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Kenai Peninsula Natural Gas Study

Final Report June 30, 1995

prepared for:

Kenai Peninsula Borough Economic Development District, Inc. 110 South Willow Street, Suite 106 Kenai AK 99611

prepared by:

Steve Colt Institute of Social and Economic Research University of Alaska Anchorage 3211 Providence Drive Anchorage Alaska 99508 907-786-7736

in collaboration with

Mark Foster Mark A. Foster and Associates

This project was funded by the City of Homer; the City of Seward; the Alaska Department of Community and Regional Affairs, Division of Energy; and the Kenai Peninsula Borough Economic Development District, Inc.

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Kenai Peninsula Natural Gas Study

Final Report June 30, 1995

Contents

Summary of Conclusions ............................................................................................. 1 1. Current Energy Use and Cost on the Kenai Peninsula .......................................... 2

Energy Use Patterns ................................................................................................... 2 Recent Energy Costs ................................................................................................... 3 Current Use of Natural Gas ......................................................................................... 5

2. Study Area Demographics and Potential Gas Consumption ................................ 7 Population Distribution and Recent Growth ................................................................. 7 The Experience of the Mat-Su Borough ...................................................................... 9 Potential Natural Gas Demand in Homer and Seward .............................................. 1 O Comparison of Potential Homer & Seward Demand to Other Demands ................... 1 O Future Economic and Industrial Growth .................................................................... 12

3. Delivered Cost Estimates -- Pipeline Scenarios ................................................... 12 Current Delivered Cost of Enstar Gas ....................................................................... 12 Pipeline Routes ......................................................................................................... 13 Base Case Assumptions and Delivered Costs .......................................................... 17 "Growth" Case -- Continued High Economic Growth ................................................. 19 "Local" Case -- Local Gas Supply .............................................................................. 19 "Industry" Case -- Large Industrial Load .................................................................... 19 Summary of Pipeline Cases ...................................................................................... 20

4. Break-even Cases and Alternative Delivery Options ........................................... 23 Break-even Case 1: Minimum Industrial Load ........................................................... 23 Break-even Case 2: Maximum Distance from Local Supply ...................................... 23 Break-even Case 3: Low-Cost Financing .................................................................. 23 Combination Case: Large Load and Low-Cost Financing ......................................... 24 CNG Case: Compressed Natural Gas Delivered by Truck ........................................ 25 LNG Case: Liquefied Natural Gas Delivery by Truck ................................................. 26 Barge Transportation of CNG in Tube Trailers .......................................................... 26 Summary of Break-even and Alternative Transport Cases ........................................ 27

5. Implementation Issues and Recommendations ................................................... 28 Alternative Local Gas Supplies .................................................................................. 28 Potential Involvement of Homer Electric Association ................................................ 32 Enstar Ratemaking Treatment of a High-Cost Expansion ......................................... 32 Potential Supplies of LNG ......................................................................................... 32 Recommendations ..................................................................................................... 33

References ................................................................................................................... 34

Appendix A: Detailed Calculations of Delivered Cost Appendix B: Discussion Memoranda on Cost Assumptions

List of Tables

Table 1 :Kenai Peninsula Fuel Use Patterns .................................................................... 3 Table 2: Recent Residential Energy Costs ..................................................................... .4 Table 3: 1990 Kenai/Soldotna Natural Gas Consumption ............................................... 6 Table 4: Typical Natural Gas Consumption Patterns ....................................................... 7 Table 5: Study Area Demographic Data .......................................................................... 8 Table 6: Assumptions About Potential Gas Demand in Homer and Seward ................. 10 Table 7: Perspective on Homer and Seward Natural Gas Loads .................................. 11 Table 8: Enstar Average Cost of Service ....................................................................... 12 Table 9: Base Case Delivered Cost Calculation ............................................................ 18 Table 10: Summary of Delivered Cost Calculations: Pipeline Scenarios ....................... 20 Table 11: Summary of Break-even Conditions .............................................................. 24 Table 12: The Effect of Low-Interest Financing and Industrial Load .............................. 25 Table 13: Summary of Delivered Cost Calculations: Break-even and Special Cases ... 27

List of Figures

Figure 1: Kenai Peninsula Fuel use Patterns ................................................................... 2 Figure 2: Residential Cost of Delivered Heat .................................................................. .4 Figure 3: Kenai Peninsula Residential Gas Customers ................................................... 5 Figure 4: Mat-Su Borough Natural Gas Customer Growth .............................................. 9 Figure 5: Potential Homer or Seward Load

Compared to 1993 Sales of Cook Inlet Gas ............................................. 11 Figure 6: Delivered Cost of Enstar Natural Gas (1993) ................................................. 13 Figure 7: Delivered Cost of Gas to Homer Non-Industrial Customers ........................... 21 Figure 8: Delivered Cost of Gas to Seward Non-Industrial Customers .......................... 22 Figure 9: Delivered Cost of Gas with 4% Money and

1,000,000 mcf per Year Industrial Load ................................................... 25

Maps

Map 1: Study Area and Likely Pipeline Routes .............................................................. 15 Map 2: CIRI Land Holdings ............................................................................................ 29 Map 3: Lease Sale 78 Tracts ......................................................................................... 31

Summary of Conclusions

This study examines the economics of bringing natural gas to Homer, Seward, and intermediate points along the Sterling Highway. We conclude that natural gas delivered by pipeline to Homer or Seward from the existing Enstar system will remain uneconomical or marginally competitive with diesel under plausible assumptions about economic growth. That's because both Homer and Seward have very small numbers of customers compared to the cost of a pipeline necessary to reach either community.

A very large industrial facility such as the proposed Midrex iron ore reduction facility would make a pipeline economically feasible, but the resulting cost of gas to consumers would still be about twice the level of current Enstar rates, due to higher local distribution costs. Also, under this scenario customers along the pipeline route would not automatically have access to cheap gas unless they were clustered in groups of at least 10 people within about one mile of the connection to the main line.

Local gas wells with reliable production could substantially improve the economics of gas supply. The proving up of the North Fork Gas Field might allow an economically competitive pipeline to be built to Homer. The search for new fields close to Homer on state and on private lands has been hampered recently by the cancellation of the southern half of state lease sale 78. That's because further exploration depends on access to contiguous blocks of land that cross ownership boundaries. The onshore portions of lease sale 78 may be re-offered again within the next two years. There are no local sources of gas currently apparent in Seward.

Low-cost financing (5.5% interest) could also allow a marginally competitive pipeline delivery system in Homer to serve current loads. But in Seward, higher transmission costs and lower demand mean that funds would have to be available at less than 2.5 percent to justify a pipeline.

Alternative delivery systems using compressed natural gas (CNG) or liquefied natural gas (LNG) offer the promise of gas energy to high-density market areas. CNG delivered by truck appears to be cheaper than LNG by truck, even though more energy per truckload can be carried using LNG. CNG delivery might also be possible by barge, but only if gas demand were to reach levels of about 10 times those estimated for the base case. None of these alternative delivery systems are likely to be competitive with diesel in the near future.

There are plausible combinations of events that could bring gas to Homer or Seward at a price of between $5.00 and $6.00 per mcf. One such combination would be a midsized industrial load of 1 million mcf per year, combined with access to low cost financing at about 4 percent interest. Non-profit institutions such as Homer Electric Association may have both the desire and ability to secure such low-cost financing.

ISER Kenai Peninsula Natural Gas Study 6/30/95 1

1. Current Energy Use and Cost on the Kenai Peninsula

Energy Use Patterns

In contrast to the Anchorage area, where over 90% of all households heat with natural gas, Kenai Peninsula residents and businesses use a mix of natural gas, oil, electricity, wood, propane, coal, and other fuels to meet their needs for heat and hot water.

The ISER end-use energy survey, conducted in 1988, focused on electricity but provided excellent data on overall fuel use patterns. Figure 1 and Table 1 show some of these patterns, adjusted to reflect today's increased use of natural gas. The survey showed that there is no dominant energy source on the Kenai. Natural gas is available to the major population centers in Kenai and Soldotna, but cannot effectively serve many of the outlying pockets of vacation homes, cabins, and isolated customers. Wood was used for at least some heating by almost half of all Kenai Borough residents in 1988, and was the primary heat source for 22 percent. According to the survey, propane is not used at all for primary heating, and very little for secondary and water heating. However, several Homer residents have personally stated that they use propane as a primary heating fuel.

100%

90%

oi 80% ::s .... Cl 70% C 'iii ::s 60% VI

'O 0 50% .c Q) VI ::s 40% 0 .c .... 0 30% -C Q)

~ 20% -Q) 0..

10%

0% -

2

Figure 1

Kenai Peninsula Residential Fuel Use Patterns

- - - - -

------

- - - - -

-------

primary heat hot water

•Wood

0 Bectric

11111 Propane

0 Gas

110il

ISER Kenai Peninsula Natural Gas Study 6/30/95

Table 1

Current Kenai Peninsula Residential Fuel Use

Total Oil Gas Propane Primary Heating Fuel

Households (1993) 15,510 4,343 6,285 0 percent 100% 28% 41% 0%

Fuel used for Some Heat Households 15,510 5,429 6,285 465

percent 35% 41% 3% (percentages do not add to 100 due to multiple fuel use)

Fuel used for Hot Water Households 15,510 1,861 6,285 620

percent 100% 12% 38% 4%

data sources: !SER 1987 Electricity End Use Survey

Enstar Natural Gas Co. Customer Counts

ADOL 1991 Population Overview and 1993 Special Tabulations

Wood/ Electric Other

1,551 3,257 10% 21%

5,118 8,686 33% 56%

6,825 310 44% 2%

The survey was somewhat biased towards primary dwellings only, because it was conducted by phone. Even so, the data show widespread use of multiple fuels, especially the wood/electric combination. These patterns suggest that there will always be a role for wood, electric, and propane energy systems in second homes and remote cabins where annual energy use is low and delivery costs are high.

Recent Energy Costs

Table 2 shows recent fuel prices on the Kenai Peninsula and for Alaska as a whole. (Natural gas is typically measured in thousand cubic feet, or "mcf' Electricity is measured in kilowatt-hours, or "kWh"). Because fuels are sold in quantities that contain different amounts of energy, it is useful to compare prices on a "dollars per unit of heat" basis. This comparison is shown in the bottom half of Table 2 and in Figure 2. The comparisons show the cost of 1 million Btus of delivered heat. They take into account both the heat content of the fuel itself and the efficiency with which it is typically burned.

Figure 2 highlights how inexpensive natural gas is when compared to all other heating fuels. It also shows that propane, while very expensive compared to gas and oil, is still substantially cheaper than electricity.

!SER Kenai Peninsula Natural Gas Study 6/30/95 3

4

Table 2

Selected Residential Energy Costs (October 1992)

Oil (#1) Gas Propane Electric Retail Fuel Prices $/gal $/mcf $/gal $/kWh

Homer 1.11 1.40 0.116 Seward 1.13 1.40 0.104

Kenai Borough average 1.12 3.60 1.38 0.116 State of Alaska average 1.34 3.60 1.53 0.108

Cost per Million Btu Delivered Heat Oil (#1) Gas Propane Electric Homer 12.74 22.15 33.99

Seward 12.97 22.15 30.47 Kenai Borough average 12.86 5.14 21.83 33.99 State of Alaska average 15.38 5.14 24.21 31.64

:I .... Ill C

~ .E ... QI C.

<I)

assumed heat content: 134,000 1,000,000 90,300 3,413 Btu/gal Btu/mcf Btu/gal Btu/kWh

assumed combustion efficiency: 65% 70% 70% 100%

notes: 1) Propane prices reflect customer fill or in-town delivery 2) Natural gas price excludes $4.50/month customer charge

data sources: ISER/AHFC Fuel Price Tracking Survey, October 1992 Alaska Electric Power Statistics, 1992 Edition

35.00

30.00

25.00

20.00

15.00

10.00

5.00

0.00

Oil (#1)

Figure 2

Residential Cost of Delivered Heat ($ per Million Btu)

Enstar Gas Propane Electric

Ill Kenai Borough

0 a11Alaska


Current Use of Natural Gas

The residents of the Kenai area were among the first Alaskans to get natural gas service more than 20 years ago. Today more than 6,000 households in the KenaiSoldotna area are residential gas customers of Enstar. That's about 41 % of all households in the Borough. As Figure 3 shows, the steady growth in residential customers has kept pace with the increase in households in this area. The two bars in the figure express residential gas customers as a percentage of the combined number of households in Kenai, Soldotna, Nikiski, and the Ridgeway Census-designated place (CDP). The saturation is over 100% since some gas customers live outside these four areas. The point is simply that there is very high market penetration of natural gas in this area, where people have had service for a long time.

Figure 3

Kenai Peninsula Residential Gas Customers

7,000 .----------------------, 120%

6,000 _____ - _ _ _ _ _______________ _

5,000

I!! ~ 4,000 .s u, 8 3,000 .... 0

:it 2,000

1,000

0 N 00 0) ....-

------- -\--------------reflects Enstar takeover

- - of Kenai City system

(') 'SI" LO (0 I'- 00 0) 0 ....- N 00 00 00 00 00 00 00 0) 0) 0) 0) 0) 0) 0) 0) 0) 0) 0) 0) 0) ....- ....- ....- ....- ....- ....- ....- ....- ....- ....-

1- % of households -.- Res. customers )

- 100%

80%

-- 60%

- 40%

-- 20%

0% (') 'SI" 0) 0) 0) 0) ....- ....-

As Table 3 shows, a typical Kenai/Soldotna residential or small commercial customer uses almost exactly the same amount of natural gas as a typical Anchorage customer. Large commercial Kenai customers use substantially less, due to the absence of large office buildings, very large schools, etc. The table also shows that about twice as much gas is consumed during the peak winter months as during the warm summer months. These patterns are also similar to Enstar system averages. This means that any proposed pipeline or alternative delivery system must be capable of meeting a monthly peak load that is more than double the average monthly consumption.


Table 3

1990 Kenai/Soldotna Natural Gas Consumption

Small Large Monthly Consumption (met) Residential Commercial Commercial Total

Jan 128,671 66,628 44,291 239,590 Feb 136,795 74,656 47,345 258,796 Mar 155,331 74,897 49,291 279,519 Apr 95,388 50,820 33,288 179,496

May 69,930 33,620 24,670 128,220 Jun 50,467 25,155 19,744 95,366 Jul 40,181 16,232 25,040 81,453

Aug 31,839 16,418 14,082 62,339 Sep 42,727 18,368 17,013 78,108 Oct 67,496 28,979 30,814 127,289 Nov 110,947 56,446 33,980 201,373 Dec 174,866 81,093 52,755 308,714

Total 1990 Consumption 1,104,638 543,312 392,313 2,040,263 average per month 92,053 45,276 32,693 170,022

monthly load factor (*) 53% 56% 62% 55%

Number of Customers 5,626 1,133 122

Annual met per Kenai customer 196 480 3,216 [compare to Enstar averages: 199 469 5,039

Seasonality: Winter use (Nov-Apr): 143 357 2,139

Summer (May-Oct) 54 122 1,077

Average Cost per mcf 4.01 3.75 3.25 Average Annual Cost $786 $1,799 $10,447

(*) note: load factor is the ratio of average monthly demand to the highest

monthly demand recorded for that year.

source: Enstar Natural Gas Co., FERC Form 2 and special tabulations

Finally, to give a better sense of how much gas might be used in areas like Homer and Seward, Table 4 shows some actual consumption amounts for typical buildings. The consumption figures are derived from end-use surveys and actual billing data. A school about the size of Homer High is an "average" large commercial customer and uses about 25 times as much gas as a typical household. A large residential institution such as the Anchorage Pioneers' Home uses almost 20% more gas per square foot than the school, due to the 24-hour demands for heat and hot water for laundry. A light industrial site, proxied by a U.S. post office, uses only one quarter as much gas per square foot as an energy-intensive meat processor.

6 ISER Kenai Peninsula Natural Gas Study 6/30/95

Table 4

Perspectives on Typical Natural Gas Consumption Patterns

Average Avg price Approximate Annual Volume (1993) Annual Size Cost per mcf I yr $/mcf cost square ft sq ft

Residence (average Kenai/ Soldotna Enstar customer) 196 4.01 $786 1,700 $0.46

School (Elementary, circa 1984 about 500 students) 4,906 3.25 $15,936 50,000 $0.32

Large Residential Institution (Pioneer Home) 16,882 3.25 $54,843 143,000 $0.38

Meat Processor (paying small commercial rate) 1,238 3.75 $4,643 5,000 $0.93

Warehouse/Light Industry (Anchorage Post Office) 1,630 3.75 $6,114 25,000 $0.24

source: compiled from ISER End-use survey data of individual establishments

2. Study Area Demographics and Potential Gas Consumption

Population Distribution and Recent Growth

Both the total population and the population density of the study area are very important to the economics of natural gas supply. For this analysis the Kenai Peninsula Borough can be usefully classified into the Kenai-Soldotna area, Greater Homer, Greater Seward, and points between. Table 5 shows recent demographic data for the areas not yet served by gas.

The data show that the outlying areas around Homer are growing at more than twice the rate as the core city of Homer. The entire Homer-to-Kenai corridor and the Sterling area are all growing faster than the borough average and far faster than Seward, which has barely grown at all during the past three years. The entire Borough is growing far more slowly than it did during the 1980s.

Although these highway corridors are growing rapidly, they are still small and, more important, not yet very dense. The Anchorage Bowl (estimated here using the area of four townships) has a density almost ten times greater than the City of Seward. This high a density is not critical for a gas system to be feasible, as the comparison data for Palmer and Wasilla show. Wasilla, with a medium density of about 400 people per square mile, is probably the best proxy for both the Homer and Seward areas. The gas system in Wasilla has developed in a steady manner over the past ten years, reaching pockets of population one at a time when densities permitted.


Table 5

Study Area Demographic Data

estimated estimated Census population Density: 1993 1993 1990 avg. growth Area (people per

Census Sub-area Population households Population 1990-93 (sq. miles) sq. mile) Immediate Homer Area

Fox River CDP 407 71 382 2.1% 86 5 Fritz Creek CDP 1,611 555 1,426 4.1% 61 26

Homer City 3,885 1,498 3,660 2.0% 11 353 Kachemak City 389 149 365 2.1% 2 195

Subtotal 6,292 2,273 5,833 2.6% 160 39 Between Homer and Kenai

Anchor Point CDP 1,016 368 866 5.5% 21 48 Clam Gulch CDP 83 30 79 1.7% 5 17

Cohoe CDP 556 205 508 3.1% 27 21 Happy Valley CDP 363 139 309 5.5% 34 11

Kalifonsky CDP 312 108 285 3.1% 11 28 Kasilof CDP 437 143 383 4.5% 11 40

Nikolaevsk CDP 435 94 371 5.4% 41 11 Ninilchik CDP 509 207 456 3.7% 38 13

Subtotal 3,711 1,293 3,257 4.4% 188 20 Between Kenai and Seward

Cooper Landing CDP 261 108 243 2.4% 55 5 Crown Point CDP 80 31 62 8.9% 6 13 Moose Pass CDP 105 43 81 9.0% 8 13

Primrose CDP 69 25 63 3.1% 16 4 (note: Sterling CDP not included here because much of it is already served by gas)

Subtotal 515 207 449 4.7% 85 6 Seward Area

Grouse Creek Group 584 199 580 0.2% #N/A Seward city 2,732 897 2,699 0.4% 15 182

Subtotal 3,316 1,096 3,279 0.4%

Total Study Area 13,834 4,870 12,818 2.6% Total Kenai Borough 44,411 15,510 40,802 2.9%

Comparison Areas Anchorage Borough 248,296 90,725 226,338 3.1% 144 1,724

Wasilla City 4,381 1,534 4,028 2.8% 11 398 Palmer City 3,205 1,116 2,866 3.8% 4 801

Notes: (1) CDP means "Census-designated place," usually an unincorporated area (2) Anchorage bowl area estimated at roughly 4 townships (12 * 12 miles)

source: ADOL special tabulations, ADOL 1991 Population Overview, 1990 U.S. Census CPH-1-3


The Experience of the Mat-Su Borough In the Mat-Su Borough, piped natural gas was completely unavailable until 1982. Figure 4 shows how the number of residential customers grew as gas distribution lines were made available to the area. Because there is no good data on how many houses had access to gas in any one year, the bars in the figure show the combined effect of the growing accessibility of gas and a growing number of hookups among customers with access. The line in the figure shows that the percentage of total houses using gas grew steadily over a ten-year period and seems to have leveled off at about 45 percent as of 1992. Of course, the percentage of gas-accessible houses that are hooked up is far higher -- perhaps close to 90 percent.

The Mat-Su experience suggests that the ultimate number of hook-ups in the Homer area and the Homer-Kenai corridor may be significantly larger than the base levels assumed here. But even the assumed base levels will take several years to achieve. Furthermore, the Mat-Su residents faced a far greater difference between gas and oil prices than the residents of Homer or Seward are likely to see. It is also quite clear that most of the Mat-Su area is lucky to be situated along the route of a pipeline built to serve the Anchorage demand. It would not be economic to serve much of the current Mat-Su territory if a pipeline had to be built from Anchorage solely for that purpose.

I!! (1)

E ~ ::I

(.) .... 0 .. (1) .c E ::I z

Figure 4

Mat-Su Borough Natural Gas Customer Growth 9,000 ~----------------~ 100%

8,000 -- -

7,000

6,000 - - - - - - -

5,000 - - - - - -

4,000

3,000

2,000 -

1,000

80% V, (1) V, ::I

60% _g ~ nl

40% .§ Q,

0 - 20% ~

0-1---a---.J---'--'--+--L--L+-.,_,_+--'-'--+'--'-+-'--'-+-'--'--+--'-'-l!-'-'--+--L--L+-'-'-\-0% N M ~ ~ © ~ 00 m O ~ N M ~ oo oo oo oo oo oo oo oo m m m m m m m m m m m m m m m m m m ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~

c:::::::J residential customers -- % of primary houses

(primary houses exclude vacation homes)


Potential Natural Gas Demand in Homer and Seward

For this study we make the following assumptions about the potential demand for gas due to current levels of population:

Table 6 Assumptions About Potential Gas Demand

based on Current Population

Homer Seward Customers:

Residential (Enstar "A") Small Commercial (''B") Large Commercial ("C")

1,200 200

12 Average Use per Customer (mcf/yr):

Residential (Enstar "A") 196 Small Commercial (''B") 480 Large Commercial ("C") 3,216

1,000 150

12

196 480

3,216 Total Non-industrial consumption (mcf/yr)

Residential (Enstar "A") 235,614 196,345 Small Commercial (''B") 95,907 71,930 Large Commercial ("C") 38,588 38,588

Total Consumption: 370,109 306,863

These estimates were adopted after considering current population levels, recent estimates of the Homer market by Enstar, and previous filings of Mountain Alaska Energy for a certificate to serve the Homer area. They represent mid-term estimates of customers, after a few years of conversions have taken place.

Comparison of Potential Homer & Seward Demand to Other Demands

It is useful to place the potential residential and commercial demand from Homer and Seward in the context of other demands for Cook Inlet gas. This comparison is shown in Table 7. These data show that potential demand from Homer, Seward, or both, is insignificant compared to any of the major existing industrial uses or compared to the existing Enstar non-industrial demand. There is plenty of gas available in Cook Inlet to meet any conceivable non-industrial needs of the study area without exerting any upward pressure on wellhead prices.

As Figure 5 shows, however, a facility as large as the proposed Midrex iron ore reduction plant would have a major impact on Cook Inlet gas demand. Such a facility would use almost as much gas as the entire Enstar customer base of residential and commercial users.

10 !SER Kenai Peninsula Natural Gas Study 6/30/95

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Table 7

Perspective on Homer and Seward Natural Gas Loads Compared to Overall 1993 Cook Inlet Gas Supply and Demand

billion cubic feet

Cook Inlet Remaining Reserves 2,187

Bcf/yr % of sales Total 1993 Sales of Cook Inlet Gas 180.0 100%

to LNG Plant 67.0 37% to Ammonia Plant 57.0 32%

for Electric Power Generation 32.0 18% to Enstar for Residential/Commercial use 24.0 13%

Potential Homer non-industrial use (base case) 0.4 Potential Seward non-industrial use (base case) 0.3 Potential Midrex Load (50 million cf/day) 18.3

Homer or Seward non-industrial load: as percent of Enstar Sales 1.5%

as percent of Midrex use 2.0% as percent of total sales from Cook Inlet 0.2%

source: Alaska DNR "Historical and Projected Oil and Gas Consumption," 2/94

200

180

160

140

120

100

80

60

40

20

0 ]§ 0 f-

Figure 5

Potential Homer or Seward non-industrial Load Compared to 1993 Sales of Cook Inlet Gas

(;) Ill <ii '- <ii z ·c 2 E __J 0 ~ (f)

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~


Future Economic and Industrial Growth

The latest economic and demographic projections for the overall Kenai Borough economy prepared by ISER (Goldsmith, 1994) show zero to moderate growth of population and total employment over the next ten years. The cause of the slowdown is fiscal austerity at the state level which is offset to varying degrees by continued growth of private basic sector industries.

To test the effects of economic growth on the delivered cost of gas, we use Goldsmith's "High" case projections for household growth over the next ten years on the Kenai Peninsula. In this projection, total Borough households increase by about 20% above 1994 levels. We use these higher levels of population and households in a test case in section 3, below.

Table 7 clearly shows that a single major industrial facility, such as the proposed Midrex iron ore reduction plant, would tend to swamp the effects of population growth on overall natural gas demand in a small place like Seward or Homer. For this reason, we consider these industrial demands as special, hypothetical cases, without trying to forecast whether such facilities will or will not choose to locate in the study area.

3. Delivered Cost Estimates -- Pipeline Scenarios

This section develops estimates of the cost of delivering natural gas to Homer and Seward by pipeline. We consider several cases in order to show under what conditions it would make economic sense to supply natural gas to these areas. Section 4, below, considers alternative means of transmission other than pipelines.

Current Delivered Cost of Enstar Gas

It is useful to begin the analysis with a look at the current cost of delivering gas through the Enstar system. Though small compared to most U.S. gas utilities, this system is clearly large enough to achieve all of the important economies of scale that keep delivered prices low.

12

Table 8

Enstar Average Cost of Service $/mcf

wellhead cost 2.05 O&M 0.60

transmission capital distribution capital

other capital

0.41 0.51 0.08

Total 3.66

source: Enstar FERC Form 2, 1993

Total Cost % of total 60,147,724 56% 17,558,279 16% 12,122,055 11% 15,067,434 14% 2,351,323 2%

107,246,815 100%


4.00

3.50

3.00

2.50

.... u E 2.00 -'1)-

1.50 -

1.00

0.50

0.00

Figure 6

Delivered Cost of Enstar Natural Gas (1993)

---------

--------

--------

---------

- - - - - -

- - - -

1111 other capital

11111 distribution capital

o transmission capital

oO&M

ow ellhead cost

Figure 6 shows that the wellhead cost of gas (the amount paid to the producers) makes up over half of the average total cost. Of particular importance to this study are the very low costs per mcf of transmission and distribution capital. These costs are low because a sizable investment in transmission and distribution plant is spread over a large number of customers. The Enstar system contains 339 miles of transmission pipeline with a gross book value of $107 million. But this transmission system serves 75,000 residential customers, or about 221 customers per mile of pipeline. In addition, commercial customers pick up half the total transmission cost, so in reality the cost of a mile of transmission pipeline is shared among about 440 residential users. That works out to a manageable pipeline investment of only about $500 per residential customer.

Although it is possible to reach "efficient" levels of local distribution pipes and customer equipment with a few hundred or a few thousand people, the cost of pipeline transmission is largely fixed (within broad limits) and independent of the volume transported, especially when the volume is small. This is a crucial reason why gas pipelines have not already been built to serve Homer and Seward.

Pipeline Routes Map 1 shows the study area and indicates the probable routing of pipelines to Homer or Seward. Due to ease of access, right-of-way issues, and the desire to serve customers along the route, it is most likely that a pipeline would follow existing highway routes. The route to Homer would begin at the south end of the Kenai Gas Field. The route to Seward would begin in the Sterling area east of the Kalifornsky compressor station.


This page intentionally blank


MAP 1: Study Area and Likely Pipeline Routes

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SCALE: 1" • 12.5 Ml. DA TE: 2/23/95


KENAI NATIONAL WILDLIFE REFUGE

REVISION BLOCK

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GIS DIVISION

SOUTHERN /(ENA/

PENINSULA VICINITY

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SCALE : /" • 12.6 Ml. DATE: 2/23/95

Base Case Assumptions and Delivered Costs

The Base case consists of the following key elements:

To Homer: • Gas supplied from Kenai Gas Field via 8-inch steel pipeline • About 72 miles to Homer • Approximate capital cost= $180,000 per mile @ Local Distribution total cost= $3,300,000 • Wellhead cost= $2.00/mcf

To Seward: • Gas supplied from Enstar system downstream of Kalifornsky compressor station • About 76 miles to Seward • Approximate capital cost= $225,000 per mile • Higher cost than to Homer due to difficult terrain and rock excavation • Local Distribution total cost= $3,300,000 -- smaller system but more expensive per

mile due to required rock excavation. • Wellhead cost= $2.00/mcf

To Both Places:

• Annual O&M based on Enstar ratios of O&M expense per dollar of plant • Capital charges based on depreciation over 30 years and return on investment of

12.5% of net plant value.

Based on these assumptions, the Base case delivered costs are calculated to be $11.44 per mcf in Homer and $15.41 per mcf in Seward. These costs are about 35 percent higher than the current cost of diesel on a simple $ per Btu basis, and about 4 times current Enstar prices. Table 9 shows these calculations in some detail. The basic reason the costs are so high is that the cost of the transmission line is spread over relatively few mcf, so that about half of the cost per mcf consists of fixed payments towards the pipeline.

We next consider several special cases to explore how the cost of gas is affected by economic growth, the development of a local gas supply, and the presence of a large industrial facility. In examining these cases, it is useful to keep in mind that the "breakeven" delivered cost of gas is about $8.28 per mcf. This is the price at which gas costs the same per unit of heat energy as does diesel at $1.11 per gallon. This break-even cost is a threshold. Gas at this price would not be cheap enough to induce anyone to convert their furnace for economic reasons (although some people might switch for environmental reasons). The Mat-Su experience shows that even when gas is less than half the cost of oil, it still takes several years for people to make these conversion investments, which typically cost over $2,000 per house.


Table 9: Base Case Delivered Cost Calculation

Units Homer Seward Fixed Capital Investment

Transmission System pipe size inches 8 8 Unit Cost $/mile 180,000 225,000 Distance miles 72 76

Transmission Total $ 12,960,000 17,100,000

Distribution Mains $ 2,500,000 2,500,000 Other Fixed Distibution 800,000 800,000

(regulator station, shop, etc.) Total Fixed Distribution $ 3,300,000 3,300,000

Total Fixed Capital Investment $ 16,260,000 20,400,000

# of Customers and Variable Capital Cost Residential (Enstar "A") # cust. 1200 1000 Small Commercial (''B") # cust. 200 150 Large Commercial ("C") # cust. 12 12

Service lines & Meters $/service 1,000 1,000 Service lines & Meters $ total 1,412,000 1,162,000

Annualized Capital and O&M Cost Depreciation per $ Gross Plant % 3.3% 3.3%

Return per $ Net Plant % 12.5% 12.5% Annualized Transmission $/year 2,046,873 2,700,736 Annualized Distribution $/year 744,203 704,718 Transmission O&M $/year 115,331 152,173 Distribution O&M $/year 336,343 318,498 General & Admin $/year 252,072 238,698

Total Annualized Delivery Cost $/year 3,494,822 4,114,823

Average Use per Customer Residential (Enstar "A") mcf/year 196 196 Small Commercial (''B") mcf/year 480 480 Large Commercial ("C") mcf/year 3216 3216

Estimated Total Sales Residential (Enstar "A") mcf/year 235,614 196,345 Small Commercial (''B") mcf/year 95,907 71,930 Large Commercial ("C") mcf/year 38,588 38,588 Large Industrial Customers mcf/year

Total Gas Sales mcf/year 370,109 306,863

Delivered Price of Gas per mcf (to non-Industrial users) Wellhead Cost of Gas $/mcf 2.00 2.00 Operation & Maintenance $/mcf 1.90 2.31 Distribution Capital Charges $/mcf 2.01 2.30 Transmission Capital Charges $/mcf 5.53 8.80

Total Delivered Cost of Gas $/mcf 11.44 15.41


"Growth" Case -- Continued High Economic Growth

In this scenario customer counts are increased by about 20 percent, based on the "High" economic growth projections prepared by Goldsmith. All other assumptions are unchanged.

The effect of this household growth is to reduce the average cost slightly, to $9.94 and $13.19 per mcf in Homer and Seward respectively. These costs are still well above the $8.28 per mcf amount that is needed to purchase the same amount of heat energy per dollar as diesel at its current price of $1.11 per gallon 1

.

"Local" Case -- Local Gas Supply

In this scenario a reliable local gas supply is assumed to be developed 15 miles from the community. This replicates the circumstances in Homer when Mountain Alaska Energy expressed interest in supplying the city from a proposed well drilled into the North Fork field, about 15 miles northeast of town. A key difference between this scenario and the Mountain Alaska proposal is that we assume the use of an 8 inch steel pipeline, rather than an 8-inch plastic pipeline. This raises the transmission cost considerably. We adopted the steel pipe concept after discussions with Enstar. By using steel pipe one can run the line at higher pressures, retain the potential to send gas north as well as south, and more easily accommodate taps off the main line.

Under these assumptions the local gas could be delivered at an average cost of $6.82 (Homer) or $7.95 per mcf (Seward). These costs are slightly below the break-even $8.28 amount, but still about twice the level of current Anchorage prices.

"Industry" Case -- Large Industrial Load

For this scenario we consider a hypothetical large industrial load consuming 50 million cubic feet per day, or about 18 million mcf per year. This very large load, about 50 times the non-industrial load used in the base case, is equivalent to the load of the proposed Midrex iron ore reduction plant.

The large amount of gas consumed requires a 16-inch pipeline (possible additional compression facilities are neglected here). Nonetheless, the volume is so great that the average transmission cost per mcf drops to only 20 cents for all users. This brings the calculated delivered cost down to very attractive levels: $5.82 per mcf in Homer and $6.40 per mcf in Seward.

1 Note that these price comparisons do not make adjustments for differences in combustion efficiency. This is done for simplicity, and because advances in oil heating technology mean that it is not safe to assume an average oil efficiency below that of gas furnaces. Excellent efficiency is now available using either fuel.


It is important to note two things about this case. First, the computed cost is the cost to the non-industrial customers. The large industrial customer would avoid essentially all distribution costs and pay only about $3.80 or $5.10 per mcf. Second, it is possible that a customer consuming such large volumes could negotiate a wellhead price lower than the $2.00 assumed here. If the residential and commercial users could tag along at the industrial facility's rate, then they too could reduce their cost somewhat.

Summary of Pipeline Cases

Table 10 provides a summary of delivered costs for the pipeline scenarios just discussed. Complete calculations, similar to Table 9, are provided for each case in Appendix A.

Table 10

Summary of Delivered Cost Calculations: Pipeline Scenarios (Target Breakeven cost based on diesel at $1.11/gal = $8.28 per mcf

Delivered Case Distance Gas Demand (mcf/yr) Rate of Avg. Cost Name Method Source miles Total Res/Comm. Industrial Return $/mcf Homer: Base Pipe Enstar 72 370,109 370,109 0 13% 11.44 Growth Pipe Enstar 72 451,161 451,161 0 13% 9.94 Local Pipe Local 15 370,109 370,109 0 13% 6.82 Industry Pipe Enstar 72 18,620,109 370,109 11a,25o,ooo 1 13% 5.82

Seward: Base Pipe Enstar 76 306,863 306,863 0 13% 15.41 Growth Pipe Enstar 76 374,065 374,065 0 13% 13.19 Local Pipe Local 15 306,863 306,863 0 13% 7.95 Industry Pipe Enstar 76 18,556,863 306,863 11a,25o,ooo 1 13% 6.40

Figure 7 (Homer) and Figure 8 (Seward) provide a useful summary of the components of delivered cost for each scenario. These figures clearly show how the average delivered cost drops as the transmission system is spread over larger gas volumes.


.... u E -4h

12.00

10.00

8.00

6.00

4.00

2.00

0.00

Figure 7

Delivered Cost of Gas to Homer Non-Industrial Customers

. - -

Base Growth Local Industry

Components of Delivered Cost to Homer Case: Base Growth

Wellhead Cost O&M Transmission Capital Distribution Capital Total Cost ($/mcf)

2.00 2.00 1.90 1.65 5.53 4.54 2.01 1.76

11.44 9.94

Diesel

II Dist'n Capital

• Transmission Capital

OO&M

OWellhead cost

Local Well Industry 2.00 2.00 1.65 1.15 2.01 6.82

1.60 0.20 2.01 5.82

note: the "Diesel" bar represents the current cost of diesel expressed in terms of dollars per million Btu of heat energy. There are 1 million Btu in 1 mcf of natural gas.


'ti E -vt

22

10.00

8.00

6.00

4.00

2.00

0.00

Figure 8

Delivered Cost of Gas to Seward Non-Industrial Customers

Base Growth Local Industry

Components of Delivered Cost to Seward Case: Base Growth

Wellhead Cost O&M Transmission Capital Distribution Capital Total Cost ($/mcf)

2.00 2.00 2.31 8.80 2.30

15.41

1.98 7.22 1.99

13.19

Diesel

II Dist'n Capital

II Transmission Capital

OO&M

DWellhead cost

Local Well Industry 2.00 2.00 1.91 1.83 1.74 2.30 7.95

0.27 2.30 6.40

note: the "Diesel" bar represents the current cost of diesel expressed in terms of dollars per million Btu of heat energy. There are 1 million Btu in 1 mcf of natural gas.

!SER Kenai Peninsula Natural Gas Study 6/30/95

4. Break-even Cases and Alternative Delivery Options This section reports the delivered costs for several special cases. First, we consider three "break-even" cases. The break-even cases are used to figure out how much any single factor would have to change from the base case in order to bring the cost of gas down to the threshold level of $8.28 per mcf. Second, we consider a combination case that combines optimistic assumptions about more than one factor. Finally, we consider two options for delivering gas by truck. The trucked system cases are very rough calculations that explore the cost of bringing gas to market in compressed or liquefied form and dispensing with the transmission pipeline altogether. Detailed calculations for all cases, similar to Table 9, are shown in Appendix A.

Break-even Case 1: Minimum Industrial Load

This case answers the question: How large would an industrial load have to be in order to bring the cost of gas down to parity with oil? All assumptions are the same as in the base case, except that the amount of industrial load was increased until the approximate break-even gas price of $8.28 per mcf was reached.

The required additional load is about 450,000 mcf/yr in Homer and about 1 million mcf/yr in Seward. For comparison, recall that the average Enstar large commercial class customer uses only 5,000 mcf/yr and a state pioneer home uses about 16,000 mcf/yr. So the required load is not trivial, but it is much less than that of a giant such as Midrex. Such a load would only allow gas prices to fall to the level of diesel. It would not allow Anchorage gas prices. Therefore it is reasonable to assume that the industry would have to locate in Homer or Seward for reasons other than the cost of natural gas.

Break-even Case 2: Maximum Distance from Local Supply

In this case the distance traversed by the 8 inch steel pipeline was varied to determine how far away a gas source could be and still serve the study communities at a cost no greater than that of diesel.

The answer is about 33 miles from Homer and about 18 miles from Seward, using a wellhead gas price of $2.00 per mcf. The wellhead cost might be lower than $2.00 if the local gas well had no other place to sell its output. However, a rational supplier would attempt to set the price from such a well as high as possible. And in this case, the highest he or she could set the price would be about $2.00, the level above which diesel is the cheaper fuel.

Break-even Case 3: Low-Cost Financing

The potential involvement of nonprofit or public entities in supplying natural gas suggests that one interesting question is "How low would the cost of capital have to be


in order to deliver gas competitive with diesel?" This case provides an answer to that question by finding the break-even return on invested capital (net plant) when all the other assumptions are the same as the base case.

The break-even cost of capital turns out to be positive -- about 5.5 percent in Homer and 2.5 percent in Seward. This is an encouraging result, since all the other assumptions are rather pessimistic.

Table 11

Summary of Breakeven Conditions Any One of Which Could Yield

Delivered Gas at $8.28 per mcf (=Diesel at $1.11/gal)

Homer Seward Additional Large Load (mcf) 450,000 1,000,000

( as fraction of base case load 122% 326% (as fraction of current Enstar load 2% 4% (as fraction of "Midrex" load 2% 5%

Local Well (proximity, miles) 33 18

Cheap Money (Interest on Net Plant) 5.5% 2.5%

Combination Case: Large Load and Low-Cost Financing

This case considers a combination of two optimistic but plausible assumptions. First, we assume a mid-size industrial load (or combination of loads) totaling 1 million met per year is present. Second, we assume that financing is available at 4 percent interest.

This combination of assumptions leads to a very attractive cost of only $5.29 per met in Homer and $5.95 in Seward. Note that this is be/ow the cost of $5.82 (Homer) which was the result of a very large (Midrex-size) load alone. This case suggests that low-cost financing could play an important role in bringing gas to the study area, especially if other factors combined to create strong growth in demand or, alternatively, a local source of supply.


.... (.)

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Table 12

The Effect of a Combination of Low Interest Financing and a Large Industrial Load

Additional Large Load (mcf) Interest rate on Net Plant

Resulting Delivered Cost of Gas ($/mcf): Wellhead Cost O&M Transmission Capital Distribution Capital Total Cost ($/mcf)

Figure 9

Homer 1,000,000

4.0%

2.00 1.67 0.69 0.93 5.29

Delivered Cost of Gas with 4% Money and 1,000,000 mcf/yr Industrial Load

6.00

5.00

4.00

3.00

2.00

1.00

0.00

Homer Seward

Seward 1,000,000

4.0%

2.00 1.93 0.95 1.06 5.95

1111 Distribution Capital

o Transmission Capital

oO&M

o Wellhead Cost

CNG Case: Compressed Natural Gas Delivered by Truck

Natural gas can be compressed at modest cost to substantially reduced volumes. For example, one can transport about 160 mcf on a single tractor-trailer arrangement at 2400 pounds per square inch (psi) of pressure.

This case is based on rough cost data provided by one vendor of CNG trucking equipment and services. See Appendix B for further discussion. To serve the base case demand levels (about 1,000 mcf per day) would require an average of about 6 trailer-


loads of CNG delivered each day, with about 8 loads per day in winter. The assumed distance from the gas source is about 70 miles per trip.

The calculation of delivered cost is rough and the details are shown in Appendix A. The main result is that the cost of transmission by truck is about $3.30 per mcf to Homer and slightly more to Seward (due to its lower level of demand). While this transport cost is substantially less than the cost of a pipeline, it is still too high to make the total cost competitive with oil.

Since CNG trucking costs are strongly dependent on distance and less strongly dependent on volume delivered to a particular place, this case suggests that the use of trucked CNG could be attractive as an interim technology to bring gas to areas such as Cooper Landing that are closer to current gas supplies.

LNG Case: Liquefied Natural Gas Delivery by Truck

This case calculates the cost of bringing natural gas in liquid form from a regional liquefier facility located about 100 miles from Homer or Seward or points between. The costs are based on recent studies of the potential for LNG-fueled motor vehicles, but the concept of regional liquefier plants is well-established among U.S. gas utilities that liquefy and store gas to meet winter peak loads. The LNG is easily regasified and then piped through a local distribution system. Consumers receive piped gas just as if they were connected to a pipeline.

The basic assumption made in this case is that LNG could be purchased for about 30 cents per gallon, which equates to about $3.75 per mcf, assuming minimal losses in transit. (This price has been adopted for use in similar studies in the lower 48 states.) The cost of transport is reported by Accurex (1994) and the Gas Research Institute to be only 5 cents per gal or about $.63 per mcf transported.

Due to the high cost of the LNG, the total cost of gas under this case is about $9.00 per mcf, which is slightly higher than the cost of fuel oil. If the LNG could be purchased for less than 30 cents per gallon, delivered costs would drop accordingly.

Barge Transportation of CNG in Tube Trailers

Compressed Natural Gas can be barged, although the required volumes appear to be much larger than the assumed loads in Homer and Seward. According to Ray Warren of Gas Trans in Austin, TX, the cost to do so is in the range of $1.70 per mcf for a barged volume of 10,000 mcf per day. (See Appendix B). This is more than ten times the level of demand assumed in the base case. Although this cost appears to be less than the cost of trucking, it is highly speculative, and the technology is probably less reliable (because the truck system can tolerate failure and delay of individual trailers). The economics depend heavily on higher delivery volumes, and it is unknown how the


Coast Guard would regulate such a cargo for a voyage in the Gulf of Alaska. No explicit calculation of overall delivered cost has been made based on barge transport of CNG.

Summary of Break-even and Alternative Transport Cases

Table 13 summarizes the delivered cost calculations for the break-even and truck transport cases.

Table 13

Summary of Delivered Cost Calculations: Breakeven and Special Cases (Target Breakeven cost equal to diesel at $1.11/gal= 8.28 $/mcf)

Delivered Case Distance Gas Demand (mcf/yr) Rate of Avg. Cost Name Method Source miles Total Res/Comm. Industrial Return $/mcf Homer: Breakeven1 Pipe Enstar 72 820,109 370,109 I 4so,ooo 1 12.5% 8.24 Breakeven2: Pipe Local WI 331 370,109 370,109 0 12.5% 8.28 Breakeven3: Pipe Enstar 72 370,109 370,109 0 5.5% 8.10 Combination Pipe Enstar 72 1,370,109 370,109 1,000,000 4.0% 5.29 CNG Homer Truck Enstar 70-80 370,109 370,109 0 12.5% 8.90 LNG Homer Truck LNG 100 370,109 370,109 0 12.5% 8.93

Seward: Breakeven1 Pipe Enstar 76 1,306,863 306,863 I 1,000,000 I 12.5% 8.30 Breakeven2: Pipe Local WI 181 306,863 306,863 0 12.5% 8.31 Breakeven3: Pipe Enstar 76 306,863 306,863 0 2.5% 8.38 Combination Pipe Enstar 76 1,306,863 306,863 1,000,000 4.0% 5.95 CNG Seward Truck Enstar 70-80 306,863 306,863 0 12.5% 9.92 LNG Seward Truck LNG 100 306,863 306,863 0 12.5% 9.57


5. Implementation Issues and Recommendations

Alternative Local Gas Supplies

All observers agree that the North Fork field outside of Homer has poorly defined gas reserves and needs more wells drilled to fully delineate the field. The one completed well showed that 7,000 mcf per day was possible, but this flow rate was only tested for several days. Additional test wells are expensive, probably costing at least $1 million per well.

Other smaller fields may have gas available at attractive volumes and prices. Cook Inlet Region, Inc. (GIRi), an Alaska Native Corporation formed under the Native Claims Settlement Act, is the major private landowner in the area. According to GIRi staff, the Company has several potential prospects of interest within 10 to 20 miles of Homer, based on pre-existing geophysical assessments. They have exploration agreements with other energy companies to conduct additional geophysical and (what is far more expensive) seismic work.

The major impediment to further exploration activity on GIRi land is that the corporation's private holdings are too scattered to form economically viable units for exploration and development. In order to continue with exploration, GIRi and its partners feel that they must have access to the state lands that are intermingled with their private holdings. Lease Sale 78 offered this opportunity for lands close to Homer, but this portion of the sale was canceled due to a combination of local opposition and lack of specific industry interest, according to state officials. Now the state is planning to re-offer this acreage in 1996 as part of Sale 85A, in response to a direct interest expressed by GIRi and its exploration partner Union Texas Petroleum (Anchorage Daily News, 6/20/95).

Map 2 shows GIRi's land holdings on the southern Kenai Peninsula. The important thing to note is the scattered pattern of the holdings and the number of different parcels within the 20 mile radius of Homer. It is safe to presume that most if not all of these lands were selected for their oil and gas potential. Map 3 shows the portion of Lease Sale 78 that was canceled and may be re-offered. Careful inspection of these two maps shows how interlocked is the land ownership of the State of Alaska and GIRi.

2 Kevin Brown, Exploration Manager, February 17, 1995; Larry Kimball, Land Manager, May 22, 1995


-.. ..

MAP 2: CIRI Land Holdings

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SOUTH KENAI IN-REGION

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COOK INLET REGION, INC. dlB 11/94

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STATE OF ALASKA ·f)EPARTMENT OF NATURAL RESOURCES

DIVISION OF OIL AND GAS

PROPOSED OIL AND GAS LEASE SALE 78

COOK INLET PRELIMINARY TRACT MAP

NOTE : NO DECISION HAS YET

BEEN MADE ON WHETHER THE

STATE WILL HOLD THIS LEASE

SALE. THE STATE IS GATHERING

SOCIAL ENVIRONMENTAL &

ECONOMIC INF OR MA TION ON

WHICH TO BASE A DECISION.

NOTE : THIS MAP IS NOT THE

SCALE 1:600,000 ONE INCH= 10 MILES approx. OFFICIAL TRACT MAP. A SET OF OFFICIAL TRACT MAPS IS

I _ _j10======,;:or::=====::110;;;:=;:~:=::==;==2

[0======3=o]l\Lii-lu-l AVAILABLE AT THE DEPARTMENT

t- OF NATURAL RESOURCES.

DIRECTOR D1v1s10 F DRAWN ... D_A_TE_A_P_P_Ro_v_e_D __ 7_/_1_3/_9_3--.1 rnvIsI0N OF OIL AND GAS, 3601 c

JAMES E. EASO \ BY: M.P. & BASE MAP: TRANSPOSED FROM ST., SUITE 1398. P.O. BOX 107034,

~_::_:_:.:_::..::.:_::..:.::..:.:_~~==:::::±:=:~!:::::::::::.-l--_'.O~.D~.S~. -I U.T.M. PROJECTIONS BY U.S.G.S. ANCHORAGE. ALASKA 99510-7034

PETRO. GEOPH CHECKED REDRAWN IN AUTOCAD AND PHONE (907) 762-2586

JAMES HANSEN BY: Mj CLARISCAO

Potential Involvement of Homer Electric Association

According to HEA staff3 , HEA is considering ways that it could help bring gas to

Homer. One of the most obvious would be to use its ability to borrow money at low interest rates, perhaps through the newly created Rural Utilities Service (RUS), which is the successor to the Rural Electrification Administration. The name change reflects a broadening of mission to embrace other utilities, especially water and sewer systems.

Before it can proceed with any plans to help supply natural gas, HEA must change its articles of incorporation and bylaws to allow it to participate in an activity other than providing electricity and telephone services. The board and staff have successfully completed the key steps in this process. These include passage of a bill in the Alaska legislature to allow such expanded services and passage of a membership vote to change the articles of incorporation.

While HEA staff will not reveal their specific plans for potential natural gas supply, it appears that the utility's managers have carefully studied the technical options, may have selected a technically preferred alternative, and are interested in being a project facilitator. The Association is tax-exempt, and there are RUS (formerly REA) loan funds available for rural development purposes. RUS moneys are currently available at 2% interest, to which HEA might add a handling fee.

Enstar Ratemaking Treatment of a High-Cost Expansion

According to Enstar statt4 the company could conceivably enter a high-cost market such as Homer and request "postage stamp rates," e.g., allocate the additional investment costs among all of its existing Anchorage customers. Our preliminary calculations suggest that this would add about 10 cents/mcf, or 3%, to current rates. Given the history of close scrutiny of possible cross-subsidies by the Alaska Public Utilities Commission, it is extremely unlikely that the Commission would approve such a clear and substantial cross-subsidy as this.

Potential Supplies of LNG Staff from Norgasco 5 have suggested that current production of LNG from the Phillips Petroleum plant in Nikiski might be available for local purchase. However, we feel it is extremely unlikely that they would sell locally in the near future or at a competitive price. The first reason is that all of their sales are probably tied up in long-term contracts. The second reason is that small-scale, domestic sales might have all sorts of "nuisance effects" such as tax implications, the need to install special loading equipment, and the possible tightening of environmental regulations.

3 Rick Eckert, Controller, personal communication, January 11 1995 4 Dan Dieckgraeff, Manager, Rates & Planning, 1/12/95 5 Charlie Helm, Norgasco Engineer, 12/30/94


The plans of an Anchorage company, Northern Eclipse, are probably of greater interest and relevance to Kenai Peninsula audiences. Northern Eclipse is developing a regional liquefier facility in Southcentral Alaska. The facility is being built next to the Beluga pipeline near Point McKenzie and will have a capacity of 10,000 gallons per day. That's equal to about 800 mcf per day, which is slightly less than the base case demands for either Homer or Seward shown above in Table 6. Since the project will require local regasification and local distribution facilities, the obvious initial market to develop is Fairbanks, where there is significant use of high-cost propane. The small town of Girdwood is also a probable market, and a promising area over the long term is the Anchorage motor vehicle market (LNG Express, February 1995).

If this project proceeds it should provide valuable operating experience and cost data to anyone wishing to transport natural gas by means other than an expensive pipeline.

Recommendations

1. The Economic Development District (KEDD) and other interested parties should actively monitor the progress of the Northern Eclipse regional LNG facility. If the project succeeds, it may be worthy of emulation, since the distance to be covered by truck from Kenai to Homer or from Soldotna to Seward is far less than the distance from Pt. McKenzie to Fairbanks.

2. This study supports the idea that gas service to Homer would be feasible from a local supply source. KEDD should therefore consider working with GIRi and state officials to ensure that any leasing activities somehow encourage the provision of local gas supplies to Homer. This is a political issue, but the leasing process is intended to be responsive to such concerns.

3. KEDD should work closely with Homer Electric to evaluate options for low-cost financing of gas development projects. Specifically, a local distribution system based on trucked LNG could be the starting point for future expansion and an eventual pipeline.

4. The southern Kenai is already well-diversified away from diesel. Wood, the most obvious alternative energy source, is already heavily used by local residents. Electricity is already generated completely by gas and hydro. Further activities should therefore continue to focus on options for local gas development and transportation schemes, rather than more exotic, unproven options such as coal, solar, or wind energy.


References

Accurex Environmental Corporation, 1994. LNG Vehicle Technology, Economics, and Safety Assessment. Prepared for Gas Research Institute (8600 W Bryn Mawr Ave, Chicago, IL 60631). February.

Alaska Department of Labor, 1994. Special Tabulations of 1993 Population Estimates.

Alaska Department of Labor, 1993. Population Overview: 1991 Estimates. Published by ADOL Research and Analysis Section.

Alaska Department of Natural Resources, 1994. Historical and Projected Oil and Gas Consumption. Anchorage: DNR Division of Oil and Gas.

Anchorage Daily News, 1995. Southern Kenai Oil Leases Again Eyed. June 20.

Clean Fuels Report, June 1994. Published by J.E. Sinor Consultants Inc., PO Box 649, Niwot, CO 80544.

Colt, Steve, Scott Goldsmith, et. al. 1989. Forecast of Electricity Demand in the Alaska Rai/belt Region. Prepared by ISER for the Alaska Power Authority. May.

Colt, Steve, 1992. /SER Quarterly Fuel Price Tracking Survey, 92:4. Prepared for Alaska Housing Finance Corp. Available from ISER.

Decision Focus, Inc., 1989. Rai/belt lntertie Reconnaissance Study Benefit/Cost Analysis (Appendix/). Prepared for Alaska Power Authority. June.

Enstar Natural Gas Company, 1994. FERG Form 2, Original Filing, 12/31/93.

Goldsmith, Scott, 1994. Economic Projections for Alaska and the Southern Railbelt. Prepared by ISER for Chugach Electric Association. August.

Kenai Peninsula Economic Development District, Inc., 1994. Kenai Peninsula Borough 1993 Situation and Prospects. KEDD, 110 S. Willow St., Kenai AK 99611

LNG Express, 1995. Company Profile: Northern Eclipse. February.

Mountain Alaska Energy, Inc. Statement of Public Convenience and Necessity. Filed with Alaska Public Utilities Commission under Docket U-87-77

Tavella, Michael, 1988. Memorandum to Commissioner Susan Knowles re Mountain Alaska Energy. (U-87-77). Available at Alaska Public Utilities Commission.


Tussing, Arion, and Connie C. Barlow, 1985. The Cook Inlet Gas Market. Prepared for Chugach Electric Association by ARTA Inc., Seattle WA.

Tussing, Arion and Lois Kramer, 1981. Hydrocarbons Processing: A Primer for Alaskans. Anchorage: Institute of Social and Economic Research. August.

U.S. Geological Survey, 1994. The Future of Energy Gases. USGS Circular 1115. Available from USGS Map Distribution, Box 25286, Building 810, Denver Federal Center, Denver CO 80225.


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Appendix A:

Detailed Calculations of Delivered Cost

Order of Cases:

Base (printed in report as Table 8) Growth: 20% increase in households

Local: Local gas supply available 15 miles away Industry: 50,000 mcf/day major industrial load

Break-even 1: Minimum Industrial Load Break-even 2: Maximum distance for Local gas supply

Break-even 3: Maximum return on capital Combination Case: 1 million mcf per year industrial load and 4% financing

CNG: Compressed Natural Gas Delivered by Truck LNG: Liquefied Natural Gas Delivered from regional liquefier by truck

Note: These tables include a calculation of the payback period for someone converting an existing oil heating system to gas. The calculation assumes a $2,000 conversion cost, a 65% efficient existing oil furnace, and a 70% efficient gas furnace.

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Kenai Peninsula Natural Gas Supply Model Case: Current Conditions Year: 1994

Method: Pipeline Delivery from Enstar System Comment: Base case analysis of current conditions
















Total Delivered Cost of Gas $/met 11.44 15.41 Equivalent to diesel cost of: $/gal 1.53 2.06 Current Diesel Cost $/gal 1.11 1.13

Simple Payback on Conversion to Gas years Never Never

!SER KENAIGAS.XLS Base 7/7/95 10:54 AM

Kenai Peninsula Natural Gas Supply Model Case: High Economic Growth Year: 2004

Method: Pipeline Delivery from Enstar System Comment: High rate of general economic growth consistent with ISER/CEA

High case. Kenai Peninsula households increase by 20% in 2004 compared to 1994 levels.













Estimated Total Sales Residential (Enstar "A") mcf/year 287,212 239,344 Small Commercial ("B") mcf/year 116,910 87,682 Large Commercial ("C") mcf/year 47,039 47,039 Large Industrial Customers mcf/year



Total Delivered Cost of Gas $/mcf 9.94 13.19 Equivalent to diesel cost of: $/gal 1.33 1.77 Current Diesel Cost $/gal 1.11 1.13

Simple Payback on Conversion to Gas years Never Never

ISER KENAIGAS.XLS Growth 7/7/95 11 :03 AM

Kenai Peninsula Natural Gas Supply Model Case: Local Gas Well Year: 1994

Method: Pipeline delivery from local well Comment: Consistent with Mountain Alaska proposal to bring gas

from North Fork Field to Homer, but using Steel pipe and Enstar distribution cost estimates.










Return per $ Net Plant % 12.5% 12.5% Annualized Transmission $/year 426,432 533,040 Annualized Distribution $/year 744,203 704,718 Transmission O&M $/year 24,027 30,034 Distribution O&M $/year 336,343 318,498 General & Admin $/year 252,072 238,698







Simple Payback on Conversion to Gas years 4.8 9.0

ISER KENAIGAS.XLS Local 7/7/95 11 :04 AM

Kenai Peninsula Natural Gas Supply Model Case: Major Industrial Gas User Year: 1994

Method: Pipeline delivery from Enstar System Comment: Consistent with Midrex Proposal to build industrial facility using 50 millio

cubic feet per day. This is about 60% ofTOTAL existing Enstar load and requires 16" steel pipeline with probable additional compression.









Annualized Capital and O&M Cost Depreciation per$ Gross Plant % 3.3% 3.3%

Return per$ Net Plant % 12.5% 12.5%

Annualized Transmission $/year 3,809,459 4,981,357 Annualized Distribution $/year 744,203 704,718 Transmission O&M $/year 214,644 280,675 Distribution O&M $/year 336,343 318,498 General & Admin $/year 252,072 238,698



Estimated Total Sales Residential (Enstar "A") mcf/year 235,614 196,345 Small Commercial (''B") mcf/year 95,907 71,930 Large Commercial ("C") mcf/year 38,588 38,588 Large Industrial Customers mcf/year 18,250,000 18,250,000

Total Gas Sales mcf/year 18,620,109 18,556,863

Delivered Price of Gas per mcf (to non-Industrial users) Wellhead Cost of Gas $/mcf 2.00 2.00 Operation & Maintenance $/mcf 1.60 1.83

Distribution Capital Charges $/mcf 2.01 2.30

Transmission Capital Charges $/mcf 0.20 0.27

Total Delivered Cost of Gas $/mcf 5.82 6.40 Equivalent to diesel cost of: $/gal 0.78 0.86

Current Diesel Cost $/gal 1.11 1.13 Simple Payback on Conversion to Gas years 3.3 3.8

ISER KENAIGAS.XLS Industry 7/7/95 11 :04 AM

Kenai Peninsula Natural Gas Supply Model Case: Breakeven Industry Load Year: 1994

Method: Pipeline Delivery from Enstar System Comment: Breakeven Case to determine minimum industry load

necessary to make gas competitive with diesel at $1.11/gal













Estimated Total Sales Residential (Enstar "A") mcf/year 235,614 196,345 Small Commercial ("B") mcf/year 95,907 71,930 Large Commercial ("C") mcf/year 38,588 38,588 Large Industrial Customers mcf/year 450,000 1,000,000

Total Gas Sales mcf/year 820,109 1,306,863



Simple Payback on Conversion to Gas years 14.9 13.0

!SER KENAIGAS.XLS Break1 7/7/95 11 :04 AM

Kenai Peninsula Natural Gas Supply Model Case: Breakeven Maximum Distance to Local Well Year: 1994

Method: Pipeline Delivery from Local Wells Comment: To determine maximum distance at which 8 inch steel pipeline

delivery is feasible.


Transmission System pipe size inches 8 8 Unit Cost $/mile 180,000 225,000

~

Distance miles 33 18 Transmission Total $ 5,940,000 4,050,000




# of Customers and Variable Capital Cost Residential (Enstar "A") # cust. 1200 1000 Small Commercial (118 11

) # cust. 200 150 Large Commercial ("C") # cust. 12 12



Return per $ Net Plant % 12.5% 12.5% Annualized Transmission $/year 938,150 639,648 Annualized Distribution $/year 744,203 704,718 Transmission O&M $/year 52,860 36,041 Distribution O&M $/year 336,343 318,498 General & Admin $/year 252,072 238,698






Total Delivered Cost of Gas $/mcf 8.28 8.31 Equivalent to diesel cost of: $/gal 1.11 1.11

Current Diesel Cost $/gal 1.11 1.13 Simple Payback on Conversion to Gas years 15.9 13.3

ISER KENAIGAS.XLS Break2 7/7/95 11 :04 AM

Kenai Peninsula Natural Gas Supply Model Case: Breakeven Return on Capital Year: 1994

Method: Pipeline Delivery from Enstar System Comment: Determines the maximum nominal return on invested capital to mak

pipeline feasible from Enstar system. Simulates alternative financing










Return per $ Net Plant % 5.5% 2.5% Annualized Transmission $/year 1,139,666 990,726 Annualized Distribution $/year 414,360 258,516 Transmission O&M $/year 115,331 152,173 Distribution O&M $/year 336,343 318,498 General & Admin $/year 252,072 238,698







Simple Payback on Conversion to Ga years 12.4 14.6

ISER KENAIGAS.XLS Break3 7/7/95 11 :04 AM

Kenai Peninsula Natural Gas Supply Model Case: Combo 1: Cheap Money plus Industrial Load Year: 1994

Method: Pipeline Delivery from Enstar System Comment: Combination of low-interest financing and new large

load to bring gas cost down toward Enstar level







#Customers and Variable Capital Cost Residential (Enstar "A") # cust. 1200 1000 Small Commercial (''B") # cust. 200 150 Large Commercial ("C") # cust. 12 12



Return per$ Net Plant % 4.0% 4.0% Annualized Transmission $/year 945,266 1,247,226 Annualized Distribution $/year 343,680 325,446 Transmission O&M $/year 115,331 152,173 Distribution O&M $/year 336,343 318,498 General & Admin $/year 252,072 238,698



Estimated Total Sales Residential (Enstar "A") mcf/year 235,614 196,345 Small Commercial (''B") mcf/year 95,907 71,930 Large Commercial ("C") mcf/year 38,588 38,588 Large Industrial Customers mcf/year 1,000,000 1,000,000

Total Gas Sales mcf/year 1,370,109 1,306,863


Total Delivered Cost of Gas $/mcf 5.29 5.95 Equivalent $/Btu Diesel Cost $/gal 0.71 0.80 Current Diesel Cost $/gal 1.11 1.13

Simple Payback on Oil Conversion years 2.8 3.2

ISER KENAIGAS.XLS combo1 7/7/95 11 :04 AM

Kenai Peninsula Natural Gas Supply Model Case: Trucked CNG Year: 1994

Method: Trucked Delivery of CNG from Enstar System Comment: Places existing estimate of "Turnkey" system for trucked compresse

gas in context of standard base case assumptions.


Transmission System 4 Tractors @ $70,000 $ 280,000 280,000 6 Trailers@ $120,000 $ 720,000 720,000

Compressor, Storage, etc. $ 1,071,128 888,352 Transmission Total $ 2,071,128 1,888,352






Annualized Capital and O&M Cost Depreciation per $ Gross Plant % 3% 3%

Return per $ Net Plant % 13% 13% Annualized Transmission $/year 590,273 538,181 Annualized Distribution $/year 744,203 704,718 Transmission O&M (9 people) $/year 630,000 630,000 Distribution O&M $/year 336,343 318,498 General & Admin $/year 252,072 238,698







Simple Payback on Oil Conversion years 440.7 Never

ISER KENAIGAS.XLS CNG 7/7/95 11 :04 AM

Kenai Peninsula Natural Gas Supply Model Case: LNG Trucked from Regional Liquefier Year: 1994

Method: LNG Trucked 100 miles from Regional Liquefier plant Comment: Based on LNG Fuel Supply Studies for Vehicle Fleet demands. Tee

is currently used for meeting peak demands of Lower 48 Gas Cos. Note: 1 gallon LNG = 0.080 mcf natural gas

Units Homer Seward LNG Transmission System (100 miles)

Gas demand in gallons of LNG gal/yr 4,626,365 3,835,793 Transport Cost per Gallon $/gal 0.05 0.05 Transport cost per mcf $/mcf 0.63 0.63

Fixed Capital Investment Distribution Mains $ 2,500,000 2,500,000 Other Fixed Distibution 800,000 800,000 LNG Storage tank 850,000 850,000 Total Fixed Distribution $ 4,150,000 4,150,000




Annualized Capital and O&M Cost Depreciation per $ Gross Plant % 3% 3%

Return per $ Net Plant % 13% 13% Annualized Transmission $/year 0 0 Annualized Distribution $/year 878,450 838,965 Transmission O&M $/year 0 0 Distribution O&M $/year 397,016 379,171 General & Admin $/year 297,544 284,170




Total Gas Sales mcf/year 370,109 306,863 Delivered Price of Gas per mcf (to non-Industrial users)

Cost of LNG at Liquefier $/gal LNG 0.30 0.30 Expressed as $/mcf gas $/mcf 3.75 3.75 Operation & Maintenance $/mcf 1.88 2.16 Distribution Capital Charges $/mcf 2.37 2.73 Transmission Cost from above $/mcf 0.63 0.63


Simple Payback on Oil Conversion years Never Never

ISER KENAIGAS.XLS LNG 7/7/95 11 :05 AM

Appendix B:

Discussion Memoranda on Cost Assumptions

Letter from Richard Warren, Gas Trans, re: Trucked CNG Memo from Mark A. Foster re: Pipeline length and Cost Memo from Mark A. Foster re: Meeting with Norgasco

Memo from Mark A. Foster re: Barge Transport of CNG

11-29-1994 10:21AM FROM CNG/FSA/SASSER/GOULD

GAS TRANS GAS TRANSPORT SERVICES, L. C.

November 29, 1994

Mr. Steve Colt University of Alaska, ISER 3211 Providence Drive Anchorage, Alaska 99508

Re: Trucking Natural Gas

Dear Steve:

TO 19077867739 P.01

Thank you for the interest you have expressed in Gas Transport Services, L.C. ("GAS TRANS") and more particularly in the proporietary system of transporting compressed natural gas in high pressure tubes. There might be several applications for the technology in Alaska.

GAS TRANS is licensee of certain patents and other proprietary technology related to the transportation of compressed natural gas in high pressure tubes mounted on trailers for land transportation and in high pressure vessels mounted on barges, workboats or ships for marine transport ( ''the 'l'echnology"). The Technology is owned by CNG Technologies, Inc. who acquired it from Texas Gas Transport Company. Since the mid 1970 's, operations of the combined companies have successfully applied the Technology is seventeen States and Canada where over 70,000 loads representing approximately 20 billion cubic feet of gas have been delivered.

The prospect on transporting natural gas by tube trailer into Homer is not new. Back in the late 80' s Texas Gas Transport was involved in preliminary studies in which the Technology was evaluated to provide natural gas service for both commercial and residential use. At that time natural gas was being evaluated as an alternative to the traditional fuels such as fuel oil, diesel and propane. Preliminary results indicated a likely economic advantage for the use of natural gas. Environmental considerations also favored its application.

Over the years the technology has been successfully applied in all types of road and weather conditions. We therefore would not expect to encounter any unusual problems related to gas deliveries to Homer. As in every project, a system would be specifically designed and equipped with adequate personnel and proper equipment to meet or exceed the requirements of the transport system.

The cost of service varies ~idely betw~~n pr.ojects an.d is primarily dependent upon volume deliveries and the distance to be transported. Other factors such as the gas supply pressure, market

707SOITTHWESTTOWER • 211EAST7THSTREET • AUSTIN, TEXAS7870l • (512)476-8866 • FAX(512)476-462..'i

11-29-1994 10:21AM FROM CNG/FSA/SASSER/GOULD TD 19077867739 P.02

delivery pressure and gas storage requirements, can also affect the cost. Included in your fax and part of Mr. Don Fowler's testimony before The Alaska Public Utility Commission, was a preliminary estimate of the cost to transport and deliver approximately 1,000 Mcf per day over a distance of 80 one way miles. Don's "turn-key" estimated price for this service ~t the time was $100,000 per month, or about $4.67 per Mcf. If the volume in this example were increased and the distance reduced, as you have indicated might now be the case, the cost will also reduce. For example, if the requirements of the transport system was 2,700 Mcf/d (1 Bcf/year) over a distance of 50 one way miles, the cost of service based on similar projects and assuming a reasonable return on investment would be approximately $185,000 per month, or about $2.25 per Mcf, and would likely require the following personnel and equipment:

Four tractors Six high pressure tube trailers Compressor Dehydrator Load station Offload station Offload line heater Four driver operators per tractor Two supervisors/foreman

Capital cost is estimated at approximately $2.8MM, assuming all equipment is purchased new. Lease or lease/purchase options, or purchases of used equipment, can reduce the initial expense substantially.

The subject of remote transportation of natural gas utilizing the Technology continues to come up in Alaska. Several times during the recent past we have been contacted by both private companies and Alaskan State officials alike, regarding the possible use of the Technology in a variety of applications. Interest also remains strong at the State level to replace imported fuels such as diesel, propane and fuel oil with the less expensive, clean burning domestic natural gas supplies. We believe that if given the opportunity, the Technology will prove to be a reliable and cost effective means of natural gas deliveries in Alaska.

Under separate cover I am sending additional information regarding the Technology. We welcome any opportunity to work with you, ISER, the City of Homer or the State, to determine how best to pursue applications of the Technology. Any assistance you could provide in this effort is appreciated.

Sincerely,

TOTAL P.02

TO:

FROM:

DATE:

RE:

Homer:

MEMORANDUM

Steve Colt, ISER FAX: 786-7739

Mark A. Foster, MAFA 1~ '

December 9, 1994

Natural Gas to Homer & Seward Reconnaissance Level Capital Cost Estimates

Assume gas supply near Kenai Gas Field. Approximate length of transmission facility = 72 miles Reconnaissance Level Capital Cost Estimate: per mile

8" diameter steel pipeline $180,000/mile 16" diameter steel pipeline $335,000/mile (Note 16" may require additional compression facilities)

Project Est. $13 million $24 million

Estimate Homer Distribution System Costs to average $47,000 per mile.

Seward:

Assume gas supply downstream of Enstar compression facilities. Approximate length of transmission facility = 76 miles Route to Seward involves difficult terrain and rock excavation. Reconnaissance Level Capital Cost Estimate: per mile

8" diameter steel pipeline $225,000/mile 16" diameter steel pipeline $415,000/mile (Note 16" may require additional compression facilities)

Project Est. $17 million $32 million

Estimate Seward Distribution System Costs to average $58,000 per mile. (Note: Seward distribution involves rock excavation)

TO:

FROM:

DATE:

RE:

MEMORANDUM

Steve Colt, ISER

Mark A. Foster, MAFA lf/.t;f--December 30, 1994

Kenai Natural Gas Study Meeting with Charlie Helm, Norgasco Engineer

I meet with Charlie Helm, the chief engineer at Norgasco, on November 29, 1994 to discuss the potential for providing natural gas to the communities of Homer and Seward.

Mr. Helm indicated that he had participated in discussions on this topic with the Mayor of Homer.

Mr. Helm indicated that Ed Baffin, Norgasco President, has been investigating potential supplies to serve Homer, but has not yet been able to find a source with the volume commitment required and a "competitive" price. He indicated one potential source of natural gas is the Liquefied Natural Gas (LNG) produced in Kenai that is currently being shipped to Japan.

Mr. Helm also provided some "rules of thumb" for estimating the capital project cost of a natural gas distribution system at $15 / foot for plastic and $25/foot for steel ($79,200/mile and $132,000/mile respectively).

Finally, Mr. Helm suggested that the market for compressed natural gas (CNG) vehicles might be an item to consider. However, he estimated that there were 27-28 CNG vehicles operating in Barrow primarily because the cost of gasoline was around $2.80 per gallon and thus natural gas could have a price advantage over gasoline.

Monday, January 91 1995 9:20:24 AM 907 /277-2267

TO:

FROM:

DATE:

RE:

MEMORANDUM

Steve Colt, ISER FAX: 786-7739

Mark A. Foster, MAPA

January 9, 1995

Kenai Natural Gas Study CNG Transport by 'Tube" Tracker/Trailer & Barge

I spoke with Rickard Warren of Gas Trans, Austin, Texas, to discuss the potential for providing natural gas to the com1nunities of Homer and Sevvard.

Mr. Warren indicated he vvas familiar with the area based on his companies vvork in conjunction ·with the Mountain Alaska Energy venture in the 1980's.

Based on current conditions, he believes that it would cost roughly $1.75/MCF to transport 1 MMCF per day a distance of 70 one-vvay 1niles based on an assumption of 160 MCF per trailer at 2400 psi (CNG). He is asstuning hvo trackers running around the clock and somewhere between four to six tube trailers.

For barge transport of CNG, he offers a range of $1.15 to $1.75/MCF. He cites a volume of 10 MMCF per day and 60 one-way miles for the high end of the barge transport range ($1.75/MCF ).

He indicates the key cost drivers are labor costs, barge capitalization, and fuel costs.

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