Porter Bennett, E. Russell Braziel, Jim Simpson, Bentek Energy LLC, Golden, Colo.
Kinder Morgan’s Rockies Express Pipeline needs capacity downstream from its Clarington, Ohio, terminus to expand before it can fully address growing demand in the Northeast. The availability of new takeaway capacity from projects such as those announced by Tennessee Gas and TETCO will be a key factor determining whether REX will serve Northeast demand with incremental supply or will simply displace gulf coast supplies currently serving that market.
REX’s capacity constraints at the east end of the system and their eventual resolution will add to the uncertainty surrounding flow displacements, supply-demand shifts, and regional pricing adjustments brought about by REX. Rockies prices will rise significantly relative to other producing basins. If the east end of REX is constrained, additional demand does not emerge to mitigate the displacement of supplies back into the gulf, and if net incremental production continues to add to gulf supplies, it is not unreasonable to expect that Rockies prices could even trade at a premium to gulf prices.
The first article of this series examined the background of the REX pipeline project and analyzed the effect on US natural gas markets of REX Phases I and II.
This concluding article will detail the market shifts expected as a result of the combination of REX Phase III’s completion and downstream capacity constraints.
Capacity bottlenecks
Capacity of the receiving pipelines will profoundly affect Rockies Express Pipeline Phase IIIa flows. At Lebanon, Ohio, constraints will limit the ability of customers east of REX to obtain incremental supplies from it without displacing gas from other areas. The extension to Clarington in Phase IIIb will provide access to available capacity on Dominion Transmission, TETCO, and Tennessee Gas Pipeline, but constraints east of Clarington, in Pennsylvania, New York, and New Jersey will limit shippers’ ability to use REX as an incremental supply source on peak days, particularly during the winter months.
Lebanon
When Phase IIIa is operational, shippers will be able to deliver 1.8 bcfd to Lebanon (Fig. 1). Vectren and Cincinnati Gas & Electric will be able to receive gas directly from REX. Unless they have incremental demand, however, a reduction in receipts from one or more of these companies’ traditional suppliers must offset receipts from REX.
Fig. 2 shows that Columbia Gas Transmission and Dominion are already constrained at Lebanon, particularly during heating season.
Dominion had available capacity during the 2006-07 heating season because of warm weather in December and early January and high levels of gas in storage. For these reasons, Dominion needed less gas from nonlocal supply areas.
Affiliated local distribution companies act as primary markets for both Columbia and Dominion. Flow data suggest that Columbia Gas of Ohio has experienced a roughly 10%/year (25 MMcfd) decline in sales and transport volumes since 2004. Dominion-affiliated East Ohio Gas, experienced similar declines in 2006 compared to 2005 (19 MMcfd).
Rising Appalachian production may have offset some of the decline, but some appears to be due to declining demand. Either way, without increased demand from Dominion or Columbia’s affiliated utilities, incremental volumes received by these pipelines at Lebanon must flow through either to storage facilities or customers east of Clarington.
TETCO-Clarington
Pipeline capacity east of Clarington is similarly constrained. Fig. 3 illustrates TETCO’s situation.
TETCO has two lines in Ohio: the Lebanon line and the mainline. The Lebanon line originates in East Texas and gains capacity and supply at Lebanon. It flows through the Sarahsville compressor and then turns south where it connects with the mainline. The mainline originates in South Texas and Louisiana, runs north through Kentucky, through the Athens compressor and then merges with the Lebanon line before moving east toward the Holbrook compressor located in western Pennsylvania.
The Lebanon line is significantly smaller than the mainline. Capacity at Sarahsville, for example, is about 750 MMcfd compared to about 2 bcfd for the mainline.
REX interconnects with the Lebanon line just east of Sarahsville. Capacity utilization at Sarahsville averaged 74% in 2006. It was more than 90% full for 108 days and more than 95% full for 66 days, leaving little unused capacity, particularly on a peak day in winter.
Capacity exists on the mainline and east of Holbrook. REX volumes, however, cannot enter that part of the TETCO system without first entering the constrained Lebanon line.
TETCO is currently undertaking its Time II expansion project (approved by FERC June 8, 2007), which will increase the capacity of the Lebanon line by 150 MMcfd beginning later this year. This project entails looping and replacement of existing pipeline on the Lebanon line and the southern branch of the mainline east of Holbrook.
The Time II expansion will enable incremental REX volumes to move past Holbrook to Pennsylvania, New York, and New Jersey customers, as well as to many of the storage facilities accessed by TETCO in Pennsylvania and Maryland. The expansion will not, however, significantly affect TETCO shippers’ ability to move gas east from storage facilities to their markets on peak days. These constraints will continue to limit incremental volumes from reaching East Coast markets.
TGP-Clarington
A similar situation exists on Tennessee Gas Pipeline. Fig. 4 shows capacity utilization at Compressor Station 219 in western Pennsylvania. REX interconnects with Tennessee Gas southwest of Station 219. Flows over the past 2 years show that Tennessee Gas has significant unused capacity and could receive incremental volumes from REX. In the summer, such volumes presumably would be used either by power generators or to fill storage, increasing the storage fill rate.
As was the case with TETCO, however, capacity constraints east of Pennsylvania and New York pose a significant impediment to shippers who want to bring incremental volumes to markets in Tennessee. Flows through Tennessee Gas either east of the storage facilities on the southern line or east of the interconnection points where Canadian gas enters the system at Niagara are constrained during peak load periods.
Canadian imports have been declining at Niagara and other Northeast locations over the past few years but remain an integral part of Tennessee Gas shippers’ current supply portfolio. Curtailments occur at Stations 245 and 321 (Fig. 4). Incremental REX volumes will allow Tennessee Gas to fill storage more rapidly and may also offset declining Canadian supplies, but these capacity constraints will limit their ability to do so.
Tennessee Gas announced an expansion of its pipeline in New York to improve deliverability to East Coast markets. The expansion entails construction of a high-pressure pipeline originating near Clarington and extending eastward to an interconnect with Iroquois Pipeline near Poughkeepsie, NY. The proposed line will have 1-1.5 bcfd capacity and is to be in service 2010-11. If constructed, the expansion will significantly improve the full deliverability potential of REX to customers in the highly constrained East Coast market.
REX advantage
The REX project can operate at a maximum allowable operating pressure (MAOP) of up to 1,480 psig, as compared to 600-1,050 psig for TETCO, 450-790 psig for Tennessee Gas, and similar pressures for the other interconnected pipelines. This advantage translates to lower charges for fuel and lost and unaccounted for gas in the REX tariff. The implications of this advantage become apparent when comparing the delivered price incurred by shippers when moving gas to either Lebanon or Clarington.
The variable components of each pipeline’s tariff-commodity charge, plus fuel and loss-provide the basis for evaluation of market economics. The much larger demand component of the tariff must be paid regardless of whether the shipper moves a molecule of gas.
Transportation alternatives that influence shipper behavior and market pricing hinge solely on the variable cost associated with alternative movements of natural gas, for the purposes of this article, which uses fuel charges for REX as reported in its “Fuel Guidance” dated Sept. 11, 2006. Original capacity holders on REX have contractual fuel rates lower than used here and will thus derive an even greater advantage than shown in this analysis.
A similar scenario holds true for shippers on competing pipelines. To the extent such shippers enjoy discounted prices, transportation economics will differ from the following analysis.
Tariff comparison
When REX East opens, REX shippers will have a dramatic price advantage to Lebanon over traditional supply areas, primarily because of the commodity cost differential. Fig. 5 shows the advantage by comparing the delivered price to Lebanon using REX to the current pipeline alternatives, defining commodity costs as the average 2006 price for the appropriate supply point.
The average 2006 price of $5.78 at Cheyenne serves as a proxy for REX. With one exception, competitive pipeline prices use the 2006 average price at the appropriate gulf supply point. Midwestern Gas Transmission commodity prices use the average 2006 price at Joliet. Price comparison demonstrates that REX shippers are able to purchase gas at a $0.50-1.00/MMbtu discount to alternative supply sources. Customers purchasing supply from REX suppliers that can use Opal or another producing area price point that historically trades at an additional $0.10-0.30/MMbtu discount to Cheyenne can gain an additional advantage.
The 2007 supply build up in the Rockies has so far greatly exaggerated Rockies price differentials. In April 2007 Cheyenne and Opal prices averaged $3.02/MMbtu less than Henry Hub prices.
This price advantage, coupled with the fuel-loss percent advantage, yields significantly lower-priced supply at Lebanon. Fig. 5 shows the advantage ranging from $0.13/MMbtu on Panhandle Eastern to $0.80/MMbtu on Texas Gas Transmission and ANR’s Southeast leg. This advantage will initially force spot prices to decline in the gulf and East Texas supply areas relative to Cheyenne, Opal, and other Rockies production pricing points.
REX IIIa will cause a significant readjustment in prices, with Rockies prices rising sharply relative to gulf areas prices.
Once prices adjust after REX IIIa enters service, the differential between Cheyenne and the gulf and Cheyenne and Joliet should settle at about $0.10-0.20/MMbtu.
Assuming gas prices across supply areas equal to $7.00/MMbtu at the relevant purchase points, further demonstrates the relative economics of REX. This is not a price forecast but instead highlights the differences in gas transportation economics.
Assuming commodity-price differences that settle to reflect variable transportation differentials, Fig. 6 shows current differentials narrowing substantially, settling with gulf prices about $0.20 higher than Rockies prices, approximating the variable cost differential between the pipelines. This transition, however, will occur between December 2008 when REX IIIa commences service and July 2008 when REX IIIb becomes operational.
Reaching Clarington maximizes the REX market advantage. Rockies producers received an average of $0.52-0.91 less for their production than did gulf-area producers in 2006.This differential is substantially larger in 2007 and, coupled with the lower fuel charges associated with REX, translates into a $0.80-1.17/MMbtu delivered price advantage for REX shippers over shippers purchasing supplies from the traditional gulf areas.
Assuming that REX’s commodity cost advantages continue through 2008, REX volumes should displace gulf volumes once REX reaches Clarington.
REX’s price advantage at Clarington will drive relative prices down in the gulf and raise relative Rockies prices at Cheyenne and Opal.
Again using a $7.00/MMbtu supply-area reference case, in which spot prices at Cheyenne and the gulf are equal, REX supplies hold an advantage over Tennessee Gas and TETCO and will be only slightly more expensive than supplies shipped to the region via Columbia Gulf. If the Rockies-to-gulf price spread settled equal to the variable transport differential, Rockies gas might hold as much as a $0.42 premium over some gulf supply points on TETCO and slightly less on Tennessee Gas.
Other factors will likely intervene to reduce or eliminate some of the Rockies premium, but the data clearly show that REX will go a long way toward allowing Rockies gas to trade at or near parity with gulf supplies.
REX market pressures will not occur in a vacuum. Other factors will affect the market while REX is being built. Production increases in the East Texas, Fort Worth, Arkoma, and Arkla basins will put gulf supplies under pressure. Increases in Northeast power generation demand could absorb some incremental supplies given new pipeline capacity east of Clarington to deliver REX supplies to the new markets. Lower Canadian imports could also make room for additional REX supplies. Each of these developments could buffet regional supply-demand balances as the REX realignment rolls through the market.
Canadian decline
Lower Canadian import volumes could make room for REX gas. Canadian gas is a significant component of Dominion and Tennessee Gas shippers’ supply portfolios and also makes up a large portion of the overall supply portfolios of customers in the upper Midwest.
Imports into the Northeast declined by 157 MMcfd, or 6%, in 2006, and in the Midwest imports declined by 193 MMcfd, or 5%. Three factors led to the declines: falling production in Alberta, increased use of natural gas for the production of bitumen (oil sands), and growing need for gas as a generation fuel for new power facilities. All of these factors increase the demand for Rockies gas.
Supply build
The sharp buildup of new production in the gulf region has compounded the need for gas from the area to find a new market. Exploration and development success in the Barnett Shale, Woodford Shale and other relatively new production areas in East Texas, the Fort Worth, Arkoma, and Arkla basins has resulted in strong incremental production gains.
During the next 2 years, several new Gulf of Mexico projects, such as Anadarko’s Independence Hub, are scheduled to come online and could increase production by more than 1 bcfd.
These projects will cause incremental production in the region to swell for at least a few years. If production gains continue to accelerate even slightly, production from the region will be more than 1 bcfd higher by the end of 2008, when REX East comes online.
Demand growth
At the same time supply is building, demand is also growing. Bentek’s demand forecast through 2010, which closely matches the most recent US Energy Information Administration forecast, calls for growth in the Upper Midwest, Northeast, Texas-Louisiana, and Southeast market areas, almost entirely based on increased power-generation demand. Aggregate demand from the four regions will have grown 3.9 bcfd, a 2.3%/year compound growth rate, by 2010. The Texas-Louisiana-Arkansas and Southeast regions show the highest incremental demand, 1.3 bcfd and 1.1 bcfd, respectively, but demand in the Upper Midwest and Northeast regions will grow as well, by a 0.7 bcfd and 0.8 bcfd, respectively.
Much of the gulf supply build will supply this growing demand. CenterPoint Energy’s recently completed Carthage-to-Perryville pipeline and other pipelines under development will improve producers’ ability to deliver supplies to the higher demand-growth areas. Similarly, gulf, East Texas, and other Midcontinent supplies will be able to use ANR, NGPL, Trunkline, and Texas Gas Transmission to increase flows to the Upper Midwest.
LNG wild card
LNG could add significantly to the gulf supply build. Lake Charles already has the potential to deliver more than 2.0 bcfd on a peak day and 1.8 bcfd on a sustained basis. Four new gulf coast LNG regasification plants-Sabine Pass, Freeport, Golden Pass, and Cameron-are set to come online in 2008 or 2009, bringing an aggregate 7.6 bcfd of incremental supply to the region.
Global competition for LNG supply among Europe, Asia, and the US, will likely lead to low load factors at these new US terminals, but a substantial amount of LNG could arrive during the shoulder and summer months. Asia and Europe have inadequate storage to pull demand for storage injection, resulting in a high likelihood that summer and shoulder-month prices in the US will be more attractive to global LNG suppliers.
Recontracting capacity
A large number of firm transportation contracts on multiple interstate pipelines will expire between 2007 and 2010. Fig. 7 shows the percentage of volume covered by those expiring contracts on pipelines that interconnect with REX (based on analysis of the January 2007 Index of Customer filings at FERC).
Across the pipelines shown, an average of 50% of firm contract volume will expire before 2010. NGPL has the largest percentage of firm transport contracts expiring (69%), but because of the competitive tariff economics it will probably be the least affected by REX. On the other hand, TETCO, Tennessee Gas, and Panhandle, the three pipelines which may be at the greatest competitive disadvantage, have 56%, 50%, and 55%, respectively, of their firm contracts expiring for before 2010.
The expiry of so much of the contracted firm transport volume between now and commencement of service on REX East suggests that many East Coast and Midwest utilities and end users (the primary capacity holders on the affected pipelines) will have the opportunity to realign their supply portfolios.