The year 2005 will be remembered for its hurricanes and record-setting natural gas prices, events that continuously grabbed the top headlines in the Natural Gas Intelligence newsletters, making them the longest-running top stories for the industry. Besides the actual hurricanes and consequent price spikes, it appeared that nearly everyone in a position to be quoted — congressmen, regulators, analysts, advocates, and industry executives — had comments, warnings, or prognostications about the events that roiled the industry. Other events — while important — only sporadically managed to shove hurricanes and prices out of the spotlight.

For instance, the Congress and Administration did wind up five years of effort and produced the Energy Policy Act of 2005. The battle over LNG siting raged among locals and state and federal regulators on the East and West coasts. Numerous new pipelines were proposed, topped by competing super-long lines from the Rockies to the East. Assessments of future U.S. and Canadian production abounded. And, as usual, there were several large mergers among producing, pipeline and midstream companies, as well as and power utilities.

Veteran natural gas industry analyst John Olson considers 2005 to have been a year of trade-offs. Prices hit levels high enough to spur exploration and production activity. High prices also spurred demand destruction in the industrial sector. However, there appeared to be no net demand destruction as gas consumption for power generation continued to increase, Olson told Daily GPI. On the gas supply front, Olson sees survival in the promise of LNG imports and also in opening the Arctic National Wildlife Refuge.

“We have transitioned further away from the low-hanging fruit in exploration and production for natural gas and we are drilling a lot of no-brainers out there, and with much higher decline curves,” Olson said. “If you look at a 1990 vintage of gas wells being completed, the initial decline curve was somewhere around 19% in the first year. And then in ’05 it was running closer to 30%. And that puts this country, and for that matter North America, on a very big treadmill. We will drill about 26,000 gas wells this year [2005] in the United States and something north of 16,000 in Canada. And all we’re doing is replacing the natural declines.”

The single story in 2005 that garnered the most clicks on NGI’s website, also turned out to be the most prescient: “Goldman Sachs ‘Super-Spike’ Report Warns of $13/MMBtu Gas, $105/bbl Crude” (see Daily GPI, April 1, 2005). Read below the headline, however, and it is revealed that the Goldman Sachs “super-spike” is a multi-year affair and the $13 gas price wasn’t expected until 2007. In April, when the article was published, Goldman and other analysts were calling for gas prices to average about $6.70, going to $7.00 in 2006. At the end of 2005, the conventional measure used by most analysts to create an average from the closing Nymex settlement prices for each of the 12 months turned up an average of $8.62/MMBtu, with a range from $6.123 (June) up to $13.907 (October).


In between came what the National Oceanic and Atmospheric Administration (NOAA) said was the busiest Atlantic hurricane season on record. The 2005 season included 26 named storms, including 14 hurricanes in which seven were major (Category 3 or higher). The number of named storms shattered the previous record of 21 set in 1933. In contrast, the government agency said that the average over the last 40 years is for a season to have 11 named storms, six hurricanes and two major hurricanes (see Daily GPI, Dec. 1, 2005). After NOAA’s report was issued in early December the 27th named storm, Tropical Storm Zeta, saw the old year out and the new year in, thankfully without approaching the Gulf Coast (see Daily GPI, Jan. 3). The name for the first big storm originating in 2006 will be Alberto. The weather service is likely to retire the name Katrina from its cycle of names and probably a couple others, a spokesman said.

Katrina, Rita and Wilma all reached Category Five intensity, which is the first season since 1851 that three storms have achieved that level. NOAA warned that its data for the season could change because Tropical Storm Cindy may have reached hurricane force at landfall in Louisiana and Hurricane Emily might have briefly reached Category Five strength during its run. But that last is nit-picking; the storms were major and did major damage.

“This hurricane season shattered records that have stood for decades — most named storms, most hurricanes and most category five storms. Arguably, it was the most devastating hurricane season the country has experienced in modern times,” said retired Navy Vice Adm. Conrad C. Lautenbacher Jr., Ph.D., undersecretary of commerce for oceans and atmosphere and NOAA administrator. “I’d like to foretell that next year will be calmer, but I can’t. Historical trends say the atmosphere patterns and water temperatures are likely to force another active season upon us,” and the active cycle could last another 10 to 20 years.

Of the 2005 hurricanes, Katrina, which made landfall Aug. 29, was certainly the worst. New Orleans-based Entergy called the storm the worst in history (see Daily GPI, Aug 31, 2005) — not just for people, but for damage to the natural gas infrastructure as well, traveling as it did dead on through the heart of the Gulf production area. While not as severe, Gulf of Mexico producers could have easily done without Hurricane Rita, which followed on the heels of Katrina just a few weeks later and scared everyone out of Houston for a few days.

Two other storms in the first two weeks of July served as a warm-up and ensured no area of the Gulf was left untouched. Tropical Storm Cindy was milder, but hit some of the West Gulf, swinging wide to the west and then going ashore near the Texas-Louisiana border, while Hurricane Dennis filled in the far east Gulf, going ashore in the Florida Panhandle.

In late September about 78% of the daily natural gas production and 100% of the oil production in the Gulf of Mexico remained shut in, according to Minerals Management Service (MMS), which compiled reports from 76 producers. MMS also reported that almost 93% of the 819 manned platforms and 75% of the 134 rigs also remained evacuated (see Daily GPI, Sept. 27, 2005). July’s Hurricane Dennis was gentler on Gulf producers; however, it did damage BP’s Thunder Horse platform and along with Katrina and Rita is responsible for delaying production start-up until early this year (see Daily GPI, July 27, 2005).

And just to prove weather rules, the absence of blustery, bone-chilling winter over much of the United States in the last part of December and early January 2006 was setting the price roller-coaster on a downward plunge.

Energy Policy Act of 2005

No politician’s bluster can equal the force of a category five hurricane; however, it was years of bluster that finally culminated in passage of the Energy Policy Act (EPACT) of 2005 (see Daily GPI, Aug. 9, 2005). While last year’s hurricanes will be remembered for their devastating impact, EPACT might well be recalled for all that it did not do. The industry was counting on comprehensive energy legislation that would put the country on a glide path to supply security, but that didn’t happen.

While the Act’s passage was not a non event, it was anticlimactic in the eyes of many, and a downright disappointment to others. Provisions to allow drilling on a resource-rich part of the Arctic National Wildlife Reserve (ANWR) or expand offshore exploration opportunities to the nation’s East and West coasts or the eastern Gulf of Mexico did not make it into the new law. Also omitted was liability protection for producers of the gasoline additive methyl tertiary butyl ether, a key issue for the petroleum industry.

Possibly the most important item in the book-length measure enacted in August was the repeal of the Public Utility Holding Company Act of 1935. In its place the new law handed FERC authority to review the books and records of holding companies.

EPACT 2005 also spelled out clear authority for the Commission (not the states) over the siting of LNG terminals, as well as long-line transmission lines and pipelines. And it gave FERC significant new responsibilities to oversee and enforce mandatory power grid reliability rules, to protect against market manipulation and the exercise of market power, and to grant market-based rate treatment for new natural gas storage capacity. The Act also included royalty relief to spur development in the deep waters of the Gulf of Mexico and measures to expand access to federal lands and streamline the permitting process for drillers. It called for a federal inventory of oil and gas on the 1.67 billion-acre OCS and it permanently banned drilling on the U.S. side of the Great Lakes.

Favorable tax treatment was offered for small producers, along with incentives for clean coal, nuclear and renewables development. Although it increased the authorization for the Low-Income Home Energy Assistance Program (LIHEAP) to $5.1 billion, the Congress voted late last year not to back it up with an increased appropriation. The LIHEAP appropriation is still on the table in 2006, and the ANWR debate almost surely will return.


A comprehensive energy policy has been a long term goal of the industry. However, all the policy in the world means nothing without energy supply. To augment supply the gas industry has pinned much of its hopes on LNG.

LNG — which by now everyone knows stands for liquefied natural gas — continued to raise the hopes of industry participants and regulators, while siting raised the hackles of a good number of citizens and politicians. Squabbles over receipt terminal siting and state-federal jurisdiction of the same made many headlines, as did the growing worry that the United States might not fare as well in a global gas market as had been originally hoped. Another concern that came to the fore is how well gas from LNG would be integrated with North America’s traditional gas stream. But along the way, proposals for LNG facilities continued, and a number of projects passed regulatory hurdles.

Last year began with a request to Congress from FERC for modification of Section 3 of the Natural Gas Act to make “clear and unambiguous” that FERC has exclusive authority over the siting of LNG import terminals onshore and in state waters as well as over pipelines that deliver LNG-derived gas (see Daily GPI, Jan. 19, 2005). FERC got its wish with EPACT 2005. Chairman Joseph Kelliher said that the sweeping legislation removed “a cloud” over FERC’s jurisdiction and should aid the development of LNG facilities (see Daily GPI, Aug. 9, 2005). FERC had been in a turf battle with the State of California, and while California ultimately conceded to FERC on the jurisdictional point, it didn’t give up fighting a proposed LNG terminal at the Port of Long Beach (see Daily GPI, Oct. 10, 2005).

Despite jurisdictional uncertainty, LNG infrastructure development continued to move ahead. In March, Excelerate Energy’s Gulf Gateway Energy Bridge was on track to become the world’s first deepwater LNG port, 116 miles off the coast of Louisiana in 298 feet of water (see Daily GPI, March 4, 2005). Gulf Gateway received its first cargo in April (see Daily GPI, April 7, 2005).

In June FERC approved two import terminals — Weaver’s Cove in Fall River, MA — where there is significant local and state opposition — and Golden Pass in Sabine Pass, TX — and rejected another — KeySpan’s Fields Point in Providence, RI — on safety concerns. Commissioner Nora Brownell said the decision to nix Fields Point was in line with Commission policy “that addresses the very real concerns made by the residents in communities and all of the towns nearby the proposed project.”

Despite approval by FERC, Weaver’s Cove ran aground in August when seven lines of text were inserted into the Transportation Authorization Bill, which basically made it illegal for a bridge to be demolished in order to allow LNG traffic up the Taunton River to the site of the proposed Weaver’s Cove terminal (see Daily GPI, Aug. 10, 2005). Shell Gas & Power’s Gulf Landing terminal was approved by the U.S. Maritime Administration (MARAD). The 1 Bcf/d terminal is to be located in West Cameron Block 213, about 38 miles offshore Louisiana. Service is expected in late 2008 or early 2009 (see Daily GPI, Feb. 18, 2005).

Last year also saw approval of Cheniere Energy’s third Gulf Coast LNG terminal when FERC signed off on the company’s 2.6 Bcf/d facility in Corpus Christi, TX (see Daily GPI, April 14, 2005). Cheniere has four LNG projects under way along the Gulf Coast, and by 2011 it is projected to have 11.4 Bcf/d available from the regasification facilities (see Daily GPI, Nov. 16, 2005).

Cheniere’s Freeport, TX facility is expected to be ready to receive 1.5 Bcf/d by 2008. The Sabine Pass, LA project, with construction quickly moving along, is expected to be ready to receive 2.6 Bcf/d by 2008, with an increase to 4 Bcf/d by 2009. The Corpus Christi, TX facility should have 2.6 Bcf/d available by 2010, and the newest project, the Creole Trail, LA facility, will have 3.3 Bcf/d available by 2010.

In June FERC approved ExxonMobil Corp. affiliates’ Vista del Sol terminal and associated pipeline facilities near Corpus Christi, TX, marking the fifth new LNG terminal project the FERC approved since 2001, all of them in the Gulf Coast region (see Daily GPI, June 16, 2005).

In July FERC approved Occidental Petroleum’s Ingleside, TX, LNG terminal and associated San Patricio Pipeline. The 1 Bcf/d terminal is to be located near Occidental’s chemical plant on Corpus Christi Bay (see Daily GPI, July 22, 2005).

In September Irving Oil and Repsol announced the initial phase of construction on their $445 million Canaport terminal, adjacent to Irving’s 250,000 bbl/d Canaport refinery in St. John, New Brunswick about 65 miles from the U.S. border (see Daily GPI, Sept. 13, 2005). The project is expected to be completed and in service by 2008 with deliveries of up to 750,000 Dth/d to U.S. and Canadian markets via the Maritimes & Northeast pipeline. The remaining 250,000 Dth/d will serve the refinery. The terminal also will have capacity to store 480,000 cubic meters of LNG.

Also under construction is a C$600 million terminal and regasification facility on Cape Breton Island, along the Strait of Canso in Nova Scotia (see Daily GPI, May 5, 2005). Anadarko Petroleum Corp. subsidiary Bear Head LNG Corp. is developing the 1 Bcf/d terminal.

Sempra Energy’s LNG unit said in October that it signed a “heads of agreement” (HOA) with Algeria’s Sonatrach S.A., and is proceeding with “detailed negotiations” to bring Algerian LNG to the U.S. Gulf Coast trough its Cameron LNG facility under construction in Lake Charles, LA (see Daily GPI, Oct. 26, 2005). Sempra is developing three LNG receiving terminals — Energia Costa Azul along the Pacific Coast of North Baja in Mexico (about 55 miles south of the U.S.-Mexico border), which is currently on schedule to begin receiving its first shipments in early 2008; Cameron, which is targeted to begin receiving shipments in late 2008; and a third facility still seeking permits near Port Arthur, TX. With timely federal permits, Port Arthur could be operational in 2009, Sempra said. Costa Azul is now fully under construction.

While the Commission weighed the merits of LNG projects, others attempted to take measure of the United States’ future clout in a global LNG marketplace. Arlington, VA-based Energy Ventures Analysis (EVA) posited that worldwide liquefaction capacity would grow three-fold by early 2011, but only a portion of the incremental capacity would be earmarked for the United States.

Europe and Asia were predicted to be highly competitive with U.S. markets (see Daily GPI, July 5, 2005). EVA’s prediction was optimistic compared to that of Tristone Capital, which weighed in later in the year. Tristone estimated that global liquefaction capacity will grow from 20.3 Bcf/d in 2005 to 33 Bcf/d in 2010, while regasification capacity will balloon to 53.9 Bcf/d by the end of the decade. “With the global market increasingly net short LNG supply, we expect the current sellers’ market to persist well through the end of the decade,” said Tristone’s Chris Theal (see Daily GPI, Dec. 15, 2005).

Finally, with seemingly the whole world wanting regasified LNG, there was at least one party that didn’t, or at least blamed the gas for creating havoc on its distribution system. LNG from Dominion Resources’ Cove Point terminal was blamed for causing leaks on the Washington Gas Light Co. distribution system in Prince Georges County, MD (see Daily GPI, May 18, 2005). Dominion disputed the claim, but WGL pointed to a study that cited gas composition, along with winter ground temperatures and aging seals and maintained that gas composition was the leading factor.


The promise of LNG, gas supply from hot plays such as the Barnett Shale, as well as the Rocky Mountain region inspired a number of pipeline projects last year.

In August, Kinder Morgan Energy Partners LP and Sempra Pipelines & Storage said that they agreed to develop a 1,500-mile interstate pipeline that would link Rockies gas production to markets in the upper Midwest and eastern United States (see Daily GPI, Aug. 18, 2005). The 42-inch diameter line would have capacity of up to 2 Bcf/d and cost an estimated $3 billion. As announced, the line would originate at the Wamsutter Hub in Wyoming and extend to eastern Ohio with the ultimate route dictated by shipper interest. The companies said their project would feature as many as 40 interconnects with other pipelines.

And in early October El Paso Corp. jumped into the fray to help Rockies producers get their gas to market when it proposed the Continental Connector, a new system with more than 1,000 miles of up to 42-inch pipe to ship 1-2 Bcf/d of Rockies gas east by connecting six of its pipelines — in the West, Colorado Interstate, WIC and Cheyenne Plains — going east to ANR Pipeline, Tennessee Gas Pipeline, and Southern Natural Gas. El Paso said the project could be in service as early as November 2008 (see Daily GPI, Oct. 5, 2005).

The Rocky Mountain region wasn’t the only natural gas breadbasket to attract pipeline interest. As the Barnett Shale has come into its own as a huge source of gas supply — the largest in Texas, in fact — the pipeline proposals have followed. Following completion of feasibility studies, Crosstex Energy LP said it would proceed with construction of its North Texas Pipeline project to bring Barnett Shale production to markets in the Midwest and East (see Daily GPI, Feb. 28, 2005). The project was first announced in December 2004 (see Daily GPI, Dec. 14, 2004).

The siren call of East Texas also was heard by Kinder Morgan. In May the company announced an open season to test interest in a new 700,000 Dth/d interstate pipeline to carry gas from the Bossier Sand and Barnett Shale, as well as imports from new LNG terminals along the Gulf Coast to pipelines in Louisiana (see Daily GPI, May 26, 2005). At the downstream end of the new pipeline, Crosstex LIG was planning to extend and expand its system to accommodate the additional supply from the new Carthage line as well as production from growing supply basins in North Louisiana.

And less than two weeks later, Boardwalk Pipelines LLC subsidiaries Gulf South Pipeline Co. LP and Texas Gas Transmission LLC, along with Energy Transfer Partners LP said that they were jointly developing two independently owned and operated pipeline systems that would interconnect near Carthage, TX to integrate with systems in East Texas, home of the Bossier Sand and Barnett Shale plays (see Daily GPI, June 6, 2005).

Mergers and Acquisitions

Last year was a relatively light one for mergers and acquisition deal flow, at least for anyone who remembers the utility consolidation that took place during the late 1990s. However, there were a number of power-oriented deals, and the producer transactions that were announced were noteworthy for the dollar amounts attached. A good deal of assets changed hands, particularly in the midstream. And some asset sales were a further reminder of how the energy landscape has changed post-Enron. There were some big names cutting loose some big assets last year.

The merger most bullish for natural gas came at the end of the year when in December ConocoPhillips said it would buy Burlington Resources for $35.6 billion, an amount some thought excessive but others thought, “cheaper today than perhaps tomorrow” (see Daily GPI, Dec. 14, 2005). The announcement was further evidence of renewed interest in the United States by major producers and was thought to be a harbinger of more acquisitions by cash-rich majors. However, another bullish deal had already been announced earlier in 2005. ChevronTexaco Corp., the second largest U.S.-based oil major agreed to buy ninth-ranked Unocal Corp. in a cash-and-stock transaction worth about $16.4 billion. ChevronTexaco also agreed to assume $1.6 billion in debt (see Daily GPI, April 5, 2005)

Pipelines changed hands, too. In July General Electric said that it and Canada’s largest institutional investor, Caisse de depot et placement du Quebec, agreed to buy the Southern Star Central natural gas pipeline system from AIG Highstar Capital for an estimated $362 million, plus assumption of $476 million in debt and preferred stock (see Daily GPI, July 12, 2005). Southern Star spans more than 6,000 miles in Kansas, Oklahoma, Missouri, Wyoming, Nebraska, Colorado and Texas, making it the largest gas transmission system based on mileage in the central United States. Assets also include eight gas storage fields. AIG Highstar Capital acquired Southern Star in 2002 from The Williams Cos., and GE’s Energy Financial Services unit acquired a 2% share in 2003.

In August Kinder Morgan announced a deal to acquire British Columbia gas utility and pipeline company Terasen (formerly BC Gas) for $3.1 billion in cash plus $2.5 billion in assumed debt (see Daily GPI, Aug 2, 2005). The price represented a 20% premium to Terasen’s previous 20-day average stock price.

Also in August, Dynegy — which formerly was known as Natural Gas Clearinghouse — officially stepped out of the natural gas business with the $2.475 billion sale of its gas gathering, processing and liquids operations to Targa Resources Inc., a tightly held Houston-based midstream operator affiliated with private equity investor Warburg Pincus (see Daily GPI, Aug. 3, 2005). Dynegy said that it would consider “every opportunity” for its remaining power generation business.

Another transaction that surely reminded some of the past trading go-go days was Duke Energy’s deal, announced in September, to sell all of Duke Energy North America’s (DENA) physical and commercial assets outside the midwestern United States, including about 6,200 MW of power generation as well as DENA’s trading book.

The plan was expected to be completed in 12 months as Duke and Cinergy continue through the regulatory process on their mega utility merger (see Daily GPI, May 10, 2005). And that Duke-Cinergy deal, announced in May, was a big one (see Daily GPI, May 10, 2005). Duke said it would acquire Cincinnati, OH-based Cinergy Corp. for $9 billion in stock, creating a company with 5.4 million gas and electric customers. Executives hinted that Duke might jettison its gas assets and meet the future as a pure electric play.

In May Warren Buffett’s MidAmerican Energy Holdings Co. agreed to buy PacifiCorp from ScottishPower for $5.1 billion in cash and assumption of $4.3 billion in debt. The acquisition added to MidAmerican’s two major interstate gas pipelines and midwestern utility operations (see Daily GPI, May 25, 2005). The outcome is a holding company that serves three million electric and gas customers in 10 contiguous western states and 6.6 million customers worldwide, according to MidAmerican, which is based in Des Moines, IA. MidAmerican was bought in October 1999 by an investor group led by Berkshire Hathaway, of which Buffett is chairman (see Daily GPI, Oct. 26, 1999).

Although it was announced in 2004, the combination of Exelon Corp. and Public Service Enterprise Group (PSEG) is worth mentioning here as it gained FERC approval in 2005 (see Daily GPI, July 5, 2005). Commissioner Joseph Kelliher, who had recently been named FERC’s new chairman, noted at the time that the Commission “hadn’t dealt with a large merger in a number of years.” The deal, and it’s approval by FERC, were particularly noteworthy for the amount of divestiture prescribed. Kelliher said that the two utilities offered up “very robust” mitigation, with a combined 6,600 MW of physical and “virtual” divestiture. He said this MW divestiture number is “really unprecedented at the Commission.”

Finally, the last merger announcement of the year was of a post-PUHCA deal to combine FPL Group and Constellation Energy. The “modified merger of equals,” announced in December, was touted as a non regulated asset play (see Daily GPI, Dec. 20, 2005). The transaction brings together the regulated Florida Power & Light and Baltimore Gas & Electric. But more noteworthy is the non regulated generating asset base, particularly coal and nuclear.

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