20160915Comments.pdf

BRANDON KARPEN
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 7956
Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5918
Attorney for the Commission Staff
RECE IVED
~''J l S ~EP I 5 PM I: I I
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF INTERMOUNTAIN GAS )
COMP ANY'S APPLICATION FOR )
AUTHORITY TO DECREASE ITS PRICES (2016)
PURCHASED GAS COST ADJUSTMENT). )
) __________________ )
CASE NO. INT-G-16-03
COMMENTS OF THE
COMMISSION STAFF
The Staff of the Idaho Public Utilities Commission comments as follows on
Intermountain Gas Company's Application.
BACKGROUND
On August 12, 2016, Intermountain Gas Company (the "Company") filed its annual
Purchased Gas Cost Adjustment ("PGA") Application. The PGA adjusts rates up or down each
year to reflect changes in the Company's costs to buy natural gas from suppliers-including
transportation, storage, and other related costs. See Order No. 26019. A change in the PGA does
not affect the Company's earnings. With this Application, the Company proposes to decrease
overall prices for customers and decrease the Company's annualized revenues by $17.2 million
(7.11%).
The Company proposes to pass through to customers gas-related cost changes that would
decrease the average bill of: (1) residential customers who use natural gas for space heating and
water heating, by $3.48/month (7.55%); (2) customers who use gas for space heating only, by
$2.31/month (6.50%); and (3) commercial customers by $14.23/month (7.34%). The Company
proposes that the new rates take effect October 1, 2016.
STAFF COMMENTS SEPTEMBER 15, 2016
The Company explains that its proposed price changes incorporate all changes in costs
relating to the Company's firm interstate transportation capacity including any price changes or
projected cost adjustments implemented by the Company's pipeline suppliers and any volumetric
adjustments in contracted transportation agreements that have occurred since the Company's last
PGA filing.
The Company proposes decreasing the Weighted Average Cost of Gas ("W ACOG") used
to calculate its PGA rates from $0.32764 per therm to $0.29695 per therm. The Company
explains that shale reserves and an abundant supply contributed to the proposed W ACOG
decrease. The Company states that it has entered into various price agreements to lock in the
price for significant portions of its storage and other winter "flowing" supplies.
The Company states that the proposed overall price changes reflect a just, fair, and
equitable pass through of changes in gas-related costs to the Company's customers. The
Company states that it has notified customers about the Application and price changes through
direct customer notice and a press release.
STAFF ANALYSIS
Staff thoroughly reviewed the Company's Application and verified that the Company's
PGA proposal would not impact the Company's earnings, that the Company's deferred costs are
prudent and properly calculated, and that the Company's WACOG request is reasonable.
The Company states that the decrease in rates is attributable to: (1) decreased
transportation costs; (2) a decrease in the Company's WACOG; (3) an updated customer
allocation of gas-related costs under the Company's PGA provision; (4) the inclusion of
temporary surcharges and credits relating to the Company's deferred gas cost accounts; and (5)
benefits resulting from the Company's management of its storage and firm capacity rights. The
temporary surcharges approved in last year's PGA Order No. 33386 have also been eliminated.
Table 1 below summarizes the impact of the Application's proposed changes on customer
classes:
STAFF COMMENTS 2 SEPTEMBER 15, 2016
Table 1: Summary of proposed changes on customer classes
Proposed Proposed Proposed Proposed
Change in Average Average Average
Class Change in % Price
Customer Class: Revenue $/Therm Change $/Therm
RS-1 Residential $ (1,834,368) (0.05776) -6.50% 0.83049
RS-2 Residential (9,917,867) (0.05678) -7.55% 0.69519
GS-1 General Service (5,191,513) (0.05071) -7.34% 0.64006
L V-1 Large Volume (498,910) (0.08739) -17.65% 0.40773
T-3 Transportation (948) (0.00002) -0.11 % 0.01788
T-4 Transportation 213,988 0.00086 2.80% 0.03161
T-5 Transgortation 5,161 0.00068 0.67% 0.03330
$(17)241457) -7.11%
The overall effect of the Company's proposed changes is a decrease in annual revenues
of $17,224,457. This decrease is comprised of the following items detailed in Table 2:
Table 2: Proposed Changes to Annual Revenue
Deferrals:
Removal of INT-G-15-02 Temporary Credits and Charges
Additional INT-G-16-03 Temporary Credits and Charges
Fixed Deferred Gas Costs
Variable Deferred Gas Costs
Lost and Unaccounted for Gas
LNG Sales Credit
Total Additional Temporary Credits and Surcharges
Total Deferrals
Changes in W ACOG
Reallocation and True-Up of Fixed Costs
Fixed Cost Changes:
NWP Full Rate Reservation
NWP Discounted Reservation
Upstream Full Rate
Upstream Discounted
Storage Capacity Fixed Costs
Total Fixed Cost Changes
Total Annual Revenue Change
STAFF COMMENTS 3
$(11,223,766)
(1 ,871 ,097)
(1 ,458,962)
(236,805)
$ (234,550)
193,540
(174,059)
71,518
(16,069)
$ 3,814,294
$ (14,790,630)
$ (10,976,336)
$ (9,652,489)
$ 3,563,988
$ (159,620)
$ (17 .224.457)
SEPTEMBER 15, 2016
Weighted Average Cost of Gas (WACOG)
The WACOG is the Company's average variable cost to buy and transport gas to satisfy
its customers' estimated annual gas requirements. The WACOG includes the volumetric
interstate transportation rate, city gate costs, IGI Resources administrative fees, and Gas
Technology Institute (GTI) charges. It does not include fixed capacity costs for interstate
transportation, liquid storage, and underground storage. The proposed W ACOG is $0.29695 per
therm. This is $0.03069 or 9.4% per therm lower than the WACOG established in the 2015
PGA. Chart 1 shows the Company's historical WACOG:
Chart 1 : Weighted Average Cost of Gas (Per Therm)
0.9000 ~
0 .8000 I
0 .7000 I
0.6000
§ o.sooo
CIJ .r: ..... ~ 0.4000
0.3000
0 .2000 "
0.1000
0 .0000 + ·
,_
ci 'V">
YEAR 00 01 02 03 04 05 06 07 08 *08 *•09 1.0 11 •11 ••12 1.3 14 15 16
• % Change based on pr·evious reglilary scr'eduled PGA tHin:g
..... % Change ba5ed on previou5 December filing
Market Fundamentals & Price Analysis
Dec. Dec.
Although the Company has hedged most of its forecasted throughput at fixed prices,
market fluctuations can impact the WACOG. Thus, Staff analyzed the Company's projected
cost to purchase natural gas, and compared the Company's forecast to forecasts from national
and regional organizations, including the Energy Information Administration ("EIA"), the
Northwest Gas Association ("NWGA"), and the Northwest Power and Conservation Council
("NWPCC").
Of particular interest, the EIA projects Henry Hub prices will increase from an average of
$2.41/MMBtu in 2016 to $3.01/MMBtu in 2017. Regionally, customers benefit from lower
STAFF COMMENTS 4 SEPTEMBER 15, 2016
prices at the Sumas, Rockies, and AECO hubs when compared to the Henry Hub prices. Staff
examined futures prices for the upcoming PGA year to determine price differentials between the
Henry Hub and hubs the Company utilizes. For the PGA period, price differentials are AECO
$-0.5527, Sumas $-0.0616 and Rockies $-.0823. The Company primarily purchases from
AECO.
Based on Staffs analysis of the market, weighted average cost of the Company's hedges,
and estimated cost of forward-looking index Company purchases, Staff believes that the
Company 's W ACOG of $0.29695 per therm is reasonable. Staff recommends that the
Commission accept the proposed W ACOG and direct the Company to return to the Commission
with a n€w filing if prices significantly deviate from proposed rates during the forthcoming year.
Risk Management
Staff scrutinized how the Company manages price and risk given the Company's market
purchases, storage, and interstate transportation capacity. Staff also analyzed the Company's
operations and business practices to determine whether the Company purchased gas at market
prices in a way that minimized risk to ratepayers. Staff found that the Company's approach is
flexible, allowing it to opportunistically buy gas, manage storage, and utilize interstate
transportation capacity as market conditions change. Overall, the Company's strategy and
practices associated with managing its resource portfolio provide price stability for customers.
The Company fulfills its mainline requirement with hedges, spot market purchases,
underground storage, and LNG storage. Underground storage enables the Company to purchase
gas for the upcoming heating season during the summer when natural gas prices are typically
lower. When opportunities are present, the Company manages its interstate transportation
capacity, selling surplus in the market.
Purchasing
Staff analyzed the Company's purchasing practices to determine if the Company
reasonably adapted them to meet current market conditions. Similar to last year, about 32% of
the Company's total throughput are index or spot purchases. The Company's hedged supply
went from 46.7% of total throughput last year to 48.1 % this year. Including the Company's
storage gas, about 68% is essentially hedged which is the same as last year. Staff believes the
Company's hedging ratio adjustments compliment current market conditions, particularly since
STAFF COMMENTS 5 SEPTEMBER 15, 2016
natural gas prices are at historical lows. The Company continues to utilize index or spot
purchases, allowing it to further take advantage of lower prices and react to upward price risk.
Natural Gas Underground Storage
Staff analyzed the Company's practices for utilizing underground storage. The Company
plans to withdraw about the same amount (approximately 28%) of its underground storage to
meet total throughput.
According to the Company, its management of storage assets benefits customers.
Management of the Company's storage assets at Jackson Prairie and Clay Basin result in $1.8
million savings. Because gas added to storage is procured during the summer season when
prices are typically lower, the Company's cost of storage gas is typically lower than what could
be procured in winter months. The Company has also entered into various fixed price
agreements for portions of underground storage and other winter flowing supplies to further
stabilize prices.
LNG Storage
In Order No. 32793, the Commission authorized the Company to sell LNG from its
excess capacity at its Nampa LNG facility to non-utility customers. Pursuant to that Order, the
Company provides a credit to ratepayers of2.5 cents per every gallon of LNG sold for O&M
related expenses. Additionally, the Company is required to share 50% of the total net margin
from the non-utility sale of LNG with ratepayers, up to $1.5 million, and then 70% on any
amounts greater than $1. 5 million. In this Application, the Company proposes to credit
ratepayers $236,805 for their share of the revenues from the non-utility sale of LNG. Staff has
reviewed the Company's non-utility sales of LNG, and verified that the credit to ratepayers has
been calculated correctly.
Interstate Transportation
The Company delivers domestically produced natural gas to its city gates through
Northwest Pipeline. The Company also delivers natural gas from Canada by using capacity on
Gas Transmission Northwest (GTN), TransCanada's Foothills Pipeline system (Foothills), and
TransCanada's Alberta system known as Nova Gas Transmission (NOVA).
STAFF COMMENTS 6 SEPTEMBER 15, 2016
Permanent transportation and storage costs reflect a net decrease totaling almost
$160,000 relative to last year. This decrease is driven in large part by rate changes of all three
upstream transportation providers that reduced the Company's upstream transportation charges
by around $103,000. Additionally, renegotiation of a previously full rate contract with
Northwest Pipeline to a discounted rate contract1 reduced transportation costs by around
$41,000. Finally, the cost of domestic gas purchased from Northwest Pipeline is slightly reduced
to reflect the adjustment for the leap year.
Capacity Release Revenue
The Company generally utilizes 100% of its available capacity during the winter months.
During non-winter months, the Company seeks to maximize value by selling excess available
capacity on the open market. During the 2016 PGA year, revenues from the sale of excess
capacity totaled $10,511,397. The Company proposes to pass back this amount to customers.
This amount is an increase of approximately $1.2 million over the previous year's revenue, and
can be attributed to the Company selling more excess capacity due to warmer than normal
weather. The 2016 total of $10,511,397 includes revenues from releases on a segment of
Northwest Pipeline and releases on pipelines delivering natural gas from Canada.
Lost and Unaccounted for Gas (LAUF Gas)
LAUF Gas is the difference between the volume of natural gas delivered to the
distribution system at the city gate and the volume of gas billed to customers at the meter. The
Company recovers LAUF Gas amounts through a per therm surcharge if the amount is above
what was included in Commission-approved base rates. Conversely, the Company credits
customers if the amount is below what was included in base rates.
This year, the Company's estimated LAUF Gas rate of 0.03% is below the maximum
allowable level as specified in Commission Order No. 30649.2 The estimated deferral account
balance credit of $1,458,962 as of September 30, 2016, listed in Table 2 will be credited to
customers if the PGA filing is approved.
1 Discount to Reservation Charge under Northwest Pipeline Rate Schedule TF-1.
2 The Company uses actual LAUF Gas results through August and estimates the amount of LAUF Gas from October
through September. Commission Order No. 30649 caps the Company's allowable LAUF Gas at .85% of
throughput.
STAFF COMMENTS 7 SEPTEMBER 15, 2016
Line Break-Lost and Unaccounted for Gas
The current Line Break Rate is $0.55674 per therm. The Company proposes to decrease
the Line Break Rate to $0.54067 per therm. The proposal includes a $0.24372 Fixed-Cost
Component per therm, and a $0.29695 Variable-Cost Component per therm for a total of
$0.54067. Both components of the Line Break Rate are determined annually with the PGA
filing. Staff represents that the Company correctly calculated the proposed Line Break Rate
consistent with Order No. 33139.
Demand Allocation Factors
As outlined in the Company's PGA tariff, the fixed cost of gas is allocated based on
peak-day usage. Last year, the Company continued to use the 2013 peak day of 63 heating
degree days. Staff learned the Company reviewed peak days before this filing, and updated its
allocation factors. According to the Company, the updated allocation factors include 57 heating
degree days. The allocated fixed cost of gas is then divided by normalized sales volumes for
each class based on a Rolling 30 year average definition of normal weather.
Warmer than normal weather in 2015 and the removal of an extremely cold year from the
rolling average, lowers the billing determinants causing fixed costs to be collected over fewer
therms. This results in an increase in projected fixed costs collection of $3,563,988. Any
difference between the actual fixed cost of gas and fixed costs collected from Intermountain's
customers will be deferred and included in next year's PGA filing.
Customer Billing
Last year, the Company implemented a new Customer Care and Billing System. Among
the resulting changes was a new bill format. Staff was concerned about changes in how the
Company itemized charges on bills. Staff determined that the itemized charges added up to the
total cents per therm charge authorized by the Commission. However, Staff could not consult
the Company's tariff to verify the accuracy of each separately itemized charge as it appeared on
customer bills. In addition to the inability to verify charges, Staff was also concerned about the
increased complexity of customer bills.
The Company agreed to work with Staff to resolve these issues and Staff and the
Company reached agreement on how to revise the Company's tariff and bill statements to reflect
STAFF COMMENTS 8 SEPTEMBER 15, 2016
the PGA's cost components. Intermountain Gas' revised tariff became effective July 1, 2016,
and the resulting changes were included on customer bills beginning in August.
CUSTOMER NOTICE AND PRESS RELEASE
Intermountain Gas filed copies of its press release and customer notice with its
Application. Staff reviewed both documents and found that neither document informed
customers that written comments regarding the utility's application may be filed with the
Commission as required by Rule 125.04 of the Commission's Rules of Procedure (IDAPA
31.01.01). When Staff notified the Company of the omission on August 16, 2016, it corrected
the customer notice posted on its website and revised the remaining notices being sent to
customers.
In addition to the problem noted above, the customer notice and press release discussed
two separate cases -its PGA (INT-G-16-03) and General Rate Case (INT-G-16-02)-under the
caption "Intermountain Gas Company files for an overall decrease to its prices." Staff believes it
is inappropriate and potentially misleading to focus customers' attention on the net impact of two
separate cases. Although both Applications were filed on the same day, one case addresses a
temporary rate adjustment and the other a permanent change in base rates. Staff notes that Rule
125.03 of the Commission's Rules of Procedure states in relevant part, "[t]he information
required by this rule is to be clearly identified, easily understood, and pertain only to the
proposed rate change." Staff recommends that in the future, the Company not issue any
combined notice of separate Applications.
The customer notice was mailed with cyclical billings beginning August 15 and ending
September 12. Most customers will have the opportunity to file comments on or before
September 15, 2016.
CUSTOMER COMMENTS
As of September 15, 2016, the Commission has not received any comments from
customers regarding the price decrease proposed in this case.
STAFF COMMENTS 9 SEPTEMBER 15, 2016
STAFF RECOMMENDATION
After examining the Company's Application, exhibits, workpapers, and gas purchases for
the year, Staff recommends the Commission approve the Company's Application and filed tariffs
to decrease the Company's annual revenue by $17 .2 million (7 .11 % ) and establish a W ACOG of
$0.29695 per therm. Staff also recommends that the Commission order the Company to continue
to file its monthly Summary of Deferred Gas Costs report and quarterly W ACOG projections.
Staff also recommends that the Company not issue any combined notice of separate
Applications.
Respectfully submitted this IS ,t\,-.
Technical Staff: Kevin Keyt
Donn English
Bentley Erdwurm
Daniel Klein
i:umisc/comments/intgl 6.3bkkskdebedk comments
STAFF COMMENTS
day of September 2016.
10 SEPTEMBER 15, 2016
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 15TH DAY OF SEPTEMBER 2016,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. INT-G-16-03, BY MAILING A COPY THEREOF, POSTAGE PREPAID,
TO THE FOLLOWING:
MICHAEL P McGRATH
DIR-REGULATORY AFFAIRS
INTERMOUNT AIN GAS CO
PO BOX 7608
BOISE ID 83707
E-MAIL: mike.mcgrath(a),intgas.com
RONALD L WILLIAMS
WILLIAMS BRADBURY
1015 W HAYS ST
BOISE ID 83 702
E-MAIL: [e-mail]
SECtR~
CERTIFICATE OF SERVICE