is the average daily change in USHO's NAV for any period
of 30 successive valuation days, i.e., any day as of which USHO
calculates its NAV, and
     B is the average daily change in the price of the
Benchmark Futures Contract over the same period.
    The General Partner will attempt to place USG's trades in Gasoline
Interests and otherwise manage USG's investments so that ``A'' will be
within plus/minus 10% of ``B'', where:
     A is the average daily change in USG's NAV for any period
of 30 successive valuation days, i.e., any day as of which USG
calculates its NAV, and
     B is the average daily change in the price of the
Benchmark Futures Contract over the same period.

The General Partner believes that market arbitrage opportunities should
cause USHO's and USG's Unit prices to closely track each Partnership's
per-Unit NAV, which are targeted at the current Heating Oil Benchmark
Futures Contract and Gasoline Benchmark Futures Contract, respectively.

III. Commission Findings and Accelerated Approval

    After careful review, the Commission finds that the proposed rule
change is consistent with the requirements of the Act and the rules and
regulations thereunder applicable to a national securities exchange.\9\
In particular, the Commission finds that the proposed rule change is
consistent with Section 6(b)(5) of the Act,\10\ which requires that an
exchange have rules designed, among other things, to prevent fraudulent
and manipulative acts and practices, to promote just and equitable
principles of trade, to foster cooperation and coordination with
persons engaged in facilitating transactions in securities, and to
remove impediments to and perfect the mechanism of a free and open
market and a national market system, and, in general to protect
investors and the public interest; and is not designed to permit unfair
discrimination between customers, issuers, brokers, or dealers, or to
regulate by virtue of any authority conferred by the Act matters not
related to the purpose of the Act or the administration of the
Exchange. The Commission notes that it previously approved the original
listing and trading of certain partnership units similar to the
Units.\11\
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    \9\ In approving this proposed rule change, the Commission notes
that it has considered the proposed rule's impact on efficiency,
competition, and capital formation. See 15 U.S.C. 78c(f).
    \10\ 15 U.S.C. 78f(b)(5).
    \11\ See Securities Exchange Act Release Nos. 56831 (November
21, 2007), 72 FR 67612 (November 29, 2007) (SR-Amex-2007-98)
(approving listing and trading of units of the United States 12
Month Oil Fund, LP and the United States 12 Month Natural Gas Fund,
LP); 53582 (March 31, 2006), 71 FR 17510 (April 6, 2006) (SR-Amex-
2005-127) (approving Amex Rules 1500-AEMI and 1501 through 1505 in
conjunction with the listing and trading of units of the United
States Oil Fund, LP) (``Amex 2005-127 Order''); and 55632 (April 13,
2007), 72 FR 19987 (April 20, 2007) (SR-Amex-2006-112) (approving
the listing and trading of shares of the United States Natural Gas
Fund, LP) (``Amex 2006-112 Order'').
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    The Commission further believes that the proposal is consistent
with Section 11A(a)(1)(C)(iii) of the Act,\12\ which sets forth
Congress's finding that it is in the public interest and appropriate
for the protection of investors and the maintenance of fair and orderly
markets to assure the availability to brokers, dealers, and investors
of information with respect to quotations for and transactions in
securities. The Amex will disseminate for each Partnership every 15
seconds throughout Amex's trading day by means of the Consolidated Tape
Association/Consolidated Quote High Speed Lines information with
respect to the indicative partnership value (``IPV''). The Exchange
will also make available on its Web site daily trading volume, the
closing prices, and the NAV. Web site disclosure of portfolio holdings
for both Partnerships will be made daily and will include, as
applicable, the specific types, the name and value of each Heating Oil
or Gasoline Interest, the specific types of Heating Oil or Gasoline
Interests and characteristics of such interests, Treasuries, and amount
of Cash held in the portfolio of the Partnerships. In addition, Amex
represented that quotations and last-sale information regarding the
Futures Contracts are widely disseminated through a variety of market
data vendors worldwide, including Bloomberg and Reuters. In addition,
the Exchange

further represented that real-time futures data is available by
subscription from Reuters and Bloomberg.
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    \12\ 15 U.S.C. 78k-1(a)(1)(C)(iii).
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    Furthermore, the Commission believes that the proposal to list and
trade the Units is reasonably designed to promote fair disclosure of
information that may be necessary to price the Units appropriately and
to prevent trading when a reasonable degree of transparency cannot be
assured. The Commission also believes that the Exchange's trading halt
rules are reasonably designed to prevent trading in the Units when
transparency is impaired. Trading in the Units will be halted in the
event the market volatility trading halt parameters set forth in Amex
Rule 117 have been reached. If the IPV or the underlying benchmark
futures contract of a Partnership is not being disseminated as
required, the Exchange may halt trading during the day in which the
interruption to the dissemination occurs. If the interruption to the
dissemination of the IPV or the underlying benchmark futures contract
persists past the trading day in which it occurred, the Exchange will
halt trading no later than the beginning of the trading day following
the interruption.\13\ In addition, the Exchange has represented that,
if it learns or becomes aware that a Partnership fails to disseminate
its NAV to all market participants at the same time, trading of such
Partnership Units will be halted.\14\
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    \13\ E-mail from Jeffrey P. Burns, Vice President & Associate
General Counsel, Exchange, to Michou Nguyen, Special Counsel,
Division of Trading and Markets, Commission, on January 22, 2008;
see also Amex Rule 1502(b)(ii)-(iii).
    \14\ E-mail from Jeffrey P. Burns, Vice President & Associate
General Counsel, Exchange, to Brian Trackman, Special Counsel,
Division of Trading and Markets, Commission, on January 17, 2008.
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    The Commission further believes that the trading rules and
procedures to which the Units will be subject pursuant to this proposal
are consistent with the Act. The Exchange has represented that the
Units will be traded on the Exchange similar to other equity
securities.
    In support of this proposal, the Exchange has made the following
representations:
    (1) The Exchange will obtain a representation from each
Partnership, prior to listing, that the NAV per Unit for USHO and USG
will be calculated daily and made available to all market participants
at the same time. In addition, the Exchange represents that disclosure
of the portfolio composition for each Partnership will be made to all
market participants at the same time.
    (2) The Exchange's surveillance procedures are adequate to deter
and detect violations of Exchange rules relating to trading of the
Units. Specifically, the surveillance procedures will be similar to
those used for units of the United States Oil Fund, LP and the United
States Natural Gas Fund, LP \15\ as well as other commodity-based
trusts, trust issued receipts, and exchange-traded funds. In addition,
the surveillance procedures will incorporate and rely upon existing
Amex surveillance procedures governing options and equities. The
Exchange currently has in place a comprehensive surveillance sharing
agreement with each of NYMEX and ICE Futures for the purpose of
providing information in connection with trading in, or related to,
futures contracts traded on NYMEX and ICE Futures, respectively. To the
extent that a Partnership invests in Heating Oil Interests or Gasoline
Interests traded on other exchanges, the Amex will enter into
comprehensive surveillance sharing agreements with those particular
exchanges. The Exchange has represented that each of the Partnerships
will only invest in futures contracts on markets where the Exchange has
entered into the appropriate comprehensive surveillance sharing
agreements.
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    \15\ See Amex 2005-127 Order and Amex 2006-112 Order, supra note
11.
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    (3) Prior to the commencement of trading, the Exchange will inform
its members and member organizations in an Information Circular. The
Information Circular will discuss the special characteristics, and
risks, of trading in the Units. Specifically, the Information Circular,
among other things, will discuss what the Units are, how a basket of
Units is created and redeemed, the requirement that members and member
firms deliver a prospectus to investors purchasing the Units prior to,
or concurrently with, the confirmation of a transaction, applicable
Amex rules, dissemination of information regarding the per-Unit IPV,
trading information, and applicable suitability rules. The Information
Circular will also reference the fact that there is no regulated source
of last sale information regarding physical commodities, and describe
the regulatory framework relating to the trading of heating oil and
gasoline based futures contracts and related options. The Information
Circular will also discuss any relief, if granted, by the Commission or
the staff from any rules under the Act.
    (4) The Trust is required to comply with Rule 10A-3 under the Act
\16\ for the initial and continued listing of the Units.
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    \16\ 17 CFR 240.10A-3.
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    This approval order is based on the Exchange's representations.

IV. Acceleration

    The Commission finds good cause, pursuant to Section 19(b)(2) of
the Act,\17\ for approving the proposed rule change, as amended, prior
to the thirtieth day after the date of publication of notice in the
Federal Register. The Commission notes that the present proposal is
similar to prior proposals that the Commission has approved,\18\ is
consistent with current Amex listing requirements, and received no
comments following publication in the Federal Register. The Commission
does not believe that the proposed rule change, as amended, raises
novel regulatory issues. Consequently, the Commission believes that it
is appropriate to permit investors to benefit from these additional
investment choices without delay.
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    \17\ 15 U.S.C. 78s(b)(2).
    \18\ See supra, note 11.
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    Accordingly, the Commission finds that there is good cause,
consistent with Section 6(b)(5) of the Act,\19\ to approve the
proposal, as amended, on an accelerated basis.
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    \19\ 15 U.S.C. 78s(b)(5).
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V. Conclusion

    It is therefore ordered, pursuant to Section 19(b)(2) of the
Act,\20\ that the proposed rule change (SR-Amex-2007-70), as amended,
be, and is hereby approved on an accelerated basis.
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    \20\ 15 U.S.C. 78s(b)(2).

    For the Commission, by the Division of Trading and Markets,
pursuant to delegated authority.\21\
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    \21\ 17 CFR 200.30-3(a)(12).
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Florence E. Harmon,
Deputy Secretary.
[FR Doc. E8-1613 Filed 1-29-08; 8:45 am]

BILLING CODE 8011-01-P