7. Issues

7.1. Access to Rocky Mountain Gas Supplies

7.1.1. Position of the Parties

PG&E's primary justification for acquiring capacity on the Ruby Pipeline is to increase its access to Rocky Mountain gas supplies in order to diversify away from its heavy reliance on declining gas supplies in Canada. Currently, PG&E obtains more than half of its gas from the Western Canadian Sedimentary Basin (WCSB). According to PG&E, gas exports to the United States from the WCSB are declining due to falling production and increased gas consumption within Canada. The domestic supply regions that serve California - principally the San Juan Basin in the Four Corners area of New Mexico and Colorado, and the Permian Basin in west Texas - have leveled off and are expected to decline in the future. In contrast, gas production in the Rocky Mountains has been increasing for several years and will continue to increase. PG&E states that other sources of natural gas, such as imported liquefied natural gas, will not be available in sufficient quantities for several years.

DRA supports increased access to Rocky Mountain gas supplies in order to increase diversity of supply. DRA believes that increased diversity will enhance reliability and promote competition among gas suppliers.

GTN sees little need for increased access to Rocky Mountain gas supplies. GTN states that California has access to ample gas supplies, and that PG&E itself projects scant growth in gas demand. GTN opines that gas demand in California may actually decline over time due to (1) increased reliance on energy efficiency and renewable generation in lieu of gas-fired electric generation, and (2) statutorily mandated reductions of greenhouse gas (GHG) emissions.

Reid states there is no demonstrated need to access Rocky Mountain gas supplies or to diversify gas supplies.

7.1.2. Discussion

PG&E has historically obtained more than half of its natural gas from the WCSB.3 The record of this proceeding indicates that the WCSB is in long-term decline. PG&E projects that WCSB production will decline from approximately 16.2 Bcf/d in 2007 to 12.7 Bcf/d by 2015, and to 11.3 Bcf/d by 2025. PG&E also projects that an increasing portion of the diminishing WCSB gas supply will be consumed within Canada, primarily to extract petroleum from oil sands. PG&E estimates that the use of natural gas for this purpose will increase steadily, from 1.0 Bcf/d in 2007 to 3.0 Bcf/d by 2025.4 Ruby LLC provided similar forecasts of falling WCSB production and rising Canadian demand.5 GTN agrees that the WCSB will be a diminishing source of supply.6

In contrast, the record of this proceeding shows that the Rocky Mountains region is experiencing significant growth in gas production. PG&E projects that Rockies production will increase from approximately 8.6 Bcf/d in 2007 to 11.6 Bcf/d in 2015, and will continue to grow until 2026.7 Ruby LLC provided a similar forecast of increasing Rockies production.8

For the preceding reasons, we conclude that PG&E has a need to diversify away from its heavy reliance on declining WCSB supplies by increasing its access to Rocky Mountain gas, provided that it is cost effective to do so. Our conclusion is consistent with Commission policy. In D.04-09-022, the Commission determined that gas utilities should hold a diverse portfolio of pipeline capacity across multiple supply basins to ensure adequate supplies for core gas customers.9 In D.06-09-039, the Commission instructed electric utilities to take all necessary steps to ensure adequate gas supplies for gas-fired generation.10 And in Order Instituting Ratemaking (OIR) 07-11-001, the Commission stated its commitment to obtaining more gas from the Rocky Mountains:

In D.04-09-022, we had addressed the procedures for the utilities to seek pre-approval of contracts for interstate pipeline capacity, which will continue to be essential for supplying California with most of its natural gas supplies...Although the present OIR is focused primarily upon LNG supply related issues, nothing in this OIR should be interpreted as relieving the California natural gas utilities' obligation to have sufficient firm capacity rights on interstate pipelines to meet their customers' needs. Moreover, the Commission is fully committed to...diversification of supplies to include more natural gas from the producing basins in the Rocky Mountains, the enhancement of infrastructure with additional storage facilities, and the loading order's priorities of promoting energy efficiency, conservation and renewable energy sources. These other matters are being addressed or will be addressed in other proceedings. (OIR 07-11-001, p. 6. Emphasis added.)

There is no support for GTN's suggestion that current gas supplies are ample, making it unnecessary for PG&E to obtain increased access to Rocky Mountains gas supplies. The record shows that the main source of PG&E's gas supplies - the WCSB - is in steep decline. We are not persuaded by GTN's suggestion that demand for gas in California will decline because of statutorily mandated reductions in greenhouse gas emissions, making it unnecessary to increase access to the Rockies. While the use of gas for electric generation may decline, it is not foreordained.11 Moreover, there is no firm plan at this time for reducing the amount of gas used to heat homes, schools, and businesses. What is more certain, however, is that gas exports from the WCSB will probably decline, perhaps significantly. As regulators, we have a responsibility for ensuring that California has access to adequate supplies of gas. The proposed Ruby Pipeline will help to achieve this vital objective.12 Conversely, if Ruby is not built and gas exports from the WCSB decline as forecasted, California could face higher prices for a shrinking supply of gas and, perhaps, even shortages.

7.2. Costs and Benefits for Core Gas Supply

We previously concluded that it is reasonable for PG&E to acquire expanded access to Rocky Mountain gas supplies, provided that it is cost effective to do so. We next consider the costs and benefits of the proposed Ruby Pipeline, starting with PG&E's Core Gas Supply.

7.2.1. Position of the Parties

PG&E proposes to acquire 250 MDth/d of capacity on the Ruby Pipeline for Core Gas Supply and simultaneously to de-contract the same amount of capacity on the GTN pipeline. Thus, PG&E does not seek to increase its overall capacity holdings for Core Gas Supply. PG&E's objective is to diversify both its interstate pipeline portfolio and its sources of gas supply in order to foster competition among supply regions, enhance supply security, and improve reliability for PG&E's core gas customers.

PG&E prepared six different forecasts of the net present value of purchasing Rocky Mountain supplies, transported via Ruby, over a 15-year period compared to purchasing WCSB supplies transported via GTN. PG&E's analysis shows that purchasing Rockies gas and transporting it via PG&E's proposed 250 MDth/d of Ruby capacity will be less costly than purchasing supplies from the WCSB and continuing to use 250 MDth/d of its existing capacity on GTN. Depending on the forecast, PG&E projects cost savings ranging from $113 million to $613 million.

CARE believes the Ruby Pipeline will create competition for the transportation of gas to the California-Oregon border, which should lower transportation costs over the long run.

DRA and TURN support PG&E's request to obtain capacity on the Ruby Pipeline. They believe it is prudent to replace capacity connected to a region where gas production is declining with capacity connected to a region experiencing significant growth in production. They also believe that PG&E has negotiated very favorable rates, terms, and conditions.

GTN argues that PG&E's calculation of benefits rests on two flawed assumptions. First, PG&E assumes that the price of gas in the WCSB will remain significantly above the price of gas in the Rockies. GTN believes this is unlikely. Second, PG&E underestimates the increase in rates that will occur on the GTN system due to PG&E's de-contracting of 250 MDth/d of capacity. GTN argues that the increase in rates on the GTN system will offset any benefits the Ruby capacity provides to PG&E's core gas customers. The issue of PG&E's de-contracting of GTN capacity is addressed later in today's decision.

Reid states PG&E's motivation for acquiring Ruby capacity is PG&E's belief that Rocky Mountain gas will be cheaper than WCSB gas. Reid sees this as improper speculation in energy markets with ratepayer funds.

7.2.2. Discussion

Our review of the costs and benefits of PG&E's proposed Ruby capacity for Core Gas Supply is within the context of the Commission's policy of requiring gas utilities to hold a diverse portfolio of pipeline capacity to multiple supply regions to reduce the risks of supply disruption and price instability.13 PG&E's current portfolio for Core Gas Supply lacks diversity. PG&E's interstate pipeline portfolio is 63% GTN capacity, 21% El Paso capacity, and 16% Transwestern capacity. Almost all gas for Core Gas Supply comes from just two regions - the WCSB and the San Juan Basin.14

Acquiring Ruby capacity will provide needed diversification for the Core Gas Supply portfolio by adding a fourth interstate pipeline and a third major gas supply region. The added diversification will increase supply security, reliability, and price stability. It should also help PG&E to exploit differences in the price of gas among supply regions, thereby lowering costs for ratepayers.

The additional security and reliability afforded by the Ruby Pipeline will provide significant benefits. As mandated by D.06-07-010, Core Gas Supply must hold sufficient assets to meet a 1-in-10 year peak day demand.15 If temperatures drop below the 1-in-10 year level, and core-storage withdrawals cannot meet incremental demand, Core Gas Supply must turn to the citygate market to procure gas. If supplies are not available, PG&E must divert gas from non-core customers, including electric generation, for delivery to core customers.

During low-temperature events, history has shown that supplies delivered by the GTN pipeline tend to diminish due to increased consumption in upstream markets where temperatures are also low. This reduction in flows puts upward price pressure at the PG&E citygate market at a time when supplies are most needed. The Ruby Pipeline will increase available supplies, which should lower the cost of citygate purchases during cold weather events and reduce the likelihood of non-core gas diversions.

PG&E conducted a multi-faceted analysis of the risks, costs, and benefits of the proposed Ruby capacity for Core Gas Supply. The analysis used several gas-price forecasts that PG&E developed internally and obtained from independent sources. In general, these forecasts anticipate that price of gas in the WCSB will remain above the price of gas in the Rockies for the duration the 15-year Precedent Agreement. PG&E's analysis shows that the Ruby Pipeline leads to significant reductions in expected risks and costs for core gas customers. While the ultimate outcome 15 years hence cannot be known, PG&E' analysis suggests that it is likely the proposed Ruby Pipeline capacity will advance the Commission's policy objectives of gas supply security, reliability, and price stability at no additional cost - or even less cost - to core gas customers.

The Ruby Precedent Agreement contains three provisions that reduce risk for PG&E's customers. First, PG&E is guaranteed to receive the lowest transportation rate provided to shippers who contract for a term of one to 15 years. Second, the Agreement includes capacity step-down rights in Years 11 through 15. The step-down rights provide flexibility to reduce capacity if conditions warrant. Third, at the end of the initial 15-year term, PG&E has the right to annually renew the Precedent Agreement for up to ten one-year extensions. This ensures that PG&E can maintain prudent diversification for an additional 10-year period at favorable rates ($0.68/Dth) if conditions warrant.

For the preceding reasons, we conclude that PG&E's core gas customers will likely benefit from PG&E's proposed Ruby Pipeline arrangements. We are not persuaded by GTN's argument that PG&E's analysis of costs and benefits is based on the unrealistic assumption that the price of gas in the WCSB will remain significantly higher than the price of gas in the Rocky Mountains throughout the 15-year term of the Precedent Agreement. GTN's argument overlooks the fact that PG&E's gas supplies are weighted disproportionately towards the WCSB, a producing region that is in steep decline. Currently, the price of gas in the WCSB is significantly higher than the price of gas in the Rockies. If PG&E does not diversify away from the WCSB, it is all but certain that the price of gas in the WCSB will remain above the price of gas in the Rockies, as there will be the same level of demand chasing a declining level of WCSB supply.

Conversely, if PG&E obtains access to cheaper gas supplies in the Rocky Mountains and there is a subsequent narrowing of the price differential between the WCSB and the Rockies as suggested by GTN, it is reasonable to assume that the narrowing is due, at least in part, to competition between the regions, and that the price paid by PG&E for gas from either region would be less what PG&E would have paid had it relied on WCSB supplies alone.

We disagree with Reid's assessment that PG&E's justification for the proposed Ruby capacity amounts to speculation in energy markets. The fundamental purpose of the proposed Ruby capacity is to diversify away from PG&E's disproportionate reliance on Canadian gas supplies in order to reduce portfolio risk. Reid's own analysis shows that it is cost effective for PG&E to reduce portfolio risk by acquiring Ruby capacity.16 Moreover, the amount of interstate pipeline capacity that PG&E can hold for Core Gas Supply is capped by D.04-09-022. PG&E's testimony explains how the Ruby capacity fits within this cap while diversifying its portfolio.17 In sum, the record shows that PG&E seeks diversification to minimize risks and costs. There is no evidence of market speculation.

7.3. Costs and Benefits for Electric Fuels

PG&E proposes to acquire 250 MDth/d of Ruby capacity for its Electric Fuels Department for a four-month period beginning on July 1, 2011, and 125 MDth/d for a 15-year period beginning on November 1, 2011. Electric Fuels currently has no pipeline capacity and is limited to purchases at the PG&E citygate. Beginning in July 2009, it has one contract for 50 MDth/d on the GTN system, which will be effective July 1, 2009 through May 31, 2014.18

7.3.1. Position of the Parties

To demonstrate that Electric Fuels has a need for the proposed Ruby capacity, PG&E provided two long-term forecasts of Electric Fuels' net open position and gas demand for the period of 2011 through 2026. One forecast assumed a 20% Renewable Portfolio Standard (RPS), and the other assumed a more aggressive 33% level. Both forecasts assumed that half of the net open position (i.e., unmet need for electric generation) would be filled by contracts for gas-fired generation that require PG&E to procure gas supply. Both forecasts show that Electric Fuels' need for gas will grow substantially beginning in the year 2010, when PG&E must procure fuel for several new, Commission-approved gas-fired generation plants. Under the current 20% RPS, the proposed Ruby capacity represents 27% of Electric Fuels' expected average daily gas demand and 10% of expected peak demand. Under the 33% RPS, the Ruby capacity represents approximately 45% of expected average daily demand.

To demonstrate that the proposed Ruby capacity for Electric Fuels is cost effective, PG&E provided six different forecasts of the direct costs, direct benefits, and indirect benefits of the proposed Ruby capacity relative to the status quo. PG&E's calculation of direct benefits and direct costs compares two different gas-purchasing strategies: (1) the Ruby strategy of buying gas in the Rockies and transporting it to the PG&E citygate using Electric Fuels' proposed capacity on the Ruby Pipeline and the Redwood Path; and (2) the status quo strategy of buying the same volume of gas at the PG&E citygate. Four of PG&E's forecasts show that the direct benefits of the Ruby strategy outweigh the direct costs. Two of the forecasts show the direct costs of the Ruby strategy outweigh the direct benefits. However, when indirect benefits are considered, all six of forecasts show the Ruby strategy results in lower costs compared to the status quo. The indirect benefits consist of lower priced gas from increased gas-on-gas competition made possible by the Ruby Pipeline.

DRA and TURN find that PG&E has demonstrated a need to acquire the proposed Ruby capacity to support growing demand for gas-fired generation and that it is cost effective to do so. DRA states that it is important to obtain the Ruby capacity relatively soon because there are three large gas-fired generating plants (Colusa, Gateway, and Russell City) that will come online by 2010 for which PG&E will have to supply gas. TURN adds that only a fraction of Electric Fuels' needs will be met with Ruby capacity, leaving PG&E free to rely on citygate purchases to a significant extent, particularly for swing supply.

GTN contends that PG&E has not demonstrated a need to acquire Ruby capacity for Electric Fuels. GTN believes that PG&E's projected need for gas-fired generation can be met, in large part, by renewable generation, direct access, and energy efficiency. GTN also asserts that PG&E will have to reduce its projected use of gas-fired generation in order to reach statutorily mandated reductions in GHG emissions.

GTN argues that PG&E's own evidence shows that electric ratepayers will be worse off with the proposed Ruby capacity. PG&E calculated the net present value of the proposed Ruby capacity using six different price forecasts over the 15-year life of the contract. Four of the forecasts show positive net benefits, while two show negative net benefits. GTN maintains that the two forecasts showing negative net benefits are the most reliable.

Ruby LLC opines that it is reasonable for Electric Fuels to diversify its gas procurement strategy away from near total dependence on citygate purchases.

7.3.2. Discussion

In D.06-09-039, the Commission held that securing "firm interstate gas pipeline capacity rights is an important element of electric utility resource planning and an important factor in assuring the reliability of the natural gas delivery system.19" Currently, PG&E's portfolio of interstate pipeline capacity for the Electric Fuels consists of a single contract for 50 MDth/d on the GTN pipeline for a 59-month period beginning on July 1, 2009. This represents only a fraction of PG&E's forecasted average daily need of more than 400 MDth/d for electric generation throughout the period of 2011 through 2026, and forecasted peak demand of more than 1,000 MDth/d.20 Thus, PG&E has a substantial unfulfilled need for interstate pipeline capacity to serve electric generation. We find that the proposed Ruby capacity will help achieve the Commission's policy of securing firm interstate pipeline capacity for electric generation.

We also find that PG&E conducted a reasonable analysis of the risks, costs, and benefits of the proposed Ruby capacity for Electric Fuels. The analysis shows the net present value benefits of the Ruby Precedent Agreement ranges from $52 million to $343 million, depending on the forecast used. The major representatives of PG&E's customers - DRA and TURN - agree with PG&E's analysis and support PG&E's requested Ruby capacity.

For the preceding reasons, we conclude that PG&E's bundled electric customers will likely benefit from the proposed Ruby capacity for Electric Fuels. We are not persuaded by GTN's argument that PG&E has overestimated its need for gas-fired generation. PG&E's forecast of gas-fired generation incorporated aggressive energy efficiency and RPS goals. PG&E also assumed that only half of its net open position would be filled by gas-fired generation with fuel supplied by PG&E. But even if PG&E has overestimated its need for gas-fired generation, the proposed Ruby capacity is still only a fraction of the gas-fired generation that will be in-service in 2011.21 Thus, there is still a reasonable need for Ruby capacity even if no additional gas-fired generation is built. Furthermore, to limit risk, PG&E has negotiated capacity step-down rights in Years 11 through 15 of the Ruby Precedent Agreement. If the need for gas-fired generation does not materialize, PG&E will be able to reduce its capacity on the Ruby Pipeline.

GTN's claim that PG&E's own forecasts show that electric ratepayers will be worse off is misleading. PG&E presented six forecasts; four show net direct benefits and two show net direct costs. The net direct costs shown in latter two forecasts are $100 million and $104 million, respectively, over 15 years.

However, PG&E anticipates, and we agree, that the large volume of Rocky Mountain gas that Ruby will bring to Malin will compete head-to-head with PG&E's other main sources of supplies from the WCSB and the San Juan Basin, putting downward pressure on gas prices. PG&E forecasts that the indirect benefits of competition will average $0.10/Dth over the 15-year life of the Ruby contract, which will save PG&E's bundled electric ratepayers approximately $200 million.22 These forecasted savings from gas-on-gas competition more than offset the net direct costs in the two forecasts at issue.23

7.4. Alternatives

We previously concluded in today's decision that PG&E has a need for increased access to Rocky Mountain gas supplies and that PG&E's proposed contract for long-term capacity on the Ruby Pipeline provides a cost-effective means for doing so. We next consider alternatives to the Ruby Pipeline.

There were four alternatives identified in this proceeding:

1. The no-project alternative.

2. The proposed expansion of the Kern River Pipeline.

4. The proposed Sunstone Pipeline Project.

Three of these alternatives can be easily rejected. First, we previously rejected the no-project alternative because it would keep PG&E dependent on declining WCSB gas supplies. Second, PG&E presented unrebutted testimony that obtaining capacity on an expanded Kern River Pipeline is both uneconomic and infeasible.24 No party supports this alternative. Third, Spectra Energy has canceled the Bronco Project because it could not match the rates that Ruby LLC is offering to PG&E and other shippers.25

The one remaining alternative is the proposed Sunstone Pipeline Project (Sunstone) sponsored by Williams and GTN's parent company, TransCanada. Sempra Pipelines & Storage has an option to acquire a 25% equity interest in Sunstone. If built, Sunstone would transport gas from Opal, Wyoming to an interconnection with GTN's pipeline system at Stanfield, Oregon. Sunstone shippers could then use the GTN pipeline to transport gas south to Malin, Oregon. The distance of the Opal-Stanfield-Malin route is approximately 900 miles, which is about 230 miles longer than Ruby. A map of the proposed Sunstone and Ruby pipelines is presented previously in today's decision.

7.4.1. Position of the Parties

PG&E maintains that Sunstone is inferior to Ruby because (1) GTN has not offered PG&E a rate equal to or better than the $0.68 rate offered by Ruby, (2) GTN has not offered the other favorable terms in the Ruby Precedent Agreement, such as capacity step-down rights, and (3) Sunstone would provide less gas-on-gas competition for California markets compared to Ruby because much of the gas transported by Sunstone would flow to the Pacific Northwest. PG&E also contends that Sunstone would provide less reliability because it would deliver gas at Stanfield. PG&E would then have to transport its gas some 335 miles on GTN to Malin. As a result, PG&E's gas supplies would be subject to disruption on the GTN pipeline between Stanfield and Malin. With Ruby, a disruption on GTN would not affect the flow of Rockies gas to California.

CARE supports Ruby over Sunstone. CARE believes that having separate pipelines on separate routes and owned by separate companies is the only way to have transportation-on-transportation competition.

DRA and TURN likewise supports Ruby over Sunstone. In DRA's opinion, Ruby offers better terms and conditions. Ruby has the added advantages of creating transportation-on-transportation competition with GTN, and providing a superior opportunity for gas-on-gas competition in California by delivering gas directly to the California-Oregon border instead of 335 miles upstream at Stanfield where much of the gas will flow to non-California markets.

TURN believes that the Ruby Pipeline is a "great deal" for PG&E's ratepayers. TURN notes that even Reid, who opposes the Ruby Pipeline, calculated that the benefits of Ruby would exceed its costs by more than 2 to 1.

GTN asserts that Sunstone-GTN can offer a better deal than Ruby if only PG&E would negotiate. GTN also argues that only Sunstone retains the ability to access future gas supplies in the Arctic regions of Alaska and Canada because Sunstone, unlike Ruby, will use the GTN system. The GTN system, in turn, will interconnect with future pipelines built to transport gas from Arctic regions. In contrast, Ruby would displace much of the gas that is currently transported by GTN, which could force GTN to retire capacity. The retired capacity could not be used to transport future gas supplies from the Arctic.

Reid used an option pricing model to compare pipeline alternatives. His analysis shows that Ruby is a slightly better alternative than Sunstone. Reid states there is no evidence the Ruby Pipeline will be more reliable than the Sunstone pipeline or the existing GTN pipeline.

Ruby LLC contends that its pipeline offers a number of benefits that Sunstone cannot match. First, the Ruby Pipeline has a 15-year fixed rate of $0.68/Dth that is lower than either (1) the combined rate on GTN and upstream pipelines that transport WCSB gas, or (2) the Sunstone-GTN option. Ruby LLC believes its fixed rate is especially valuable in an era of rising costs.

Second, Ruby provides most-favored-nation rate protection, term-extension rights, and the option to step-down capacity during the final five years of the contract term. Sunstone has not offered equal or better terms.

Third, the Ruby Pipeline provides enhanced reliability. Currently, GTN is the only pipeline that delivers gas at Malin. Adding Ruby will enable PG&E to receive gas at Malin from Ruby in the event of a disruption on the GTN system. Ruby LLC views this as a valuable benefit given California's heavy reliance on gas for electric generation and winter heating.

Fourth, Ruby will provide increased gas-on-gas competition and transportation-on-transportation competition at Malin. While Sunstone could provide some increase in competition, its impact would be diluted because it will not deliver gas directly to Malin.

Finally, the Ruby Pipeline has a significant head start. Ruby has already: (1) signed sufficient binding agreements with shippers (i.e., agreements that do not allow the shipper to cancel the contract) to permit Ruby to proceed with its project; (2) signed contracts with steel mills for all of the pipe needed for the project; (3) executed incentive-based contracts with a consortium of three construction companies; and (4) initiated the FERC "pre-filing" environmental review process in early 2008. Sunstone has not achieved any of these milestones.

Ruby LLC downplays GTN's claims that Sunstone offers better access to future Arctic gas supplies because Sunstone will ensure that GTN remains in operation. Ruby LLC argues that GTN can backhaul the gas delivered by the Ruby Pipeline to Malin to markets in Oregon and Washington. These backhauls should ensure continued use of GTN, according to Ruby LLC.

7.4.2. Discussion

We conclude the Ruby Pipeline is a better alternative than Sunstone for accessing Rocky Mountain gas supplies. Ruby provides favorable rates, terms, and conditions that have not been matched by Sunstone-GTN. PG&E's principal customer representatives in this proceeding - DRA and TURN - support the proposed Ruby Precedent Agreement. There is no opposition from PG&E's non-core gas customers, electric generators, gas producers and marketers, and nearly all other market participants. The main opposition comes from the owners and sponsors of competing pipelines (i.e., Sunstone and GTN).

Ruby is clearly superior in terms of transportation costs. PG&E will pay $0.68/Dth or less for capacity on the Ruby Pipeline, plus fuel costs. GTN has not provided in this proceeding a rate for the Sunstone-GTN route to Malin. However, there are reasonable approximations available. These are:

Rate for

Sunstone-GTN Route

Basis for Rate

$0.746/Dth

GTN rate is assumed to be its current recourse rate of $0.20 less a 50% discount. Sunstone rate is assumed to be the same as Ruby ($0.68) less a 5% discount for the shorter mileage compared to Ruby. (Exhibits PG&E-3, p. 3-8, lines 10-19, and PG&E-6, p. 4-2.) Note: GTN did not offer any evidence to support this rate. We derived this rate from PG&E's testimony.

$0.835/Dth

Sunstone-GTN offer to PG&E in December 2007 in response to PG&E's Rockies Pipeline Project Framework. (Exhibits PG&E-5, pp. 1-4 to 1-6, and PG&E-6, p. 4-2.)

$0.845/Dth

Negotiated rate offered during Sunstone's open season. (Exhibit PG&E-6, pp. 4-3 and 4-4.) Note:  This rate is for Sunstone only. It excludes GTN transportation costs.

$0.846/Dth

GTN rate is assumed to be its current recourse rate of $0.20. Sunstone rate is assumed to be the same as Ruby ($0.68) less a 5% discount for the shorter mileage compared to Ruby. (Exhibit PG&E-3, p. 3-8, lines 10-19.)

The above table shows the Ruby rate of $0.68/Dth is less than any rate likely to be charged for the Sunstone-GTN route. This comparison does not include pipeline fuel costs, which would likely be more for Sunstone-GTN than Ruby because of the longer distance of the Sunstone-GTN route.26

Ruby has other advantages over Sunstone. First, Ruby would interconnect with PG&E's system at Malin, while Sunstone would interconnect with GTN's system at Stanfield, several hundred miles upstream of Malin. Having two major pipelines delivering gas at Malin, GTN and Ruby, increases reliability compared to having just one pipeline, GTN, delivering gas at Malin. If there is an outage on GTN, gas supplies from the Rockies will continue to flow on Ruby. If there is an outage on Ruby, gas supplies from the WCSB will continue to flow on GTN. The added reliability provided by Ruby is a significant advantage given California's heavy reliance on gas for electric generation and winter heating.

Second, Ruby offers a distinct geographic advantage in fostering competition that will benefit California. While both Ruby and Sunstone-GTN would transport Rockies gas to Malin, which under virtually all scenarios will be priced below WCSB supplies, Ruby will provide more gas-on-gas competition at Malin. That is because all of Ruby's capacity (i.e., at least 1.3 Bcf/d) will flow to Malin, whereas only a portion of Sunstone's capacity of 1.2 Bcf/d will flow to Malin, with the remainder going to the Pacific Northwest.27 The increased gas-on-gas competition provided by Ruby should be more effective at reducing gas prices in California compared to Sunstone,28 all else being equal.

We give little credence to GTN's claim that Sunstone-GTN can offer a superior deal if only PG&E would negotiate. Sunstone-GTN had at last two opportunities to beat the Ruby deal. One opportunity was in December of 2007 when PG&E asked Sunstone-GTN to respond to PG&E's "Framework" proposal. This proposal is described in more detail later in today's decision. The second opportunity was at the evidentiary hearing were GTN's witness was asked if Sunstone could offer, then and there, a better deal than Ruby LLC. On both occasions Sunstone did not avail itself of the opportunity presented.29

Sunstone-GTN have known the terms of the Ruby deal since February 1, 2008, when the Precedent Agreement was made public. Sunstone could have sent a written offer to PG&E at any time. All Sunstone-GTN had to do was offer the same non-rate terms and conditions as Ruby LLC and a better rate. The fact that Sunstone-GTN have not done so indicates that they are unwilling or unable to beat the Ruby deal.

We accord little weight to GTN's claim that Sunstone is superior because it will keep all of GTN's capacity in service and thereby preserve the option of accessing Arctic gas supplies.30 It is pure speculation whether any pipelines will be built to Arctic regions. Even if such pipelines are built, it will be many years before they enter service,31 and the cost of transporting gas from the distant Arctic to California will be much more expensive than transporting gas from the Rocky Mountains over the Ruby Pipeline.

7.5. Capacity on PG&E's Redwood Path

7.5.1. Position of the Parties

The Ruby Pipeline will deliver gas to PG&E at Malin, Oregon, where it will be transported into California via PG&E's Redwood Path pipeline. PG&E's Core Gas Supply Department currently has firm capacity on the Redwood Path, while PG&E's Electric Fuels Department does not.

In A.07-12-021, PG&E requests authority for Electric Fuels to acquire capacity on the Redwood Path that matches Electric Fuels' upstream arrangements on the Ruby Pipeline. The specific transportation arrangements on the Redwood Path proposed for Electric Fuels are as follows:

· 250 MDth/d of firm capacity for four months followed by 125 MDth/d for 15 years. Electric Fuels' will be able to use its Redwood Path capacity to make both firm on-system and firm off-system deliveries.

· The Redwood Path capacity commitment will commence at the same time that Electric Fuels' Ruby transportation arrangements go into effect.

· Electric Fuels and PG&E's California Gas Transmission (CGT) Department, which operates PG&E's gas transmission system, will each have the right to terminate the Redwood Path arrangements if the Ruby Pipeline fails to make reasonable progress towards commercial operations.

Electric Fuels' Redwood Path arrangements will be subject to the rates, terms, and conditions set forth in PG&E Tariff Schedule G-AFTOFF. The current tariffed rate for firm service on the Redwood Path is $8.9095/Dth/month.32 The annual cost for Electric Fuels' 125 MDth/d of capacity on the Redwood Path will be $13.4 million,33 plus a usage rate of $0.0070/Dth. However, the flexible start date and termination rights are non-standard conditions that require Commission approval. The proposed contract between Electric Fuels and CGT containing these non-standard conditions is set forth in PG&E Exhibit 6, Chapter 7, Appendix B. PG&E will offer the same arrangements to similarly situated shippers. PG&E represents that the proposed arrangements for Electric Fuels on the Redwood Path are consistent with the "Gas Accord" decisions, beginning with D.97-08-055 and most recently in D.07-09-045.

Under the current Gas Accord, PG&E has authority to offer a total of 400 MDth/d of long-term firm capacity on the Redwood Path.34 Because long-term transportation arrangements on the Redwood Path related to the Ruby Pipeline would represent a significant percentage of the 400 MDth/d, PG&E requests that Ruby-related arrangements not count against the 400 MDth/d.

CARE supports PG&E's proposal. CARE also recommends that the actual costs of using the Redwood Path be determined in a separate proceeding.

DRA notes that Electric Fuels currently purchases most of its gas at the PG&E citygate. DRA believes Electric Fuels' acquisition of firm capacity on the Redwood Path will enhance the reliability of Electric Fuels' gas supply.

SoCalGas/SDG&E claim that PG&E's proposal to provide Electric Fuels with both firm on-system and firm off-system delivery rights on the Redwood Path violates PG&E Tariff Schedule G-AFTOFF. They argue that Tariff Schedule G-AFTOFF only allows for firm off-system delivery. On-system delivery is not labeled as "firm" under G-AFTOFF, but as "alternate."

SoCalGas/SDG&E contend that PG&E's proposal for the Electric Fuels to acquire firm, non-tariffed, on-system delivery rights on the Redwood Path, together with PG&E's request for other non-standard conditions, amounts to a modification of the Gas Accord. They further argue that that PG&E's proposal would allow Electric Fuels to obtain rights that are not available to others under the current Gas Accord. They recommend that the Commission direct PG&E to pursue this matter in the next Gas Accord proceeding where all other shippers on PG&E's Redwood Path may seek similar treatment.

7.5.2. Discussion

We will approve PG&E's proposed transportation arrangements on the Redwood Path for the Electric Fuels Department, with certain clarifications described below. PG&E provides electricity to millions of Californians, much of it through gas-fired generation, yet the Electric Fuels Department currently has no firm capacity on PG&E's intrastate gas transportation system. The firm gas transportation arrangements approved by today's decision will provide an important measure of reliability for the Electric Fuels Department's gas supply.35

SoCalGas/SDG&E assert that PG&E seeks to improperly use Tariff Schedule G-AFTOFF for firm on-system deliveries. We agree. G-AFTOFF is plainly intended for firm off-system deliveries. The Tariff Schedule states, in relevant part, as follows: "Applicability: This rate schedule applies to the firm transportation of natural gas on PG&E's Backbone Transmission system to the Off-System Delivery Points." (Emphasis added.) However, the record clearly indicates that PG&E plans to use its Redwood Path capacity primarily for on-system deliveries.36 The proper tariff for firm on-system deliveries is G-AFT which states, in relevant part, as follows: "Applicability: This rate schedule apples to the firm transportation of natural gas on PG&E's Backbone Transmission System to On-System Delivery Points(s) only.37"

PG&E contends that G-AFTOFF can be used for firm on-system deliveries because the Tariff states that customers may designate an "alternate" on-system delivery point. We agree with SDG&E/SoCalGas that "alternate" is not the same as "firm." We interpret G-AFTOFF as providing firm off-system delivery service, and permitting alternate on-system delivery points on a non-firm basis.

For the preceding reasons, we will require PG&E's Electric Fuels Department to use Tariff Schedule G-AFT for firm on-system deliveries. If PG&E believes it is beneficial to deliver off-system from time-to-time, PG&E shall use the provision in G-AFT that specifies the procedures for making off-system deliveries.38 Like all shippers, Electric Fuels may use other current and future tariffs for proper purposes. However, before switching to another tariff, PG&E shall obtain Commission approval (or pre-approval) to the extent required by the Commission's rules and regulations at that time. If no procedures are in place for obtaining such approval (or pre-approval), PG&E shall file an advice letter pursuant to GO 95-B, Rule 3.6.

The rates, terms, and conditions of service on the Redwood Path provided to Electric Fuels will be inherently fair, reasonable, and nondiscriminatory because service will be governed by a Commission-approved tariff schedule. The only non-standard conditions are (1) a start date tied to the in-service date of the Ruby Pipeline, and (2) termination rights for both Electric Fuels and CGT in the event the Ruby Pipeline does not progress in a timely manner. These non-standard conditions serve a legitimate purpose, and there is no evidence these conditions are detrimental to PG&E's ratepayers. The non-standard conditions do not discriminate against other shippers, as PG&E will offer these conditions to similarly situated shippers.

We decline to adopt SoCalGas/SDG&E's recommendation to defer consideration of Electric Fuels' Redwood Path arrangements to the next Gas Accord proceeding. Their recommendation is based on the premise that Electric Fuels' Redwood Path arrangements are inconsistent with the Gas Accord. We disagree. For the reasons stated previously, the authorized Redwood Path arrangements for Electric Fuels are consistent with PG&E's existing tariffs. The only non-standard terms are the flexible start date and termination rights. These non-standard terms do not modify the Gas Accord. Rather, they address a situation that is unique to the Ruby Pipeline. As such, the instant proceeding is the appropriate forum to consider the non-standard terms.

Finally, we decline to grant PG&E's request to exclude Ruby-related transportation arrangements on the Redwood Path from the 400 MDth/d that is reserved on the Redwood Path by the Gas Accord for long-term firm capacity. This matter is directly related to the Gas Accord and, as such, should be addressed in PG&E's next Gas Accord proceeding.

7.6. Recovery in Retail Rates

7.6.1. Position of the Parties

PG&E requests authority to recover in retail rates for core gas customers and bundled electric service customers all rates and charges that PG&E pays to Ruby LLC. PG&E also seeks authority to recover in bundled electric rates all amounts paid for Electric Fuels' matching downstream capacity on the Redwood Path. PG&E states that because the proposed gas transportation arrangements are reasonable and beneficial to ratepayers, the Commission should authorize PG&E to recover all associated costs, including reservations charges and volumetric charges.

CARE and DRA support PG&E's recovery in retail rates of PG&E's proposed gas transportation arrangements to the extent these arrangements are used by PG&E to provide gas service to its core gas customers and bundled electric customers.

GTN opposes PG&E's request for reasons addressed elsewhere in today's decision. Ruby LLC responds that PG&E's request is consistent with the Commission's policy of pre-approving gas transportation commitments.39

7.6.2. Discussion

We conclude elsewhere in today's decision that PG&E's proposed gas transportation arrangements on the Ruby Pipeline and the Redwood Path are reasonable. Therefore, we will authorize PG&E to recover in retail rates the costs that it incurs to transport gas on the Ruby Pipeline and the Redwood Path, subject to the following conditions. First, the amount that PG&E is authorized to recover in retail rates for core gas customers is limited to the rates and charges that PG&E pays under the Precedent Agreement for Core Gas Supply to transport 250 MDth/d. As a general principle, PG&E is not authorized to recover from core gas customers any costs associated with capacity reserved on the Ruby Pipeline and Redwood Path for Electric Fuels. This prohibition does not apply to short-term capacity acquired by Core Gas Supply through arms-length capacity brokering transactions or to capacity diverted to serve core customers.

Second, the amount that PG&E is authorized to recover in retail rates for bundled electric service customers is limited to (1) the rates and charges that PG&E will pay under the Precedent Agreement for Electric Fuels to transport 250 MDth/d for an initial 4-month period followed by 125 MDth/d for a 15-year period, and (2) tariffed rates and charges that the Electric Fuels pays for matching downstream capacity on the Redwood Path. PG&E is not authorized to recover from bundled electric service customers any costs for capacity reserved on the Ruby Pipeline for Core Gas Supply. This prohibition does not apply to short-term capacity acquired through arms-length capacity brokering transactions.

Third, the Precedent Agreement specifies that the rate PG&E pays for Ruby capacity will the lower of (1) $0.68 Dth/d, (2) the Initial Recourse Rate less 5%, or (3) any lower rate paid by similarly situated shippers. PG&E is authorized to recover the lowest rate available under the Precedent Agreement, not to exceed $0.68 Dth/d.40 Whenever PG&E seeks Commission approval to recover Ruby Pipeline costs, PG&E shall certify that it is paying the lowest rate available under the Precedent Agreement. This certification may take the form of (1) a sworn declaration signed by an officer of PG&E or Ruby under penalty of perjury,41 or (2) any other form deemed acceptable by the Commission.

Fourth, the amount that PG&E may recover in retail rates for Ruby fuel surcharges and other surcharges is limited to the amounts paid to Ruby pursuant to Section 3(b)(iii) of the Precedent Agreement.42

Fifth, PG&E has the right after 10 years to reduce its Ruby capacity by 20% annually. The Commission will decide at that time whether it is appropriate for PG&E to keep or release the step-down capacity. To that end, Core Gas Supply and Electric Fuels shall each use the procedures the Commission has in place at that time to obtain Commission approval (including pre-approval) to either keep or release the step-down capacity.43 If no procedures are in place, PG&E shall file an application at least one year prior to the first step down to obtain authority to either keep or release the step-down capacity. The application shall include a proposal for Commission review and approval of any subsequent decisions by PG&E to retain or release step-down capacity under the Precedent Agreement.

Sixth, at the end of the initial 15-year term of the Precedent Agreement, PG&E has the option of letting the Precedent Agreement expire or, alternatively, exercising one-year extensions through October 31, 2036 (for ten possible 1-year extensions) for all or part of the contracted capacity. The Commission will decide at that time whether it is appropriate to let the Precedent Agreement expire or, alternatively, to extend the Agreement for one-year terms. To that end, Core Gas Supply and Electric Fuels shall each use the procedures the Commission has in place at that time to obtain Commission approval (including pre-approval) to either extend the transportation arrangements or let them expire.44 If no procedures are in place, PG&E shall file an application at least one year prior to the expiration of the initial 15-year term of the Precedent Agreement to obtain authority to either extend the transportation arrangements or let them expire. The application shall include a proposal for Commission review and approval of any subsequent decision(s) by PG&E to annually extend or terminate the transportation arrangements under the Precedent Agreement.

Finally, PG&E may recover costs for Electric Fuels' Redwood Path arrangements in future years only to the extent the Commission has authorized recovery of Electric Fuels' upstream arrangements on the Ruby Pipeline. Thus, if the Commission does not authorize Electric Fuels to retain step-down capacity on the Ruby Pipeline in Years 11 through 15 of the Precedent Agreement, PG&E may not recover Electric Fuels' matching step-down capacity on the Redwood Path in Years 11 - 15.45 Similarly, if the Commission does not authorize annual one-year extensions of Electric Fuels' capacity on the Ruby Pipeline in Years 16 through 25 of Precedent Agreement, Electric Fuels may not recover its matching downstream capacity on the Redwood Path in Years 16 - 25.

The authority granted by today's decision is consistent with the Commission's policies. In D.04-09-022, the Commission expressed its preference for pre-approval of rate recovery of interstate pipeline costs, and authorized utilities to file applications to request pre-approval of costs for interstate pipeline capacity acquired to serve core gas customers.46 The Commission also held that pre-approval of costs for long-term interstate pipeline capacity is consistent with the electric procurement requirements in Pub. Util Code § 454.5.47 In D.07-12-052, the Commission authorized investor-owned electric utilities to file applications to obtain pre-approval for long-term gas supply contracts for gas-fired generation.48

Today's decision does not address PG&E's recovery of (1) any rate increase on the GTN system that might occur as a result of de-contracting, or (2) any rate increase on the Ruby Pipeline due to FERC actions that might occur under the scenarios raised by GTN that are addressed later in today's decision. These rate increases are unlikely and/or highly speculative for the reasons set forth later in today's decision. However, if such rate increases occur, and PG&E seeks to recover these increases in retail rates, the Commission will decide on the appropriate course of action at that time.

7.7. Core Procurement Incentive Mechanism

7.7.1. Position of the Parties

The Core Procurement Incentive Mechanism (CPIM) is a Commission-approved mechanism designed to encourage cost-effective procurement of gas for core gas customers. The CPIM has been in effect for more than 14 years, and has been modified from time to time to reflect changing circumstances.

Under the CPIM, PG&E's gas costs are compared to a market-based benchmark equal to the weighted average of published monthly and daily natural gas price indices at the points where PG&E buys gas. PG&E gas commodity costs that fall within or below the "tolerance band" of 99% to 102% of the benchmark are considered reasonable per se and are fully recoverable in core gas rates. Customers receive 80% of any savings from costs that are below the tolerance band and pay 50% of any costs that exceed the tolerance band. Any shareholder award is capped at the lower of $25 million or 1.5% of total annual natural gas commodity costs.

Development of the CPIM commodity benchmark begins with forecasted daily demand, including storage injections. The total benchmark load is served first from storage withdrawals during the winter, then from flowing supplies. Currently, a firm block of 200 MDth/d, split evenly from the San Juan Basin and the WCSB, is the first flowing gas sequenced each day. The remaining demand is sequenced between supply basins on a least cost basis. A daily benchmark is calculated by multiplying the sequenced volumes by the associated price indices. This process is repeated for each day of the year. At the end of the annual CPIM period, the daily commodity benchmarks are added together to form the annual aggregate commodity benchmark. Finally, fixed and variable pipeline and storage costs are added to the commodity benchmark to formulate the total annual CPIM benchmark. DRA audits and evaluates the CPIM results annually.

In A.07-12-021, PG&E requests that the Commission, in approving the proposed Ruby Pipeline transportation arrangements, also authorize conforming modifications to the CPIM, to become effective on November 1, 2011, to incorporate the costs of Ruby capacity and Rocky Mountain supplies into the CPIM benchmark. These modifications pertain only to the Core Gas Supply capacity on Ruby (250 MDth/d). Adjusting the CPIM benchmark to accommodate the proposed Ruby capacity would require reducing GTN and Canadian pipeline capacity by 250 MDth/d, adding 250 MDth/d of Ruby into the sequence; and choosing the appropriate gas price index for Rocky Mountain purchases. The specific CPIM modifications are described below.

Ruby Pipeline Transportation Costs

· The transportation benchmark will include a dollar amount equal to the applicable Ruby Pipeline firm transportation reservation charges plus all commodity charges and surcharges in the Ruby Pipeline tariff for service from Opal, Wyoming, to Malin, Oregon.

· The transportation benchmark will be adjusted to reflect a reduction of 250 MDth/d of pipeline capacity from Canada and the addition of 250 MDth/d of Ruby capacity.

Supply Sequencing

· The supply sequencing order will be revised to include three Firm Blocks of 75 MDth/d each instead of two Firm Blocks of 100 MDth/d. These Firm Blocks are deemed to be the first flowing gas sequenced on any given day. The three blocks of gas supplies are from (1) the Rocky Mountain Supply Area; (2) the San Juan Basin; and (3) the AECO "C" hub in Alberta, Canada.

· Following the Firm Blocks, the remaining supplies will be sequenced on a least cost basis determined by monthly gas price indices from the Rocky Mountain Supply Area, San Juan Basin, and AECO "C."

· All remaining commodity sequencing is unchanged.

Commodity Index

· The commodity benchmark will include the "Rocky Mountain, Northwest Pipeline Corp." monthly index as published in Platt's Inside FERC's Gas Market Report, or other appropriate industry standard index agreed to by DRA and PG&E, to reflect gas purchases from the Ruby Pipeline.

All other aspects of CPIM would remain unchanged.

DRA was the only party to respond to PG&E's proposed modifications to the CPIM. DRA supports PG&E's proposal.

7.7.2. Discussion

PG&E's CPIM has been modified periodically to conform to market and regulatory changes. The CPIM modifications requested by PG&E in this proceeding are of a similar conforming nature. There is no opposition to PG&E's proposed modifications to the CPIM. With one exception, we find that the proposed modifications are reasonable, and we hereby adopt them.

The one exception concerns PG&E's proposal to include in the transportation benchmark component of the CPIM what PG&E calls "the applicable Ruby Pipeline firm transportation reservation charges plus all commodity charges and surcharges set forth in the Ruby pipeline tariff for service from Opal, Wyoming, to Malin, Oregon." We will require the transportation benchmark component to reflect the actual firm transportation rates that PG&E pays under the Precedent Agreement, which will be $0.68/Dth or less, plus all tariffed charges for fuel and L&U gas to the extent allowed by the Precedent Agreement. This is because the amount that PG&E is obligated to pay to Ruby LLC is fixed by the Precedent Agreement approved by today's decision. The CPIM benchmark should reflect the amount that PG&E is obligated to pay under the Precedent Agreement, which may be different than the firm transportation reservation charges (and other charges) in Ruby's tariff.

7.8. Environmental Considerations

The Ruby Pipeline will be constructed entirely outside of California. The California Environmental Quality Act (CEQA) does not apply to projects located outside of California that are subject to an environmental impact review under the National Environmental Policy Act (NEPA), with the exception that emissions or discharges that could have a significant impact on California are not exempt from CEQA.49

FERC will be the lead agency for purposes of conducting an environmental review of the Ruby Pipeline project under NEPA.50 FERC will cooperate with other federal and state agencies to develop measures to avoid, minimize, or mitigate the potential environmental impacts of the Ruby Pipeline project. There is no evidence in the record of this proceeding that the Ruby Pipeline may cause significant impacts on California.

For the preceding reasons, it is evident that CEQA does not apply to the proposed Ruby Pipeline. Even so, the Commission may take environmental considerations into account in deciding whether to grant PG&E's application. In order to provide the Commission with a full record, the Scoping Memo instructed the parties to address the following issues:

How do the various alternatives (including the no-project alternative) compare in terms of greenhouse gas emissions and other environmental impacts? Environmental impacts include construction of new right-of-way on previously undisturbed land, fuel consumption, and other effects. This issue does not assume at this time that any environmental assessment by the Commission under CEQA is required in this proceeding[.] (Scoping Memo, p. 5, Issue 3.F.)

7.8.1. Position of the Parties

PG&E provided testimony that shows Ruby will produce lower GHG emissions than other alternatives, including the no-project alternative, primarily because Ruby will use less compressor fuel to transport gas to California.

CARE believes that Ruby will have a lower impact in terms of greenhouse gas (GHG) emissions relative to Sunstone because (1) the Ruby route from Opal to Malin is shorter than the Sunstone-GTN route to Malin, thus requiring less compressor fuel to transport gas to California; (2) Ruby will use more efficient compressors; and (3) Ruby LLC's commitment to minimizing fossil fuel use.

CARE disagrees with GTN's argument that Sunstone is environmentally superior to Ruby because Sunstone can transport gas to the Pacific Northwest to displace coal-fired generation. CARE states the Ruby Pipeline can also transport gas to the Pacific Northwest via backhaul service on GTN.

GTN asserts that Sunstone will create fewer environmental impacts during construction compared to the Ruby Pipeline because Sunstone will be built alongside an existing gas pipeline and, therefore, will use existing corridors and facilities. GTN also contends that Sunstone will result in lower GHG emissions than Ruby. Sunstone is 100 miles shorter than Ruby, which means there will be fewer construction-related emissions. More significantly, Sunstone will allow utilities in the Pacific Northwest to replace coal-fired generation with natural gas. Substituting gas for coal will reduce GHG emissions far more than the small difference in GHG emissions from compressor fuel use on pipelines.

GTN disputes CARE's assertion that GTN can transport gas delivered by Ruby at Malin to the Pacific Northwest using backhaul service. Because the Ruby Pipeline would replace much of GTN's forward haul throughput, there would be no significant potential for backhaul by displacement.

To minimize construction related environmental impacts, Ruby LLC states that it has selected a route that avoids Areas of Critical Environmental Concern, Wilderness Study Areas, Instant Study Areas, and Native American lands. The chosen route also minimizes contact with wild and scenic rivers and other sensitive environmental areas.

Ruby LLC pledges to mitigate 100% of its GHG emissions. Ruby LLC will mitigate GHG emissions during construction by contracting for low-emissions equipment and using bio-diesel to the extent possible. Ruby LLC will offset the balance of GHG emissions during construction by purchasing Voluntary Emissions Reduction (VER) credits. Once operational, Ruby LLC will undertake a portfolio approach to its mitigation efforts. These include the purchase of renewable electric power for compressors where possible, internal pipe coating, re-forestation, Best (methane) Management Practices, application of the US Green Building Council Leadership in Energy and Environmental Design for buildings, and VER credit purchases.

Ruby LLC disputes GTN's claim that Sunstone offers a better means to transport gas from the Rockies to the Pacific Northwest where it can be used to displace coal-fired generation and thereby achieve large reductions in GHG emissions. This assumes that GTN cannot backhaul gas from Malin to the Pacific Northwest. Ruby LLC states that GTN's FERC-approved tariff authorizes GTN to backhaul gas from Malin to the Pacific Northwest.

7.8.2. Discussion

FERC will conduct a detailed environmental review of the proposed Ruby Pipeline under NEPA. Our environmental review in the instant proceeding was limited to identifying, on a preliminary basis, significant environmental issues that might call into question whether PG&E's application should be approved. As noted previously, CEQA does not apply to the Ruby Pipeline because it will be located entirely outside of California, will be subject to an environmental review under NEPA, and there is no evidence in this proceeding that the Ruby Pipeline will have any significant impacts on California.

We are not persuaded by GTN's claim that Sunstone is superior to Ruby in terms of environmental impacts because (1) Sunstone will be constructed in exiting corridors and will use existing facilities, and (2) the gas delivered by Sunstone can be used to offset coal-fired generation serving the Pacific Northwest, thereby producing a substantial reduction to GHG emissions. GTN's claim is pure speculation. There has been no formal environmental review completed by FERC for either the Ruby or Sunstone pipelines. Thus, there is no basis to conclude that the construction of the Ruby Pipeline will have a greater environmental impact than the construction of the Sunstone pipeline. Further, GTN failed to provide a single example of a coal-fired plant that will be replaced by gas-fired generation. In light of growing concerns about climate change, it is possible that if and when coal-fired generation is replaced, it will not be replaced with more fossil fuel generation, but with renewable resources.

Even assuming that new gas-fired generation is built to displace coal-fired generation as GTN asserts, there is no basis to conclude that the Sunstone pipeline will serve this new load. Ruby could serve some of this new load through backhaul on the GTN system, as demonstrated by GTN's FERC-approved tariff for backhaul service.51 Additional gas from the WCSB might also be available to the Pacific Northwest to the extent that Ruby displaces WCSB gas delivered at Malin with gas from the Rocky Mountains.

In its comments on the proposed decision, GTN states that utilities and regulators in the Pacific Northwest at one time had anticipated 1,500 megawatts of new coal-fired generation by 2020, but they now anticipate new gas-fired generation instead.52 For the reasons stated in the two previous paragraph, there is no basis to conclude that the Sunstone pipeline will serve new gas-fired generation that is built in lieu of new coal-fired generation.

For the preceding reasons, we conclude there are no environmental issues that warrant the denial of PG&E's application. We recognize that it is possible that FERC might identify significant environmental issues during its environmental review of the Ruby Pipeline. If that occurs, we will take appropriate actions, as necessary.

7.9. Other Issues Raised by the Parties

GTN and Reid raised several additional arguments opposing PG&E's application. For the reasons set forth below, we find their arguments do not warrant the denial of PG&E's application.

7.9.1. Selection Process

7.9.1.1. Position of the Parties

El Paso approached PG&E in the spring of 2007 to discuss a new pipeline to bring Rocky Mountain gas directly to northern California. Negotiations commenced on June 14, 2007, and concluded with the execution of the Ruby Precedent Agreement on December 20, 2007.

PG&E states that it used a reasonable process to select Ruby over competing pipelines. Before committing to Ruby, PG&E solicited bids from the two competing Rocky Mountains pipeline projects that had approached PG&E. Spectra approached PG&E about the Bronco project in the fall of 2007, and GTN approached PG&E about the Sunstone project in December 2007. PG&E provided to them a written "Rockies Pipeline Project Framework" that identified the key terms that PG&E wanted based on what PG&E had already negotiated with Ruby LLC, but left blank the proposed rates. PG&E represents that it informed Spectra and GTN that each needed to give its best offer.

Bronco and Sunstone provided written responses to PG&E's Framework on December 17, 2007. Bronco offered to meet all of the key terms, but proposed a fixed rate of $0.80/Dth. PG&E represents that Sunstone was not willing to meet the key terms and proposed a fixed rate of $0.835/Dth. In light of these offers, PG&E concluded that neither project was competitive with the fixed rate of $0.68/Dth offered by Ruby LLC, and that Sunstone was not competitive on the other key terms.

In response to criticisms from GTN and Reid that PG&E should have used a request for offers (RFO) process, PG&E states that it knows of no instance where a prospective shipper has issued an RFO for a new interstate pipeline. PG&E even contacted several pipeline companies, including Kern River, Spectra, and El Paso, to get their views on the feasibility of an RFO prior to ruling out this option. According to PG&E, the general practice is for pipeline developers to solicit customers and not the other way around. To this end, FERC requires the developers of new interstate pipelines to hold an open season for prospective shippers to make offers for portions of the pipeline capacity.

CARE believes that PG&E acted properly in signing the Precedent Agreement without an RFO.

DRA states that D.04-09-022 specifies the procedures that gas utilities must use to obtain Commission approval for interstate pipeline capacity. That decision did not require an RFO process. DRA says the typical process for acquiring capacity on a new interstate pipeline is through direct negotiations or an open season held by the pipeline. DRA emphasizes that no party offered any examples of utilities obtaining capacity on a new pipeline through an RFO process or any evidence that an RFO process would have benefited ratepayers.

DRA opposes Reid's recommendation, described below, to henceforth require PG&E to conduct an RFO when acquiring pipeline capacity, and that PG&E retain an Independent Evaluator to ensure the RFO is fair to all participants. DRA states the Ruby agreement is a very good deal for ratepayers, and that Reid is attempting to fix something that is not broken.

GTN contends that utilities are required to use an open, transparent, and competitive process to obtain large increments of interstate pipeline capacity. Specifically, Pub. Util. Code § 454.5 requires electric utilities to use a competitive process to acquire new electric resources and for the Commission to specify "criteria to insure that the auction process is open and adequately subscribed."

Similarly, in D.04-09-022 the Commission announced that it would "consider the alternatives available to the utilities when deciding whether...to pre-approve their new [pipeline capacity] contracts.53" In the same proceeding, the Commission required PG&E to use a competitive process to obtain gas storage services, and PG&E subsequently issued an RFO for storage services. The RFO was successful, and in approving the contracts the Commission observed that "RFOs have been sanctioned for use by the Commission in a variety of different contexts...to minimize...procurement costs.54"

GTN stresses that it is not arguing that the Commission has mandated the use of RFOs exclusively; rather, it requires utilities to use an open, competitive, and transparent process. Thus, even if PG&E is correct that an RFO would not work, PG&E could have used another competitive process in which the participants knew they were competing, for how much, with a reasonable period to respond, and with an opportunity to negotiate.

GTN states that PG&E did not use an open and fair competitive procurement process. Rather, PG&E held secret negotiations with El Paso and had agreed on all substantive terms by mid-October 2007. To create the appearance of competition, PG&E used a "Framework" to request bids from the Sunstone and Bronco pipelines. PG&E requested the bids on Thursday, December 13, 2007, and required a response by 8 a.m., Monday, December 17.

Sunstone-GTN was able to submit a timely "first offer" on December 17. To GTN's dismay, PG&E rejected the offer 24 hours later, on December 18. El Paso signed the Precedent Agreement on December 19, and PG&E signed the Agreement on December 20. The following day, December 21, 2007, PG&E filed A.07-12-021 for authority to contract with the Ruby Pipeline. Thus, from the time GTN was provided the Framework proposal by PG&E, to the actual filing of a fully-detailed application, was one week. Any analysis of the Sunstone-GTN offer by PG&E lasted less than one day, even though hundreds of millions of ratepayers dollars were at stake.

GTN states that it had no idea that PG&E and El Paso had been negotiating for months, and that PG&E was on the verge of executing a binding commitment for the Ruby Pipeline. GTN intimates that Sunstone-GTN might have responded differently to PG&E's Framework proposal had they known the circumstances. Regardless, Sunstone-GTN were denied the same opportunity to compete as Ruby LLC. Thus, PG&E failed to conduct a fair procurement process for the benefit of its ratepayers who are being asked to assume all costs and risks.

Reid argues that PG&E's pipeline selection process was unfair to companies other than Ruby LLC, which effectively denied ratepayers the benefits of competition. PG&E did not seriously consider competitors to Ruby until December 14, 2007, when PG&E solicited proposals from two other pipeline companies. The terms of the two bids were based on what PG&E had already negotiated with Ruby LLC, giving Ruby a distinct advantage. Reid doubts that PG&E intended to seriously consider these two bids, as PG&E's senior executives had previously approved the Ruby Precedent Agreement on November 14, 2007. To ensure a fair process in the future, Reid recommends that the Commission:

1. Require PG&E to conduct an RFO when acquiring pipeline capacity for a contract term of more than three years or a quantity of more than 100 million cubic feet per day (Mcf/d).

2. Order PG&E to retain an Independent Evaluator to ensure that the above mentioned RFO is fair to all participants.

Ruby LLC states that if PG&E had held a RFO, it would have allowed Ruby's competitors an unfair chance to catch up and to learn of the essential terms of its negotiations with PG&E. Ruby LLC would no longer have been the first mover and, therefore, would have been less inclined to agree to the many terms of the Precedent Agreement that are favorable to PG&E.

TURN believes that PG&E acted properly by focusing on the Ruby Pipeline and foregoing the RFO process. TURN states the RFO model works well for electric generation where PG&E is typically seeks an amount of new generation capacity that exceeds the capacity of any single project. In that situation, the utility can contract for the full capacity of a new generator.

In contrast, PG&E represented only a fraction of the total capacity needed to support a new interstate pipeline to the Rockies. In that situation, the pipeline developer needs to secure commitments from other shippers in order for the project to succeed. In light of these circumstances, it would have made no sense for PG&E to conduct its own RFO.

TURN opines that it would have been unfair to El Paso, which had displayed considerable entrepreneurship in conceiving, marketing, and developing the Ruby project, to impose an ad hoc "competitive process" to allow slower-moving competitors to catch up. Such an approach would guarantee that no one in the future would pursue efforts similar to Ruby's here, because the reward for such initiative would be removed.

7.9.1.2. Discussion

As a general principle, utilities should use an open and competitive process to procure resources. Such a process is most likely to result in the lowest cost and the best terms and conditions for utilities. The process used by PG&E to acquire Ruby Pipeline capacity was clearly not a paragon of an open and competitive process. The question before us is whether the process used by PG&E was reasonable under the circumstances.

We conclude that the process used by PG&E was reasonable. As noted by DRA, PG&E, Ruby LLC, and TURN, the usual industry practice is for the developer of an interstate pipeline to solicit customers for its project through bilateral negotiations and an open season held under FERC rules. This is exactly what El Paso did with its Ruby project. The process used by PG&E - bilateral negotiations with El Paso - was consistent with industry practice.

We agree with PG&E, Ruby LLC, and TURN that it would have made no sense for PG&E to issue an RFO when PG&E represented only a fraction of the capacity needed to fill a new interstate pipeline. The fallacy of the RFO approach is borne out empirically. Witnesses for PG&E, Ruby LLC, and GTN all testified that they do not know of one instance of a pipeline customer issuing a successful RFO for a greenfield pipeline.55 As Ruby's witness Thomas Price testified:

[T[here are times when an RFO makes sense, and there are times when it does not. I have never seen an RFO used in a greenfield project where a shipper is only a proportion or a partial revenue contributor to the project. For a project of the scope of Ruby to be viable, it needs broad customer support. This is a $3 billion project. PG&E's contribution, revenue contribution, is under 20 percent of what we need to make it economically viable. (6 TR 601-602.)

We recognize that PG&E had an opportunity to negotiate with two competing pipelines, but that PG&E did not pursue this opportunity vigorously. PG&E provided these two competitors only three days to respond to PG&E's Framework proposal, and PG&E rejected their bids within 24 hours. This was a very abbreviated process compared to the months that PG&E spent negotiating with Ruby LLC. GTN and Reid argue that the fact that PG&E did not spend more time and effort on the opportunity presented by these two pipelines leaves some room for doubt about whether the Ruby deal is the best deal.

These doubts are hypothetical, however. The weight of the evidence demonstrates the Ruby Pipeline is a better alternative for accessing Rocky Mountain gas supplies than the two closest competitors - the proposed Bronco and Sunstone pipelines. PG&E used a competitive process of sorts when it invited Bronco and Sunstone to submit bids with all the same terms and conditions as the Ruby Precedent Agreement except price.56 This provided an apples-to-apples comparison of the Ruby Pipeline to its competitors. PG&E informed the two competitors that they needed to respond to PG&E's invitation with their best offer.57 Bronco and Sunstone were unable to match Ruby's price, and Sunstone was unwilling to match the other favorable terms of the Ruby Precedent Agreement. Although GTN claims that Sunstone can beat the Ruby deal if only PG&E would negotiate, this appears to be empty rhetoric. Sunstone had a chance to beat the Ruby deal in December 2007, but did not. Since then, Sunstone could have offered a better deal at any time, but has not. There is no evidence besides GTN's general statements that PG&E could have reached a better deal if it had used a different competitive process.

In its comments on the proposed decision, GTN states that while Sunstone could send a written offer to PG&E at any time, there is no point in doing so. PG&E has no incentive to negotiate with Sunstone, according to GTN, because PG&E faces financial penalties under the Ruby Precedent Agreement if PG&E's actions undermine or delay the Ruby Pipeline project.58 We see no reason why PG&E's predicament should prevent Sunstone from submitting a better offer. If anything, submitting a better offer would help GTN to achieve its primary goal in this proceeding of having the Commission deny A.07-12-021 by providing the Commission with a strong justification for doing so.

GTN argues that PG&E had a duty to give Sunstone an opportunity to meet or beat Ruby's offer. We find that PG&E did provide an opportunity for the previously stated reasons. Moreover, the proposed Ruby project was presented to PG&E in early 2007, while GTN and Williams did not form a partnership to pursue the Sunstone project until November 2007, 59 and did not approach PG&E until December 2007.60 It would be contrary to ratepayer interests if PG&E had to wait for competitors to emerge in order to pursue opportunities that present themselves, as was the case here.

The evidence shows that PG&E obtained the best available price for capacity on the Ruby Pipeline among similarly situated shippers. The Precedent Agreement guarantees that PG&E will receive the lower of (1) $0.68/Dth, (2) the initial Recourse Rate less 5%, or (3) any lower rate offered to a similarly situated shipper. The Agreement also provides PG&E with term-extension rights and the option to reduce contract capacity over the final five years of the contract term. None of Ruby's competitors have offered equal or better terms to PG&E.

Whatever the shortcomings of the competitive process used by PG&E, we are confident that a better deal is not available from either Ruby or competitors. The two parties in this proceeding representing ratepayer interests - DRA and TURN - agree that PG&E has struck a good bargain. The following statement by TURN provides a fair summary of the situation at hand:

[T]he Ruby agreement has come to represent not just a "good deal" but a "great deal" for PG&E's ratepayers...PG&E will obtain firm pipeline capacity of 375 MDth/d from the rapidly expanding Rocky Mountain gas producing area to Malin...at a fixed rate of 68 cents per Dth. This attractive price has remained in place despite projected cost increases for the project of roughly 50% (from $2 billion at the time of the application to $3 billion at the time of the hearings)...[N]on-anchor tenant customers of Ruby will be paying 95 cents per Dth, almost 40% more than PG&E's anchor tenant rate under the precedent agreement (5 TR 579: 11-15). Clearly PG&E has obtained an excellent bargain for its ratepayers. (TURN Opening Brief, pp. 1 - 2. Citation in original.)

GTN cites Pub. Util. Code § 454.5 and several Commission decisions as requiring PG&E to hold an open, transparent, and competitive process for acquiring large increments of long-term interstate pipeline capacity. However, nothing cited by GTN specifies exactly what process should be used.61 We find for the previously stated reasons that the competitive process used by PG&E was reasonable under the circumstances.

We decline to adopt Reid's proposals to require PG&E to use an RFO process to acquire interstate pipeline capacity contracts for a term longer than three years or for capacity larger than 100 Mcf/d. We disagree with the premise of Reid's proposal, namely, that the process used by PG&E was fatally flawed. Because the process used by PG&E was reasonable under the circumstances, we see no need to adopt the corrective measures proposed by Reid.

7.9.2. Let the Market Decide

7.9.2.1. Position of the Parties

3 2008 California Gas Report, p. 51. We take official notice of the 2008 California Gas Report pursuant to Rule 13.9 of the Commission's Rules of Practice and Procedure.

4 Exhibit PG&E-3, pp. 2-4 to 2-5.

5 Exhibit Ruby-1, pp. 1 - 3.

6 Exhibit GTN-2, p. 8, lines 13-15.

7 Exhibit PG&E-3, p. 2-1, lines 11-12, and p. 2-3, lines 26-32.

8 Exhibit Ruby-1, pp. 1 - 2.

9 D.04-09-022, Findings of Fact 1 and 8.

10 D.06-09-039, p. 31.

11 Instead of reducing the amount of gas-fired generation, it is possible that utilities and regulators may decide to purchase the emissions credits needed for gas-fired generation under a cap-and-trade regime.

12 It is possible that demand for natural gas could increase if natural gas is used to replace gasoline as a transportation fuel, either directly in compressed natural gas vehicles or indirectly through plug-in hybrids and all-electric vehicles. Under this scenario, it is even more important to obtain increased access to Rocky Mountain gas supplies to offset declining supplies in the WCSB.

13 D.04-09-022, Finding of Fact 1.

14 Exhibit PG&E-3, p. 5-8.

15 The Ruby capacity for Core Gas Supply fits within the Commission-established capacity range for PG&E set forth in D.04-09-022, Findings of Fact 23 and 24.

16 Reid Opening Brief, pp. 10 - 12.

17 Exhibit PG&E-5, pp. 5-6 to 5-9.

18 PG&E also manages a California Department of Water Resources purchased power agreement (PPA) with PPM Energy that supplies power to PG&E. The PPA includes 51.8 MDth/d of capacity on the GTN pipeline and expires on June 30, 2011.

19 D.06-09-039, Finding of Fact 37.

20 Exhibit PG&E-4, pp. 3 - 8.

21 Exhibit PG&E-4, pp. 3 and 8.

22 Exhibit PG&E-3, Chapter 6, p. 6-11, lines 13-16. Ruby LLC separately estimated that the benefits of competition would be in the range of $0.08 to $0.12/Dth. (Exhibit Ruby-1, p. 3, lines 12-18.)

23 The forecasted net benefits do not include the additional benefits of enhanced supply security, improved physical reliability, and increased price stability that comes from holding interstate pipeline capacity across multiple supply regions.

24 Exhibit PG&E-5, pp. 1-3 and 1-4.

25 Exhibit Ruby-21, p. 10, lines 8-14.

26 Sunstone-GTN estimated that it would charge a fuel rate equal to 1.69% of volume shipped on the Opal to Malin route (Exhibit PG&E-5, p. 106), which is higher than the currently estimated Ruby Pipeline fuel rate of 1.1%. (6 TR 617:3-7.)

27 Exhibit Ruby-26, the 13th slide ("Sharing the Load"); and GTN Opening Brief, p. 26.

28 PG&E estimates that increased gas-on-gas competition at Malin will reduce prices by $.10/Dth over the initial 15-year term of the PG&E-Ruby agreement. (Exhibit PG&E-3, p. 6-11, lines 13-16.) Ruby LLC's estimate is $.08 to $.12/Dth. (Exhibit Ruby-1, p. 3, lines 12-18.) These projected savings equate to hundreds of millions of dollars over the term of the PG&E-Ruby agreement. (Exhibit PG&E-3, p. 6-11, lines 18-26.)

29 7 TR 731: 23 - 732: 9, and 7 TR 806: 6-14 (GTN/Ferron-Jones).

30 We address elsewhere in today's decision GTN's claim that it may retire capacity if Ruby is selected over Sunstone.

31 A pipeline from Alaska may not enter service until 2020. (PG&E Reference Item 15.)

32 This is the "straight-fixed variable" rate.

33 $13,364,250 = 125,000 Dth x $8.9095/Dth/month x 12 months.

34 The 400 MDth/d does not include certain firm capacity held by PG&E's Core Gas Supply and other entities.

35 The Electric Fuels Department can use its firm capacity on the Redwood Path to transport gas received from both the GTN system and the Ruby Pipeline.

36 4 TR 367: 20-28.

37 We take official notice of Tariff Schedule G-AFT pursuant to Rule 13.9.

38 Tariff Schedule G-AFT states: "To arrange for the further transportation and delivery of natural gas to an Off-System Delivery Point, one of the following additional rate schedules must be utilized: G-AFTOFF, G-AAOFF, G-NFTOFF or G-NAAOFF."

39 D.04-09-022, pp. 24 - 25.

40 The maximum amount that PG&E may recover is $93,075,000 (375 MDth/d x $0.68/Dth x 365 days). This amount will be slightly higher in years with 366 days.

41 We recognize that any declaration submitted by PG&E will necessarily rely on information that PG&E receives from Ruby pursuant to the Most Favored Nation Rights in 3(v) of the Precedent Agreement.

42 Section (b)(iii) states, in relevant part, as follows: "Fuel and [Lost & Unaccounted (L&U)] Surcharges; Usage/Reservation Charges. In addition to the negotiated rate, Shipper shall pay those applicable fuel and L&U surcharges...approved by the FERC...Shipper shall also pay [the Annual Change Adjustment], and all other surcharges applicable to transportation on the Ruby Pipeline under the Tariff. The Anchor Shipper Negotiated Rate shall not include any commodity or usage charge, unless Transporter is required by FERC to assess such a commodity charge, in which case the commodity charge shall be set at the minimum permissible level and the reservation rate described in Section 3(b)(ii) shall be reduced to a level that cause the combined commodity and reservations rates to equal 100% of load factor rate of the bid amount."

43 For example, under existing rules, if PG&E's Core Gas Supply decides to exercise a contract quantity step-down provision in a previously approved contract, PG&E would recommend to DRA and TURN to reduce its existing contract quantity, along with a corresponding replacement by other capacity. If PG&E receives their concurrence, PG&E would then seek the Commission's approval of the replacement contract. The Commission's approval of the replacement contract has the effect of ratifying PG&E's decision to step down capacity under the original contract. If this procedure remains in place, PG&E may use it to obtain the Commission's approval for Core Gas Supply's decision to step down its Ruby Pipeline capacity.

44 For example, if PG&E decides to extend the Ruby Precedent Agreement via its evergreen right, PG&E may do so under the contract approval procedures applicable at that time, including any expedited advice letter approval process for contracts that meet the criteria for such treatment.

45 Electric Fuels' step down capacity is 25 MDth/d in Year 11, 50 MDth/d in Year 12, 75 MDth/d in Year 13, 100 MDth/d in Year 14, and 125 MDth/d in Year 15.

46 D.04-09-022, pp. 24 - 25.

47 D.04-09-022, p. 24 and Finding of Fact 8.

48 D.07-12-052, Conclusion of Law 41.

49 Cal. Pub. Res. Code § 21080(b)(14) and Cal. Code Regs., Title 14, § 15277.

50 The Natural Gas Act, 15 U.S.C. § 717n(b)(1) (2008), designates FERC as lead agency for the purposes of complying with NEPA.

51 There little evidence to support GTN's claim that backhaul is infeasible, since GTN has not analyzed the viability of backhauls from Malin if the Ruby Pipeline is built. (Exhibit PG&E-16.) On the other hand, the available evidence indicates that, with facility modifications, GTN's system could flow gas in both directions, as shown by the flow reversal modifications on GTN's affiliated North Baja Pipeline. (Exhibit Ruby-30; 7 Tr. 754-55.) The record also indicates that GTN will continue to have backhaul capability, even after PG&E steps down its capacity in 2011, due to the fact that GTN will continue to have numerous forward haul contracts, including some with PG&E and other shippers that deliver to Malin. (Exhibit Ruby-29.)

52 GTN Opening Comments, pp. 19 - 20, citing Exhibit GTN-6, pp. 8, 10, and 11.

53 D.04-09-022, p. 22.

54 Resolution G-3398, p. 11.

55 Exhibit PG&E-6, p. 1-5, lines 7-13; 6 RT 601:16-22 (Ruby LLC /Price); 6 RT 653-654 (GTN/Carpenter); and GTN Opening Brief, p. 1. It is telling that the Sunstone Pipeline has not received an RFO from any potential shipper for new capacity to the Rocky Mountains. (Exhibit PG&E-17 and 7 TR 794: 3-9, GTN/Ferron-Jones.)

56 GTN's comments on the proposed decision note that the "framework proposal" which PG&E gave to the two competitors included a provision that placed PG&E at risk for pipeline construction cost overruns in excess of 10%. (GTN Opening Comments, Fn. 93, citing GTN Exhibit 9, pp. 38 - 39.) This provision should have encouraged the two competitors to bid their lowest possible prices.

57 PG&E informed GTN and Spectra that they needed to respond with "their best offer" and that there was "no time for protracted, extended discussions." (1 TR 79:10 - 80:11 and 1 TR 83:19 - 25.)

58 GTN Opening Comments, p. 16, citing Exhibit GTN-4, Attachment 4.

59 7 TR 735: 21-23.

60 1 TR 75: 24 - 76: 1.

61 D.07-12-052 deferred to an unspecified future proceeding the topic of electric utilities' procurement of firm interstate pipeline capacity. Until then, D.07-12-052 directed electric utilities to file applications to obtain approval for proposed long-term interstate pipeline contracts. (D.07-12-052, pp. 179 - 180.) In D.04-09-022, the Commission held that gas utilities should use the procedures set forth in that Decision to obtain approval, or pre-approval, of long-term interstate pipeline capacity contracts, but D.04-09-022 did not specify the nature of the competitive process that should be used to acquire long-term capacity. (D.04-09-022, pp. 24 - 25.)

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