20130318Comments.pdf

KARL T. KLEIN
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
P0 BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 5156
01 1 1 M.-"k 10 13 P11 14:23
I.
''
U mmlo
Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5918
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF INTERMOUNTAIN GAS )
COMPANY'S APPLICATION TO SELL ) CASE NO. INT-G-13-2
LIQUEFIED NATURAL GAS. )
) COMMENTS OF THE
) COMMISSION STAFF
The Staff of the Idaho Public Utilities Commission comments as follows on Intermountain
Gas Company's ("Intermountain Gas"; "Company") Application to sell Liquefied Natural Gas.
BACKGROUND
On January 23, 2013, the Company applied for authority to sell excess liquefied natural gas
("LNG") to non-utility customers at market-based prices.' The Company asked for the new service
to take effect on March 10, 2013. On February 1, 2013, the Commission issued a Notice of
Application and Notice of Modified Procedure that suspended the proposed effective date to
September 9, 2013 or until the Commission issues an earlier decision in the case. See Order No.
32735.
In its Application, the Company says it expects to have excess LNG capacity for the next
few years. Application at 4. It proposes to sell LNG from this excess capacity, less a 50% reserve
Exhibit 2 to the Application attached the Company's proposed standard contract for LNG sales. On March 14, 2013,
the Company filed a substitute Exhibit 2 containing a new proposed standard contract. These comments address the
Application as modified by the substitute Exhibit 2.
STAFF COMMENTS 1 MARCH 18, 2013
margin, to non-utility customers until system growth requires the Company to use its entire LNG
capacity to meet core market peak-day needs. Id. For the near future, however, the Company says
it can meet utility-customer needs and still have enough LNG to provide an extra 6 million therms
(or 7.3 million gallons) of LNG for year-round non-utility sales. Id. at 5. The Company says it will
use any and all stored LNG to first satisfy utility-customer demand even if that LNG was initially
designated for non-utility use. Id.
The Company says that non-utility customers must sign a contract before buying LNG. The
Company says the contract will protect utility customers from financial risk, and the Company from
risks arising after the LNG is transferred to the non-utility customer. The contract also will ensure
that only surplus LNG is available for sale under the new service. Id. at 6.
The Company says it will accept all financial risk of the venture. Further, it will insulate
utility customers from any costs associated with non-utility sales by separately accounting for any
quantities of natural gas liquefied for non-utility sales and tracking all related costs independent of
utility costs. The Company will separately identify all costs associated with non-utility sales
deferring all amounts benefiting utility customers until the next Purchased Gas Cost Adjustment
("PGA") case.2 The Company then will provide actual sales calculations to Commission Staff
during the annual PGA audit. Id. at 4-5.
The Company proposes to pass the benefit of reduced operating costs to its firm customers.
The Company proposes a 2.50 credit per each gallon sold to recover any direct operations and
maintenance ("O&M") costs that may result from non-utility LNG sales. The Company expects
that the booked credit amounts ultimately will offset base-utility O&M over and above the O&M
related to non-utility sales. Id. at 5-6. The Company also acknowledges that increased use of the
LNG facility may accelerate capital expenditures or increase maintenance costs at the Nampa
facility. Id. at 6. The Company thus proposes to set aside another 2.50 per each gallon of LNG sold
to defray any such costs. Id.
The Company proposes to share all net margins from LNG sales on a 50150 basis with utility
customers through the PGA deferral mechanism. Id. at 6. The ratepayer part of net margins would
be deferred as credits in a new deferral account and passed back to applicable sales and firm
2 The PGA or "Purchased Gas Cost Adjustment" mechanism is used to adjust rates to reflect annual changes in the
Company's costs for the purchase of natural gas from suppliers - including transportation, storage, and other related
costs.
STAFF COMMENTS 2 MARCH 18, 2013
transportation customers in a similar manner to other peaking demand costs during the next PGA.
Id.
The Company says its proposal will not increase utility customer rates. It could, however,
potentially decrease the future prices that the Company's sales customers pay when the projected
deferred credits become part of future PGA filings. Id.
STAFF REVIEW
Staff's review of the Company's Application focused on six areas: (1) the LNG market and
market pricing; (2) the Company's capacity to produce LNG; (3) the costs associated with
producing LNG; (4) the sharing of potential benefits to core customers; (5) the allocation of benefits
to core customer classes; and (6) the standard contract to be used to minimize risk to utility
customers. Details of the analysis and justification for Staff recommendations are found in the
following sections.
Market Price Analysis
Staff analyzed the LNG market in detail. Staff's largest concern is how the Company
proposes to set prices and how the price will impact LNG customers. Staff believes customers will
not be harmed so long as the Company sets market-based prices.
Although the Company has stated that prices will be market based, its proposed method for
setting prices combines cost and market-based factors. Intermountain Gas plans to base its price off
the first-of-month index price of natural gas (published by Platts or FERC) and charge a margin
adder sufficient to cover its costs, make a reasonable profit, and place the price within the range of
LNG market prices. While the Company's pricing method does not differentiate between retail and
wholesale customers, Staff believes the Company's proposal provides flexibility to adjust margin
adders resulting in either a wholesale or retail market price.
Retail market prices are readily available since they are indexed off the price of diesel fuel
offset by a discount; however, there are currently no public exchanges trading LNG that would
allow transparency to establish a wholesale market price. Because the market and the selling of
LNG are in their infancy, Staff believes it is unlikely that harm from potential uncompetitive pricing
will arise in the short-term. But if the market develops and barriers-to-entry occur due to
STAFF COMMENTS 3 MARCH 18, 2013
monopolistic pricing, then the Company and the Commission should remain open to changing the
framework for selling LNG.
Capacity Analysis
Staff analyzed whether the Company's LNG production and storage capabilities have
sufficient capacity to meet the Nampa facility's peak-shaving needs while selling LNG to non-
utility customers. Based on its analysis, Staff believes the following:
1)The Company has sufficient idle capacity at its Nampa facility to sell LNG to third
parties; and
2)The Company could sell LNG indefinitely into the future as long as a market exists and
the facility continues to operate consistent with the peak-supply role it plays in the
Company's system.
The Company's Nampa LNG facility was constructed in 1976 to meet extreme peak demand
periods and emergency situations due to system integrity issues. The facility has the capacity to
liquefy 42,000 gallons per day and store over 7 million gallons of LNG (vaporization capacity is not
an issue for this analysis because it is not required to sell LNG).3 The facility was designed to meet
peak winter weather and temperature extremes during the coldest five-day period of the coldest year
over the last 30 years. Because of cost considerations and time required to liquefy sufficient
quantities of LNG for winter-peaking purposes, gas is only withdrawn when all other forms of
flowing gas and gas storage have been utilized.
Because of the facility's peak-supply role, the Company believes there is enough excess
capacity to sell LNG on the open market while maintaining capability to meet the facility's intended
purpose. Staff analysis is reflected in Table 1 below. It illustrates the capacity available for LNG
sales given different percentages of storage levels covering the actual range at the Nampa facility
over the last four years ranging from 50 to 78 percent.4
See Intermountain Gas 2011 Integrated Resource Plan, P. 57 (12.1 gallons/Dth conversion rate)
Due to additional costs to maintain LNG at a specific temperature, the Company only stores enough LNG to meet
expected use during the winter months. The percentages of utilized storage capacity reported in Staffs comments over
the past 4 PGA's are: 50% in INT-G-12-01, 78% in INT-G-1 1-01, 59% in INT-G-10-03, and 59% in INT-G-09-02.
STAFF COMMENTS 4 MARCH 18, 2013
Table I
Percent Storage Capacity Required to meet System Peak 50% 60% 70% 80% 90% 100%
LNG Required for System Peak 3.5 4.2 4.9 5.6 6.3 7.0
Max Sales Capacity (net of winter storage needs) 11.9 11.2 10.5 9.8 9.1 7.7
Twice-thucycle Sales Capacity (net of winter storage needs) 10.5 9.8 9.1 8.4 7.7 7.0
(Million of Gallons)
Staff determined the Company could sell a maximum of between 7.7 and 11.9 million
gallons of LNG based on total liquefaction capacity net of capacity needed to fill winter storage
requirements. However, the ability to utilize 100% of idle liquefaction capacity could be limited by
potential up-stream capacity shortages during winter months or down-stream blocking conditions
caused by fully utilized storage capacity and inconsistent LNG sales. Therefore, Staff believes an
estimate of between 7 and 10.5 million gallons is more realistic based on an annual, twice-through
fill cycle 5.
Staff believes the ability to sell LNG from the Nampa facility is not limited by growth of
core market needs as suggested in the Company's Application. For winter peaking needs, the
constraining resource is the size of the storage tank. But Staff believes the ability to continue
selling LNG hinges on the amount of liquefaction capacity available, not on the utilization of the
storage tank. LNG sales only require sufficient storage capacity to buffer the sale of tanker truck
loads in up to 10,000 gallon increments. As Staff's analysis shows, even when 100% of the storage
tank is needed for peak winter months, the Company still can use about 7.0 million gallons of
liquefaction capacity for LNG sales.
Cost Analysis
Staff reviewed the Company's plans to insulate utility customers from cost resulting from
LNG sales. As a result of its analysis, Staff identified several important findings and made a
number of recommendations as listed below:
1) The method the Company proposes to pay for future capital cost due to additional wear
and tear is reasonable but the amount of 2.50 per gallon should be audited during future
PGA filings and adjusted as needed;
A twice-through fill cycle assumes the storage tank can be filled twice annually with one of the cycles partially used to
meet winter peak. The remainder would be available for sales of LNG on the open market.
STAFF COMMENTS 5 MARCH 18, 2013
2)Staff believes the method the Company proposes to pay for O&M cost related to
producing and selling LNG allows the Company to double recover costs. Staff
recommends that 100% of the 2.50 per gallon for O&M be credited to customers for
each gallon sold. However, these costs should be tracked and the method and amounts
should be adjusted based on actual operation;
3)The method the Company proposes to separate purchases of natural gas for utility and
non-utility customers and resolve monthly imbalances should ensure gas purchases for
LNG sales minimize any adverse affect on the cost of gas for utility customers; and
4)Staff recommends that actual purchased gas cost for LNG be tracked and reported
separately in the Company's quarterly Weighted Average Cost of Gas ("WACOG")
report.
Staff's analysis focused on three elements of cost affected by the sale of LNG: capital cost,
O&M cost, and the cost of purchased gas. In traditional cost-based regulation methods, capital
costs are recovered through rates based on a depreciation schedule over the facility's useful life. If
LNG customers were a separate class, they would be expected to pay their share of depreciated
capital cost plus the authorized rate of return. However, the Nampa LNG facility, except for some
recent minor upgrades, is fully depreciated.6 In cases when the useful life of a large asset is
exceeded but still in operation, the only remaining capital costs are small capital acquisitions to
maintain the overall operation of the asset due to wear and tear. Because the sale of LNG is not
purely based on cost of service, the Company has proposed to instead set aside 2.50 for every gallon
sold into a separate account to cover the cost of future incremental capital replacement cost. This
account's funds will be withdrawn and used to replace capital equipment as needed due to increased
wear and tear from LNG sales.
Staff believes this is an equitable and reasonable method to cover this type of cost. But Staff
also believes that these funds should only be used for capital replacement costs of existing
equipment and not to buy extra capacity or improve currently functioning equipment. Staff also
recommends that all purchases using these funds be audited during the Company's yearly PGA and
the per gallon amount adjusted as required. If the account balance becomes unreasonably large, the
Commission should also consider crediting a portion of the funds back to utility customers.
See Order No. 28311, Case INT-G-99-02; Order No. 32427, Case INT-G- 11-02.
STAFF COMMENTS 6 MARCH 18, 2013
O&M is the second category of cost incurred from the sale of LNG. Examples of this cost
include liquefying LNG, filling tanker trucks, and performing additional maintenance on the facility
as a result of selling LNG. The Company has proposed to directly assign these costs as an LNG
cost and pay for them with funds from an account that accumulates 2.50 per gallon of LNG sold.
Staff believes that the Company's method allows the Company to double-recover a portion
of O&M cost. As described previously, the Company only uses and staffs the Nampa facility to
meet infrequent peak-demand situations. Staff believes initial incremental quantities produced and
sold as LNG will more fully utilize idle resources, which are theoretically included in or "internal"
to base rates. Because it is difficult to separate "internal" costs from incremental costs, Staff
believes the Company should err on the side of utility customers by crediting 100% of the 2.50 per
gallon O&M cost to customers for more fully utilizing existing resources.
In conversations between Staff and the Company, the Company has concurred with Staffs
recommended treatment of O&M. However, Staff also recommends the Company track all LNG
sales-related actual costs to determine how much of the total cost is "internal" to current O&M
resource cost and how much is incremental so that more accurate figures can be determined. Staff
recommends this be reviewed in subsequent PGAs and the amount be adjusted accordingly. Staff
also believes, after reviewing actual cost, that it may be better to modify the overall method by
crediting customers a fixed amount for "internal" O&M cost, while accounting for incremental
O&M on a cost per gallon basis.
The final cost element is the cost of natural gas purchased to produce LNG for sale to non-
utility customers. Staff's largest concern is ensuring incremental gas purchased for LNG sales does
not adversely affect the cost of gas consumed by utility customers. In response to a Staff
information request, the Company says it plans to track all purchases of natural gas for non-utility
sales separate from purchases used for utility sales.7 In cases where there are monthly imbalances
between nominations and daily usage, the Company plans to adjust the utility and non-utility
accounts by purchasing shortages at the actual monthly WACOG or by selling any overage at the
lesser of the actual non-utility cost or a price not to exceed the utility's actual monthly WACOG.
Adherence to this methodology alleviates Staff's concern. In order to provide transparency, Staff
7 See Production Request Nos. 9 and 14, JNT-G-13-02
STAFF COMMENTS 7 MARCH 18, 2013
recommends that the Company's quarterly WACOG reports separate the balances for non-utility
and utility sales.
Benefit Analysis
Intermountain Gas proposes sharing 50% of all net margins from the sale of LNG with
utility customers. Staff evaluated the Company's proposal and came to the following conclusions:
1)Even with a 50150 sharing percentage, the sale of LNG benefits both the Company and
utility customers; and
2)The sharing of net margin should be adjusted to be more in-line with current sharing
percentages applied to net power costs in other Idaho utilities' Power Cost Adjustment
(PCA) mechanisms. Staff recommends net margins be shared 70% to customers and 30%
to the Company.
The sale of LNG is analogous to off-system sales of electricity. Idaho electric utilities
currently reduce their customers' net power costs by selling surplus electricity on the open market.
To encourage the utility to maximize net benefit from off-system sales (and other operational
behaviors reducing customer rates), the Commission allows the utility to share net benefits with its
customers through annual PCAs. In the case of Idaho electric utilities, the utility is allowed to keep
5 to 10% of the net benefit.
Although 95/5 or 90/10 sharing is reasonable for electric utilities and provides a benchmark
for sharing net margin of LNG sales, Staff believes the amount of risk Intermountain Gas will incur
is likely higher than a utility transacting off-system sales of electricity. It is inherently more risky
because: (1) the LNG market is in its infancy; (2) LNG customers have incurred large amounts of
debt by investing in LNG infrastructure, which affects their credit worthiness; (3) LNG sales can be
more volatile and uncertain than off-system electricity sales due to unforeseen market conditions;
and (4) the Company must buy gas to be converted to LNG several weeks before it receives
payment for delivered LNG. These combined factors make it more likely that customers will
default on LNG orders, payments, or both, which can lead to losses that the Company has agreed to
fully absorb. Staff believes this additional risk entitles the Company to receive a higher share of
reward than that received by electric utilities.
However, the Company's utility customers also have a stake in the outcome. Utility
customers have removed any capital risk by paying for all LNG infrastructure necessary for the
STAFF COMMENTS 8 MARCH 18, 2013
Company to produce and sell LNG. Because of the facility's large capital cost, Staff believes the
capital risk alleviated by ratepayer investment is more than all other risk the Company is likely to
absorb, and that ratepayers therefore deserve more than 50% of the benefits the Company has
proposed in its Application. Based on this rationale, Staff believes the Company's share in benefits
should be between the 50% proposed by the Company and the 10% used in electric utility PCAs.
The table below shows the amount of O&M and profit margin the Company and utility customers
will share given various sharing percentages. These figures are based on assumptions contained in
Exhibit 1 of the Company's Application and in Staff's capacity analysis contained in Attachment
A.8
Table 2
any snare i'ercentage
Annual Net Margin (based on twice-through fill cycle)
Utility Ratepayer O&M Reimbursement
Utility Ratepayer Share of Margin
Total Utility Ratepayer Benefit

50% 400A 300A 20% 10%
$3,512,536 $3,512,536 $3,512,536 $3,512,536 $3,512,5361

$228,087 $228,087 $228,087 $228,087 $228,087
$1,756,268 $2,107,521 $2,458,775 $2,810,029 $3,161,282
$1,984,355 $2,335,608 $2,686,862 $3,038,115 $3,389,369
Share of 268 $1,405,014 $1,053,761
Staff recommends the sharing percentage be set at 30% to the Company and 70% to
customers for no other reason than it is the halfway point of the range. This could provide roughly
$1 million annually to the Company and roughly $2.7 million in total net benefit to utility
customers. Staff also encourages the Company to gather actual data to quantify the Company's risk
and propose changes to the sharing percentage if appropriate.
Class Allocation of Benefits
Staff has reviewed the Company's proposed method of allocating shared benefits back to
customer classes and believes it to be fair and reasonable. The percentages are based on peak-day
allocators used to allocate demand charges as illustrated in Exhibit 3 of the Company's Application.
It includes transportation customer classes (T-4 and T-5) because a portion of LNG facility costs are
included in transportation customer base rates. The Company plans to credit the utility customers'
shares of profit margin to a deferral account each month and allocate them to each applicable rate
8 Sales are based on maximum utilization of liquefaction capacity based on a twice-through fill cycle, 70% of storage
required for peak-shaving purposes, and a liquefaction rate of 42.3 thousand gallons/day.
STAFF COMMENTS 9 MARCH 18, 2013
class in future PGA filings. Staff believes this method should also be used to allocate the 2.50 per
gallon O&M reimbursement.
Analysis of Standard Contract
Because of the short lead time potential customers will need to take delivery of LNG once a
contract is signed, the Company is requesting the Commission pre-approve a standard contract. The
request and a copy of the standard contract are included as Exhibit 2 to the Application. See
footnote 1, above. Staff has reviewed the contract and has come to the following conclusions and
recommendations:
1)Staff believes the standard contract contains all the necessary provisions to execute the
sale of LNG aligned to the expectations and method stipulated in the Company's
Application;
2)Staff recommends that the standard contract be approved as part of the overall
Application; and
3)Subsequent approvals of individual contracts are not necessary as long as the standard
contract is utilized or the contract used is not materially different from the standard
contract.
Each contract is structured with an extendable three-year term. Individual purchases are
executed using a transaction confirmation that identifies aspects of the transaction that can vary but
are bounded by terms and conditions in the contract. Included in the transaction confirmation is the
price (index price of gas plus a margin adder), additional costs the buyer is obligated to pay, the
quantity, whether the sale is firm or non-firm, and the amount of liquidated damages the seller or
buyer agrees to pay for not delivering or not taking delivery, respectively.
According to the Company, the contract will "protect utility customers from any financial
risk, the Company from any operational difficulties or risk after LNG is transferred to a non-utility
customer, and ensures that only surplus LNG would be available for sale under this new service."9
Staff believes a contract can never completely shield the Company from potential risk. If sufficient
harm comes to the Company, it can affect the Company's ability to attract low-cost capital for
future reinvestment in the utility, which can potentially harm utility customers. However, through
9 See Application, INT-G-13-02, p. 6.
STAFF COMMENTS 10 MARCH 18, 2013
the contract's terms and conditions, Staff believes the Company has sufficiently minimized risk to
its core customers and to the Company. Through its contract analysis, Staff believes the contract:
(1) ensures that LNG buyers assume all risk due to buyer equipment malfunction and for any
expense or risk after the point of delivery; (2) allows the Company to refuse to deliver LNG to
potential buyers who pose a safety risk, risk of default, or generally cannot adhere to any provision
in the contract; (3) obligates the Company to deliver LNG only if there is sufficient LNG to meet
core customer peak-shaving needs; and (4) relieves the seller (and buyer) of obligations due to
Force Majeure.
STAFF RECOMMENDATIONS
After a thorough review of the Company's Application, Staff recommends that the
Commission approve the Application with the following additions and changes:
1.Require the Company to obtain Commission approval for any contracts to sell LNG that
materially differ from the standard contract;
2.Limit the Company's use of future capital expense funds to the replacement of existing
Nampa Plant Capital Infrastructure due to accelerated wear and tear from producing LNG
for sale. Recovery of incremental capital expense required to increase capacity or improve
existing capital infrastructure must be done separately through standard Commission
approval processes and procedures;
3.Require the Company to provide a 2.50 credit for every gallon of LNG sold for O&M
related expenses and pass through 100% of this amount to utility customers through the
PGA using the same class allocation method proposed to distribute shared net margin. The
Company concurs with this recommendation;
4.Require the Company to credit 70% of total net margin to ratepayers for sales of LNG
through the PGA, allowing the Company to keep 30%;
5.Require the Company to prepare a review of all costs and benefits as a result of selling LNG
as part of the annual PGA filing;
6.As part of the next IRP filing, require the Company to prepare a review of the method and
framework for selling LNG and whether the Company should continue to sell it; and
7.Require the Company to separately track actual purchased gas cost for LNG sales and report
the results in the Company's quarterly WACOG report.
STAFF COMMENTS 11 MARCH 18,2013
Respectfully submitted this 3 U day of March 2013.
)Y (IL
Karl T. Klein
Deputy Attorney General
Technical Staff: Mike Louis
i:umisc/oomments/intgl 3.2kkdeml comments
STAFF COMMENTS 12 MARCH 18, 2013
Attachment A
Capacity Analysis of LNG facility
Capacity Assumptions:
1 LNG Gallon Conversion Rate (Gal/Dth)
2 Std. Tanker Size (gallons LNG)
3 Days of operation
4 Number days of winter peak requirements
6 Storage space required to liquity (Gal)
6 In-kind Mainline to Citygate Fuel Rate (%)
7 Estimated Liquefaction Fuel (%)
12.10009
10,000
365
183
10000
1.40%
22.00%
Notes:
Exhibit 1 of Application
Exhibit 1 of Application
Exhibit 1 of Application
Dth Gallons Truckloads
8 Total Nampa Storage Capacity 580,000 7,018,053 702 2011 Intermountain IRP
Dth/da Galsidav Trckldslday
9 Max Liquifaction Rate 3500 42350 4.24 2011 hterrneuntain RP
10 'MaxVaporization rate 60000 726008 72,60 2011 Intermountain RP
Unit Cost Assumptions: $rrrckld
11 Estimated Mainline Gas Cost $3000 $02479 $2,479 Exhibit 1 of Application
12 In-kind Mainline to Citygate Fuel Rate Cost $0043 $00035 $35 = line 11 x line 6/(1 - fine 6)
13 Com modity Trans port Cost $0032 $00026 $26 Exhibit lofApplication
14 Reservation Transport Cost $0041 $00034 $34 Exhibit 1 of Application
15 Delivered Cost at Nampa $3.11540 $0257 ' $2,575 = linel 1+line12+line13+llne14
16 Liquifaction Fuel Cost $068539 $00566 $566 = fne15 x fine 7
17 Cost ofLNG $3801 $0314' $3,141 = 1ine15+line16
18 O&M Recovery $0303 $0025 $250 Exhibit 1 of Application
19 Future Capital Cost Recovery $0303 $0025 $250 Exhibit 1 of Application
20 Dld Cost of LNG at Nampa fueling Station ' $4,406 $0364 - $3,641 = lIne17+line18+line19
21 Estimated Sales Price Adder $4659 $03850 $3,850 Exhibit 1 of Application
22 Estimated Sales Price $9064 $0749 $7,491 line20 + hne2l
Percent Storage Capacity Required to meet System Peak i,Q9j4
LNG Required for System Peak (dekatherms) 290,000 348,000 406,000 464,000 522,000 580,000
LNG Required for System Peak (Gal.) 3,509,027 4210.832 4,912,637 6,614,443 6,316,248 7,018,053
LNG Required for System Peak (truckloads) 351 421 491 561 632 702
Days to fill Storage Rqd for System Peak 83 99 116 133 149 166
Days to Empty Storage 5 6 7 8 9 10
Capacity Availability for LNG Sales
Winter Storage Available for LNG Sales (gallons) 3,509,027 2,807,221 2,105,418 1,403,611 701,805 -
Days available for Liquifaction for LNG Sales 282 266 249 232 216 183
Max Sales Capacity (net winter storage needs - Gal.) 11,948,841 11,247,035 10,545,230 9,843,425 9,141,619 7,728,934
Twice-thu-cycle Sales Capacity (net winter storage needs - Gal.) 10,527,080 9,825,275 9,123,469 8,421,684 7,719,859 7,018,053
Sales Based on Maximum Capacity
Total Revenue $6,951,020 $8,425,289 $7,899,558 $7,373,827 $8848096 $5,789,837
Delivered cost $4,350,716 $4,095,180 $3,839,844 $3,584,109 $3,328,573 $2,814,197
Net Margin $4,600,304 $4,330,109 $4,059,914 $3,789,719 $3,519,523 $2,975,839
Sales Based on Twice-through-cycle capacity
Total Revenue $7,885,961 $7,360,231 $6,834,500 $8,308,769 $5,783,038 $5,257,308
Delivered cost $3,833,036 $3,577,500 $3,321,964 $3,086,429 $2,810,893 $2,555,357
Net Margin $4,052,926 $3,782,731 $3,512,536 $3,242,341 $2,972,146 $2,701,951
Rate Payer Share based on Twice-through-cycle Capacity
O&M Reimbursement $263,177 $245,632 $228,087 $210,542 $192,996 $175,451
Rate-payer Share of Margin plus 0&M
50% $2,289,640 $2,138,997 $1,984,355 $1,831,712 $1,679,069 $1,528,427
60% $2,694,932 $2,515,270 $2,335,608 $2,155,946 $1,976,284 $1,796,622
70% $3,100,225 $2,893,543 $2,688,862 $2,480,180 $2,273,498 $2,066,817
80% $3,505,518 $3,271,816 $3,038,115 $2,804,414 $2,570,713 $2,337,012
90% $3,910,810 $3,850,090 $3,389,369 $3,128,648 $2,867,927 $2,807,207
Company Share based on Twice-through-cycle Capacity
Company Share of Margin
50% $2,026,463 $1,891,365 $1,756,268 $1,621,170 $1,488,073 $1,350,975
40% $1,821,170 $1,513,092 $1,405,014 $1,296,936 $1,188,858 $1,080,780
30% $1,215,878 $1,134,819 $1,053,761 $972,702 $891,644 $810,585
20% $810,585 $758,546 $702,507 $648,468 $594,429 $540,390
10% $405,293 $378,273 $351,254 $324,234 $297,215 $270,195
Rate is bounded by how fast distribution system can absorb vaporized gas
STAFF COMMENTS 13 MARCH 18, 2013
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 18TH DAY OF MARCH 2013,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN CASE
NO. INT-G-13-02, BY MAILING A COPY THEREOF, POSTAGE PREPAID, TO
THE FOLLOWING:
SCOTT MADISON
EXEC. VP & GENERAL MANAGER
DAVID SWENSON
LORI BLATTNER
scott.madison(intgas.com
david.swensoncintgas.com
1ori.b1attnerintgas.com
INTERMOUNTAIN GAS CO
P0 BOX 7608
BOISE ID 83707
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CERTIFICATE OF SERVICE