II. DISCUSSION

A. Commission Jurisdiction to Approve FAR Reservation Charge

SCGC contends the Decision errs because: (1) adoption of the reservation charge conflicts with relevant federal law; and (2) other factors contradict any distinction between the reservation charge and the charges previously determined to be unlawful. (SCGC Rhg. App., at pp. 4-8.)

1. Relevant Federal Law

SCGC argues the FAR reservation charge is the same type of charge deemed unlawful in Union Pacific Fuels, Inc., et al. v. Southern California Gas Company et al. ("Union Pacific I") (1996) 76 FERC ¶ 61,300, 1996 FERC LEXIS 1705.⁹ (SCGC Rhg. App., at pp. 4-6.) We do not agree.

Union Pacific I and its progeny involved evaluation of a Commission approved interconnection or access charge assessed to interstate shippers delivering gas from the Kern/Mohave interstate pipeline to Wheeler Ridge, the border receipt point where Kern/Mohave interconnects with SoCalGas' intrastate pipeline system. In finding the charge unlawful, FERC was guided by the Hinshaw exemption under Section 1(c) of the Natural Gas Act, stating: "[W]e interpret the exemption as drawing the line of demarcation between Federal and State regulation at the point when the intrastate company receives gas from an interstate shipper."¹⁰

FERC took no issue with our jurisdiction to impose charges which relate to intrastate facilities or the transportation of gas on intrastate facilities.¹¹ FERC objected to charges which it viewed as tied to the shipper's interstate activity of nominating to deliver gas to the Wheeler Ridge interconnection point and moving gas over the Kern/Mohave interstate pipeline and delivering it to Wheeler Ridge. FERC did not view the charge as tied to any service performed by SoCalGas on its intrastate system after it received the gas.¹² Further, as SCGC acknowledges, a charge which would apply to entities with service agreements for transmission of the gas on intrastate facilities is within the Commission's jurisdiction.¹³

In SCGC's view, Finding of Fact ("FOF") Number 31 proves the reservation charge is solely for "access" rather than any intrastate transmission. Thus, SCGC argues it is unlawful pursuant to Union Pacific I. FOF 31 states: "[T]he FAR reservation charge provides the holder with access to the transmission system." (D.06-12-031, at p. 136.) FOF Number 31 does not support SCGC's position because it simply recognizes that obtaining firm access to the transmission system is a component of ensuring the gas will then move on for actual transmission over the system. SCGC also ignores our many clear statements which provide that the reservation charge is in fact an unbundled portion of the transmission cost which FAR holders will pay to have the gas transported over SDG&E and SoCalGas' intrastate transmission system. (D.06-12-031, at pp. 83, 87, 90-91.) SCGC's own arguments admit as much by arguing the adopted charge does not cover enough of the full cost of transmission.

In addition, service agreements that FAR holders will execute with the utilities demonstrate the reservation charge is permissibly tied to intrastate transmission costs.¹⁴ Unlike the interconnection charge deemed unlawful in Union Pacific I, no portion of the FAR reservation charge is tied to gas transmission over interstate pipelines, or the act of nominating to deliver gas to the utilities' intrastate pipeline system. Accordingly, we reasonably concluded that the FAR reservation charge does not conflict with federal law. (D.06-12-031, at pp. 82-83.)

2. Other Factors

SCGC contends the reservation charge is in fact an unlawful "access" charge because: (a) the Decision merely creates an artificial citygate market to justify the new charge; (b) the charge is not adequate to represent actual transmission costs; and (c) the charge does not include in-kind fuel costs. (SCGC Rhg. App, at pp 7-8.) Again, we disagree with SCGC's arguments.

In SCGC's view, D.06-12-031 unnecessarily creates a new "paper point" citygate market to justify imposing the new charge. SCGC maintains there is already an existing citygate market. Further, SCGC argues that Schedule G-RPA, Sheet 2, demonstrates that the charge is in fact solely for "access" to SoCalGas' system rather than for any actual intrastate transportation.

SCGC is wrong that there is already an existing citygate market in southern California. As SCGC notes in its own rehearing application, the existing market is a "border" or "Topock" market (SCGC Rhg. App., at p. 12.). Border market receipt points are located at the perimeter of SoCalGas' service territory,¹⁵ while citygate receipt points are contemplated as internal locations in the service territory. D.06-12-031 creates a citygate market for southern California, such that end-users will have the option of purchasing gas at the producing basin, at the border, or at the citygate, noting that SoCalGas and SDG&E customers do not currently have the option of purchasing gas at the citygate. (D.06-12-031, at p. 79.)

SCGC is correct that the service agreement schedules include provisions identifying and pertaining to receipt point access to the utilities' systems. Receipt point access is an inevitable and natural component of providing gas transportation service and it would arguably be negligent for associated service agreements to exclude such provisions. However, that does not establish that the reservation charge is for the sole act of delivery to the receipt point as was the case in Union Pacific. As we mentioned above, the reservation charge service agreements and the adopted FAR system clearly provide for intrastate transportation and delivery of gas from a receipt point to a citygate location. (D.06-12-031, at pp. 79, 83, 91.)

Next, SCGC contends the reservation charge is too low to actually reflect transmission services. SCGC argues the charge must be solely for "access" rather than any actual transmission because the 5 cents/Dth reservation charge is only a portion of the total estimated backbone transmission costs of 15.75 cents/Dth. (SCGC Rhg. App., at pp. 7-8.)

We realize that the adopted charge does not cover the full intrastate transmission cost. Our Decision and the parties all acknowledge that point. However, that it is a partial rather than total transmission cost does not convert it into something else (e.g., an access charge).

SCGC argues that if the charge is indeed for transmission, end-use customers will be subsidizing FAR holders. (SCGC Rhg. App., at p. 7.) We disagree because D.06-12-031 provides that the end-user's transmission charge will be reduced by the 5 cents/Dth to be paid by FAR holders. (D.06-12-031, at pp. 87-88.) Even if some subsidization could occur, SCGC does not establish that it is either unusual or unlawful for certain customers to subsidize the service of other customers if circumstances warrant and we deem it as necessary. While we did agree it may ultimately be preferable to develop a fully cost-based charge, we determined that the utilities' next BCAP proceeding is the appropriate venue to fully assess the cost of the backbone transmission system. (D.06-12-031, at p. 88.)

Finally, SCGC contends that the reservation charge is not for transmission service because it does not include an in-kind fuel cost. SCGC argues this will result in shippers holding firm access rights that ship gas to a citygate receiving a service without bearing all the costs of that service. (SCGC Rhg. App., at pp. 8.) Again, SCGC fails to establish that a fuel cost must be imposed and our Decision provides a rational basis for determining to reject coupling in-kind fuel charges with the reservation charge. Specifically, the Decision reasoned:

The disadvantage that we see with imposing the in-kind fuel charge is that the shippers will be responsible for paying this cost upfront with in-kind fuel...[U]nder the existing cost recovery, these costs are recovered through the rates of the core and noncore customers. We believe that in designing a fair and balanced system of FAR, that fuel charges should continue to be recovered in the rates of end-use customers... (D.06-12-031, at p. 93.)

B. Rational Basis and/or Record Support for Adopting a FAR System, Set-Asides, and Aspects of the Open Season Bid Process

SCGC argues that the Decision does not comply with Public Utilities Code section 1705 and related case law. (SCGC Rhg. App., at pp. 8-10.) Section 1705 provides in pertinent part that Commission decisions:

shall contain, separately stated, findings of fact and conclusions of law by the commission on all issues material to the order or decision.

(Pub. Util. Code, § 1705.)

The courts have long held that section 1705 requires that the Commission's findings must be adequate to:

afford a rational basis for judicial review and assist the reviewing court to ascertain the principles relied upon by the commission and to determine whether it acted arbitrarily, as well as assist parties to know why the case was lost and to prepare for rehearing or review, assist others planning activities involving similar questions, and serve to help the commission avoid careless or arbitrary action.¹⁶

Further the courts note:

Every issue that must be resolved to reach that ultimate finding is `material to the order or decision,' and findings are required of the basic facts upon which the ultimate finding is based.¹⁷

1. Need for FAR

Specifically, SCGC contends the Decision contravenes section 1705 and the relevant case law because there are no basic findings to support the ultimate determination that "[T]he time is ripe to adopt a system of FAR for southern California." (SCGC Rhg. App., at pp. 10-14, citing to D.06-12-031, p. 134 [Finding of Fact Number 15.].) As we briefly explain below, SCGC's contention is not correct.

D.06-12-031 contains sufficient findings on which to base its determination for adopting the FAR system. SCGC's own rehearing application enumerates approximately ten findings in D.06-12-031 related to the ultimate finding to adopt a FAR system.¹⁸ These findings address factors such as: problems in the current gas delivery system; problems in the current capacity allocation system; the underlying system of firm tradable transmission rights has worked well in northern California; the possibility of future receipt point constraints; uncertainty faced by end-users under the current system; more flexible options for market participants via a FAR system and creation of a citygate market; more certainty of gas delivery encouraging long-term gas supply contracts; and that the FAR system will not lead to increased complexity, increased costs, or a preference toward affiliates.

SCGC dismisses these findings as "irrelevant and conclusory." However, as SCGC admits, the Commission has discretion to determine what factors are relevant to a particular decision. (SCGC, Rhg. App., at p. 9.) Here, our findings demonstrate the underlying basic factors we considered material to reaching the ultimate determination.¹⁹

SCGC next contends the Decision errs because there is no record evidence to support various findings and conclusions. SCGC's contention is based on citing to testimony, evidence, and argument it presented during this proceeding which allegedly contradict our determinations. SCGC's contention essentially asks us to reweigh the evidence and arguments which we considered and rejected during this proceeding. The contention also ignores the record evidence that does support our determinations as to each issue raised by SCGC.

First, SCGC disagrees with the Decision's finding that FAR will provide market participants with flexible options and create a new citygate market. SCGC claims the record indicates FAR will decrease flexibility, and that there is already a citygate market which operates well.²⁰ (SCGC Rhg. App., at pp. 10, 12, 13.) As previously noted, SCGC's own statements acknowledge the existing market is a border market. Further, there is evidence to support our conclusion that creation of a citygate market will provide a stronger market place than the current border locations²¹ and that a FAR system will provide more flexible market options.²²

Second, SCGC disagrees with our conclusion that end-users currently face uncertainty over whether their gas will flow through a constrained receipt point.²³ However, there is evidence that certain receipt points may be over nominated and that the current allocation system may contribute to unpredictability and uncertainty.²⁴ Finally, there is evidence to support our conclusion that a FAR system will increase and improve the certainty of gas flow.²⁵

2. Set Asides

SCGC contends the Decision errs because: (a) it fails to explain a systematic rationale for establishing set-asides; (b) it adopts arbitrary and discriminatory set-asides with respect to noncore customers with long-term upstream capacity contracts, producers, and certain displacement customers. (SCGC Rhg. App., at pp. 16-23.) SCGC's allegations are not correct, although there appears to be some ambiguity that needs clarification on these issues.

a) Rationale for Establishing Set-Asides

SCGC generally asserts the Decision fails to clearly explain a rationale for establishing set-asides, and argues the Decision grants individual set-asides on an "ad hoc" basis. (SCGC Rhg. App., at p. 16.)

We are not constrained by any one approach or requirement in determining set-aside priorities and preferences. Nor must we adopt equal set-asides for all market participants. In explaining the FAR proposals, the open season process, and the adopted modifications, our Decision consistently reflects a rational basis for determining set-aside priorities under a FAR structure. The adopted bid protocol first allocates set-asides for existing capacity, followed by new and displacement capacity. The Step 3 open season process will operate such that Step 1 will allocate FAR set-asides for the utilities' retail and wholesale core customers, Core Transportation Aggregators ("CTAs"), entities with existing Commission approved long-term firm transportation contracts, and California Gas producers. In the Decision it is self-evident that we applied that rationale as the basis for determining set-aside preferences.

b) Set-Asides for Noncore Customers with Long-Term Upstream Capacity Contracts, Producers, and Displacement Customers

SCGC contends the Decision is patently discriminatory because it denies Step 1 set-asides for noncore customers with long-term commitments on upstream pipelines at the same time it approves set-asides for certain other entities with similar commitments. In particular, SCGC claims there is no record to support the Decision's reason for denying the specified set-asides. (SCGC Rhg. App., at pp. 17-19.) These contentions have no merit.

In denying the specified Step 1 set-asides, we stated: "[S]uch a set-aside is likely to reduce the amount of capacity available to end-users at the most popular receipt points, and little, if any capacity would be available to end-users and other market participants in Steps 2 and 3." (D.06-12-031, at p. 95.) SCGC attempts to discount this conclusion by arguing that no party claimed an EG set-aside would consume "all" of the Step 2 and 3 capacity, and that Step 3 capacity would still be available at Wheeler Ridge. These are merely disputes regarding degree that were presented and considered during the proceeding. No party disputes that Wheeler Ridge and Kramer Junction are the two most popular receipt points. And the table SCGC offers reflects that granting the requested set-asides would significantly reduce available capacity as we reasoned in D.06-12-031. (SCGC Rhg. App., at p. 20.) SCGC also fails to acknowledge that we denied Step 1 set-asides for the specified contracts because such a set-aside is likely to reduce the amount of capacity available to end-users at the most popular receipt points. (D.06-12-031, at p. 95.)

SCGC next contends the Decision is unlawful because there is not parity between the set-asides for California gas producers and noncore customers. SCGC argues that "to maintain parity with producers, noncore customer Step 2 bidding rights should be based on customer's peak month volumes over the most recent three year period." (SCGC Rhg. App., at pp. 22.)

There is no mandate that we ensure parity between different market participants that are not similarly situated. SCGC also incorrectly suggests that producer bidding rights are based on a customer's peak month volumes over the most recent three year period. In fact, we adjusted the producers base period to be a three-year historical average - explaining that the three year historical average will provide a better indicator of production for California producers. (D.06-12-031, at p.100.) We do not believe SCGC actually desires parity with this adjusted producer base period, since its argument here merely reiterates its preference for the peak month base period that it advocated during the proceeding.²⁶

Finally, SCGC contends the Decision is unlawful because the set-asides for displacement capacity at Otay Mesa are more generous than the set-asides for displacement capacity at other receipt points. (SCGC Rhg. App., at pp. 22-23.)

In making this argument SCGC compares the following two paragraphs from D.06-12-031:

If a funding party builds new capacity or expands existing capacity on a displacement capacity basis at Otay Mesa, up to 700 MMcfd, and the funding party pays for it on an incremental cost basis, the funding party shall be eligible to receive a Step 1 set-aside for firm rights in the Southern Zone at Otay Mesa in the open season for the amount of capacity that the funding party paid for. (D.06-12-031, at p. 74.)

If a funding party builds new capacity or expands capacity on a displacement capacity basis, and the funding party pays for it on an incremental cost basis, the funding party shall be eligible to receive a Step 1 set-aside in the appropriate zone for the amount of capacity that the funding party paid for, but that set-aside shall be subject to nominations at other receipt points in the same transmission zone. (D.06-12-031, at p. 75.)

SCGC interprets this language to exempt Otay Mesa, but not other receipt points, from nominations and potential prorating if take-away capacity is oversubscribed. SCGC is wrong because nothing in the language of D.06-12-031 or related discussion provides for such an exemption.

3. Open Season Bid Process

In summary, the 3 step open season process will operate such that Step 1 will allocate FAR set-asides for the utilities' retail and wholesale core customers, Core Transportation Aggregators ("CTAs"), entities with existing Commission approved long-term firm transportation contracts, and California Gas producers. The contract term is set at three years.²⁷ Step 2 will allow bids from end-use customers or their designated agents. As recently modified by D.07-06-003,²⁸ bids will be limited to the total amount of capacity available at each existing receipt point, minus any Step 1 set-asides. The contract term is set at three years.²⁹ Finally, Step 3 will allow bids for remaining existing receipt point capacity, for a term of three to 20 years.³⁰ SCGC contests the following aspects of the open season process.

a) Step 2 Annual Bids vs. Seasonal Bids

SCGC contends the Decision errs by requiring annual bids rather than monthly or seasonal bids in Step 2 of the open season. SCGC asserts this will increase the unit cost of gas transmission capacity for low load factor electric generators ("EGs"), or force them to rely on less reliable purchases which will in turn increase their cost of obtaining natural gas service. (SCGC Rhg. App., at pp. 23-34.)

Despite SCGC's allegations, our Decision relied on record support and provided a rational basis for the determination to require annual bids. Record support includes testimony that: (a) annual bids provide greater economic value to the utilities by maximizing the use of system capacity; (b) monthly or seasonal bids could result in pro-rating because a receipt point is full in some months, but not other months;³¹ and (c) monthly or seasonal bids create gaps in firm access rights.³² The record also contains evidence to support a conclusion that SCGC is wrong regarding its allegations of economic harm to low load factor EGs.³³

Our Decision provides a rational basis by enumerating some of this information and explaining we were not persuaded by the proposal for monthly or seasonal bids. We went on to reason: "[A]lso, with the set-aside for the upstream contracts of electric generators, they should be able to obtain most, if not all, of what they need." (D.06-12-031, at p. 104.) SCGC's argues this statement is incorrect because we denied its request to allow Step 1 set-asides for noncore customers with long-term contract commitments on upstream pipelines. (SCGC Rhg. App., at p. 24.) SCGC's criticism suggests an ambiguity on page 104 that requires clarification. Accordingly, we will clarify the last sentence of the second paragraph in D.06-12-031, at p. 104 to state:

Also, with the opportunity for electric generators to bid in Steps 2 and 3 of the open season, they should be able to obtain most, if not all, of what they need.

b) Step 1 & 2 Receipt Point Capacity Limit

SCGC contends the Decision errs in adopting a five-year monthly average associated with the limit on available capacity in Steps 1 and 2. In SCGC's view, this does not square with the stated goal to ensure market participants will have access to capacity and ensure end-users will receive access to capacity they have already paid for.³⁴ Thus, SCGC proposes that the capacity limit be eliminated, or at least adjusted to ensure the stated goals can in fact be achieved. (SCGC Rhg. App., at pp. 24-25.)

We do not need to revisit this issue here because it was already reconsidered in our recent Opinion Regarding SCGC's Petition for Modification³⁵ of D.06-12-031.³⁶ We granted SCGC's request and eliminated the five-year monthly average process. We provided that end-users will be allowed to bid for capacity up to the total amount of capacity available at each existing receipt point, minus any Step 1 set asides.³⁷ Accordingly, this issue is moot.

c) Step 3 Contract Term

SCGC takes exception to the Step 3 contract term and while not specifying any legal error, requests that D.06-12-031 provide that the contract term for existing capacity be set at three years to match the term for existing capacity in Step 1 and 2. (SCGC Rhg. App., at pp. 25-26.)

Because SCGC fails to specify any legal error, we deny rehearing on this issue. Further, we note that we recently revisited this issue and reaffirmed our determination in D.06-12-031 to set the Step 3 contract term at three to 20 years so that it would remain flexible.³⁸

C. Evidence Supporting the Reservation Charge

SCGC contends the Decision errs because the 5 cents/Dth reservation charge is not supported by the record and not cost-based. Accordingly, SCGC argues it is arbitrary and capricious, and either the charge should be set at zero or implementation should be delayed until after the utilities' next BCAP proceeding. (SCGC Rhg. App., at p. 26.)

SCGC is wrong that there is no record to support the adopted reservation charge. Certainly there was controversy regarding the amount that should be charged and what that amount should encompass (e.g., noncore backbone transmission, local transmission and distribution, an at-risk component, a credit-back component, an in-kind fuel charge). However, we did rely on evidence to support the determination to set the amount at 5 cents/Dth and parties had ample opportunity to address the issue, and the proposed 5 cent/Dth level, in testimony and briefs.³⁹

We do agree that the reservation charge is not cost-based - at least to the extent it does not represent the full amount of transmission costs. Nevertheless, we are not required to only adopt charges that are fully cost-based. We have broad authority in regulating public utilities, including setting rates and allocating costs among customers.⁴⁰ Here, we provided a rational basis to for our determination consistent with the particular circumstances. While 15.75 cents/Dth may be closer to the total backbone transmission costs,⁴¹ we explained it was necessary to set a lower charge because: (a) unbundling backbone transmission costs could result in cost-shifting;⁴² (b) the 15.75 cent charge is intended to unbundle backbone transmission costs from the end-user's total transmission rate, however, parties failed to identify which transmission assets should be designated as backbone; (c) a reservation charge as high as 15.75 cents/Dth is likely to discourage many market participants from holding FAR; and (d) certain components included in the charge should not be included as part of the reservation charge adopted at this time (for ex., the at-risk component of the 15.75 cent charge). (D.06-12-031, at pp. 86-87.) In addition, we explained why we rejected allegations that a 5 cent charge is not sufficiently cost based to warrant adoption,⁴³ and specifically considered and rejected SCGC's proposal to set the charge at zero. We explained that a zero reservation charge encourages hoarding and would unfairly allow a FAR holder to avoid paying for any of the costs of the transmission system. (D.06-12-031, at pp. 90-91.)

Similarly, we provided a rational basis for moving forward with a FAR system at this time even though a fully cost-based charge is not yet developed. We noted a history of policy decisions leading to this point⁴⁴ as well as flaws in the current market structure,⁴⁵ which warrant taking action now.⁴⁶ Our Decision states:

We firmly believe that should we postpone a decision on whether a system of FAR should be adopted for SDG&E and SoCalGas, we are likely to be in the same position again in a couple of years trying to resolve the same problems and issues that we have been struggling with for the last nine years. The time is ripe to adopt a system of FAR for southern California. (D.06-12-031, at p. 63.)

In the interim, it is important to implement a system of FAR, and a five cent charge is appropriate at this time. Moving forward with a system of FAR now will give SDG&E, SoCalGas, market participants, and the Commission valuable experience with a FAR market structure in southern California, and will give FAR holders an assurance that they can bring gas into southern California on a firm basis. (D.06-12-031, at p. 88.)

The FAR proposal, with unbundled FAR reservation charge, is being selected over the unbundled FAR proposal with the 15.75 cents reservation charge because it provides a better starting point for introducing a system of FAR to southern California. (D.06-12-031, at p. 89.)

D.06-12-031 also reasonably provides for adjustment of the reservation charge pending proper development of a cost study in the utilities' BCAP proceedings:

We agree with some parties that a cost-based FAR reservation charge tied to the cost of the backbone transmission system is desirable.""...[H]owever, in the absence of a cost study identifying backbone transmission-related costs, we cannot adopt a cost-based rate in this decision. The BCAP is the appropriate proceeding to fully assess the cost of the backbone transmission system.⁴⁷ (D.06-12-031, at p. 88.)

Finally, we ensured that no unjust or unlawful charges will be collected by ordering the utilities' to establish a balancing account so that the utilities will not be at risk for under-recovery of the unbundled FAR reservation charge revenues, and so that any over-recovery will be refunded to ratepayers. (D.06-12-031, at pp. 88, 142 [Ordering Paragraph Number 6.].)

D. Issues to be Determined in SoCalGas' Next BCAP Proceeding

SCGC contends the Decision appears to prejudge certain cost-shifting and rate design issues to be examined in SoCalGas' next BCAP. SCGC requests the Commission clarify that these issues will be impartially examined in that proceeding. (SCGC Rhg. App., at p. 27.)

In D.06-12-031, we reviewed retention of SoCalGas' peaking rate tariff GT-PS. The tariff applies to noncore partial bypass customers who use interstate pipeline for baseload service and return to SoCalGas for peaking service. As we explained, the peaking rate is intended to close the "regulatory gap" between the fixed rate structure of the interstate pipelines and SoCalGas' variable volumetric rate, and prevent cost shifting that would occur when large customers migrate to the gas service of competing customers leaving the remaining core customers to pay all the costs of the transmission system. The peaking rate contains a demand charge that applies each month whether or not the customer takes peaking service that month and is intended to compensate the utility for the facilities associated with standing ready to provide firm peaking level service. (See D.06-12-031, at pp. 122-129.)

SCGC takes exception with Ordering Paragraph ("OP") Number 9 which states in pertinent part:

a. In its next Biennial Cost Allocation Proceeding (BCAP), SoCalGas shall include a proposal for a total redesign of its rate consistent with the discussion regarding closing or minimizing the regulatory gap.

b. Upon closing of the regulatory gap, the existing peaking service tariff shall sunset at the conclusion of the next BCAP. (D.06-12-031, at pp. 142-143 [Ordering Paragraph Number 9.].)

SCGC argues that this language seems to prejudge that the "regulatory gap" should be closed and as a consequence, that increased demand charges will be imposed. Our Decision does contemplate that some change to the existing peaking tariff is likely to occur at the conclusion of the next BCAP. However, we acknowledged that solutions could range from eliminating the tariff (i.e., eliminating demand charges), to imposing different or additional charges (by minimizing or closing the regulatory gap). Our Decision clearly intended to resolve these issues later, after a complete reexamination of the matter in SoCalGas' next BCAP. That said, we realize that the language "upon closing of the regulatory gap" as stated in OP 9 b. could suggest there is no choice but to close the regulatory gap and thus increase demand charges to equalize any differences between the interstate rates and SoCalGas' volumetric rate. To eliminate any perception of predetermination, we will modify OP 9 b., and the last sentence of the first paragraph on page 130 to read:

At the conclusion of SoCalGas' next BCAP, we intend to sunset the existing peaking rate tariff.

E. California GHG Emissions Policy

SCGC contends the Decision errs in adopting a FAR system because it conflicts with the California climate change and greenhouse gas ("GHG") emissions reduction policy enacted in Assembly Bill ("AB") 32,⁴⁸ as well as Commission policies to increase natural gas supply and lower natural gas costs.⁴⁹ (SCGC Rhg. App., at pp. 15-16.)

SCGC does not specify or analyze how D.06-12-031 contravenes any particular provision of AB 32, instead relying on the following language:

The CPUC is aggressively pursuing policies to address the threat of climate change. The Commission is investigating adopting a greenhouse gas emissions performance standard for new electricity procurement contracts entered into by the investor-owner utilities that would limit greenhouse gas emissions to the level emitted by modern natural gas-fire generation. If the Commission determines that promoting gas-fired generation over other types of generation is necessary to achieve our climate change goals, then the Commission should clearly adopt policies that increase the supplies of natural gas needed to fuel these plants. (Phase II Order [D.06-09-039], supra, at p. 156 (slip op.), emphasis added.)

Consistent with this language, SCGC argues the Commission should make it easier and less costly to burn gas. SCGC asserts a FAR structure creates "roadblocks to gas-fired generation" by making the operation of gas-fired EGs more complicated and costly. (SCGC Rhg. App., at pp. 14-15.) We are not persuaded by SCGC's argument.

First, SCGC does not provide any specific facts or analysis of how a system of firm access rights will in fact confound the GHG emissions reduction goals. To that end, while increasing California's natural gas supply is unquestionably important, there is substantially more to California's GHG emissions reduction policy than SCGC suggests. For example, the Energy Action Plan ("EAP") and EAP II, adopted by this Commission and the California Energy Commission ("CEC") are geared to effectuate the Governor's climate action and GHG policies as articulated in Executive Order S-3-05,⁵⁰ through state resource panning and energy procurement goals. The EAP sets guiding principles for investor owned utility procurement and establishes the following "loading order" of preferred resources: (1) energy efficiency; (2) demand response; (3) renewable resources (including distributed generation ("DG")); (4) clean fossil-fired DG; clean central station generation.⁵¹

Second, SCGC offers no evidence that a FAR system will increase costs to EGs as it claims. As previously discussed in Section B.3.a. above, we relied on evidence which supports an opposite conclusion.⁵² Also contrary to SCGC's claim, that FAR will result in a more difficult and complicated system, we were convinced by evidence indicating that FAR will improve flexibility and certainty of gas supplies in California.⁵³

Third, SCGC's allegations ignore our express goal to improve access to gas supply on the SDG&E and SoCalGas systems, and to provide assurance to market participants that their gas will be delivered. For example, we stated:

The FAR system will enable any market participant (e.g., end-user, gas supplier, gas marketer) in southern California to hold FAR on the various receipt points on the SDG&E and SoCalGas integrated gas transmission system. This system will ensure that the holder of the FAR will be able to access the receipt points on the transmission system and have their gas transported to the designated delivery points. This is in contrast to the current system where upstream gas shippers and end-use customers have no guarantee that their gas will flow through the receipt points. This problem is exacerbated under the current system where there are capacity constraints on the SoCalGas transmission system. (D.06-12-031, at p. 2.)

The FAR system will provide gas shippers, marketers, and end-users with new options and opportunities. (D.06-12-031, at p. 3.)

The current system of capacity allocation can result in a situation where access to the system is available only on an interruptible basis, shippers' gas supplies are pro-rated, and receipt points are constrained. (D.06-12-031, at p. 134 [Finding of Fact Number 9.].)

The adoption of the FAR proposal provides certainty to FAR holders that the their gas can be delivered from the receipt point to the citygate, which in turn will encourage parties to enter into long-term gas supply contracts. (D.06-12-031, at p. 136 [Finding of Fact Number 27.].)

While SCGC may disagree with our conclusions, we believe that D.06-12-031 is inconsistent with California's GHG emissions reduction policies.

⁹ Rehearing denied in Union Pacific Fuels, Inc., et al. v. Southern California Gas Company ("Union Pacific II") (1996) 77 FERC ¶ 61,283, 1996 FERC LEXIS 2314; petition for review denied in part an granted in part in Public Utilities Commission of the State of California v. FERC ("PUC v. FERC") (1998) 143 F.3d 610, 1998 U.S. App. LEXIS 10451.

¹⁰ See Union Pacific I, supra, 76 FERC at ¶ 62, 496, 1996 FERC LEXIS 1705, at *10, *11.

¹¹ Id.

¹² See Union Pacific I, supra, 76 FERC at ¶ 62,496, 1996 FERC LEXIS 1705, at *9; Union Pacific II, supra, 77 FERC at ¶ 62, 248, 1996 FERC LEXIS 2314, at *7.

¹³ See Union Pacific II, supra, 77 FERC at ¶ 62,245, 1996 FERC LEXIS 2314, at *3.

¹⁴ See Reporter's Transcript ("TR") Vol. 5, SDG&E/SoCalGas (Watson), at p. 749; TR Vol. 10, Watson/IP/CCC/CMTA (Beach), at p. 1504; Exh. 15, Schedule G-RPA, Sheet 4; Exh. 15, Rule No. 30, Transportation of Customer-Owned Gas; Exh. 15, Schedule M, Receipt Point Master Agreement; and Exh. 15, Schedule K, Pooling Service Agreement.

¹⁵ Border locations are those such as Wheeler Ridge (interconnecting with the PG&E system), Kramer Junction (interconnecting with the Kern/Mohave interstate pipeline), Blythe (interconnecting with the El Paso interstate pipeline), or Needles (interconnecting with the Transwestern interstate pipeline).

¹⁶ California Manufacturers Association v. Public Utilities Commission ("Calif. Mfrs. Assn.") (1979) 24 Cal. 3d 251, 259, 1979 Cal. LEXIS 256, at *8; see also Greyhound Lines, Inc. v. Public Utilities Commission ("Greyhound Lines") (1967) 65 Cal. 2d 811, 813, 1967 Cal. LEXIS 390, at *4; and California Motor Transport Co. v. Public Utilities Commission ("California Motor Transport") (1963) 59 Cal. 2d 270, 274-275, 1963 Cal. LEXIS 159, at *5, *6.

¹⁷ See Calif. Mfrs. Assn., supra, 59 Cal. 2d, at p. 274, 1963 Cal. LEXIS, at *5; Greyhound Lines, supra, 65 Cal. 2d, at 814, 1967 Cal. LEXIS, at *3.

¹⁸ See SCGC Rhg. App., at pp. 11-12, citing to D.06-12-031, pp. 133-136 [Finding of Fact Numbers 7, 8, 9, 15, 16, 18, 19, 20, 26, 27, and 28.]

¹⁹ SCGC admits the Commission has the discretion to determine what issues are relevant to a particular decision. (SCGC Rhg. App., at p. 9.)

²⁰ See D.06-12-031, p. 135 [Finding of fact Number 26] stating: "[T]he FAR proposal will continue to provide market participants with flexible options and result in the creation of a citygate market for southern California.

²¹ See TR. Vol. 15, SCE (Alexander), at p. 2363.

²² See Exh. 13, SDG&E/SoCalGas (Watson), at p. 2; Exh. 44, Watson/IP/CCC/CMTA (Beach), at pp. 6-12.

²³ See D.06-12-031, at p. 135 [Finding of Fact Number 20] stating: "[U]nder the current system, end-users face uncertainty over whether their gas will flow through a constrained receipt point." Also see D.06-12-031, at p. 136 [Finding of Fact number 27] stating: "[T]he adoption of a FAR proposal provides certainty to FAR holders that their gas can be delivered from the receipt point to the citygate, which in turn will encourage parties to enter into long-term gas supply contracts."

²⁴ See e.g., TR. Vol. 15, SCE (Alexander), at pp. 2341, 2326, 2335, 2357; TR Vol. 8, SDG&E/SocalGas (Watson), at p. 1172; Exh. 15, SDG&E/SoCalGas (Schwecke), at pp. 2-3; Exh. 16, SDG&E/SocalGas (Schwecke), at p. 13; TR Vol. 10, Watson/IP/CCC/CMTA (Beach), at p. 1529; TR Vol. 12 Coral (Travis), at pp. 1873-1874; TR Vol. 4, SDG&E/SoCalGas (Schwecke), at pp. 406, 411, 432, 438; TR Vol. 9, Watson/IP/CCC/CMTA (Beach), at pp. 1282, 1302.

²⁵ Exh. 12,SDG&E/SoCalGas (Watson), at p. 5; Exh 43, Watson/IP/CCC/CMTA (Beach), at pp. 12-15; TR Vol. 9, Watson/IP/CCC/CMTA (Beach), at pp. 1299, 1335, 1350; TR Vol. 14, PG&E (Graham), at p. 2164.

²⁶ See D.06-12-031, at pp. 33-34 discussing SCGC's proposal that bidding rights be set at the customer's highest usage in each month over the past three years.

²⁷ See D.06-12-031, at pp. 14-15 (proposed Step 1 participants), & 93-100 (additional Step 1 set-asides), & 104 (contract term).

²⁸ In the Matter of the Application of San Diego Gas & Electric Company (U 902 G) and Southern California Gas Company (U 904 G) for Authority to Integrate Their Gas Transmission Rates, Establish Firm Access Rights, and Provide Off-System Gas Transportation Services ("Opinion Regarding SCGC's Petition for Modification") [D.07-06-003] (2007) __ Cal.P.U.C.3d __, 2007 Cal. LEXIS 224.

²⁹ See D.06-12-031, at p. 16 (proposed Step 2 participants), & p. 104 (contract term).

³⁰ See D.06-12-031, at pp. 16-17 (proposed Step 3 participants), & p. 105 (contract term).

³¹ Exh. 44, Watson/IP/CCC/CMTA (Beach), at p. 14.

³² Exh. 12, SDG&E/SoCalGas (Watson), at pp. 11-12.

³³ Exh. 44, Watson/IP/CCC/CMTA (Beach), at pp. 10-12; Exh. 13, SDG&E/SoCalGas (Watson), at pp. 4-6.

³⁴ Citing to D.06-12-031, at p. 136 [Finding of Fact Number 30].

³⁵ In the Matter of the Application of San Diego Gas & Electric Company (U 902 G) and Southern California Gas Company (U 904 G) for Authority to Integrate Their Gas Transmission Rates, Establish Firm Access Rights, and Provide Off-System Gas Transportation Services ("Opinion Regarding SCGC's Petition for Modification") [D.07-06-003] (2007) __ Cal.P.U.C.3d __, 2007 Cal. PUC LEXIS 224.

³⁶ SCGC filed a Petition for Modification of D.06-12-031 on March 9, 2007 and filed an Application for Rehearing of D.06-12-031 on January 16, 2007.

³⁷ See Opinion Regarding SCGC's Petition for Modification [D.07-06-003], supra, at pp. 4-5, 8 [Conclusion of Law Number 1.] (slip op.).

³⁸ See Opinion Regarding SCGC Petition for Modification [D.07-06-003], supra, at pp. 3, 6, 8 [Conclusion of Law Number 2.] (slip op.).

³⁹ See Exh. 15, SDG&E/SoCalGas (Schwecke), at pp. 20-21, Schedule No. G-RPA; Exh. 12, SDG&E/SoCalGas (Watson), at pp. 11-12; Exh. 13, SDG&E/SoCalGas (Watson), at pp. 16-17, TR Vol. 8, SDG&E/SoCalGas (Smith), at pp. 1200-1202; For enumeration of excerpts from the record see Opening Brief of SDG&E and SoCalGas, dated September 14, 2007, at pp. 27-29; and SCGC Opening Brief, dated September 14, 2007, at pp. 62.

⁴⁰ See Southern California Edison v. Peevey (2003), supra, 31 Cal. 4^th at 792 [As a state agency of constitutional origin, the Commission has broad powers over public utilities, including setting rates and allocating costs between customers, and these powers have been liberally construed.]

⁴¹ SCGC takes issue with the Decision's conclusion that "a reservation charge lower than the unbundled FAR proposal rate of 15.75cents per Dth is needed to stimulate participation in the FAR." SCGC argues that if the FAR program were truly necessary and deemed valuable, the Commission would not have to stimulate participation by adopting the lower 5 cent/Dth charge. We found this argument unconvincing, and our conclusion is not inconsistent with the law.

⁴² A reservation charge based on unbundled noncore backbone transmission could result in cost-shifting because FAR holders would pay all of the backbone transmission costs while others purchasing gas at the citygate would avoid paying those costs. (See D.06-12-031, at p. 86.)

⁴³ See D.06-12-031, at pp. 83, 87.

⁴⁴ See D.06-12-031 at pp. 3-8, 63-65.

⁴⁵ See e.g., D.06-12-031, at p. 134 [Finding of Fact Number 9] stating: "[T]he current system of capacity allocation can result in a situation where access to the system is available only on an interruptible basis, shippers' gas supplies are pro-rated, and receipt points are constrained."

⁴⁶ D.06-12-031 notes that a FAR system has been in existence for PG&E since 1998 through the Gas Accord and related decisions. (See D.06-12-031, at p. 4, fn. 4, & p. 64 referring to Re Pacific Gas and Electric Company [D.97-08-055] (1997) 73 Cal.P.U.C.2d 754, as extended most recently in Application of Pacific Gas and Electric Company Proposing Cost of Service Rates for Gas Transmission and Storage Services for 2005 and backbone Level Service and Rates Starting January 1, 2005, as Required by Commission Decision 03-12-061 [D.04-12-050] (2004) __ Cal.P.U.C.3d __, 2004 Cal. PUC LEXIS 579.

⁴⁷ SDG&E and SoCalGas' witness Smith testified that the proposed five cent charge represents a portion of total transmission costs. He estimated that it would take approximately three to four months, with substantial discovery, to conduct an embedded-cost study of the nature required. According to the testimony, such a study would require an embedded study of the whole transmission system, identifying backbone and local transmission assets. Costs associated with each asset would then be backed out in order to split the backbone and local transmission costs, and develop a reservation rate for a backbone transmission value. (See TR. Vol. 8, SDG&E/SoCalGas (Smith), at pp. 1200-1202.)

⁴⁸ Approved by the Governor September 27, 2006, as the California Global Warming Solutions Act of 2006.

⁴⁹ Citing to Order Instituting Rulemaking to Establish Policies and Rules to Ensure Reliable, Long-Term Supplies of Natural Gas to California ("Phase II Order") [D.06-09-039] (2006) __ Cal.P.U.C.3d __, at p. 156 (slip op.), 2006 Cal. PUC LEXIS 337.

⁵⁰ Executive Order S-3-05 established GHG emission reduction targets for California such that the state should by 2010, reduce emissions to 2000 levels; by 2020, reduce emissions to 1990 levels; and by 2050, reduce emissions to 80 percent below 1990 levels.

⁵¹ The "loading order" as well as the intent to establish annual limits on carbon-based energy procurement as a means to meet EAP goals was further memorialized in the Commission's Opinion Adopting Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company's Long-Term Procurement Plan ("Long-Term Planning Decision") [D.04-12-048] (2004) __ Cal.P.U.C.3d __, 2004 Cal. PUC LEXIS 598.

⁵² See ante, fn. 45.

⁵³ Exh. 13, SDG&E/SoCalGas (Watson), at pp. 2-7; Exh. 44, Watson/IP/CCC/CMTA (Beach), at pp. 6-10; Exh. 12 , SDG&E/SoCalGas (Watson), at pp. 1-5; TR Vol. 9, Watson/IP/CCC/CMTA (Beach), at pp. 1298-1299, 1350, 1355.