HomeMy WebLinkAbout20020506Decision Memo.doc DECISION MEMORANDUM
TO: COMMISSIONER KJELLANDER
COMMISSIONER SMITH
COMMISSIONER HANSEN
JEAN JEWELL
RON LAW
LOU ANN WESTERFIELD
BILL EASTLAKE
LYNN ANDERSON
RANDY LOBB
DON HOWELL
ALDEN HOLM
MICHAEL FUSS
DAVE SCHUNKE
TERRI CARLOCK
GENE FADNESS
BEV BARKER
TONYA CLARK
WORKING FILE
FROM: LISA NORDSTROM
DATE: MAY 6, 2002
RE: IN THE MATTER OF INTERMOUNTAIN GAS COMPANY’S 2002 INTEGRATED RESOURCE PLAN. CASE NO. INT-G-02-2.
On April 19, 2002, Intermountain Gas Company (IGC; Company) submitted its 2002 Integrated Resource Plan (IRP) with the Idaho Public Utilities Commission (Commission). The Company’s filing complies with the Commission’s direction in Order No. 24342, Case No. GNR-G-93-2 (reference PURPA § 303(b)(3), Energy Policy Act of 1992).
In its prior Order in Case No. GNR-G-93-2, the Commission adopted the following statement of Commission policy regarding PURPA § 303(b)(3) and integrated resource planning for gas utilities:
POLICIES ADDRESSING INTEGRATED RESOURCE PLANNING.
01. Purpose and Process. Each gas utility regulated by the Idaho Public Utilities Commission with retail sales of more than 10,000,000,000 cubic feet in a calendar year (except gas utilities doing business in Idaho that are regulated by contract with a regulatory commission of another State) has the responsibility to meet system demand at least cost to the utility and its ratepayers. Therefore, an integrated resource plan shall be developed by each gas utility subject to this rule.
02. Definition. Integrated resource planning. Integrated resource planning means planning by the use of any standard, regulation, practice, or policy to undertake a systematic comparison between demand side management measures and the supply of gas by a gas utility to minimize life cycle costs of adequate and reliable utility services to gas customers. Integrated resource planning shall take into account necessary features for system operation such as diversity, reliability, dispatchability, and other factors of risk and shall treat demand and supply to gas consumers on a consistent and integrated basis.
03. Elements of Plan. Each gas utility shall submit to the Commission on a biennial basis an integrated resource plan that shall include:
a. A range of forecasts of future gas demand in firm and interruptible markets for each customer class for one, five, and twenty years using methods that examine the effect of economic forces on the consumption of gas and that address changes in the number, type and efficiency of gas end uses.
b. An assessment for each customer class of the technically feasible improvements in the efficient use of gas, including load management, as well as the policies and programs needed to obtain the efficiency improvements.
c. An analysis for each customer class of gas supply options, including: (1) a projection of spot market versus long term purchases for both firm and interruptible markets; (2) an evaluation of the opportunities for using company owned or contracted storage or production; (3) an analysis of prospects for company participation in a gas futures market; and (4) an assessment of opportunities for access to multiple pipeline suppliers or direct purchases from producers.
d. A comparative evaluation of gas purchasing options and improvements in the efficient use of gas based on a consistent method for calculating cost effectiveness.
e. The integration of the demand forecast and resource evaluations into a long range (e.g., twenty year) integrated resource plan describing the strategies designed to meet current and future needs at the lowest cost to the utility and its ratepayers.
f. A short term (e.g., two year) plan outlining the specific actions to be taken by the utility in implementing the integrated resource plan.
04. Relationship Between Plans. All plans following the initial integrated resource plan shall include a progress report that relates the new plan to the previously filed plan.
05. Plans to Be Considered in Rate Cases. The integrated resource plan will be considered with other available information to evaluate the performance of the utility in rate proceedings before the Commission.
06. Public Participation. In formulating its plan, the gas utility must provide an opportunity for public participation and comment and must provide methods that will be available to the public of validating predicted performance.
07. Legal Effect of Plan. The plan constitutes the base line against which the utility's performance will ordinarily be measured. The requirement for implementation of a plan does not mean that the plan must be followed without deviation. The requirement of implementation of a plan means that a gas utility, having made an integrated resource plan to provide adequate and reliable service to its gas customers at the lowest system cost, may and should deviate from that plan when presented with responsible, reliable opportunities to further lower its planned system cost not anticipated or identified in existing or earlier plans and not undermining the utility's reliability. In order to encourage prudent planning and prudent deviation from past planning when presented with opportunities for improving upon a plan, a gas utility's plan must be on file with the Commission and available for public inspection. But the filing of a plan does not constitute approval or disapproval of the plan having the force and effect of law, and deviation from the plan would not constitute violation of the Commission's Orders or rules. The prudence of a utility's plan and the utility's prudence in following or not following a plan are matters that may be considered in a general rate proceeding or other proceedings in which those issues have been noticed.
Order No. 24342
THE INTEGRATED RESOURCE PLAN
According to the IRP’s Executive Summary, the IRP is meant to describe the currently anticipated conditions over the five-year planning horizon, the anticipated resource selections and the process for making those resource decisions. IRP at 1. IGC estimates that its average increase in residential and commercial customers between the first quarters of fiscal year 2001 and 2002 to be 5%. Id. During fiscal year 2001, 50 percent of the throughput on IGC’s system was attributable to industrial sales and transportation. Id.
Peak Day Load Growth. IGC developed peak day sendout studies and load duration curves under design weather conditions to determine the magnitude and timing of future deficiencies in firm peak day delivery capability. Residential, commercial and industrial peak day sendout was matched against available resources to determine which combination of new resources would be needed to meet IGC’s future peak day delivery requirements at the best possible cost. Id. at 2. Residential, commercial and industrial peak day load growth on IGC’s system is forecasted over the five-year period to grow at an average annual rate of 4%.
Regional Studies. Certain geographic regions within IGC’s service territory were analyzed based upon the anticipated or known need for distribution system upgrades within each specific region. Id. at 4.
The Idaho Falls Lateral Region serves a number of cities between Pocatello north to St. Anthony. The residential, commercial and industrial load served off this region represents approximately 14% of the total Company customers and 18% of the Company’s total winter sendout during the winter of 2001-2002. Id. IGC hopes to work with industrial customers in this region who use alternative fuels to mitigate small, short duration peak day distribution delivery deficits. However, the projected delivery deficits are of such magnitude that “looping” of the existing system is warranted, adding the necessary firm delivery capacity to that area. Id.
The Sun Valley Lateral Region represents approximately 4% of the total Company customers and 3% of the Company’s total winter sendout during the winter of 2001-2002. Id. at 5. When forecasted peak day sendout in this region is matched against the existing peak day distribution capacity (120,000 therms), a peak day delivery deficit occurs during 2003 and increases thereafter. Id. Growth along the Sun Valley Lateral Region warrants an upgrade to the existing pipeline system since its limited industrial load does not currently have the capability to switch to alternative fuels as a means of mitigating peak day sendout. Id. at 6.
The Canyon County Region represented approximately 12% of the total Company customers and 14% of the Company’s total winter sendout during the winter of 2001-2002. Id. When forecasted peak day sendout in this region is matched against the existing peak day distribution capacity (600,000 therms), a peak day delivery deficit occurs during 2006 and increases thereafter. Id. This region’s diverse industrial customer base does not currently have the capability to switch to alternative fuels as a means of mitigating peak day sendout and IGC is currently exploring optional means of enhancing this region’s distribution capability. Id. at 7. IGC is also awaiting the outcome of a planned natural gas fired electric generation plant in the Canyon County Region as the construction of this facility can potentially provide synergies to the design of IGC’s distribution facilities in that region. Id.
STAFF RECOMMENDATION
Staff recommends that the Company’s IRP filing be processed under Modified Procedure with a 60-day comment period to facilitate a thorough review of the IRP. Reference Commission Rules of Procedure, IDAPA 31.01.01.201-204. Staff does not currently anticipate that workshops will be needed since Intermountain Gas held several workshops to gather public input prior to drafting their IRP.
COMMISSION DECISION
Does the Commission believe that Modified Procedure is appropriate? If not what is the Commission’s preference?
Lisa Nordstrom
M:INTG0202_ln
DECISION MEMORANDUM 3
DECISION MEMORANDUM 5