20130219IGC to Staff 1-14.pdf

EXECUTIVE OFFICES
INTERMOUNTAIN GAS COMPANY
555 SOUTH COLE ROAD • P.O. BOX 7608 • BOISE, IDAHO 83707 • [phone] • FAX: g PM 14: 149
February 19, 2013
Ms. Jean Jewell
Idaho Public Utilities Commission
472 W. Washington Street
P.O. Box 83720
Boise, ID 83720-0074
r'rH PUiLf
UTiL!11E COMM1E5.
RE: Intermountain Gas Company
Case No. INT-G-13-02
Dear Ms. Jewell:
Enclosed for filing with this Commission is an original and seven (7) copies of Intermountain
Gas Company's Response to Staff's First and Second Production Requests relating to the above
referenced Case.
Please acknowledge receipt of this filing by stamping and returning a copy of this Application
cover letter to us.
If you have any questions or require additional information regarding the attached, please contact
me at 377-6105 or Dave Swenson at 377-6118.
Very t urs,
S . Madison
Vice President - Chief Accounting Officer
cc: K.F. Morehouse
D. Haider
M. Parvinen
SWMImt
Scott Madison
Executive Vice President & General Manager
Intermountain Gas Company
P.O. Box 7608
Boise, Idaho 83707
Telephone: [phone]
t3EEB'9 ?ti49
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF
INTERMOUNTAIN GAS COMPANY TO SELL
LIQUIFIED NATURAL GAS.
CASE NO. INT-G-13-02
INTERMOUNTAIN GAS
COMPANY'S RESPONSE TO
FIRST PRODUCTION
REQUEST OF THE
COMMISSION STAFF
COMES NOW Intermountain Gas Company and responds to the First Production
Request of the Commission Staff as follows:
REQUEST NO. 1: Page 5 of the Application says: "the company proposes to separately
account for any quantities of natural gas liquefied for non-utility sales and track all related costs
independent of utility costs." Are these costs incremental or inclusive of the $0.25/gallon credit
for O&M and accelerated capital expense?
RESPONSE NO. 1: First Intermountain would like to point out that the proposed credits
are 2.50 per gallon sold. The Company proposes to separately track every type of cost related to
natural gas liquefied for non-utility sales. These costs would include the purchased cost of gas
and related delivery costs, the cost of liquefaction fuel, the proposed credit for O&M recovery of
2.5I gallon, and a capital recovery of 2.5/ gallon sold. Following the illustration on Exhibit
No. 1, shows all relevant costs that will be booked and credited at each applicable month-end
close to ensure these credits will be passed through to utility customers on a timely basis before
any margin is calculated.
INTERMOUNTAIN GAS COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF -1
REQUEST NO. 2: How did the Company derive the $0.25/gallon rate for accelerated
future capital cost? Please provide the data and derivation of the cost as well as an explanation
of the method. Please include all workpapers with formulas intact.
RESPONSE NO. 2: The derivation of the capital cost credit is not necessarily a
straightforward analysis. Many of the Nampa systems and/or equipment will not be affected by
additional use. Other equipment does not have known maximum hours of service or definite life
spans and so it is very difficult to surmise what future costs might be accelerated and by how
much. Intermountain believes it is reasonable to assume that there may be some accelerated
capacity expense associated with incremental usage relating to non-utility activities but there is
no hard and fast data to rely upon. Therefore, Intermountain assumed the same per gallon credit
as is proposed for O&M to offset or defray future capital expenditures at the LNG facility(please
see Company's Response to Request No. 4). There is no workpaper associated the accelerated
capital expenditure proposal.
REQUEST NO. 3: Please explain the following passage found on page 6 of the
Application: "the company also proposes to set aside an additional $0.25 per each gallon sold to
defray any such accelerated (capital) costs." Does this mean that the funds will be used "just-in-
case" there are additional capital expenditures or does this mean $0.25 will be credited to utility
customers for capital expenditures for every gallon of LNG sold to non-utility customers?
RESPONSE NO. 3: Intermountain proposes to book these credits to the balance sheet
and utilize them as appropriate costs are incurred. Based on an annual target sales level of
2,600,000 gallons as shown on Exhibit No. 1, the proposed credit would allocate $65,000 per
year - or $325,000 over a five-year period - toward capital expenditures. Intermountain believes
pre-flinding capital expenses to the LNG facility in this manner will help ensure that utility
customers do not have to bear any non-utility costs.
REQUEST NO. 4: How did the Company derive the $0.25/gallon rate for O&M
recovery? Please provide the data and derivation of the cost as well as an explanation of the
method. Please include all workpapers with formulas intact.
INTERMOUNTAIN GAS COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF -2
RESPONSE NO. 4: The Company evaluated several direct cost scenarios relating to
LNG sales, including direct labor O&M, electricity costs and potential overtime charges, and
estimated that at most, it would spend no more than $200 for direct O&M per LNG load (see
attachment No. 1). That $200 estimate divided by 10,000 (the maximum expected number of
gallons per load) equals 20 per gallon. The Company chose to increase that proposed credit per
therm to 2.50 per gallon to provide a cushion to ensure utility customers are kept whole.
REQUEST NO. 5: Please provide the basis or rationale used to determine the 50150
sharing allocation of net revenue in the Company's proposal.
RESPONSE NO. 5: Intermountain proposed a sharing allocation that it felt fairly
compensated customers given their full protection from all downside risks, but would still
provide enough potential benefit to the company to encourage active pursuit of the potential
opportunities and accept the downside risks. The Company also proposes to credit the
appropriate utility cost accounts at month-end regardless of whether or not any sales occurred in
that month so that the non-utility sales program would bear the cost of money on any LNG
designated for non-utility sales.
REQUEST NO. 6: What are the Company's potential risks of selling LNG to non-utility
customers justifying the Company's 50150 sharing proposal?
RESPONSE NO. 6: The biggest risk identified is default risk. This is a new venture
with as yet to be determined customers with yet to be determined credit worthiness. If an LNG
customer defaults on its contract it could leave Intermountain with significant non-utility
uncollectibles. However, because of the pre-funded amounts for O&M and accelerated capital
recovery, utility customers will benefit even if there is no margin to share.
Other risk potentials identified are due to market changes. Significant amounts of time
could take place between placing gas into storage versus the actual sale and payment for the sale.
Since the Company will pass back to utility customers all relevant costs and credits at each
month-end close, it will completely bear any costs related to timing and carrying costs.
INTERMOUNTAIN GAS COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF -3
Another significant risk is that unforeseen market conditions could swing the prices
markets are willing to pay for LNG which could result in uneconomic and over-priced unsold
inventory leaving the non-utility venture the choice to liquidate LNG at a loss or continue to bear
the cost of money invested in inventory. Lastly the Company is absorbing any unforeseen issues
or complication that may arise, thus holding the core customers harmless.
REQUEST NO. 7: Please explain operationally (procedurally) how the Company will
maintain minimum levels of LNG necessary to maintain full peak-shaving capability (plus 50%
reserve margins) while supplying LNG to non-utility customers.
RESPONSE NO. 7: Intermountain recognizes its first obligation is to provide safe,
reliable service to its utility customers. Intermountain will utilize the design weather scenarios
from its Integrated Resource Plan (IRP) —and ongoing internal forecasts - to determine the
expected amount of Nampa LNG withdrawal that might be needed under the coldest weather
conditions during the December-through-February winter peaking season. The company would
add a 50% reserve margin to that projected amount and calculate, on a rolling basis, the absolute
minimum inventory level that would support such peak withdrawals. It would then ensure that
minimum level would be available on every day throughout the December-through-February
winter peaking season. And as stated in the Application, if for whatever reason, the projected
peak-plus 50% margin amount was insufficient to serve core loads, the core market would still
have priority right to any "non-utility" LNG in the tank.
REQUEST NO. 8: Page 4 of the Application says: "Intermountain proposes to only use
capacity in excess of utility peak shaving needs for non-utility sales and only until such time as
system growth would indicate that all Nampa capacity might be needed to meet core market
needs." Please explain the criteria and the method for determining when this happens.
RESPONSE NO. 8: As stated in the response to Request No. 7, Intermountain will
annually review its IRP and all internal forecasts to determine the potential peaking need for the
upcoming winter season. The method, as outlined in Intermountain's IRP, is to analyze system
demand based on design weather conditions. The criteria for determining capacity requirements
INTERMOUNTAIN GAS COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF -4
will be the peak day requirements of the core market versus the amount of available LNG. This
assessment of potential peaking needs will be made annually before the start of the winter
heating season.
As loads continue to grow over time, it is anticipated that the projected core market
withdrawal needs will eventually equal the maximum capacity of the facility. At that point, the
company will not provide any non-utility service during the peak winter months.
REQUEST NO. 9: Please explain how the Company will ensure that incremental gas
purchased to meet the needs for non-utility LNG sales will not adversely affect the cost of gas to
its utility customers. What cost will be used to determine actual mainline gas cost used for non-
utility LNG sales and how will it be determined?
RESPONSE NO. 9: The Company will not co-mingle non-utility gas supplies with
utility purchases. Intermountain will show any natural gas purchases or related hedging activities
specific to non-utility LNG sales separate from utility purchases in its monthly reports. The
Company is aware that month-end imbalances can occur as there are typically differences
between daily nominations and daily usage. In the event of an imbalance, Intermountain will
settle the volume between its utility and the non-utility books either purchasing any shortage at
the actual monthly utility WACOG or by selling any overage at the lesser of the actual non-
utility cost or at a price not to exceed the utility's actual monthly WACOG.
REQUEST NO. 10: According to the Company's Application, LNG sales price to non-
utility customers will be market-based. Please provide the methods, standards and/or indexes the
Company plans to use as a basis for setting these prices.
RESPONSE NO. 10: The Company will use the competitive market to set its sales
prices vis-à-vis other market alternatives. As can be seen on Exhibit No. 2 of the Application, the
Company will, when applicable, use standard natural gas industry price indices (see Attachments
No. 2 and No. 3). These indices reflect either the First-of-Month index price for a particular
supply point or basin or a similar Daily price index. Note that these index prices are stated in
dollars per dekatherm but because LNG is sold in gallons, Intermountain will convert the index
INTERMOUNTAIN GAS COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF -5
prices to dollars per gallon using appropriate conversion factors. To that base price it will add a
negotiated dollar per gallon adder amount (the 38.50 per gallon adder as shown in the
Application is merely illustrative). As shown on Exhibit No. 3, Intermountain may also sell LNG
at a fixed price per gallon.
It will be critical that Intermountain understand both the competitive market price levels
and know its actual inventory cost in order to ensure a margin is generated from each sale. But as
stated in the Application, Intermountain accepts all risks associated with this service, will
completely insulate its utility customers from any additional costs, pre-fund certain O&M and
capital credits to utility customers and share any net margins, but no losses, from any non-utility
sales.
PURSUANT TO IDAPA 31.01.01.228, the record holders and/or witnesses who could
sponsor the documents in the event of a hearing are:
1.In General
Scott Madison
Executive Vice President & General Manager
Intermountain Gas Company
Boise, Idaho 83707
Telephone: [phone]
2.For Responses 1 - 10
David Swenson
Manager, Industrial Services
Intermountain Gas Company
P.O. Box 7608
Boise, ID 83707
208-377-6118
DATED this 19th day of February, 2013
INTERMOUNTAIN GAS COMPANY
Scott W. Madison
Executive Vice President & General Manager
INTERMOUNTAIN GAS COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF -6
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on this 19th day of February, 2013, I caused a true and correct
copy of the foregoing INTERMOUNTAIN GAS COMPANY'S RESPONSE TO THE
FIRST PRODUCTION REQUEST OF THE COMMISSION STAFF to be served by the
method indicated below, and addressed to the following:
Karl T. Klein ( ) U.S. Mail, Postage Prepaid
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES ( ) Hand Delivered
COMMISSION Overnight Mail
P.O. Box 83720 ( )
Boise, ID 83720-0074 ( ) Facsimile
INTERMOUNTAIN GAS COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF -7
Scott Madison
Executive Vice President & General Manager
Intermountain Gas Company
P.O. Box 7608
Boise, Idaho 83707
Telephone: [phone]
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF )
INTERMOUNTAIN GAS COMPANY TO SELL )
LIQUIFIED NATURAL GAS. )
)
)
)
)
))
CASE NO. INT-G-13-02
SECOND PRODUCTION
REQUEST OF THE
COMMISSION STAFF TO
INTERMOUNTAIN GAS
COMPANY
COMES NOW Intermountain Gas Company and responds to the Second Production
Request of the Commission Staff as follows:
REQUEST NO. 11: Please explain how the 50% allocation of margin (derived from the
"Sales Price Adder") will be credited to the different utility customer classes in the PGA.
RESPONSE NO. 11: The net margin due ratepayers will be the difference between the
sales price, including the adder, less the total cost of the LNG sold including all the components
shown on Exhibit No 1. The proposed 50% share for the ratepayers will be deferred in a new 192
account at each month-end close and allocated to each applicable rate class as shown on Exhibit
No. 3. Intermountain will make all relevant sales and cost information available to Staff during
the PGA audit.
Intermountain would also like to point out an unintended coincidence of numbers that
may cause confusion. The 38.5 0 per gallon adder as shown on the Exhibit No. 3 is meant to
convey a sales price "adder" amount that when combined with either of the base price
components, also shown on Exhibit No. 3, would determine the total price per gallon that the
INTERMOUNTAIN GAS COMPANY'S RESPONSE TO THE SECOND PRODUCTION
REQUEST OF THE COMMISSION STAFF 1
Company would sell LNG. The same 38.5 0 per gallon amount is shown on Cot. (d), Line 12 of
Exhibit No. 1. However that figure is meant to convey that under the illustration provided, the
difference between an assumed sates cost and the actual cost, including the O&M and capital
credits, or the amount per gallon subject to margin sharing would be 38.5 0 per gallon. The like
figures on Exhibit No's 1 and 3 should not be assumed to be directly related nor in reality likely
to be the same.
REQUEST NO. 12: Please explain how the $0.25 per LNG gallon credit for O&M and
the $0.25 per LNG gallon credit for Accelerated Capital Cost will flow through the PGA
mechanism and how the credits will be allocated to the different classes.
RESPONSE NO. 12: The 2.5çt per gallon credit for O&M will be credited to a deferred
account at each monthly close and then be credited to applicable customers during the next PGA
using an allocation method similar to that shown on Exhibit No. 3. The 2.50 per gallon credit
for accelerated capital costs for each gallon sold will not flow through the PGA but will be
booked to a balance sheet account and utilized as applicable capacity costs are realized.
REQUEST NO. 13: Please explain the differences between Exhibit No. 3 in the
Application and Workpaper No. 5 contained in the Application for Case No. INT-G- 12-01.
RESPONSE NO. 13: The method used to develop Exhibit No. 3 is the same method
utilized to create Workpaper No. 5 from the most recent PGA filing (1NT-G-12-01). Note that
the RS-1, RS-2 and GS peak day therms (line 7 of the PGA and line 4 of the LNG filing) are
identical. LV-1 is slightly different because of additional LV-1 customers and/or LV-1 firm
demand since Intermountain filed the INT-G- 12-01.
The main difference between the two workpapers is the addition of T-4 and T-5 customers to the
allocation in the LNG filing. Since Transport customers do not buy their gas supplies from
Intermountain, they are not included in the traditional PGA items requiring allocators (i.e. fixed
gas costs and variable credits). Thus, they were not included on workpaper 5 of the PGA.
INTERMOUNTAIN GAS COMPANY'S RESPONSE TO THE SECOND PRODUCTION
REQUEST OF THE COMMISSION STAFF 2
However, since the T-4 and T-5 rates were designed as firm distribution tariffs and therefore
based upon the original LV-1 rate design, those rates were allocated a portion of the LNG facility
costs in their base rates. Even though no inventory cost (i.e. WACOG) is included in transport
rates, firm delivery to transport customers on a peak day may depend on LNG facility
withdrawals. For example, if system pressures dropped below adequate levels because more gas
supply was needed for the core market during a peak event, Intermountain could withdraw
Nampa LNG storage. But if system pressures were already dropping, it is possible that LNG
withdrawals would provide the needed supply but not enough to immediately restore system
pressures. Thus the transporters could end up being curtailed even if adequate gas supplies were
delivered on their behalf, in order to protect system pressures and the core market. So while
Intermountain wouldn't directly withdraw Nampa storage to provide any transporter gas
shortage, the firm transporters do derive an indirect benefit from storage.
If the LNG filing is approved, Intermountain would file two sets of peak day allocators in its next
PGA filing. The traditional set that would continue to be used to allocate Fixed Costs and the
new set including T-4 and T-5 that would be used only to allocate LNG sales credits.
REQUEST NO. 14: On page 5 of the Company's Application, it says, "the company
proposes to separately account for any quantities of natural gas liquefied for non-utility sales and
track all related costs independent of utility costs." Please explain how the Company will ensure
that lower-cost gas purchases are not allocated to non-utility LNG sales rather than to purchases
required to meet utility customer demand. Also, please explain how the allocation methodology
can be verified in the PGA audit.
RESPONSE NO. 14: Intermountain will plan its non-utility liquefaction based on
known or projected future sales and will purchase appropriate amounts of natural gas separate
from utility needs. The Company will direct its Administrative Service provider to separately
show non-utility gas purchases on its monthly statements/invoices. The monthly records will
specifically show the amounts and prices of non-utility purchases.
INTERMOUNTAIN GAS COMPANY'S RESPONSE TO THE SECOND PRODUCTION
REQUEST OF THE COMMISSION STAFF 3
PURSUANT TO IDAPA 31.01.01.228, the record holders and/or witnesses who
could sponsor the documents in the event of a hearing are:
1. In General
Scott Madison
Executive Vice President & General Manager
Intermountain Gas Company
Boise, Idaho 83707
Telephone: [phone]
For Responses 11 - 14
David Swenson
Manager, Industrial Services
Intermountain Gas Company
P.O. Box 7608
Boise, ID 83707
208-377-6118
DATED this 19th day of February, 2013
INTERMOUNTAIN WAS/COMPANY
Wo
ive Vice President & General Manager
INTERMOUNTAIN GAS COMPANY'S RESPONSE TO THE SECOND PRODUCTION
REQUEST OF THE COMMISSION STAFF 4
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on this 19th day of February, 2013, I caused a true and correct
copy of the foregoing INTERMOUNTAIN GAS COMPANY'S RESPONSE TO THE
FIRST PRODUCTION REQUEST OF THE COMMISSION STAFF to be served by the
method indicated below, and addressed to the following:
Karl T. Klein () U.S. Mail, Postage Prepaid
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES ( ) Hand Delivered
COMMISSION Overnight Mail
P.O. Box 83720
( )
Boise, ID 83720-0074 ( ) Facsimile
( ) Email
INTERMOUNTAIN GAS COMPANY'S RESPONSE TO THE SECOND PRODUCTION
REQUEST OF THE COMMISSION STAFF 5
First Production Request
Case No. INT-G-13-02
Intermountain Gas Company
Page 1 of I
ATTACHMENT NO. I
Line
No. Description
(a)
1 Two personnel @ $45/hr for one hour
2 Direct sales Cost
3 Estimated other misc. costs
4 Total O&M
Base Overtime
(b) (c)

$90 $135

$10 $10

$10 $10

$110 $155
5 Divided by maximum gallons/load 10,000 10,000
6 Cents per Gallon $0.011 $0.016
• First Production Request
Case No.. INT-G-13-02
Intermountain Gas Company
Page 1 of I
ATTACHMENT NO. 2
www.plaffs.com
Inside FERC'sGas Market Report
February 2013
Prices of Spot Gas Delivered to Pipelines, February 1 (per MMBtu)
Range Index Volume Deals
ANR Pipeline Co.
Louisiana $3.18 to $3.18 $3.18 121 16
Oklahoma $3.13 to $3.37 $3.21 163 39
CanterPoint Energy Gas Transmission Co.
East $3.05 to $3.35 $3.16 174 30
Colorado Interstate Gas Co.
Rocky Mountains $3.13 to $3.32 $3.17 298 32
SouthernNaturalGasCo.
Range Index Volume Deals
Oneok Gas Transportation LLC
Oklahoma $3.05 to $3.33 $3.15 98 24
Panhandle Eastern Pipe Line Co.
Texas,Oklahoma (mainline)$3.09to $335 $3.21 499 107
Questar Pipeline Co.
Rocky Mountains $3.25 to $325 $325
Columbia Gas Transmission Corp.
Appalachia $3.20 to $3.45 $3.23 291 53
Columbia Gulf Transmission Co.
Louisiana $3.18 to $3.19 $3.19 63 8
Mainline $3.18 to $3.42 $3.19 327 37
Dominion Transmission inc.
Appalachia $3.11 to $3.40 $3.1356071
El Paso Natural Gas Co.
Permian Basin $3.12 to $3.38 $3.26 596 102
Sari Juan Basin $3.14 to $3.37 $3.24 308 42
Florida Gas Transmission Co.
Zone 1 $3.23 to$3.29 $3.25326
Zone 2 $3.23 to $3.25 $3.24 43 12
Zone 3 $3.25 to $3.28 $-3-...2. 3.27 36-0€€--4-- 0 42
Kern River Gas Transmission Co.
Wyoming $3.19 to$3.42 $3.29743' 105
Millennium Pipeline Co
East receipts $3.16 to $3.31 $3.21 22 8
Natural Gas Pipeline Co. of America
Midcontinent zone $3.10 to $3.37 $3.20173 44
Texok zone $3.14 to $3.41 $3.19 531 67
South Texas zone $3.15 to $3.16 $** 3€.'1€5 230 22
Northern Border Pipeline Co.
Ventura Transfer Point $3.35 to $3.35 $3.35 12 2
Northern Natural Gas Co.
Demarcation $3.32 to $3.59 $3.47 202 47
Ventura, Iowa $3.29 to $3.59 $3.41 256 58
Northwest Pipeline Corp.
Rocky Mountains $3.12 to $3.42 $328 948 116
Canadian border $3.48 to $3.68 $3.58 293 71
Louisiana $3.23 to$3.31$3.2530440
Southern Star Central Gas Pipeline In c.
Texas, Oklahoma, Kansas $3.13 to $3.34 $325 39 9
Tennessee Gas Pipeline Co.
Louisiana, 500 leg $3.21 to $3.42 $322 79 19
1ouisiana,8004eg $3.18 to$3.43 $3.18 95.22
Texas, zone 0 $3.15 to $3.39 $3.15 299 40
Zone 4-Ohio NA toNA NA 0 0
Zone 4-300 leg $2.90 to $3.03 $2.96 131 29
Texas Eastern Transmission Corp.
M-1 304nch (Kos!) $3.19 to $3.42 $3.20 211 34
M-2 receipts $3.22 to $3.40 $324 193 27
East Louisiana zone $3.17 to $3.42 $3.18 32 14
WestLouisiana zone $3.17to$3.45 $3.18 19 8
East Texas zone $3.11 to $3.19 $3.13 15 10
South Texas zone $3.15 to $3.17 $3.15 209 25
Texas Gas Transmission Corp.
-Zone 1 $3.17 to $3.40 $3.19 66 14
Zone SL $3.20 to $3.20 $3.20 0.3 -f -
Transcontinental Gas Pipe Line Corp.
Zone 1 $3.18 to $3.21 $3.18 56 11
Zone 2 $122 to $323 $3.22 12 2
Zone 3 $3.20 to $3.47 $3.25 393 54
Zone4 $3.24 to $3.45 $3.24 592 54
Transwestern Pipeline Co.
Permian Basin $3.12 to $3.30 $323 73 19
San Juan Basin $3.37 to $3.39 $3.37 80 9
Trunkline Gas Co.
Louisiana $3.18 to $3.21 $3.19 65 8
Zone 1A $3.18 to $3.18 $3.18 29 8
The McGraw Hi!! Campeniec
First Production Request
Case No. INT-G-13-02
Intermountain Gas Company
Page lofI
ATTACHMENT NO. 3
p Laff www.plafts.com
Gas Daily
Friday, June 1, 2012
I Daily price survey ($/MMBtU) I
NATIONAL AVERAGE PRICE: 2.300
Volcker rule's impact on hedging sparks debate
If federal regulators impose strict trading limits on banks, it will
be far more difficult to hedge risk through energy derivatives, Jeff
Agosta, executive vice president and CFO with Devon Energy, said
Thursday - an argument financial reform advocates disputed.
Agosta said that if a bank trading ban is imposed through the
Volcker rule, prices will become more volatile, energy firms will
scale back production efforts and there will be a severe drop in the
number of hedging instruments for energy firms, which he said
(continued on page 6)
California Senate rejects fracking notification bill
The California Senate this week voted down a bill that would have
required oil and gas operators to notify surrounding property owners
before they performed hydraulic fracturing on their wells.
By a vote of 1847, the Senate defeated SB 1054, which was pushed
by Senator Fran Pavly, a Democrat representing the Los Angeles sub-
urb of Agoura Hills.
The vote calls into question the likelihood of passage of another
bill pending before the Legislature requiring producers to disclose the
(continued on page 4)
Lawmakers spar over Obama energy policies
Lawmakers, lobbyists and academics offered a House of
Representatives committee strikingly different views Thuriday on
whether the country is following an "all-of-the-above" energy strategy
the Obama administration has promoted.
What became clear during the two-part, five-hour hearing is that
one's opinion depends largely on what set of statistics are invoked -.
and how they are interpreted.
"President Obama likes to take credit for an uptick in domestic
(continued on page 3)
NYMEX inches higher, cash prices pull back
The NYMEX July gas futures contract settled 0.4 cents
4 higher at $2.422/MMBtu on Thursday as it trimmed mid-
afternoon gains by the end of the session. Cash prices fell
in nearly every region.
Analysts were mixed on the impact of the weekly gas storage
report, which at a build of 71 Bcf was within market expectations
(see story, page 3).
IAF Advisors analyst Kyle Cooper believed the report to be bullish,
as the surplus over last year and the five-year average has been nat-
at a rour-montn rntraoay nign or %z.15 on May Z4.
He also attributed some of the market enthusiasm to EIA's month-
ly production data, also released Thursday, which showed a slight
C..... n.....a.. ........ ., ..,.,. ,-. ... - .....
Trans. date: 5/31
Flow date(s): 6/01
Midpoint Absolute Common Volume Deals
Permian Basis Area
ElPa39, Permian 2.340 -0.055 2.22-2.37 2.30-2.37 455 72
Waha 2.290 -0.105 2.25-2.35 2.27-2.32 184 36
Transwestem, Pern,Ian 2.240 -0.075 2.20-2.26 2.23-2.26 26 7
East Texas-North Louisiana Area
Ca
NGPL, Texok zone 2.290 -0.085 2.26-2.33 2.27-2.31 748 92
Tx. Eastem,ETX 2225 -0.105 2.21-2.25 2.22-2.24 20 11
Tx. Gas, zone 1 2.270 -0.100 2242.31 2.25-2.29 466 65
ast4lousthW(aty
ustonShipChannel ....Q 36 ...
25-2 37 32
South-Corpus Christi
gua Dulce Hub 2.330 -0.090 2.28-2.37 2.31-2.35 155 13
NGPl, STX 2.330 -0.055 2.20-2.36 2.29-2.36 175 24
Tennessee,zone 0 2.285 -0.095 2.22-2.33 2.26-2.31 437 66
Tx. EaemS1)( 2.265 -0.080 2.24-2.30 2.25-2.28 73 16
Transco, zone 1 2.285 -0.090 2.25-2.32 2.27-2.30 21 7
Louisiana-Onshore South
ANR, La 2.250 -0.120 2.21-2.312.23-2.28 235 45
Columbia Gulf, La 2.290 -0.085 2.25-2.31 2.28-2.31 35 12
Columbia GuLmainline 2.270 -0.100 2.22-2.31 2.25-2.29 571 78
Florida Ga5. zone 1 2.360 -0.040 2.32-2.36 2.35-2.36 28 7
Florida GaA,zmt2 2.330 -0.080 2.30-2.36 2.32-2.35 36 10
Florida Gas, zone 3 2.600 .0.020 2.36-2.67 2.52-2.67 117 20
Hub __ 83
Southern Natural, La. 2.295 -0.105 2.27-2.32 2.28-2.31 156 23
Tx. Eastern, WLA 2.300 -0.080 2.28-2.35 2.28-2.32 42 15
Tx. Eastern, ELA 2.285 -0.110 2.242.31 2.27-2.30 93 18
Ti. Gas, zone SL 2.250 -0.095 2.24-2.26 2.25-2.26 45 5
Transcq, zone 2 2.275 .0.140 2.25.2.33 2.26-2.30 38 13
Transco, zone 3 2.305 .0.120 2.23-2.35 2.28-2.34 363 54
Trunidine, V&A_.__. 2.305 -0.085 2.30-2.32 2.30-2.31 31 5
Trunldine, ELA - 2.300 -0.070 2.27-2.33 2.29-2.32 71 16
ANR, Olda. 2.225 -0.120 2.20-223 2.22-123 26 13
CenterPoInt,ast 2.285 -0.070 2.25-2.31 2.27-2.30 315 49
NGPL Midcontinent 2.260 -0.080 2.23-2.29 2.25-2.28 570 96
Oneok, OkIa. 2.245 .0.120 2.23-2.27 2.24-2.26 43 12
Panhandle, TL-Olda. 2.225 -0.110 2.19-2.26 2.21-2.24 183 40
Southern Star 2.210 -0.105 2.20-2.22 2.21-2.22 59 12
New Mexico-San Juan Basin
Paso ELondad 2.265 -0.025 2.23-2.28 2.25-218 34 6
El Paso San Juan 2.285 -0.010 2.22-2.33 2.28-2.31 413 61
Tranawestern, San Juan 2.275 -0.020 2.24-2.33 2.25-2.30 93 16
Rockies
CIG,Rockies 2.185 -0.030 2.14-2.20 2.17-2.20 89 19
-Stanfield, Ore: 2.175 .0.040 2.17-2.19 2.17-2.18 143 15
25339
.W .
GreenRiver2.175-0.0052.15-2.192.17-21912920
White River Hub 2.205 -0.055 2.18-2.24__2.19-2.22 49 9
Cansdlsn ttes