Alberta straddle plants could process Alaskan gas

Dec. 23, 2002
For many years, the economics of NGL recovery at Alberta's straddle plants have generally ensured that the higher heating value and hydrocarbon dew point met gas-pipeline-quality specifications. Higher gas prices, however, have squeezed margins on NGL recovery.

For many years, the economics of NGL recovery at Alberta's straddle plants have generally ensured that the higher heating value and hydrocarbon dew point met gas-pipeline-quality specifications. Higher gas prices, however, have squeezed margins on NGL recovery.

In recent years, operators have become concerned about increasing levels of CO2– in Alberta's gas pipe- lines. The presence of such contaminants complicates ethane recovery, and a recent Alberta regulatory decision discusses the impact of and mitigation measures for the increasing CO2– levels in the Alberta gas pipelines.1

The volume of gas available for processing at Empress has diminished because of nonrenewals of firm capacity on the system operated by TransCanada PipeLines Ltd.,2 but there is the possibility of processing Canadian gas from the Mackenzie Delta or some Alaskan gas for NGL recovery at Alberta's straddle plants.

Click here to enlarge image

Table 1 shows the capacity of the Empress straddle plants.

Last week's Part 1 of this four-part series presented an historical perspective on the straddle plants. This second article focuses on what lies ahead for these straddle plants.

Straddle plant NGL recovery

Total Alberta raw gas volumes include transfers from British Columbia, and Alberta raw gas transfers to British Columbia. Table 1 shows a forecast of total raw and marketable Alberta gas production and the corresponding gas flows at the Empress straddle plants.

Click here to enlarge image

The Empress gas volume is likely to drop to slightly more than 7 bcfd in 2005. These volumes are well below the 9.8-bcfd capacity of the Empress plants shown in Table 2, and therefore there may be some rationalization of the Empress capacity.

As noted in Part 1, margins for NGL recovery at the Alberta straddle plants have narrowed over the last 2 years. Several of the straddle-plant ethane sales contracts to Alberta's petrochemical industry face renegotiation by mid-2004.

This renegotiation will be important to satisfactory cost recovery and return on investment at these straddle plants.

Implications of gas pricing

Escalation of gas prices is generally a windfall for most gas producers. For midstream operations, however, gas is the major cost factor that can profoundly affect their viability. A significant range in the gas-price outlook creates uncertainty for the processor and means that margins can fluctuate dramatically.

Part 1 showed that Alberta ethane prices were historically based on payment for shrinkage value plus a fee or margin to cover processing (recovery and fractionation) and transportation costs.

The Alberta straddle plants have experienced a difficult period of weak NGL prices and high shrinkage and fuel costs. Weak NGL prices have been largely the result of weather and depressed economic activity.

These prices should strengthen relative to crude with economic recovery and a rebound in petrochemical production.

Moreover, proposals by TransCanada PipeLines would increase the toll for interruptible transportation, which would likely widen the basis differentials.2 If these tolls are adopted, the result could be lower gas prices in Alberta and improved processing margins.

In addition, Alberta's electricity prices have escalated, and the straddle plants with electric-driven recompression have experienced unanticipated increases in operating costs. In the future, Alberta ethane pricing will likely have escalators for electricity costs.

Frontier gas NGL

There are plans to connect gas production in the Alaskan North Slope (ANS) with markets in the Lower 48 and to develop gas resources in Canada's far north Mackenzie Delta region. There may also be an opportunity to process gas from Mackenzie Delta and some of the Alaskan gas in Alberta's straddle plants.

At this point it is unclear whether the ultimate cost of the existing pipelines leaving the Western Canadian Sedimentary Basin (WCSB) will offer an attractive package for Alaskan gas producers in terms of transportation costs.

Recovering the ethane and NGL from Alaskan gas in Alberta would make sense to the extent that the Alaskan gas is scheduled to move in existing gas pipelines from the WCSB.

For Alaskan gas, the butane and natural gasoline spiked (or blended) into ANS crude oil during 2000 were 41,000 b/d and 55,000 b/d, respectively.3 The propane available in ANS gas may exceed 100,000 b/d. The NGL constituents of ANS gas may primarily be ethane and propane. Alaskan policy relating to NGL recovery may favor removal of the NGL prior to the gas reaching Alberta.

The Mackenzie Delta gas producers have considered processing their gas at Norman Wells, NWT, for C3+ recovery and then transporting the C3+ NGL through an existing crude oil pipeline. Any incremental volumes of C3+ NGL recovered at Norman Wells would allow the fixed costs on the crude oil pipeline system to be allocated to a larger volume, thereby reducing unit costs.

Alaskan gas propane recovery

The potential propane supply from ANS gas is large. Fig. 1 shows the Petroleum Administration Defense District on the US West Coast (PADD V) propane demand in 2000 was 65,000 b/d, and local supply met 84% of that demand on an average annual basis.3

Click here to enlarge image

This means that the US West Coast propane market is small, and any propane recovery from Alaskan gas at Valdez, Alas., or another location such as Fairbanks in excess of this PADD V demand would have to be exported.

For this reason, there may not be a strong market or economic driver to favor propane recovery in Alaska from ANS natural gas.

Click here to enlarge image

In contrast to PADD V, the propane market in PADD I (Florida to Maine) was 202,000 b/d in 2000, and only 20% of this demand was met by local supply (Fig. 2).3 The deficiency is filled from marine imports (15,000-25,000 b/d), imports from Canada (8,000-16,000 b/d), and pipeline transfers from PADD II (US Midwest including Oklahoma) or PADD III (New Mexico to Alabama including Texas; 125,000-140,000 b/d).

For this reason, PADD I may have a more urgent need for the propane recovered from Alaskan gas. The delivery of Alaskan propane to PADD I would enhance homeland security.

Although it may not be widely appreciated, one of the advantages that Alliance Pipeline and Aux Sable Liquid Products exploited was that the Alliance connections with existing pipelines in the Chicago area required gas pressure be reduced to the operating pressure of the connecting pipelines.

In effect, the pressure drop at Joliet was going to happen anyway; therefore, the Aux Sable plant did not have to recompress the gas leaving it to the Alliance operating pressure of 1,740 psi.

If Alaskan gas moves through Alberta in a high-pressure line, the economics and market considerations may favor leaving the NGL in the gas until it reaches a US market center with underground storage, pipeline, and market access.

One possible justification to process Alaskan gas for NGL recovery in Alberta is the Alberta NGL infrastructure, which can store propane and butane during the summer season and provide seasonal delivery.

Since a portion of the US market is already served by Canadian propane and butane,3 any additional propane recovered from Alaskan gas would require an expanded market and expanded pipeline infrastructure.

Alberta has a robust market for pentanes plus or natural gasoline for use as a heavy-oil diluent (OGJ, Oct. 28, 2002, p. 64). Although the natural gasoline recovered on the North Slope is currently spiked into the ANS crude oil, it is possible that the pentanes stream may have a higher value in Alberta.

If that happens, the owners of the Alberta straddle plants and other stakeholders in the recovery of ethane and NGL in Alberta, should give careful consideration on how to make the case for processing Alaskan gas in Alberta for ethane and NGL recovery.

Ethane recovery from Alaskan gas

An Alaska-Alberta hub might create a visible market and price of gas in Alberta. The business decision on processing Alaskan gas in Alberta would likely hinge on adding value to both the gas and NGL streams.

The volume of Alaskan gas offloaded at an Alberta hub would depend on the spare capacity in the existing outbound gas pipelines leaving the WCSB and the tolls on these gas pipeline systems compared to any new high-pressure system.

Historically, Alberta's petrochemical industry has paid no significant upgrade for ethane constituents other than as processing fee for investment in ethane recovery or ethane infrastructure. From an ethane perspective, the Alaskan gas producer may not see any upgrade from allowing the existing Alberta straddle plants to process Alaskan gas for ethane and NGL recovery.

It may be possible to develop petrochemical operations in Alaska. World-scale ethylene plants based on ethane feedstock appear to be sized in the 2-3 billion lb/year range, and this means that substantial investment in ethylene, ethylene-derivative plants, and ethane infrastructure would be required to create an Alaskan petrochemical industry.

Such ethylene plants would have ethane feedstock requirements in the range of 60,000-90,000 b/d. That is large, but may be significantly less than the ethane contained in 4 bcfd of Alaskan gas.

While there would be substantial lead time to develop an Alaskan petrochemical industry, there likely will also be a substantial lead time to develop the Alaskan gas pipeline.

To date, there has been a vigorous debate on Alaskan gas pipeline routing, but this debate could expand to encompass industrial development.

After Alaska, the next closest market for ethane is Alberta, where the existing ethylene plants can be debottlenecked to take about 300,000 b/d of ethane.3

On the market side, there is no significant market for ethane in either US PADD V or PADD I. While there is a 50,000-b/d market for ethane in Illinois and Iowa,3 these plants can receive ethane from the Midcontinent fractionators, Aux Sable, or from Canada.

Click here to enlarge image

Fig. 3 shows that the US PADD III ethane demand has exceeded 700,000 b/d.3 This market is more distant than Alberta. While the PADD III market may offer a higher value for ethane, there will be higher transportation costs in reaching this market, and ethane will face competition from other feedstocks.

Given the volume of ethane potentially available from ANS gas, there should be economies of scale for new ethane pipeline infrastructure to move any ANS ethane to the US Gulf Coast.

Potential acquisitions

With the announced sale of Williams Cos.' Canada midstream assets,4 there are now substantial Canadian processing assets on the market. The Williams Canada midstream assets include ownership of the Cochrane straddle plant and interests in the BP Canada Energy Empress complex (Trains 2 and 3), and the Redwater, Alta., fractionator (OGJ, Oct. 7, 2002, p. 54).

The commercial arrangements for the straddle plants generally have a merchant exposure to ethane and propane plus markets, which are subject to term contracts.

The ethane contracts likely reflect recovery of shrinkage costs and a processing fee. The basis for the processing fee may not reflect full recovery of operating costs particularly with regard to electricity costs.

The owners may also have assumed some of the throughput risks. In terms of the propane plus, these arrangements are generally market responsive. Because some of the ethane sales to the Alberta petrochemical industry are to be renegotiated by mid-2004, there may be some upside in these renegotiations.

Depending on Alberta gas prices, the Alberta petrochemical industry may not have much flexibility to pay higher prices for ethane feedstock.

Since 1998, several factors have affected or will affect the operation and economics of the Alberta straddle plants, and particularly, the Empress straddle plants.

First, the basis differential between US and Alberta gas prices has narrowed (see Part 1). Second, the expansion of gas pipeline capacity and the nonrenewals of TransCanada firm capacity have reduced the volume of gas available for processing at the Empress straddle plants.

Third, the Alliance Pipeline volumetric toll favors receipts of relatively high-btu gas, which has modestly reduced the ethane and propane-plus content in the inlet gas at the Empress straddle plants.

The new Alberta gas-royalty system values gas streams based on constituents. This may provide an incentive to recover the liquefiable constituents at field plants. The new Alberta royalty regime could therefore adversely affect the straddle plants.

While these straddle plants are substantial entities, the market risk associated with the commercial arrangements may diminish the market value of these assets and the scope of interest from prospective buyers.

If gas prices decline when substantial volumes of Alaskan gas reach market in the Lower 48, there will be an opportunity to participate in the processing upgrade on NGL recovery.

Prospective buyers of straddle plant assets should be careful in their due diligence, so that they properly understand the opportunity, the revenue and margin outlook, the cost structure, and the volume and capacity utilization risk.

References

  1. "Nova Gas Transmission Ltd. Gas Transportation Tariff Carbon Dioxide (CO2–) Gas Quality Requirements Phase II CO2– Management Service and Tariff Amendments," Alberta Energy and Utilities Board Decision 2002-084, Sept. 24, 2002.
  2. "Application by TransCanada PipeLines pursuant to Part IV of the Act for approval of 2003 tolls," September 2002.
  3. Hawkins Gas Consultants, "LPG Outlook 2002," multiclient study, July 2002.
  4. "Williams Considers Selling its Western Canada Assets," Williams Cos. press release, July 25, 2002.